10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED June 30, 2017

OR

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

SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM          TO

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

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

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes ý No ¨

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

Public Service Enterprise Group Incorporated	Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company  o
Public Service Electric and Gas Company	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company  o
PSEG Power LLC	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company  o

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

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

As of July 18, 2017, Public Service Enterprise Group Incorporated had outstanding 505,889,953 shares of its sole class of Common Stock, without par value.

As of July 18, 2017, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.

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

		Page
FORWARD-LOOKING STATEMENTS		ii
FILING FORMAT		iii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated	1
	Public Service Electric and Gas Company	6
	PSEG Power LLC	11
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation	16
	Note 2. Recent Accounting Standards	16
	Note 3. Early Plant Retirements	19
	Note 4. Variable Interest Entity (VIE)	20
	Note 5. Rate Filings	21
	Note 6. Financing Receivables	22
	Note 7. Available-for-Sale Securities	24
	Note 8. Pension and Other Postretirement Benefits (OPEB)	29
	Note 9. Commitments and Contingent Liabilities	31
	Note 10. Debt and Credit Facilities	39
	Note 11. Financial Risk Management Activities	40
	Note 12. Fair Value Measurements	45
	Note 13. Other Income and Deductions	53
	Note 14. Income Taxes	54
	Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax	55
	Note 16. Earnings Per Share (EPS) and Dividends	59
	Note 17. Financial Information by Business Segments	60
	Note 18. Related-Party Transactions	61
	Note 19. Guarantees of Debt	63
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	66
	Executive Overview of 2017 and Future Outlook	66
	Results of Operations	73
	Liquidity and Capital Resources	78
	Capital Requirements	80
	Accounting Matters	81
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	81
Item 4.	Controls and Procedures	82
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	82
Item 1A.	Risk Factors	82
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	82
Item 5.	Other Information	83
Item 6.	Exhibits	86
	Signatures	87

i

FORWARD-LOOKING STATEMENTS

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

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

• our ability to obtain adequate fuel supply;

• any inability to manage our energy obligations with available supply;

• increases in competition in wholesale energy and capacity markets;

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

• economic downturns;

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

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

• changes in state and federal legislation and regulations;

• the impact of pending rate case proceedings;

• regulatory, financial, environmental, health and safety risks associated with our ownership and operation of nuclear facilities;

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

• changes in federal and state environmental regulations and enforcement;

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

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

• changes in tax laws and regulations;

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

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

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

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

• any inability to successfully develop or construct generation, transmission and distribution projects;

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

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

ii

• any inability to maintain sufficient liquidity;

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

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

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

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

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

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

FILING FORMAT

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

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

iii

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions, except per share data

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
OPERATING REVENUES	$	2,133		$	1,905		$	4,725		$	4,521
OPERATING EXPENSES
Energy Costs	588			624			1,462			1,460
Operation and Maintenance	708			710			1,420			1,439
Depreciation and Amortization	641			224			1,469			448
Total Operating Expenses	1,937			1,558			4,351			3,347
OPERATING INCOME	196			347			374			1,174
Income from Equity Method Investments	5			4			8			6
Other Income	70			44			142			92
Other Deductions	(9		)	(10		)	(20		)	(31		)
Other-Than-Temporary Impairments	(3		)	(10		)	(4		)	(20		)
Interest Expense	(91		)	(97		)	(189		)	(189		)
INCOME BEFORE INCOME TAXES	168			278			311			1,032
Income Tax Expense	(59		)	(91		)	(88		)	(374		)
NET INCOME	$	109		$	187		$	223		$	658
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505			505			505
DILUTED	507			508			507			508
NET INCOME PER SHARE:
BASIC	$	0.22		$	0.37		$	0.44		$	1.30
DILUTED	$	0.22		$	0.37		$	0.44		$	1.30
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.43		$	0.41		$	0.86		$	0.82

See Notes to Condensed Consolidated Financial Statements.

1

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
NET INCOME	$	109	$	187		$	223	$	658
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(9), $(10), $(25) and $(26) for the three and six months ended 2017 and 2016, respectively	10		10			25		26
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $0 and $(1) for the three and six months ended 2017 and 2016, respectively	—		(1		)	—		1
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(4), $(6), $(8) and $(12) for the three and six months ended 2017 and 2016, respectively	6		8			12		16
Other Comprehensive Income (Loss), net of tax	16		17			37		43
COMPREHENSIVE INCOME	$	125	$	204		$	260	$	701

See Notes to Condensed Consolidated Financial Statements.

2

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	June 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	430		$	423
Accounts Receivable, net of allowances of $61 in 2017 and $68 in 2016	1,021			1,161
Tax Receivable	9			78
Unbilled Revenues	210			260
Fuel	270			326
Materials and Supplies, net	577			561
Prepayments	273			76
Derivative Contracts	113			163
Regulatory Assets	276			199
Other	9			7
Total Current Assets	3,188			3,254
PROPERTY, PLANT AND EQUIPMENT	38,794			39,337
Less: Accumulated Depreciation and Amortization	(9,157		)	(10,051		)
Net Property, Plant and Equipment	29,637			29,286
NONCURRENT ASSETS
Regulatory Assets	3,349			3,319
Long-Term Investments	961			1,050
Nuclear Decommissioning Trust (NDT) Fund	1,968			1,859
Long-Term Tax Receivable	111			104
Long-Term Receivable of Variable Interest Entity (VIE)	600			589
Other Special Funds	224			217
Goodwill	16			16
Other Intangibles	120			98
Derivative Contracts	90			24
Other	260			254
Total Noncurrent Assets	7,699			7,530
TOTAL ASSETS	$	40,524		$	40,070

See Notes to Condensed Consolidated Financial Statements.

3

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	June 30, 2017			December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	900		$	500
Commercial Paper and Loans	—			388
Accounts Payable	1,293			1,459
Derivative Contracts	8			13
Accrued Interest	99			97
Accrued Taxes	46			31
Clean Energy Program	200			142
Obligation to Return Cash Collateral	134			132
Regulatory Liabilities	51			88
Other	433			426
Total Current Liabilities	3,164			3,276
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,755			8,658
Regulatory Liabilities	99			118
Clean Energy Program	27			—
Asset Retirement Obligations	744			726
OPEB Costs	1,304			1,324
OPEB Costs of Servco	467			452
Accrued Pension Costs	525			568
Accrued Pension Costs of Servco	124			128
Environmental Costs	378			401
Derivative Contracts	1			3
Long-Term Accrued Taxes	192			180
Other	205			211
Total Noncurrent Liabilities	12,821			12,769
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	11,621			10,895
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016—534 shares	4,929			4,936
Treasury Stock, at cost, 2017 and 2016—29 shares	(747		)	(717		)
Retained Earnings	8,962			9,174
Accumulated Other Comprehensive Loss	(226		)	(263		)
Total Stockholders’ Equity	12,918			13,130
Total Capitalization	24,539			24,025
TOTAL LIABILITIES AND CAPITALIZATION	$	40,524		$	40,070

See Notes to Condensed Consolidated Financial Statements.

4

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

	Six Months Ended
	June 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	223		$	658
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,469			448
Amortization of Nuclear Fuel	101			105
Renewable Energy Credit (REC) Compliance Accrual	51			50
Provision for Deferred Income Taxes (Other than Leases) and ITC	91			334
Non-Cash Employee Benefit Plan Costs	45			63
Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes	(30		)	(30		)
Net (Gain) Loss on Lease Investments	45			—
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(42		)	153
Net Change in Regulatory Assets and Liabilities	(124		)	(125		)
Cost of Removal	(47		)	(74		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(58		)	(2		)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	69			301
Accrued Taxes	15			94
Margin Deposit	59			(46		)
Other Current Assets and Liabilities	(56		)	(120		)
Employee Benefit Plan Funding and Related Payments	(49		)	(78		)
Other	(6		)	(9		)
Net Cash Provided By (Used In) Operating Activities	1,756			1,722
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,981		)	(1,971		)
Purchase of Emissions Allowances and RECs	(29		)	(36		)
Proceeds from Sales of Available-for-Sale Securities	711			392
Investments in Available-for-Sale Securities	(726		)	(407		)
Other	36			18
Net Cash Provided By (Used In) Investing Activities	(1,989		)	(2,004		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(388		)	(364		)
Issuance of Long-Term Debt	1,125			1,550
Redemption of Long-Term Debt	—			(171		)
Cash Dividends Paid on Common Stock	(435		)	(415		)
Other	(62		)	(64		)
Net Cash Provided By (Used In) Financing Activities	240			536
Net Increase (Decrease) in Cash and Cash Equivalents	7			254
Cash and Cash Equivalents at Beginning of Period	423			394
Cash and Cash Equivalents at End of Period	$	430		$	648
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(30	)	$	(276	)
Interest Paid, Net of Amounts Capitalized	$	189		$	176
Accrued Property, Plant and Equipment Expenditures	$	513		$	513

See Notes to Condensed Consolidated Financial Statements.

5

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
OPERATING REVENUES	$	1,368		$	1,350		$	3,180		$	3,062
OPERATING EXPENSES
Energy Costs	472			529			1,225			1,258
Operation and Maintenance	351			352			718			734
Depreciation and Amortization	166			136			337			275
Total Operating Expenses	989			1,017			2,280			2,267
OPERATING INCOME	379			333			900			795
Other Income	22			19			47			39
Other Deductions	(1		)	(1		)	(2		)	(2		)
Interest Expense	(69		)	(74		)	(144		)	(142		)
INCOME BEFORE INCOME TAXES	331			277			801			690
Income Tax Expense	(123		)	(98		)	(294		)	(249		)
NET INCOME	$	208		$	179		$	507		$	441

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

6

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2017		2016		2017			2016
NET INCOME	$	208	$	179	$	507		$	441
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0, $1 and $0 for the three and six months ended 2017 and 2016, respectively	—		1		(1		)	1
COMPREHENSIVE INCOME	$	208	$	180	$	506		$	442

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

7

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	June 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	192		$	390
Accounts Receivable, net of allowances of $61 in 2017 and $68 in 2016	755			810
Accounts Receivable—Affiliated Companies	20			76
Unbilled Revenues	210			260
Materials and Supplies	198			180
Prepayments	193			9
Regulatory Assets	276			199
Other	6			6
Total Current Assets	1,850			1,930
PROPERTY, PLANT AND EQUIPMENT	27,562			26,347
Less: Accumulated Depreciation and Amortization	(5,930		)	(5,760		)
Net Property, Plant and Equipment	21,632			20,587
NONCURRENT ASSETS
Regulatory Assets	3,349			3,319
Long-Term Investments	293			299
Other Special Funds	45			43
Other	104			110
Total Noncurrent Assets	3,791			3,771
TOTAL ASSETS	$	27,273		$	26,288

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

8

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	June 30, 2017		December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	400	$	—
Accounts Payable	587		718
Accounts Payable—Affiliated Companies	146		260
Accrued Interest	78		76
Clean Energy Program	200		142
Derivative Contracts	—		5
Obligation to Return Cash Collateral	134		132
Regulatory Liabilities	51		88
Other	301		296
Total Current Liabilities	1,897		1,717
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	6,232		5,873
OPEB Costs	983		1,009
Accrued Pension Costs	223		250
Regulatory Liabilities	99		118
Clean Energy Program	27		—
Environmental Costs	310		332
Asset Retirement Obligations	215		213
Long-Term Accrued Taxes	115		130
Other	112		116
Total Noncurrent Liabilities	8,316		8,041
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	7,842		7,818
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2017 and 2016—132 shares	892		892
Contributed Capital	945		945
Basis Adjustment	986		986
Retained Earnings	6,395		5,888
Accumulated Other Comprehensive Income	—		1
Total Stockholder’s Equity	9,218		8,712
Total Capitalization	17,060		16,530
TOTAL LIABILITIES AND CAPITALIZATION	$	27,273	$	26,288

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

9

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

	Six Months Ended
	June 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	507		$	441
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	337			275
Provision for Deferred Income Taxes and ITC	330			290
Non-Cash Employee Benefit Plan Costs	25			36
Cost of Removal	(47		)	(74		)
Net Change in Other Regulatory Assets and Liabilities	(124		)	(125		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	108			50
Materials and Supplies	(15		)	(14		)
Prepayments	(184		)	(165		)
Accounts Payable	(30		)	(29		)
Accounts Receivable/Payable—Affiliated Companies, net	(72		)	181
Other Current Assets and Liabilities	16			17
Employee Benefit Plan Funding and Related Payments	(42		)	(62		)
Other	(39		)	(13		)
Net Cash Provided By (Used In) Operating Activities	770			808
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,389		)	(1,355		)
Proceeds from Sales of Available-for-Sale Securities	28			12
Investments in Available-for-Sale Securities	(29		)	(13		)
Solar Loan Investments	(3		)	2
Other	5			—
Net Cash Provided By (Used In) Investing Activities	(1,388		)	(1,354		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	—			(153		)
Issuance of Long-Term Debt	425			850
Redemption of Long-Term Debt	—			(171		)
Other	(5		)	(10		)
Net Cash Provided By (Used In) Financing Activities	420			516
Net Increase (Decrease) In Cash and Cash Equivalents	(198		)	(30		)
Cash and Cash Equivalents at Beginning of Period	390			198
Cash and Cash Equivalents at End of Period	$	192		$	168
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(75	)	$	(255	)
Interest Paid, Net of Amounts Capitalized	$	144		$	134
Accrued Property, Plant and Equipment Expenditures	$	319		$	381

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

10

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
OPERATING REVENUES	$	929		$	714		$	2,213		$	2,027
OPERATING EXPENSES
Energy Costs	397			381			1,104			1,019
Operation and Maintenance	254			265			484			518
Depreciation and Amortization	465			80			1,115			159
Total Operating Expenses	1,116			726			2,703			1,696
OPERATING INCOME (LOSS)	(187		)	(12		)	(490		)	331
Income from Equity Method Investments	5			4			8			6
Other Income	46			25			84			51
Other Deductions	(7		)	(9		)	(14		)	(27		)
Other-Than-Temporary Impairments	(3		)	(10		)	(4		)	(20		)
Interest Expense	(13		)	(20		)	(29		)	(42		)
INCOME (LOSS) BEFORE INCOME TAXES	(159		)	(22		)	(445		)	299
Income Tax Benefit (Expense)	62			11			178			(118		)
NET INCOME (LOSS)	$	(97	)	$	(11	)	$	(267	)	$	181

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

11

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Millions

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
NET INCOME (LOSS)	$	(97	)	$	(11	)	$	(267	)	$	181
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $ $(9), $(9), $(27) and $(25) for the three and six months ended 2017 and 2016, respectively	10			9			29			25
Pension/OPEB adjustment, net of tax (expense) benefit of $(3), $(5), $(7) and $(10) for the three and six months ended 2017 and 2016, respectively	5			7			10			14
Other Comprehensive Income (Loss), net of tax	15			16			39			39
COMPREHENSIVE INCOME (LOSS)	$	(82	)	$	5		$	(228	)	$	220

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

12

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	June 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	29		$	11
Accounts Receivable	207			276
Accounts Receivable—Affiliated Companies	139			205
Short-Term Loan to Affiliate	233			87
Fuel	270			326
Materials and Supplies, net	379			381
Derivative Contracts	112			162
Prepayments	10			10
Other	3			2
Total Current Assets	1,382			1,460
PROPERTY, PLANT AND EQUIPMENT	10,881			12,655
Less: Accumulated Depreciation and Amortization	(3,055		)	(4,135		)
Net Property, Plant and Equipment	7,826			8,520
NONCURRENT ASSETS
NDT Fund	1,968			1,859
Long-Term Investments	91			102
Goodwill	16			16
Other Intangibles	120			98
Other Special Funds	55			53
Derivative Contracts	90			24
Other	71			61
Total Noncurrent Assets	2,411			2,213
TOTAL ASSETS	$	11,619		$	12,193

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

13

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	June 30, 2017			December 31, 2016
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts Payable	$	536		$	539
Accounts Payable—Affiliated Companies	20			25
Derivative Contracts	8			8
Accrued Interest	20			20
Other	95			88
Total Current Liabilities	679			680
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	1,979			2,170
Asset Retirement Obligations	526			511
OPEB Costs	256			251
Derivative Contracts	1			3
Accrued Pension Costs	179			191
Long-Term Accrued Taxes	93			77
Other	126			129
Total Noncurrent Liabilities	3,160			3,332
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
LONG-TERM DEBT	2,384			2,382
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,340			4,782
Accumulated Other Comprehensive Loss	(172		)	(211		)
Total Member’s Equity	5,396			5,799
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,619		$	12,193

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

14

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

	Six Months Ended
	June 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(267	)	$	181
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,115			159
Amortization of Nuclear Fuel	101			105
Provision for Deferred Income Taxes and ITC	(226		)	37
Interest Accretion on Asset Retirement Obligation	15			13
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(42		)	153
Renewable Energy Credit (REC) Compliance Accrual	51			50
Non-Cash Employee Benefit Plan Costs	14			19
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(58		)	(2		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	58			86
Margin Deposit	59			(46		)
Accounts Receivable	36			(12		)
Accounts Payable	(14		)	(10		)
Accounts Receivable/Payable—Affiliated Companies, net	75			179
Other Current Assets and Liabilities	7			11
Employee Benefit Plan Funding and Related Payments	(4		)	(10		)
Other	12			4
Net Cash Provided By (Used In) Operating Activities	932			917
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(576		)	(598		)
Purchase of Emissions Allowances and RECs	(29		)	(36		)
Proceeds from Sales of Available-for-Sale Securities	602			346
Investments in Available-for-Sale Securities	(616		)	(359		)
Short-Term Loan—Affiliated Company, net	(146		)	(972		)
Other	30			12
Net Cash Provided By (Used In) Investing Activities	(735		)	(1,607		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	—			700
Cash Dividend Paid	(175		)	—
Other	(4		)	(6		)
Net Cash Provided By (Used In) Financing Activities	(179		)	694
Net Increase (Decrease) in Cash and Cash Equivalents	18			4
Cash and Cash Equivalents at Beginning of Period	11			12
Cash and Cash Equivalents at End of Period	$	29		$	16
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	66		$	(53	)
Interest Paid, Net of Amounts Capitalized	$	29		$	38
Accrued Property, Plant and Equipment Expenditures	$	194		$	132

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

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 1. Organization and Basis of Presentation

Organization

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 solar generation projects and has implemented energy efficiency and demand response 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 through competitive energy sales in well-developed energy markets and fuel supply functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; 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); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2016.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.

Note 2. Recent Accounting Standards

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

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

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possible changes in presentation.

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the transmission and distribution of electricity and distribution of gas to retail residential and commercial and industrial customers, is in scope of the new accounting standard. PSEG expects no change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. Revenue from contracts with customers will be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. Upon formal resolution of the implementation issues noted above, and upon completion of contract evaluations, PSEG will elect its transition method.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

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

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.

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

Measurement of Credit Losses on Financial Instruments

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

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

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.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements including its future disclosure requirements.

Business Combinations: Clarifying the Definition of a Business

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.

Simplifying the Test for Goodwill Impairment

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

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)

This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.

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 will be eligible for capitalization, when applicable.

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

Premium Amortization on Purchased Callable Debt Securities

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

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

adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle.

PSEG is currently analyzing the impact of this standard on its financial statements.

Stock Compensation - Scope of Modification Accounting

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

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

Note 3. Early Plant Retirements

Fossil

In October 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Both units were available to operate through May 31, 2017 and were subsequently retired from operation on June 1, 2017.

In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.

In the three and six months ended June 30, 2017, Power recognized total D&A of $390 million and $964 million, respectively, for the Hudson and Mercer units. In the three and six months ended June 30, 2017, Power also recognized pre-tax charges in Energy Costs of $2 million and $9 million, respectively, primarily for coal inventory lower of cost or market adjustments. For the three and six months ended June 30, 2017, Power also recognized pre-tax charges in O&M of $4 million of shut down costs and an increase in the ARO liability due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material.

As of December 31, 2016, Power had reduced the estimated useful life of Bridgeport Harbor Station unit 3 (BH3) from 2025 to the summer of 2021 as it was more likely than not it will retire the unit by this time. The change in the estimated useful life did not have a material impact on Power’s 2017 financial results.

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

Nuclear

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. This situation is generally due to low natural gas prices, and the related decline in market prices of energy, resulting from the growth of shale gas production since 2007, the continuing cost of

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

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

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

	As of June 30, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	83		$	80		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	453			561			208		758
Nuclear Fuel In-Service, net of Accumulated Depreciation	136			113			—		125
Construction Work in Progress (including nuclear fuel)	168			109			9		31
Total Assets	$	840		$	863		$	217	$	955
Liability
Asset Retirement Obligation	$	146		$	159		$	—	$	162
Total Liabilities	$	146		$	159		$	—	$	162
Net Assets	$	694		$	704		$	217	$	793
NRC License Renewal Term	2046			2036/2040			—		2033/2034
% Owned	100		%	57		%	—		50		%

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

The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments and decommissioning trust fund requirements and other commitments, as well as future energy prices. Power maintains a NDT Fund that funds its decommissioning obligations. See Note 7. Available-for-Sale Securities.

Note 4. Variable Interest Entity (VIE)

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary 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

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. Servco recorded $112 million and $101 million for the three months and $224 million and $199 million for the six months ended June 30, 2017 and 2016, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Condensed Consolidated Statement of Operations.

Note 5. Rate Filings

This Note should be read in conjunction with Note 6. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2016.

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

Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June 2017, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2017 which represents estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. The petition requests rates to be effective September 1, 2017, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.

Basic Gas Supply Services (BGSS)—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase of $61 million in annual BGSS revenues. If approved, the BGSS rate would be increased from approximately 34 cents to 37 cents per therm for residential gas customers effective October 1, 2017. This matter is pending.

Green Program Recovery Charges (GPRC)—Each year PSE&G files with the BPU for annual recovery of its Green Program investments which include a return on its investment and recovery of expenses. In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery for the ten combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2017 through September 30, 2018 designed to recover approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU-approved programs. This matter is pending.

In March 2017, the BPU gave final approval to PSE&G’s petition to recover approximately $37 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved GPRC programs. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge. 

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

In June 2017, PSE&G filed a petition requesting approval to collect $55 million in total net deficiency revenues comprised of $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and the remaining carryover balance of $24 million in net deficiency gas revenue from the 2015-2016 Winter Period. The deficiency gas revenue would be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). This matter is pending.

Transmission Formula Rate Filings—In June 2017, PSE&G filed its 2016 true-up adjustment pertaining to its transmission formula rates in effect for 2016. This resulted in an adjustment of $12 million more than the 2016 originally filed revenues.

Remediation Adjustment Charge (RAC)—In June 2017, the BPU approved PSE&G's filing with respect to its RAC 24 petition allowing recovery of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016.

Gas System Modernization Program (GSMP)—In July 2017, PSE&G filed its annual GSMP cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $28 million effective January 1, 2018. This increase represents the return of and on investment for GSMP investments expected to be in service through September 30, 2017. This request will be updated in October 2017 for actual costs.  

21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 6. 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. The loans are generally paid back with solar renewable energy certificates generated from the installed solar electric system. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”

Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	June 30, 2017		December 31, 2016
	Millions
Commercial/Industrial	$	167	$	164
Residential	11		11
Total	$	178	$	175

Energy Holdings

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

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

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

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

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

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

lease receivables. The second quarter 2017 pre-tax write-down and additional charge were reflected in Operating Revenues and are included in Gross Investment in Leases for June 30, 2017.

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

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	559		$	629
Estimated Residual Value of Leased Assets	333			346
Total Investment in Rental Receivables	892			975
Unearned and Deferred Income	(315		)	(326		)
Gross Investment in Leases	577			649
Deferred Tax Liabilities	(619		)	(674		)
Net Investment in Leases	$	(42	)	$	(25	)

The corresponding receivables associated with the lease portfolio are reflected in the following table, 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 June 30, 2017
	As of June 30, 2017
	Millions
AA	$	15
BBB+ — BBB-	317
BB-	133
CC	94
Total	$	559

The “BB-” and the “CC” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of June 30, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $348 million ($(159) million, net of deferred taxes). A more detailed description of such assets under lease, as of June 30, 2017, is presented in the following table.

Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	83	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Shawville Station Units 1, 2, 3 and 4	PA	$	91	100	%	596	Gas	CC (A)	REMA

(A) REMA’s parent company, GenOn, and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. On June 16, 2017, Moody’s downgraded the GenOn Corporate Family Rating to D-PD and provided a rating of Caa1 for REMA.

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. 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 wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service.

Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.

Note 7. Available-for-Sale Securities

NDT Fund

Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power.

Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	699	$	305	$	(5	)	$	999
Debt Securities
Government	551		10		(4		)	557
Corporate	356		6		(1		)	361
Total Debt Securities	907		16		(5		)	918
Other Securities	51		—		—			51
Total NDT Available-for-Sale Securities	$	1,657	$	321	$	(10	)	$	1,968

24

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858

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

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	25	$	8
Accounts Payable	$	22	$	5

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

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	63	$	(5	)	$	—	$	—	$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	279		(4		)	7		—		276		(6		)	4		—
Corporate (C)	94		(1		)	7		—		139		(3		)	15		(1		)
Total Debt Securities	373		(5		)	14		—		415		(9		)	19		(1		)
Other Securities	51		—			—		—		—		—			—		—
NDT Available-for-Sale Securities	$	487	$	(10	)	$	14	$	—	$	535	$	(19	)	$	27	$	(2	)

(A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2017.

25

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(B) Debt Securities (Government)—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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from NDT Fund Sales (A)	$	320		$	154		$	567		$	331
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	32		$	10		$	53		$	25
Gross Realized Losses	(5		)	(6		)	(9		)	(22		)
Net Realized Gains (Losses) on NDT Fund	$	27		$	4		$	44		$	3

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $158 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of June 30, 2017.

The NDT available-for-sale debt securities held as of June 30, 2017 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	29
1 - 5 years	239
6 - 10 years	223
11 - 15 years	65
16 - 20 years	66
Over 20 years	296
Total NDT Available-for-Sale Debt Securities	$	918

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

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, 2017, Other-Than-Temporary Impairments (OTTI) of $4 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be

26

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

Rabbi Trust

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

PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	—	$	—		$	22
Debt Securities
Government	85		1		(1		)	85
Corporate	113		2		—			115
Total Debt Securities	198		3		(1		)	200
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	222	$	3	$	(1	)	$	224

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	11	$	—		$	22
Debt Securities
Government	105		—		(2		)	103
Corporate	92		1		(2		)	91
Total Debt Securities	197		1		(4		)	194
Other Securities	1		—		—			1
Total Rabbi Trust Available-for-Sale Securities	$	209	$	12	$	(4	)	$	217

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	—	$	3

27

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government (B)	29		(1		)	1		—		60		(2		)	1		—
Corporate (C)	19		—			3		—		46		(2		)	3		—
Total Debt Securities	48		(1		)	4		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	48	$	(1	)	$	4	$	—	$	106	$	(4	)	$	4	$	—

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

(B) Debt Securities (Government)—Unrealized 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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)	$	93		$	36		$	144		$	61
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2		$	17		$	3
Gross Realized Losses	(1		)	(1		)	(4		)	(2		)
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	1		$	13		$	1

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains/losses in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets were immaterial as of June 30, 2017.

28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Time Frame	Fair Value
	Millions
Less than one year	$	1
1 - 5 years	35
6 - 10 years	29
11 - 15 years	6
16 - 20 years	18
Over 20 years	111
Total Rabbi Trust Available-for-Sale Debt Securities	$	200

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

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in an indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, 2017, no OTTIs were recognized on securities in the Rabbi Trust. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
PSE&G	$	45	$	43
Power	55		53
Other	124		121
Total Rabbi Trust Available-for-Sale Securities	$	224	$	217

Note 8. Pension and Other Postretirement Benefits (OPEB)

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

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $12 million and $24 million for the three months and six months, ended June 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.

29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco.

	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Six Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2017			2016			2017			2016			2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	28		$	27		$	4		$	4		$	57		$	54		$	8		$	8
Interest Cost	51			51			16			14			102			101			32			29
Expected Return on Plan Assets	(99		)	(99		)	(9		)	(7		)	(197		)	(197		)	(17		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(4		)	(5		)	(2		)	(4		)	(9		)	(9		)	(5		)	(7		)
Actuarial Loss	25			40			12			10			49			79			25			20
Total Benefit Costs	$	1		$	14		$	21		$	17		$	2		$	28		$	43		$	35

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

	Pension Benefits					OPEB				Pension Benefits					OPEB
	Three Months Ended					Three Months Ended				Six Months Ended					Six Months Ended
	June 30,					June 30,				June 30,					June 30,
	2017			2016		2017		2016		2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	7	$	13	$	11	$	(2	)	$	14	$	27	$	22
Power	1			4		6		5		1			8		13		11
Other	1			3		2		1		3			6		3		2
Total Benefit Costs	$	1		$	14	$	21	$	17	$	2		$	28	$	43	$	35

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

Servco Pension and OPEB

At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco plans to contribute $35 million into its pension plan trusts during 2017. Servco’s pension-related revenues and costs were $8 million and $6 million for the three months ended June 30, 2017 and 2016, respectively, and $17 million and $12 million for the six months ended June 30, 2017and 2016, respectively. The OPEB-related revenues earned and costs incurred were $1 million and $2 million for the three months and six months ended June 30, 2017. The OPEB-related revenues earned and costs incurred were immaterial for the three months and six months ended June 30, 2016.

30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 9. 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,898		$	1,806
Exposure under Current Guarantees	$	137		$	139
Letters of Credit Margin Posted	$	142		$	157
Letters of Credit Margin Received	$	98		$	99
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(1	)
Net Broker Balance Deposited (Received)	$	(2	)	$	57
Additional Amounts Posted:
Other Letters of Credit	$	61		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 11. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.

Environmental Matters

Passaic River

Historic operations 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)

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

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

In early 2007, 73 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

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miles of the lower Passaic River. At such time, the CPG also 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 seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.

In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

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

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

The CPG, which consisted of 51 members as of June 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million, which the CPG continues to incur. Of the estimated $190 million, as of June 30, 2017, the CPG had spent approximately $163 million, of which PSEG’s total share was approximately $12 million.

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

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

Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of June 30, 2017, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

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

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(UNAUDITED)

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

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

In March 2017, the EPA sent a letter to 20 PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements in return for payments by each PRP of $280,600. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. It is unclear how the EPA made that determination or how many PRPs will accept the proposal. The settlement is subject to a 30 day public comment period that has not yet commenced. The impact of this settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

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 operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

that the estimated cost to remediate all MGP sites to completion could range between $373 million and $430 million through2021, 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 $373 million as ofJune 30, 2017. Of this amount, $74 million was recorded in Other Current Liabilities and $299 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $373 millionRegulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether 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.

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

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

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

Clean Water Act (CWA) Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), 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 rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing

power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing

adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range

of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for

review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental

organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the

Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by

mid-2017.

In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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 intake structures 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 BH3. To address compliance with the EPA’s CWA Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would 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. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements.

Separately, Power has also negotiated 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 its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. 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 BH5. All major environmental permits have been obtained. Operations are expected to begin in mid-2019.

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

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

Jersey City, New Jersey Subsurface Feeder Cable Matter

In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the actions necessary to address the leak and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs was extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s initial debris removal activities were completed in May 2017. Since then, efforts have been ongoing to inspect portions of the pipe-type cables. As of mid-July 2017, the immediate vicinity of the leak appears to have been located and efforts are ongoing to identify the precise leak location and attempt repairs. If the leak cannot be located or if repairs cannot be effectuated at a reasonable cost and within a reasonable time frame, retirement of the affected facilities may be an option to address the leakage.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations and pretreatment standards for the aforementioned waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Basic Generation Service (BGS) 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, 2016 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $335.33 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
	2014	2015	2016	2017
36-Month Terms Ending	May 2017	May 2018	May 2019	May 2020	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$97.39	$99.54	$96.38	$90.78

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

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 (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.

PSE&G has a full-requirements contract with 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 18. 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,

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

enrichment and fabrication requirements through 2018 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

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

Power also has various long-term fuel purchase commitments for coal through 2021 to support its Keystone and Conemaugh fossil generation stations.

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

Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	301
Enrichment	$	340
Fabrication	$	184
Natural Gas	$	1,040
Coal	$	331

Regulatory Proceedings

FERC Compliance

PJM Bidding Matter

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

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

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

Financial Transmission Rights (FTR) Auction Matter

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in PJM’s annual FTR auction for the 2016-2017 planning year and the monthly PJM FTR auctions for February, March and April 2016. PSEG is cooperating with FERC in this matter. PSEG cannot predict the outcome of this matter at this time.

38

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 10. Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transaction occurred in the six months ended June 30, 2017:

PSEG

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

PSE&G

• issued $425 million of 3.00% Secured Medium-Term Notes, Series L due May 2027.

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.

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

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of June 30, 2017, the total available credit capacity was $4.0 billion.

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

As of June 30, 2017, total credit capacity was in excess of the total anticipated maximum liquidity requirements of PSEG, PSE&G and Power.

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of June 30, 2017 were as follows:

	As of June 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	13	$	1,487	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	13	$	1,487
PSE&G
5-year Credit Facility (A)	$	600	$	15	$	585	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	15	$	585
Power
3-year LC Facilities	$	200	$	140	$	60	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		50		1,850		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	190	$	1,910
Total	$	4,200	$	218	$	3,982

(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 June 30, 2017, neither PSEG nor PSE&G had amounts outstanding.

39

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 11. Financial Risk Management Activities

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchases and normal sales (NPNS), cash flow hedge and fair value hedge accounting. PSEG, 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 and PSE&G enter 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 relating primarily to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. 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.

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 June 30, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $4 million for the three months and six months ended June 30, 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, related primarily to variable-rate debt instruments. As of June 30, 2017 and December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of June 30, 2017 and December 31, 2016, the fair value of these hedges was $1 million. There was no ineffectiveness as of June 30, 2017 and December 31, 2016.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of June 30, 2017 and December 31, 2016. The after-tax unrealized gain expected to be reclassified to earnings during the next 12 months is $1 million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Condensed Consolidated Balance Sheets of Power and PSEG.

40

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	As of June 30, 2017
	Power (A)									PSEG (A)		Consolidated
	Not Designated									Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	479		$	(367	)	$	112		$	1	$	113
Noncurrent Assets	268			(178		)	90			—		90
Total Mark-to-Market Derivative Assets	$	747		$	(545	)	$	202		$	1	$	203
Derivative Contracts
Current Liabilities	$	(373	)	$	365		$	(8	)	$	—	$	(8	)
Noncurrent Liabilities	(170		)	169			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(543	)	$	534		$	(9	)	$	—	$	(9	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	204		$	(11	)	$	193		$	1	$	194

	As of December 31, 2016
	Power (A)									PSE&G (A)			PSEG (A)		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	435		$	(273	)	$	162		$	—		$	1	$	163
Noncurrent Assets	122			(98		)	24			—			—		24
Total Mark-to-Market Derivative Assets	$	557		$	(371	)	$	186		$	—		$	1	$	187
Derivative Contracts
Current Liabilities	$	(285	)	$	277		$	(8	)	$	(5	)	$	—	$	(13	)
Noncurrent Liabilities	(98		)	95			(3		)	—			—		(3		)
Total Mark-to-Market Derivative (Liabilities)	$	(383	)	$	372		$	(11	)	$	(5	)	$	—	$	(16	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	174		$	1		$	175		$	(5	)	$	1	$	171

(A) Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. 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 Condensed Consolidated Balance Sheets. As of June 30, 2017, net

41

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(4) million was netted against current assets, $(9) million was netted against noncurrent assets, and $2 million was netted against current liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities.

Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $16 million and $19 million as of June 30, 2017 and December 31, 2016, respectively. As of June 30, 2017 and December 31, 2016, Power had the contractual right of offset of $11 million and $9 million, respectively, related to derivative instruments that are assets with the same counterparty under 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 $5 million and $10 million as of June 30, 2017 and December 31, 2016, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months and six months ended June 30, 2017 and 2016.

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2017		2016				2017		2016
	Millions						Millions
PSEG
Interest Rate Swaps	$	—	$	(1	)	Interest Expense	$	—	$	—
Total PSEG	$	—	$	(1	)		$	—	$	—

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Six Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	—		2		Interest Expense	—		—
Total PSEG	$	—	$	2		$	—	$	—

42

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of June 30, 2017 and 2016.

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

Accumulated Other Comprehensive Income	Pre-Tax		After-Tax
	Millions
Balance as of December 31, 2015	$	—	$	—
Gain Recognized in AOCI	3		2
Less: Gain Reclassified into Income	—		—
Balance as of December 31, 2016	$	3	$	2
Gain Recognized in AOCI	—		—
Less: Gain Reclassified into Income	—		—
Balance as of June 30, 2017	$	3	$	2

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and six months ended June 30, 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 for 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						Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2017			2016			2017			2016
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	113		$	(86	)	$	196		$	130
Energy-Related Contracts	Energy Costs	(11		)	6			(16		)	8
Total PSEG and Power		$	102		$	(80	)	$	180		$	138

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2017 and December 31, 2016.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2017
Natural Gas	Dekatherm (Dth)	321	—	321	—
Electricity	MWh	349	—	349	—
Financial Transmission Rights (FTRs)	MWh	6	—	6	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—
As of December 31, 2016
Natural Gas	Dth	357	—	348	9
Electricity	MWh	323	—	323	—
FTRs	MWh	9	—	9	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—

43

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Credit Risk

Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of June 30, 2017, 97% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2017. 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.

Rating	Current Exposure		Collateral Held		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	420	$	92	$	328	1	$	130	(A)
Non-Investment Grade	9		—		9		—	—
Total	$	429	$	92	$	337	1	$	130

(A) Represents net exposure of $130 million with PSE&G.

As of June 30, 2017, collateral held from counterparties where Power had credit exposure included $92 million in letters of credit.

As of June 30, 2017, Power had 152 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 June 30, 2017, 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 June 30, 2017, 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.

44

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 12. 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 June 30, 2017, 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 June 30, 2017 and December 31, 2016, 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.

45

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Recurring Fair Value Measurements as of June 30, 2017
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	367		$	—		$	367		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	51		$	—		$	—		$	51		$	—
Debt Securities—Govt Other	$	34		$	—		$	—		$	34		$	—
Debt Securities—Corporate	$	115		$	—		$	—		$	115		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—
Interest Rate Swaps (C)	$	—		$	—		$	—		$	—		$	—
PSE&G
Assets:
Cash Equivalents (A)	$	169		$	—		$	169		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	10		$	—		$	—		$	10		$	—
Debt Securities—Govt Other	$	7		$	—		$	—		$	7		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	29		$	—		$	—		$	29		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—

46

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Recurring Fair Value Measurements as of December 31, 2016
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	37		$	—		$	—		$	37		$	—
Debt Securities—Govt Other	$	66		$	—		$	—		$	66		$	—
Debt Securities—Corporate	$	91		$	—		$	—		$	91		$	—
Other Securities	$	1		$	—		$	1		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(16	)	$	372		$	(18	)	$	(364	)	$	(6	)
PSE&G
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	13		$	—		$	—		$	13		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(5	)	$	—		$	—		$	—		$	(5	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	16		$	—		$	—		$	16		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	372		$	(18	)	$	(364	)	$	(1	)

47

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(A) Represents money market mutual funds.

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

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from 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) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(D) The fair value measurement tables exclude an immaterial amount of cash as of June 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of June 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities include primarily investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(13) million of cash collateral was netted against assets, and $2 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

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 approves risk

48

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

For PSE&G, the natural gas supply contract was measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of June 30, 2017 and December 31, 2016.

	Quantitative Information About Level 3 Fair Value Measurements
							Significant
		Fair Value as of				Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2017				Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Load Contracts	$	5	$	—	Discounted Cash flow	Historic Load Variability	0% to +10%
Gas (A)	Other	1		—
Total Power		$	6	$	—
Total PSEG		$	6	$	—

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)

(A) Includes gas positions which were immaterial as of June 30, 2017 and December 31, 2016.

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.

49

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

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

	Three Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	3		$	7	$	(1	)	$	—	$	(3	)	$	—		$	6
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	—	$	(1	)	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	2		$	7	$	—		$	—	$	(3	)	$	—		$	6
	Six Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	26	$	5		$	—	$	(25	)	$	(1	)	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	5		$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	26	$	—		$	—	$	(25	)	$	(1	)	$	6

50

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

for the Three MonthsandSix Months EndedJune 30, 2016

	Three Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21	$	1	$	(12	)	$	—	$	(5	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	10	$	—	$	(12	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	1	$	—		$	—	$	(5	)	$	—	$	7
	Six Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
PSEG
Net Derivative Assets (Liabilities)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

(A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $7 million and $26 million in Operating Income for the three months and six months ended June 30, 2017, respectively. Of the $7 million in Operating Income, $4 million is unrealized. Of the $26 million in Operating Income, $1 million is unrealized.

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

51

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(C) Represents $(3) million and $(25) million in settlements for the three months and six months ended June 30, 2017, respectively. Represents $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively.

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

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1 million and $16 million in Operating Income for the three months and six months ended June 30, 2016, respectively. Of the $1 million in Operating Income, $(4) million is unrealized. Of the $16 million in Operating Income, $(4) million is unrealized.

As of June 30, 2017, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $6 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of June 30, 2016, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $5 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

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

	As of				As of
	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	1,895	$	1,888	$	1,195	$	1,185
PSE&G (B)	8,242		8,900		7,818		8,240
Power - Recourse Debt (B)	2,384		2,646		2,382		2,578
Total Long-Term Debt	$	12,521	$	13,434	$	11,395	$	12,003

(A) As of June 30, 2017, fair value includes a $700 million floating rate term loan term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016. The fair values of the term loan debt (Level 2 measurement) were considered to be equal to the carrying values because the interest payments are based on LIBOR rates that are reset monthly.

(B) Given that most bonds do not trade, 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.

52

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 13. Other Income and Deductions

Other Income	PSE&G		Power		Other (A)			Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	45	$	—		$	45
Allowance for Funds Used During Construction	14		—		—			14
Rabbi Trust Realized Gains, Interest and Dividends	1		1		2			$	4
Solar Loan Interest	5		—		—			5
Other	2		—		—			2
Total Other Income	$	22	$	46	$	2		$	70
Six Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	76	$	—		$	76
Allowance for Funds Used During Construction	28		—		—			28
Rabbi Trust Realized Gains, Interest and Dividends	4		5		11			20
Solar Loan Interest	10		—		—			10
Other	5		3		—			8
Total Other Income	$	47	$	84	$	11		$	142
Three Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—		$	23
Allowance for Funds Used During Construction	10		—		—			10
Rabbi Trust Realized Gains, Interest and Dividends	1		1		1			$	3
Solar Loan Interest	5		—		—			5
Other	3		1		(1		)	3
Total Other Income	$	19	$	25	$	—		$	44
Six Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	48	$	—		$	48
Allowance for Funds Used During Construction	21		—		—			21
Rabbi Trust Realized Gains, Interest and Dividends	1		2		3			6
Solar Loan Interest	11		—		—			11
Other	6		1		(1		)	6
Total Other Income	$	39	$	51	$	2		$	92

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		1		3
Total Other Deductions	$	1	$	7	$	1	$	9
Six Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	13	$	—	$	13
Other	2		1		4		7
Total Other Deductions	$	2	$	14	$	4	$	20
Three Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	8	$	—	$	8
Other	1		1		—		2
Total Other Deductions	$	1	$	9	$	—	$	10
Six Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	26	$	—	$	26
Other	2		1		2		5
Total Other Deductions	$	2	$	27	$	2	$	31

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

53

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 14. Income Taxes

PSEG’s, PSE&G’s and Power’s effective tax rates for the three months and six months ended June 30, 2017 and 2016 were as

follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2017	2016	2017	2016
PSEG	35.1%	32.7%	28.3%	36.2%
PSE&G	37.2%	35.4%	36.7%	36.1%
Power	39.0%	50.0%	40.0%	39.5%

For the three months and six months ended June 30, 2017, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items. For the six months ended June 30, 2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.

For the three months and six months ended June 30, 2017, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items.

For the three months ended June 30, 2017, the differences in Power’s effective tax rate as compared to the same period in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, ITC and manufacturing deduction.

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

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

54

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

PSEG	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2017	$	2		$	(392	)	$	148		$	(242	)
Other Comprehensive Income before Reclassifications	—			—			23			23
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			6			(13		)	(7		)
Net Current Period Other Comprehensive Income (Loss)	—			6			10			16
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
PSEG	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	2		$	(378	)	$	107		$	(269	)
Other Comprehensive Income before Reclassifications	(1		)	—			8			7
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			2			10
Net Current Period Other Comprehensive Income (Loss)	(1		)	8			10			17
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	2		$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—			—			53			53
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			12			(28		)	(16		)
Net Current Period Other Comprehensive Income (Loss)	—			12			25			37
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	1			—			18			19
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			16			8			24
Net Current Period Other Comprehensive Income (Loss)	1			16			26			43
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)

55

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Power	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2017	$	—	$	(335	)	$	148		$	(187	)
Other Comprehensive Income before Reclassifications	—		—			22			22
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		5			(12		)	(7		)
Net Current Period Other Comprehensive Income (Loss)	—		5			10			15
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Power	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	—	$	(320	)	$	103		$	(217	)
Other Comprehensive Income before Reclassifications	—		—			6			6
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		7			3			10
Net Current Period Other Comprehensive Income (Loss)	—		7			9			16
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	—	$	(340	)	$	129		$	(211	)
Other Comprehensive Income before Reclassifications	—		—			50			50
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		10			(21		)	(11		)
Net Current Period Other Comprehensive Income (Loss)	—		10			29			39
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—	$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications	—		—			16			16
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		14			9			23
Net Current Period Other Comprehensive Income (Loss)	—		14			25			39
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)

56

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2017									June 30, 2017
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	4		$	(2	)	$	2
Amortization of Actuarial Loss	O&M Expense	(12		)	5			(7		)	(24		)	10			(14		)
Total Pension and OPEB Plans		(10		)	4			(6		)	(20		)	8			(12		)
Available-for-Sale Securities
Realized Gains	Other Income	34			(17		)	17			70			(34		)	36
Realized Losses	Other Deductions	(6		)	4			(2		)	(13		)	7			(6		)
OTTI	OTTI	(3		)	1			(2		)	(4		)	2			(2		)
Total Available-for-Sale Securities		25			(12		)	13			53			(25		)	28
Total		$	15		$	(8	)	$	7		$	33		$	(17	)	$	16

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	3		$	(1	)	$	2		$	6		$	(2	)	$	4
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)	(34		)	14			(20		)
Total Pension and OPEB Plans		(14		)	6			(8		)	(28		)	12			(16		)
Available-for-Sale Securities
Realized Gains	Other Income	12			(6		)	6			28			(14		)	14
Realized Losses	Other Deductions	(7		)	4			(3		)	(24		)	12			(12		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(5		)	3			(2		)	(16		)	8			(8		)
Total		$	(19	)	$	9		$	(10	)	$	(44	)	$	20		$	(24	)

57

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2017									June 30, 2017
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	4		$	(2	)	$	2
Amortization of Actuarial Loss	O&M Expense	(10		)	4			(6		)	(21		)	9			(12		)
Total Pension and OPEB Plans		(8		)	3			(5		)	(17		)	7			(10		)
Available-for-Sale Securities
Realized Gains	Other Income	32			(16		)	16			57			(29		)	28
Realized Losses	Other Deductions	(5		)	3			(2		)	(10		)	5			(5		)
OTTI	OTTI	(3		)	1			(2		)	(4		)	2			(2		)
Total Available-for-Sale Securities		24			(12		)	12			43			(22		)	21
Total		$	16		$	(9	)	$	7		$	26		$	(15	)	$	11

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	5		$	(2	)	$	3
Amortization of Actuarial Loss	O&M Expense	(14		)	6			(8		)	(29		)	12			(17		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	10			(5		)	5			25			(13		)	12
Realized Losses	Other Deductions	(6		)	3			(3		)	(22		)	11			(11		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(6		)	3			(3		)	(17		)	8			(9		)
Total		$	(18	)	$	8		$	(10	)	$	(41	)	$	18		$	(23	)

58

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 16. Earnings Per Share (EPS) and Dividends

EPS

Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:

	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	109	$	109	$	187	$	187	$	223	$	223	$	658	$	658
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505		505		505		505		505
Effect of Stock Based Compensation Awards	—		2		—		3		—		2		—		3
Total Shares	505		507		505		508		505		507		505		508
EPS
Net Income	$	0.22	$	0.22	$	0.37	$	0.37	$	0.44	$	0.44	$	1.30	$	1.30

There were approximately 0.3 million of stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for each of the three month and six month periods ended June 30, 2017 and June 30, 2016.

Dividends

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2017		2016		2017		2016
Per Share	$	0.43	$	0.41	$	0.86	$	0.82
In Millions	$	217	$	208	$	435	$	415

On July 18, 2017, PSEG’s Board of Directors approved a $0.43 per share common stock dividend for the third quarter of 2017.

59

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 17. Financial Information by Business Segment

	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Three Months Ended June 30, 2017
Total Operating Revenues	$	1,368	$	929		$	116		$	(280	)	$	2,133
Net Income (Loss)	208		(97		)	(2		)	—			109
Gross Additions to Long-Lived Assets	641		269			9			—			919
Six Months Ended June 30, 2017
Operating Revenues	$	3,180	$	2,213		$	199		$	(867	)	$	4,725
Net Income (Loss)	507		(267		)	(17		)	—			223
Gross Additions to Long-Lived Assets	1,389		576			16			—			1,981
Three Months Ended June 30, 2016
Total Operating Revenues	$	1,350	$	714		$	127		$	(286	)	$	1,905
Net Income (Loss)	179		(11		)	19			—			187
Gross Additions to Long-Lived Assets	631		265			10			—			906
Six Months Ended June 30, 2016
Operating Revenues	$	3,062	$	2,027		$	249		$	(817	)	$	4,521
Net Income (Loss)	441		181			36			—			658
Gross Additions to Long-Lived Assets	1,355		598			18			—			1,971
As of June 30, 2017
Total Assets	$	27,273	$	11,619		$	2,425		$	(793	)	$	40,524
Investments in Equity Method Subsidiaries	$	—	$	91		$	—		$	—		$	91
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 relate primarily to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 18. Related-Party Transactions.

60

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 18. 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 as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Administrative Billings from Services (B)	79		82		144		151
Total Billings from Affiliates	$	375	$	379	$	1,039	$	993

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSEG (C)	$	20	$	76
Payable to Power (A)	$	90	$	193
Payable to Services (B)	56		67
Accounts Payable—Affiliated Companies	$	146	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	115	$	130

Power

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Billings from Affiliates:
Administrative Billings from Services (B)	$	42	$	45	$	78	$	90

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSE&G (A)	$	90	$	193
Receivables from PSEG (C)	49		12
Accounts Receivable—Affiliated Companies	$	139	$	205
Payable to Services (B)	$	20	$	25
Accounts Payable—Affiliated Companies	$	20	$	25
Short-Term Loan Due (to) from Affiliate (E)	$	233	$	87
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	93	$	77

61

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(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. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.

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

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

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

(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.

62

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 19. 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 June 30, 2017 and December 31, 2016 and for the three months and six months ended June 30, 2017 and 2016.

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2017
Operating Revenues	$	—		$	910		$	47		$	(28	)	$	929
Operating Expenses	(2		)	1,103			43			(28		)	1,116
Operating Income (Loss)	2			(193		)	4			—			(187		)
Equity Earnings (Losses) of Subsidiaries	(93		)	(4		)	5			97			5
Other Income	22			56			2			(34		)	46
Other Deductions	—			(7		)	—			—			(7		)
Other-Than-Temporary Impairments	—			(3		)	—			—			(3		)
Interest Expense	(34		)	(9		)	(4		)	34			(13		)
Income Tax Benefit (Expense)	6			60			(4		)	—			62
Net Income (Loss)	$	(97	)	$	(100	)	$	3		$	97		$	(97	)
Comprehensive Income (Loss)	$	(82	)	$	(91	)	$	3		$	88		$	(82	)
Six Months Ended June 30, 2017
Operating Revenues	$	—		$	2,180		$	99		$	(66	)	$	2,213
Operating Expenses	2			2,672			95			(66		)	2,703
Operating Income (Loss)	(2		)	(492		)	4			—			(490		)
Equity Earnings (Losses) of Subsidiaries	(254		)	(5		)	8			259			8
Other Income	47			97			2			(62		)	84
Other Deductions	(1		)	(13		)	—			—			(14		)
Other-Than-Temporary Impairments	—			(4		)	—			—			(4		)
Interest Expense	(64		)	(18		)	(9		)	62			(29		)
Income Tax Benefit (Expense)	7			171			—			—			178
Net Income (Loss)	$	(267	)	$	(264	)	$	5		$	259		$	(267	)
Comprehensive Income (Loss)	$	(228	)	$	(234	)	$	5		$	229		$	(228	)
Six Months Ended June 30, 2017
Net Cash Provided By (Used In)    Operating Activities	$	(32	)	$	802		$	111		$	51		$	932
Net Cash Provided By (Used In)    Investing Activities	$	683		$	178		$	(241	)	$	(1,355	)	$	(735	)
Net Cash Provided By (Used In)    Financing Activities	$	(651	)	$	(978	)	$	146		$	1,304		$	(179	)

63

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2016
Operating Revenues	$	—		$	700		$	46		$	(32	)	$	714
Operating Expenses	2			716			40			(32		)	726
Operating Income (Loss)	(2		)	(16		)	6			—			(12		)
Equity Earnings (Losses) of Subsidiaries	(1		)	1			4			—			4
Other Income	17			30			—			(22		)	25
Other Deductions	—			(9		)	—			—			(9		)
Other-Than-Temporary Impairments	—			(10		)	—			—			(10		)
Interest Expense	(31		)	(7		)	(4		)	22			(20		)
Income Tax Benefit (Expense)	6			3			2			—			11
Net Income (Loss)	$	(11	)	$	(8	)	$	8		$	—		$	(11	)
Comprehensive Income (Loss)	$	5		$	1		$	8		$	(9	)	$	5
Six Months Ended June 30, 2016
Operating Revenues	$	—		$	2,002		$	88		$	(63	)	$	2,027
Operating Expenses	12			1,668			79			(63		)	1,696
Operating Income (Loss)	(12		)	334			9			—			331
Equity Earnings (Losses) of Subsidiaries	204			—			6			(204		)	6
Other Income	34			62			—			(45		)	51
Other Deductions	—			(27		)	—			—			(27		)
Other-Than-Temporary Impairments	—			(20		)	—			—			(20		)
Interest Expense	(61		)	(17		)	(9		)	45			(42		)
Income Tax Benefit (Expense)	16			(137		)	3			—			(118		)
Net Income (Loss)	$	181		$	195		$	9		$	(204	)	$	181
Comprehensive Income (Loss)	$	220		$	220		$	9		$	(229	)	$	220
Six Months Ended June 30, 2016
Net Cash Provided By (Used In)    Operating Activities	$	337		$	777		$	159		$	(356	)	$	917
Net Cash Provided By (Used In)    Investing Activities	$	(1,287	)	$	(504	)	$	(395	)	$	579		$	(1,607	)
Net Cash Provided By (Used In)    Financing Activities	$	951		$	(273	)	$	239		$	(223	)	$	694

64

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2017
Current Assets	$	4,156	$	1,257	$	182	$	(4,213	)	$	1,382
Property, Plant and Equipment, net	56		5,244		2,526		—			7,826
Investment in Subsidiaries	4,015		340		—		(4,355		)	—
Noncurrent Assets	184		2,225		119		(117		)	2,411
Total Assets	$	8,411	$	9,066	$	2,827	$	(8,685	)	$	11,619
Current Liabilities	$	88	$	3,156	$	1,648	$	(4,213	)	$	679
Noncurrent Liabilities	543		2,195		539		(117		)	3,160
Long-Term Debt	2,384		—		—		—			2,384
Member’s Equity	5,396		3,715		640		(4,355		)	5,396
Total Liabilities and Member’s Equity	$	8,411	$	9,066	$	2,827	$	(8,685	)	$	11,619
As of December 31, 2016
Current Assets	$	4,412	$	1,593	$	152	$	(4,697	)	$	1,460
Property, Plant and Equipment, net	55		6,145		2,320		—			8,520
Investment in Subsidiaries	4,249		344		—		(4,593		)	—
Noncurrent Assets	168		2,016		129		(100		)	2,213
Total Assets	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193
Current Liabilities	$	171	$	3,752	$	1,454	$	(4,697	)	$	680
Noncurrent Liabilities	532		2,398		502		(100		)	3,332
Long-Term Debt	2,382		—		—		—			2,382
Member’s Equity	5,799		3,948		645		(4,593		)	5,799
Total Liabilities and Member’s Equity	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193

65

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

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

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

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

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

PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; 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 and Services Agreement contractual agreement; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in Part I, Item 1. Business of our 2016 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part I, Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of 2016 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2017 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the 2016 Form 10-K.

EXECUTIVE OVERVIEW OF 2017 AND FUTURE OUTLOOK

Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:

• improving utility operations through investment in T&D and other infrastructure projects designed to enhance system reliability and resiliency and to meet customer expectations and public policy objectives,

• maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.

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Financial Results

The results for PSEG, PSE&G and Power for the three months and six months ended June 30, 2017 and 2016 are presented as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Earnings (Losses)	2017			2016			2017			2016
	Millions
PSE&G	$	208		$	179		$	507		$	441
Power (A)	(97		)	(11		)	(267		)	181
Other (B)	(2		)	19			(17		)	36
PSEG Net Income	$	109		$	187		$	223		$	658
PSEG Net Income Per Share (Diluted)	$	0.22		$	0.37		$	0.44		$	1.30

(A) Includes after-tax expenses of $229 million and $563 million in the three months and six months ended June 30, 2017, respectively, primarily for accelerated depreciation related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants. See Item 1. Note 3. Early Plant Retirements for additional information.

(B) Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges of $13 million and $45 million related to its investments in NRG REMA, LLC’s leveraged leases in the three months and six months ended June 30, 2017, respectively. See Item 1. Note 6. Financing Receivables for additional information.

Power’s results above include the realized gains, losses and earnings on the Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity and the impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	14	$	(1	)	$	22	$	(6	)
Non-Trading MTM Gains (Losses) (C)	$	21	$	(101	)	$	27	$	(88	)

(A) NDT Fund Income (Expense) includes the realized gains and losses, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions, and impairments on certain NDT securities recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization (D&A) Expense.

(B) Net of tax (expense) benefit of $(16) million, $(1) million, $(25) million and $2 million for the three and six months ended June 30, 2017 and 2016, respectively.

(C) Net of tax (expense) benefit of $(15) million $70 million, $(19) million and $61 million for the three and six months ended June 30, 2017 and 2016, respectively.

Our $78 million and $435 million decreases in Net Income for the three months and six months ended June 30, 2017, respectively, were driven primarily by

• accelerated depreciation related to the early retirement of our Hudson and Mercer coal/gas generation units at Power (see Item 1. Note 3. Early Plant Retirements), and

• charges related to leveraged lease investments (see Item 1. Note 6. Financing Receivables).

These decreases were partially offset by

• MTMgains in 2017 as compared to MTM losses in 2016,

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• higher transmission revenues, and

• higher realized gains in the NDT Fund.

During the first six months of 2017, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.

At PSE&G, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure, including our $275 million Newark Switch project that was approved by PJM in July 2017. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We also continue to modernize PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G.

As a result of our Energy Strong Order from the BPU, we will be required to file a distribution base rate case proceeding by no later than November 1, 2017. The case will provide PSE&G with the opportunity to reset assumptions on sales and O&M growth as well as provide the opportunity to recover investments not recognized in various clause mechanisms since our last base rate proceeding in 2010, and to recover prior approved storm costs. PSE&G, as part of the filing, will also request approval for a de-coupling of electric revenue from sales. We cannot predict when the distribution base rate will be approved by the BPU and the impact this proceeding will have on our distribution business.

In July, we filed for a petition with the BPU for GSMP II, a five-year extension of GSMP, which would accelerate the pace of replacement of our aging cast iron and unprotected steel mains and associated service. We proposed to invest up to $540 million per year over this five-year program beginning in 2019. In July, we also reached an agreement in principle with the BPU Staff and Rate Counsel for an extension of our Energy Efficiency program. For additional information, see Part II, Item 5. Other Information.

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

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

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

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

If trends noted above continue or worsen, our nuclear generating units could cease being economically competitive which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs,

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environmental remediation costs, and additional funding of nuclear decommissioning trust funds would likely have a material adverse impact on future financial results. We continue to advocate for sound policies that recognize nuclear power as a source of reliable and air emissions free energy and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.

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

Regulatory, Legislative and Other Developments

In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.

Transmission

In April 2017, the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission project and approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. Also, in April 2017, PJM submitted a proposal to FERC concerning the cost responsibility assigned to certain entities, including PSE&G, for the Artificial Island project.

There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey. In addition, as a basic generation service (BGS) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.

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

Wholesale Power Market Design

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources (seasonal resources). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions.

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

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

Distribution

In June 2017, the BPU issued proposed Infrastructure Investment Program (IIP) regulations that would allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under the proposed regulations, utilities could seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the

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IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. The proposed regulations will be subject to comment from interested parties.

Environmental Regulation

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

In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards, which establish emissions standards for CO₂ for certain new fossil power plants, and the Clean Power Plan, a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. Upon completion of the review, the EPA is expected to suspend, revise or rescind the rules as appropriate. 

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

For further information regarding the matters described above as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 9. Commitments and Contingent Liabilities.

FERC Compliance

Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 1. Note 9. Commitments and Contingent Liabilities.

Early Retirement of Hudson and Mercer Units

On June 1, 2017, Power completed its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operations in 2016 and continues to adversely impact their results of operations in 2017. During the first six months of 2017, Power recognized incremental D&A of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first half of 2017, Energy Costs of $9 million and O&M of $4 million were also incurred and other costs may be incurred during the remaining period in 2017. See Item 1. Note 3. Early Plant Retirements for additional information.

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

In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through 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

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capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.

Leveraged Lease Portfolio

GenOn Energy, Inc. (GenOn), the parent company of NRG REMA LLC, (REMA), and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. REMA was not included in the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity. We continue to monitor the restructuring of GenOn and the possible related impact on REMA.

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged lease receivables. For additional information, see Item 1. Note 6. Financing Receivables. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.

Additional facilities in our leveraged lease portfolio include the Joliet and Powerton generating facilities. Similar to Shawville, Joliet was recently converted to use natural gas. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois. Each of these three facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.  

Salem

Concurrently with the planned refueling outage at the Salem 2 unit that was conducted in the second quarter of 2017, we inspected and replaced baffle bolts as part of our strategy to replace baffle bolts at the Salem station.The unit was returned to service in June 2017.

Operational Excellence

We emphasize operational performance, exercising diligence in managing costs, while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market. For the first six months of 2017, our

• our utility continued top decile performance in electric reliability,

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

• diverse fuel mix and dispatch flexibility allowed us to generate approximately 26 terawatt hours, and

• combined cycle fleet produced seven terawatt hours at an equivalent availability factor of 92%.

Financial Strength

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

• maintained sufficient liquidity,

• maintained solid investment grade credit ratings, and

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

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

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Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first six months of 2017, we

• made additional investments in transmission infrastructure projects,

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

• continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and began construction of BH5 for targeted commercial operations in mid-2019.

Future Outlook    

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

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

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

• successfully launch and grow our retail energy business, which complements our existing wholesale energy business,

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

• effectively manage construction and start-up of our Keys, Sewaren 7, BH5 and other generation projects,

• advocate for measures to ensure the implementation by PJM and FERC of market design and transmission planning rules that continue to promote fair and efficient electricity markets,

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

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

For 2017 and beyond, the key issues, challenges and opportunities we expect our business to confront include:

• regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,

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

• the potential for comprehensive tax reform, particularly in light of public statements by the current U.S. administration and key members of Congress,

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

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

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

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

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

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

Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:

• the acquisition, construction or disposition of transmission and distribution facilities and/or generation units,

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

• the expansion of our geographic footprint,

• continued or expanded participation in solar, demand response and energy efficiency programs, and

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

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

RESULTS OF OPERATIONS

PSEG

Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PSE&G and Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note 18. Related-Party Transactions.

	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,									June 30,
	2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	2,133	$	1,905	$	228		12		$	4,725	$	4,521	$	204		5
Energy Costs	588		624		(36		)	(6	)	1,462		1,460		2			—
Operation and Maintenance	708		710		(2		)	—		1,420		1,439		(19		)	(1	)
Depreciation and Amortization	641		224		417			N/A		1,469		448		1,021			N/A
Income from Equity Method Investments	5		4		1			25		8		6		2			33
Other Income (Deductions)	61		34		27			79		122		61		61			100
Other-Than-Temporary Impairments	3		10		(7		)	(70	)	4		20		(16		)	(80	)
Interest Expense	91		97		(6		)	(6	)	189		189		—			—
Income Tax Expense	59		91		(32		)	(35	)	88		374		(286		)	(76	)

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

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PSE&G

	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,									June 30,
	2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,368	$	1,350	$	18		1		$	3,180	$	3,062	$	118		4
Energy Costs	472		529		(57		)	(11	)	1,225		1,258		(33		)	(3	)
Operation and Maintenance	351		352		(1		)	—		718		734		(16		)	(2	)
Depreciation and Amortization	166		136		30			22		337		275		62			23
Other Income (Deductions)	21		18		3			17		45		37		8			22
Interest Expense	69		74		(5		)	(7	)	144		142		2			1
Income Tax Expense	123		98		25			26		294		249		45			18

Three Months EndedJune 30, 2017 as Compared to 2016

Operating Revenuesincreased$18 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenuesincreased$54 million due primarily to an increase in transmission revenues.

• Transmission revenues were $45 millionhigher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

• Electric distribution revenues increased$8 million due to a $6 million increase from the inclusion of Energy Strong in base rates and a $7 million increase due to higher sales volumes, partially offset by lower Green Program Recovery Charges (GPRC) of $5 million.

• Gas distribution revenues increased$1 million due to $6 million in higher Weather Normalization Clause (WNC) revenue, a $2 million increase from the inclusion of Energy Strong in base rates, and $1 million increases in both GSMP collections and GPRC. These increases were almost entirely offset by lower sales volumes.

Commodity Revenuedecreased$57 million as a result of lower Electric and Gas revenues. The changes in Commodity revenue for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and basic gas supply service (BGSS) to retail customers.

• Electric commodity revenues decreased$40 million due primarily to an $18 million decrease in BGS revenues due to lower sales volumes and prices, $18 million of lower revenues from collections of Non-Utility Generation Charges (NGC) and a decrease of $4 million due to lower volumes of Non-Utility Generation (NUG) energy sold.

• Gas commodity revenues decreased$17 million due to lower BGSS sales volumes of $24 million partially offset by higher BGSS sales prices of $7 million.

Clause Revenuesincreased$19 million due primarily to the return in 2016 to customers of $15 million of overcollections of Securitization Transition Charges (STC) and a $7 million increase in 2017 in Margin Adjustment Clause (MAC) revenues, partially offset by lower Societal Benefit Charges (SBC) of $3 million. The changes in the STC, MAC and SBC amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC, MAC or SBC collections.

Operating Expenses

Energy Costsdecreased$57 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenancedecreased$1 million, primarily due to $6 million of lower distribution corrective and preventative maintenance, partially offset by a $5 million increase in transmission maintenance.

Depreciation and Amortizationincreased$30 million due primarily to an increase of $15 million in amortization of Regulatory Assets and a $14 million increase in depreciation due to additional plant in service.

Other Income and (Deductions)increased$3 million due primarily to an increase in Allowance for Funds Used During Construction (AFUDC).

Interest Expensedecreased$5 million due primarily to a $9 million decrease predominantly driven by a reduction in clause interest. This decrease was partially offset by an increase of $4 million due to net debt issuances in 2016 and 2017.

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Income Tax Expenseincreased$25 million due primarily to higher pre-tax income.

Six Months EndedJune 30, 2017 as Compared to 2016

Operating Revenuesincreased$118 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenuesincreased$112 million due primarily to an increase in transmission revenues.

• Transmission revenues were $82 millionhigher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

• Gas distribution revenues increased$25 million due to a $13 million increase due to the inclusion of Energy Strong in base rates, $8 million in higher WNC revenue, a $6 million increase due to the GSMP and higher GPRC of $2 million partially offset by $4 million of lower delivery volumes.

• Electric distribution revenues increased$5 million due to an $8 million increase due to the inclusion of Energy Strong in base rates and a $5 million increase due to higher sales volumes, partially offset by lower GPRC of $8 million.

Commodity Revenuedecreased$33 million as a result of lower Electric revenues partially offset by higher Gas revenues. The changes in Commodity revenue for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

• Electric commodity revenues decreased$90 million due primarily to $41 million of lower revenues from collections of NGC, a $35 million decrease in BGS revenues due to lower sales prices and volumes and a decrease of $14 million due to lower volumes of NUG energy sold.

• Gas commodity revenues increased$57 million due primarily to higher BGSS sales prices.

Clause Revenuesincreased$38 million due primarily to the 2016 return to customers of $30 million of overcollections of STC, and higher MAC revenues of $8 million in 2017. The changes in the STC and MAC amounts are entirely offset by increase in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC or MAC collections.

Operating Expenses

Energy Costsdecreased$33 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenancedecreased$16 million, of which the most significant components were decreases of

• $10 millionin distribution corrective and preventative maintenance,

• $8 million in appliance service costs,

• $6 millionin gas bad debt and

• $4 million in pension and other postretirement benefit costs, net of capitalized amounts, partially offset by

• a $6 million increase in transmission maintenance costs and

• a $6 million net increase in operational expenses.

Depreciation and Amortizationincreased$62 million due primarily to an increase of $32 million in amortization of Regulatory Assets and a $29 millionincrease in depreciation due to additional plant in service.

Other Income and (Deductions)increased$8 million due primarily to an increase of $7 million in AFUDC and a $3 millionincrease in realized gains on Rabbi Trust investments, partially offset by a net $2 milliondecrease in Solar Loan interest.

Interest Expenseincreased$2 million due primarily to an increase of $11 million due to net debt issuances in 2016 and 2017, partially offset by $8 milliondecrease predominantly driven by a reduction in clause interest.

Income Tax Expenseincreased$45 million due primarily to higher pre-tax income.

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Power

	Three Months Ended						Increase/ (Decrease)					Six Months Ended					Increase/ (Decrease)
	June 30,											June 30,
	2017			2016			2017 vs. 2016					2017			2016		2017 vs. 2016
	Millions						Millions			%		Millions					Millions			%
Operating Revenues	$	929		$	714		$	215		30		$	2,213		$	2,027	$	186		9
Energy Costs	397			381			16			4		1,104			1,019		85			8
Operation and Maintenance	254			265			(11		)	(4	)	484			518		(34		)	(7	)
Depreciation and Amortization	465			80			385			N/A		1,115			159		956			N/A
Income from Equity Method Investments	5			4			1			25		8			6		2			33
Other Income (Deductions)	39			16			23			N/A		70			24		46			N/A
Other-Than-Temporary Impairments	3			10			(7		)	(70	)	4			20		(16		)	(80	)
Interest Expense	13			20			(7		)	(35	)	29			42		(13		)	(31	)
Income Tax Expense (Benefit)	(62		)	(11		)	51			N/A		(178		)	118		N/A			N/A

Three Months EndedJune 30, 2017 as Compared to 2016

Operating Revenuesincreased$215 million due to changes in generation and gas supply revenues.

Generation Revenuesincreased$223 million due primarily to

• an increase of $219 million due to MTM gains in 2017 as compared to MTM losses in 2016. Of this amount, $182 million was due to changes in forward power prices and $37 million was due to lower gains on positions reclassified to realized upon settlement this year as compared to gains last year, and

• a net increase of $15 million in electricity sold under wholesale load contracts in the New England (NE) region due to higher volumes sold,

• partially offset by a decrease of $11 million in electricity sold under our BGS contracts due primarily to lower volumes.

Gas Supply Revenuesdecreased$9 million due primarily to

• a net decrease of $17 million related to sales to third parties, of which $22 million was due to lower volumes sold, partially offset by $5 million of higher average sales prices,

• partially offset by a net increase of $9 million due to MTM gains in 2017 as compared to MTM losses in 2016.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased$16 million due to

Generation costsincreased$33 million due primarily to

• an increase of $20 million due to MTM losses in 2017 as compared to MTM gains in 2016,

• an increase of $21 million due primarily to higher natural gas costs reflecting higher average realized prices,

• an increase of $8 million in energy purchase volumes in the NE region to serve load obligations, and

• a $2 million charge associated with a lower of cost or market coal inventory adjustment at Hudson and Mercer,

• partially offset by a net decrease of $19 million primarily due to lower congestion rates coupled with less congestion volumes.

Gas costsdecreased$17 million due mainly to a net decrease of $16 million related to sales to third parties, of which $21 million was due to lower volumes sold, partially offset by $5 million of higher average costs.

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Operation and Maintenancedecreased$11 million due primarily to a $14 million decrease at our fossil plants, due largely to higher planned outage costs in the second quarter of 2016 and retirement of the Hudson and Mercer coal units on June 1, 2017.

Depreciation and Amortization increased$385 milliondue primarily to

• $380 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,

• $4 million of greater depreciation due to the accelerated retirement date at Bridgeport Harbor 3 (BH3), and

• $3 million of higher depreciation due to new solar projects.

Other Income (Deductions) increased$23 million due primarily to higher net realized gains in the NDT Fund.

Other-Than-Temporary Impairmentsdecreased$7 million due to lower impairments of equity securities in the NDT Fund in 2017.

Interest Expensedecreased$7 million due primarily to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys.

Income Tax Expense (Benefit) reflected anincreased tax benefit of $51 million due primarily to a higher pre-tax loss in 2017.

Six Months EndedJune 30, 2017 as Compared to 2016

Operating Revenuesincreased$186 million due to changes in generation and gas supply revenues.

Generation Revenuesincreased$99 million due primarily to

• an increase of $196 million due to MTM gains in 2017 as compared to MTM losses in 2016. Of this amount, $106 million was due to lower gains on positions reclassified to realized upon settlement this year as compared to last year and $90 million due to changes in forward power prices, and

• a net increase of $24 million due primarily to higher volumes of electricity sold under wholesale load contracts in the NE region partially offset by lower average prices,

• partially offset by a net decrease of $90 million in energy sales in the PJM and NE regions due primarily to lower average realized prices,

• a net decrease of $8 million in electricity sold under our BGS contracts of which $21 million was due to lower volumes, partially offset by $13 million of higher average prices, and

• a charge of $10 million due to an increase in the FERC accrual related to the PJM bidding matter see Item 1. Note 9. Commitments and Contingent Liabilities.

Gas Supply Revenuesincreased$86 million due primarily to

• an increase of $45 million in sales under the BGSS contract, of which $37 million was due to higher average sales prices coupled with an $8 million increase in sales volumes due to periods of colder weather in March,

• an increase of $24 million related to sales to third parties, of which $48 million was due to higher average sales prices, partially offset by $24 million of lower volumes sold, and

• a net increase of $17 million due to MTM gains in 2017 as compared to MTM losses in 2016.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased$85 million due to

Generation costsincreased$32 million due primarily to

• higher fuel costs of $35 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas and oil,

• an increase of $18 million due to MTM losses in 2017 as compared to MTM gains in 2016,

• an increase of $15 million in energy purchase volumes in the NE region to serve load obligations, and

• a $9 million charge associated with a lower of cost or market coal inventory adjustment at Hudson and Mercer,

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• partially offset by a net decrease of $45 million due primarily to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, partially offset by higher transmission charges due to higher rates.

Gas costsincreased$53 million due mainly to

• an increase of $31 million related to sales under the BGSS contract due primarily to higher average gas costs and an increase in volumes sold due to periods of colder weather in March, and

• an increase of $22 million related to sales to third parties, of which $44 million was due to higher average gas costs, partially offset by a $22 million decrease in volumes sold.

Operation and Maintenancedecreased$34 million due primarily to

• a $16 million decrease at our fossil plants, due primarily to the retirement of the Hudson and Mercer units and higher planned outage costs in 2016 as compared to 2017,

• an $11 million net decrease related to our nuclear plants due primarily to lower labor-related costs and outage costs, and

• a $9 million legal accrual for environmental expenses recorded in 2016,

• partially offset by $3 million of costs related to seven new solar plants placed into service since June 2016.

Depreciation and Amortization increased$956 milliondue primarily to

• $938 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,

• $8 million of greater depreciation due to the accelerated retirement date at BH3,

• a $6 million increase due to a higher nuclear asset base, and

• $6 million of higher depreciation due to new solar projects.

Other Income (Deductions) increased$46 million due primarily to $41 million of higher net realized gains in the NDT Fund and $3 million of higher realized gains in the Rabbi Trust Fund.

Other-Than-Temporary Impairmentsdecreased$16 million due to lower impairments of equity securities in the NDT Fund in 2017.

Interest Expensedecreased$13 million due primarily to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys.

Income Tax Expense (Benefit) reflected a tax benefit of $(178) million in 2017 and a $118 million tax expense in 2016 due primarily to a pre-tax loss in 2017 as compared to pre-tax income in 2016.

LIQUIDITY AND CAPITAL RESOURCES

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

Operating Cash Flows

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

For the six months ended June 30, 2017, our operating cash flow increased$34 million as compared to the same period in 2016. The net change was due primarily to tax refunds in 2017 at Energy Holdings and the net changes from PSE&G and Power as discussed below.

PSE&G

PSE&G’s operating cash flow decreased$38 million from $808 million to $770 million for the six months ended June 30, 2017, as compared to the same period in 2016, due primarily to lower tax refunds, partially offset by higher earnings.

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Power

Power’s operating cash flow increased$15 million from $917 million to $932 million for the six months ended June 30, 2017, as compared to the same period in 2016, due primarily to a $105 milliondecrease in margin deposit requirements and a $48 millionincrease from net collection of counterparty receivables, partially offset by tax payments in 2017 as compared to tax refunds in 2016, a $28 milliondecrease from fuels, materials and supplies and lower earnings.

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.

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

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

Our total credit facilities and available liquidity as of June 30, 2017 were as follows:

Company/Facility	As of June 30, 2017
	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	13	$	1,487
PSE&G	600		15		585
Power	2,100		190		1,910
Total	$	4,200	$	218	$	3,982

As of June 30, 2017, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and thepotential impact of Power losing its investment grade credit rating from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s credit rating certain of Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if Power were to lose its investment grade credit rating was approximately $808 million and $783 million as of June 30, 2017 and December 31, 2016, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units did not have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 1. Note 3. Early Plant Retirements.

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

Long-Term Debt Financing

PSEG Parent has a floating rate $500 million term loan maturing in November 2017. PSE&G has $400 million of 5.30% Medium-Term Notes maturing in May 2018.

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

Common Stock Dividends

On April 18, 2017, our Board of Directors approved a $0.43 dividend per share of common stock for the second quarter of 2017. On July 18, 2017, our Board of Directors declared a $0.43 dividend per share of common stock for the third quarter of 2017. This reflects an indicative annual dividend rate of $1.72 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. Note16. Earnings Per Share (EPS) and Dividends.

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Credit Ratings

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

In April 2017, S&P published updated research and affirmed the ratings and outlooks of PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. Also in June 2017, Moody’s published updated research on PSE&G and Power and the ratings and outlooks remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.

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

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

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

CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures at PSE&G, Power and Services as compared to amounts disclosed in our 2016 Form 10-K.

PSE&G

During the six months ended June 30, 2017, PSE&G made capital expenditures of $1,389 million, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $47 million, which are included in operating cash flows.

In July 2017, PSE&G filed a petition with the BPU for a GSMP II program, requesting extension of our gas system modernization program through which PSE&G has proposed investing up to $540 million per year beginning in 2019 to continue to modernize our gas system. Under this proposed program, PSE&G plans to replace up to 1,250 miles of gas mains and associated service lines. This is not included in PSE&G’s projected capital expenditures.

Power

During the six months ended June 30, 2017, Power made capital expenditures of $518 million, excluding $58 million for nuclear fuel, primarily related to our Keys, Sewaren 7, BH5 and other generation projects.

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ACCOUNTING MATTERS

For information related to recent accounting matters, see Item 1. Note 2. Recent Accounting Standards.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Contracts

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

Value-at-Risk (VaR) Models

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

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

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

From April through June 2017,MTM VaR remained relatively stable between a low of $6 million and a high of $10 million at the 95% confidence level. The range of VaR was narrower for the three months ended June 30, 2017 as compared with the year ended December 31, 2016.

	MTM VaR
	Three Months Ended June 30, 2017		Year Ended December 31, 2016
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	8	$	26
Average for the Period	$	8	$	16
High	$	10	$	32
Low	$	6	$	10
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	13	$	40
Average for the Period	$	12	$	25
High	$	16	$	51
Low	$	9	$	16

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

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG, PSE&G and Power

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG, PSE&G and Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG, PSE&G and Power have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

PSEG, PSE&G and Power

There have been no changes in internal control over financial reporting that occurred during the second quarter of 2017 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. For additional information regarding material legal proceedings, including updates to information reported in Item 3 of Part I of the 2016 Annual Report on Form 10-K, see Part I, Item 1. Note 9. Commitments and Contingent Liabilities and Item 5. Other Information.

ITEM 1A. RISK FACTORS

The discussion of our business and operations in this Quarterly Report on Form 10-Q should be read together with the risk factors contained in Part I, Item 1A of our 2016 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, which describe various risks and uncertainties that could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report. There have been no material changes to the risk factors set forth in the above-referenced filings as of June 30, 2017.

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

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the second quarter of 2017.

Three Months Ended June 30, 2017	Total Number of Shares Purchased	Average Price Paid per Share
April 1 - April 30	—	$	—
May 1 - May 31	130,749	$	43.77
June 1- June 30	30,000	$	44.72

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ITEM 5. OTHER INFORMATION

Certain information reported in the 2016 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2016 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.

Federal Regulation

FERC

Capacity Market Issues

December 31, 2016 Form 10-K page 16 and March 31, 2017 Form 10-Q on page 76. PJM, the New York Independent System Operator (NYISO) and the Independent System Operator New England, Inc. each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources or resource attributes, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. FERC held a technical conference to seek input from the industry on potential options to integrate public policy goals in wholesale markets. We cannot predict what action, if any, FERC might take with regard to capacity market designs.

Capacity Market Issues—PJM

December 31, 2016 Form 10-K page 16 and March 31, 2017 Form 10-Q on page 76. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The Court of Appeals for the D.C. Circuit (D.C. Circuit) denied petitions challenging certain aspects of FERC’s Order. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. FERC has approved changes to the CP construct that will enhance the participation of intermittent and DR resources (seasonal resources). Specifically, FERC approved PJM’s modifications to the aggregation rules to improve the ability of seasonal resources to participate. However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions. We do not expect action on the complaints until additional commissioners have been nominated and confirmed so that FERC has a quorum necessary to take action.

PJM issued a series of white papers in response to public policies that seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes. The three proposals are intended to spur stakeholder discussion and include both potential capacity and energy market reforms. One energy market reform would allow inflexible generating units to set prices resulting in reduced uplift payments and improved price signals while the second energy market reform contemplates a voluntary carbon pricing program where states that elect to participate in the program would agree to put a price on carbon emissions. The capacity market proposal contemplates a two-stage capacity auction which, in its current form, would improve prices for unsubsidized resources, but would still continue to provide capacity payments for subsidized resources.

Transmission Regulation—Transmission Policy Developments

December 31, 2016 Form 10-K page 18 and March 31, 2017 Form 10-Q on page 77. In June 2015, a 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 in the complaint, according to the complaint, PSE&G is identified as one of the companies claimed to have been involved. FERC set the complaint for hearing and settlement procedures and the parties are currently engaged in discovery. We are unable to predict the outcome of these proceedings.

In August 2016, PJM announced that it had suspended the Artificial Island transmission project and would be performing a comprehensive analysis to support a future course of action. In March 2017, PJM staff made its final recommendation to the PJM Board with respect to the project. Under the recommended project, PSE&G will construct necessary upgrade work at a cost of approximately $130 million. In April 2017, the PJM Board announced that it would be lifting the suspension and approved the staff recommended project. Also, in April 2017, PJM submitted a proposal to FERC concerning the cost responsibility assigned to certain entities, including PSE&G, for the Artificial Island project. PSE&G plans to participate in this proceeding. However, we are unable to predict the outcome.

Transmission Regulation—Transmission Rate Proceedings

Numerous complaints have been filed at FERC in recent years seeking to reduce the base ROE of transmission owners across the country. Many of those complaints were resolved through agreement and settlement resulted in ROE reductions while others remain pending in the FERC adjudication process or are being litigated in the courts. Recent court decisions, as well as anticipated changes in the makeup at FERC, create some uncertainty as to the timing and outcome of these complaints. The

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results of these settlement and proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

Transmission Regulation—Con Edison Wheeling Agreement

December 31, 2016 Form 10-K page 19 and March 31, 2017 Form 10-Q on page 77. EffectiveMay 1, 2017, a wheeling arrangement which enabled Con Edison to move 1,000 MW of power from southeastern New York across the PSE&G system for delivery into New York City expired. NYISO and PJM revised their Joint Operating Agreement to modify the operational protocols for the affected interconnection between NYISO and PJM in a submittal to FERC that became effective, subject to refund, on May 1, 2017. PSE&G and the BPU jointly filed for rehearing of FERC’s order. In a related filing, PJM submitted a proposal to FERC revising the cost responsibility assigned to certain entities, including PSE&G, due to the termination of the Wheeling Agreement. This filing was accepted, subject to refund, effective May 1, 2017. PSE&G will continue to recover the costs associated with the new arrangement through its formula rate. We cannot predict the outcome of this proceeding.

State Regulation

Gas System Modernization Program II (GSMP II)

In July 2017, we filed a petition with the BPU for a GSMP II program, requesting extension of our gas system modernization program through which PSE&G has proposed investing $2.7 billion over five years beginning in 2019 to continue to modernize our gas system. Under this proposed program, we plan to replace up to 1,250 miles of gas mains and associated service lines, with cost recovery at a 9.75% rate of return on equity through an accelerated recovery mechanism. This matter is pending. We believe the petition is consistent with the draft regulations that the BPU issued in June 2017 regarding infrastructure investment programs as described below.

Connecticut Rate Filing

December 31, 2016 Form 10-K page 21. In June 2017, Power’s subsidiary, PSEG New Haven LLC, filed a mandatory annual rate case with the Connecticut Public Utilities Regulatory Authority for recovery of its costs and investment in its Connecticut-based peaking unit. Power requested 2018 revenues of $20 million. This matter is pending.

Energy Efficiency Program (Energy Efficiency 2017)

March 31, 2017 Form 10-Q on page 77. In July 2017, we reached an agreement in principle with BPU Staff and Rate Counsel related to our proposed Energy Efficiency program extension. Under the agreement, PSE&G would invest $69 million in energy efficiency equipment for hospitals, multi-family housing and other sectors and a residential energy efficiency offering for smart thermostats and data analytics. We would recover our investment with an initial ROE of 9.75% to be reset in our upcoming rate case and receive recovery of administrative costs. This agreement is subject to review by the BPU.

Infrastructure Investment Programs (IIP)

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

Environmental Matters

Climate Change

CO₂ Regulation under theClean Air Act (CAA)

December 31, 2016 Form 10-K page 23 and March 31, 2017 Form 10-Q on page 77. In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO₂ for certain new fossil power plants and the Clean Power Plan, a greenhouse gas emissions regulation under the CAA for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In April 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance for at least 60 days while the agency reviews the rule. 

Upon completion of the review, the EPA is expected to suspend, revise or rescind the rules as appropriate. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

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Water Pollution Control

Steam Electric Effluent Guidelines

December 31, 2016 Form 10-K page 23 and March 31, 2017 Form 10-Q on page 77. In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations and pretreatment standards for the aforementioned waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Waters of the United States

December 31, 2016 Form 10-K page 24 and March 31, 2017 Form 10-Q on page 78. In April 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to clarify the definition of waters of the United States under the Clean Water Act (CWA) programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. The final rule was published in June 2015 (June 2015 rule) and various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the June 2015 rule.

In February 2017, the President of the United States issued an Executive Order that instructed the EPA to review the June 2015 rule and issue a proposal to redefine “Waters of the United States.” In June 2017, the EPA and the U.S. Army Corps of Engineers announced the agencies will be (1) issuing a proposed rule to rescind the 2015 Rule and reinstate the previously existing definition of “Waters of the United States” and (2) developing a new rule, including a revised definition of “Waters of the United States.” Publication of the proposed rule to rescind the June 2015 rule is expected in the third quarter of 2017 and the process regarding a new rule will likely take several years.

Some states, including New Jersey, are subject to state requirements beyond thoseimposed under federal law. While we do not anticipate material impacts to projects in New Jersey, the new rule could impose requirements in other states and regions that could impact the development of renewables.

Endangered Species Act

December 31, 2016 Form 10-K page 25 and March 31, 2017 Form 10-Q on page 78. In June 2015, the Sierra Club and another environmental group submitted to the New Jersey Department of Environmental Protection (NJDEP) a sixty-day notice of intent to sue alleging the agency has caused violations of the Endangered Species Act by allowing our Mercer generation station to operate in a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a New Jersey Pollutant Discharge Elimination System (NJPDES) permit renewal action for Mercer which addresses the alleged Endangered Species Act violations. In May 2017, the NJDEP issued a final NJPDES renewal permit for Mercer effective June 1, 2017. The new permit will cover the waste water discharges that will be present during the period of decommissioning. In March 2017, we submitted an Incidental Take Permit application to the National Marine Fisheries Service outlining proposed operation and monitoring requirements through retirement of the Mercer generation station on June 1, 2017 and subsequent decommissioning.

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ITEM 6. EXHIBITS

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

a. PSEG:
Exhibit 10.1:	Supplemental Executive Retirement Income Plan dated July 10, 2017
Exhibit 10.2:	Retirement Income Reinstatement Plan dated July 10, 2017
Exhibit 12:	Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:	Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:	Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:	XBRL Instance Document
Exhibit 101.SCH:	XBRL Taxonomy Extension Schema
Exhibit 101.CAL:	XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:	XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:	XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:	XBRL Taxonomy Extension Definition Document
b. PSE&G:
Exhibit 10.1:	Supplemental Executive Retirement Income Plan dated July 10, 2017
Exhibit 10.2:	Retirement Income Reinstatement Plan dated July 10, 2017
Exhibit 12.1:	Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.2:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:	Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:	Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:	XBRL Instance Document
Exhibit 101.SCH:	XBRL Taxonomy Extension Schema
Exhibit 101.CAL:	XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:	XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:	XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:	XBRL Taxonomy Extension Definition Document
c. Power:
Exhibit 10.1:	Supplemental Executive Retirement Income Plan dated July 10, 2017
Exhibit 10.2:	Retirement Income Reinstatement Plan dated July 10, 2017
Exhibit 12.2:	Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.4:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5:	Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.4:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.5:	Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:	XBRL Instance Document
Exhibit 101.SCH:	XBRL Taxonomy Extension Schema
Exhibit 101.CAL:	XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:	XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:	XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:	XBRL Taxonomy Extension Definition Document

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)
By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: July 28, 2017

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)
By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: July 28, 2017

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

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

Date: July 28, 2017

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EX-10.1

Exhibit 10.1

SUPPLEMENTAL EXECUTIVE RETIREMENT INCOME PLAN

FOR NON‑REPRESENTED EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

Effective as of January 1, 2017

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SUPPLEMENTAL EXECUTIVE RETIREMENT INCOME PLAN

FOR NON‑REPRESENTED EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

Public Service Enterprise Group Incorporated (“PSEG”) had established two supplemental executive retirement plans for certain of its and its affiliates’ non-represented employees: the Limited Supplemental Benefits Plan for Certain Employees of Public Service Enterprise Group Incorporated and its Subsidiaries (the “Limited Plan”) and the Mid-Career Hire Supplemental Retirement Income Plan for Selected Employees of Public Service Enterprise Group Incorporated and its Affiliates (the “Mid-Career Plan”). These plans were established for the purpose of assisting in attracting and retaining a stable pool of key managerial and professional talent and developing long‑term key employee commitment by providing specified supplemental retirement income benefits for certain employees who participate in a Qualified Plan.

The Limited Plan and the Mid-Career Plan were each intended to constitute an unfunded plan of deferred compensation for a select group of management or highly compensated employees for purposes of Title 1 of ERISA. Effective as of December 1, 2009, the Limited Plan and the Mid-Career Plan (together, the “Prior Plans”) were merged into a single plan, this Supplemental Executive Retirement Income Plan for Non-Represented Employees of Public Service Enterprise Group Incorporated and Its Affiliates (“SERP”). The merger of these plans was not intended to change the eligibility of or benefits payable to the participants in the Prior Plans.

The SERP was amended effective January 1, 2011 to reflect that participation as to the Mid-Career Hire benefit was frozen.

Effective as of January 1, 2012, the benefit formula under the Final Average Pay Component changed from a 5-year final average pay formula to a 7-year final average pay formula. The change in the benefit formula under the Final Average Pay Component affected the benefits provided under the SERP. Accordingly, the SERP was amended effective January 1, 2012 to reflect these changes. Notwithstanding anything in the SERP to the contrary, the foregoing change shall not apply to Robert Braun, Thomas Joyce and John Perry.

The SERP is being amended effective January 1, 2017 to make certain administrative clarifications.

Section 1. Definitions

When used herein, the words and phrases hereinafter defined shall have the following meanings unless a different meaning is clearly required by the context of the SERP:

1.1 “Affiliate” shall mean (a) any organization while it is a member of a controlled group of corporations (as defined in Section 414(b) of the Code) which includes PSEG ; or (b) any trades or businesses

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(whether or not incorporated) while they are under common control (as defined in Section 414(c) of the Code, as modified by Section 415(h) of the Code) with PSEG.

1.2 “Beneficiary” shall mean any person or persons designated by a Participant who may become eligible to receive the benefits provided under the SERP in the event of such Participant’s death.

1.3 “Benefit Commencement Date” shall mean the date that is the Participant’s last day worked plus one day.

1.4“Board” or “Board of Directors” shall mean the Board of Directors of Public Service Enterprise Group Incorporated.

1.5 “Cash Balance Component” shall mean the Cash Balance Component of the Pension Plan. The Cash Balance Component was formerly the Public Service Enterprise Group Incorporated Cash Balance Pension Plan.

1.6“CEO” shall mean the Chief Executive Officer of PSEG. If PSEG has no designated Chief Executive Officer, “CEO” shall mean the President of PSEG.

1.7“Change in Control” shall mean the occurrence of any of the following events:

(a) Any “person” (within the meaning of Section 13(d) of the Securities Exchange Act of 1934, as amended from time to time (the “Act”)) is or becomes the beneficial owner within the meaning of Rule 13d-3 under the Act (a “Beneficial Owner”), directly or indi-rectly, of PSEG’s securities of (not including in the securities beneficially owned by such person any securities acquired directly from PSEG or its Affiliates) representing 25% or more of the combined voting power of PSEG then outstanding securi-ties, excluding any person who becomes such a Beneficial Owner in connection with a transaction described in clause (i) of paragraph (c) below; or

(b) The following individuals cease for any reason to consti-tute a majority of the number of directors then serving: individuals who, on December 15, 1998, constitute the Board of Directors and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, includ-ing but not limited to a consent solicitation, relating to the election of directors of PSEG) whose appointment or election by the Board or nomination for election by PSEG’s stockholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors on December 15, 1998 or whose appointment, election or

3

nomination for election was previously so approved or recom-mended; or

(c) There is consummated a merger or consolidation of PSEG or any direct or indirect wholly owned subsidiary of PSEG with any other corporation, other than (i) a merger or consolidation which would result in the voting securities of PSEG outstanding immediately prior to such merger or consoli-dation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of PSEG or any subsidiary of PSEG, at least 75% of the combined voting power of the securities of PSEG or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or (ii) a merger or consolidation effected to implement a recapitalization of PSEG (or similar transaction) in which no person is or becomes the Beneficial Owner, directly or indirectly, of securities of PSEG representing 25% or more of the combined voting power of PSEG’s then outstanding securities; or

(d) The stockholders of PSEG approve a plan of complete liquidation or dissolution of PSEG or there is consummated an agreement for the sale or disposition by PSEG of all or substantially all of PSEG’s assets, other than a sale or disposition by PSEG of all or substantially all of PSEG’s assets to an entity, at least 75% of the combined voting power of the voting securities of which are owned by stockholders of PSEG in substantially the same proportions as their own-ership of PSEG immediately prior to such sale.

Notwithstanding the foregoing subsection (a) through (d), a “Change in Control” shall not be deemed to have occurred by virtue of the consummation of any transaction or series of integrated transactions immediately following which the record holders of the common stock of PSEG immediately prior to such transaction or series of transactions continue to have substantially the same proportionate ownership in an entity which owns all or substantially all of the assets of PSEG immediately following such transaction or series of transactions.

1.8 “Code” shall mean the Internal Revenue Code of 1986, as amended. A reference to a section of the Code shall also refer to any regulations and other guidance issued under that section.

1.9“Company” shall mean Public Service Enterprise Group Incorporated and each Participating Affiliate.

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1.10 “Compensation” with respect to any Participant shall mean base salary, bonuses (as described below) and overtime up to 20% of base salary. Compensation shall include amounts deferred to the Deferred Compensation Plan for Certain Employees of Public Service Enterprise Group Incorporated and its Affiliates (“Deferred Compensation Plan”). For the period prior to March 5, 2010, refer to the prior SERP document for the definition Compensation.

For purposes of calculating the Mid-Career Hire Benefit for a Participant who is a participant in the Cash Balance Component, Compensation shall not include amounts paid prior in 2006 under the MICP or the SMICP.

For clarification purposes, all bonuses paid under the PSEG Power LLC Incentive Compensation Program for PSEG Energy Resources & Trade LLC Employees (“ER&T Plan”), as limited hereunder, the Performance Incentive Plans (“PIPs”) and the PSEG Power LLC Incentive Compensation Program for Certain Employees of PSEG Energy Solutions LLC (“Energy Solutions Plan”) are included, except those paid under the Long Island Electric Utility ServCo LLC Performance Incentive Plan.

For Participants who are participants in the Cash Balance Component, Compensation for any such year shall not exceed 150 percent of the Participant’s annual base salary in effect as of January 1 of that year. For Participants who are first hired during the Plan Year, for that year, the base salary in effect as of the date of hire shall be used. For Participants who are rehired, the base salary as of the date of rehire shall be used for determining Compensation of the year of the rehire.

For purpose of calculating the Limited Benefit, bonuses paid under the PIP, Energy Solutions Plan, MICP, SMICP and the ER&T Plan are included in Compensation for all years (including those paid prior to 2006).

For purposes of calculating SERP Benefits, bonuses paid under the PIP, Energy Solutions Plan, MICP, SMICP and the ER&T plan are included in Compensation only if the bonus is paid prior to the date of the Participant’s Separation from Service.

1.11 “Credited Service” shall mean the aggregate of all periods of employment with PSEG, an Affiliate or former Affiliate and all periods of additional Credited Service granted to Participants listed on Schedule A by PSEG for which a Participant will be given credit in computing their SERP Benefit. Service with Long Island Electric Utility ServCo LLC, LIPA and/or National Grid shall be taken into account under the SERP to the extent such service is taken into account under the Qualified Plan.

1.12 “Employee” shall mean any individual in the employ of the Company who is not included within a unit of employees covered by a collective bargaining agreement. The term “Employee” shall not include a director of the Company who serves in no capacity other than as a director, a consultant or independent contractor doing work for the Company or a person employed by a consultant or independent contractor doing work for the Company (regardless of whether a determination is made by the Internal Revenue Service or other governmental agency

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or court after the individual is engaged to perform such services that the individual is an employee of the Company for the purposes of the Code or otherwise).

1.13 “Employee Benefits Committee” shall mean the Employee Benefits Committee of PSEG.

1.14 “Employee Benefits Policy Committee” shall mean the Employee Benefits Policy Committee of PSEG.

1.15“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended. A reference to a section of ERISA shall also refer to any regulations and other guidance issued under that section.

‘

1.16“Final Average Earnings” with respect to a Participant who is entitled to a Limited Benefit:

(a) And who incurs a Separation from Service before January 1, 2012, shall mean the annual average of the sum of:

(1) The Participant’s last five years of Compensation, excluding any amounts received as an award under the MICP or the SMICP, without the application of the base pay cap in Section 1.10, and

(2) The MICP or SMICP awards for the five most recent bonus eligible years (including $0 awards) prior to the Participant’s Separation from Service. If a Participant does not have at least five MICP/SMICP awards, the average shall be determined by using the number of bonus (including PIP bonuses, ER&T Plan bonuses and Energy Solutions Plan bonuses) eligible periods during the five most recent years.

Notwithstanding the foregoing, Final Average Earnings shall not exceed 150 percent of the average of the Participant’s annual base salary in effect as of January 1 for the five years prior to and including the year in which the Participant’s Separation from Service occurs. For the year in which the Participant is hired, the base salary in effect as of the date of hire shall be used. For Participants who are rehired, the base salary as of the date of rehire shall be used for determining Compensation of the year of the rehire.

Bonuses paid under the PIP, Energy Solutions Plan, MICP, SMICP and the ER&T Plan are included in Compensation only if the bonus is paid prior to the date of the Participant’s Separation from Service.

(b) With respect to a Participant who incurs a Separation from Service on or after January 1, 2012, Final Average Earnings shall mean:

(1) With respect to periods of service prior to January 1, 2012, Final Average Earnings shall be determined in accordance with subsection (a) above,

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except that Separation from Service shall be replaced with December 31, 2011.

(2) With respect to periods of service after December 31, 2011, the annual average of the sum, (i) the Participant’s last seven years of Compensation beginning after December 31, 2011, excluding any MICP and SMICP awards, without the application of the base pay cap in Section 1.8, and (ii) the MICP or SMICP awards for the seven most recent years (including $0 awards) beginning after December 31, 2011 and prior to the Participant’s Separation from Service. If a Participant does not have at least seven MICP/SMICP awards during the seven most recent years after 2011, the average shall be determined by using the number of bonus (including PIP bonuses, ER&T Plan bonuses and Energy Solutions Plan bonuses) eligible periods after 2011 during the seven most recent years.

Notwithstanding the foregoing, Final Average Earnings shall not exceed 150 percent of the average of the Participant’s annual base salary in effect as of January 1 for the seven years prior to and including the year in which the Participant’s Separation from Service occurs (the annual base salary prior to January 1, 2012 shall not be used in such determination). For the year in which the Participant is hired, the base salary in effect as of the date of hire shall be used. For Participants who are rehired, the base salary as of the date of rehire shall be used for determining Compensation of the year of the rehire.

Bonuses paid under the PIP, Energy Solutions Plan, MICP, SMICP and the ER&T Program are included in Compensation only if the bonus is paid prior to the date of the Participant’s Separation from Service.

1.17    “Final Average Pay Component” shall mean the Final Average Pay Component of the Pension Plan.

1.18    “Limited Benefit” shall mean the benefit payable to a Participant pursuant to Section 3 of the SERP.

1.19     “Mid-Career Hire Benefit” shall mean the benefit payable to a Participant pursuant to Section 2 of the SERP.

1.20     “Mid-Career Hire Surviving Spouse Benefit” shall mean the benefit payable to a Surviving Spouse pursuant to the SERP.

1.21    “Normal Retirement Date” shall mean the first day of the month coinciding with or next following a Participant’s attainment of age 65. In the case of a Participant who is still employed beyond age 65, Normal Retirement Date shall mean the first day of the month coinciding with or next following the date on which the Participant’s Separation from Service occurs.

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1.22    “Participant” shall mean any Employee or former Employee who meets the requirements of Sections 2or 3 of the SERP.

1.23    “Participating Affiliate” shall mean any Affiliate of PSEG which (a) is the sponsor or a Participating Affiliate of the Qualified Plan; (b) adopts the SERP with the approval of the Board of Directors; (c) authorizes the Board of Directors and the Employee Benefits Committee to act for it in all matters arising under or with respect to the SERP; and (d) complies with such other terms and conditions relating to the SERP as may be imposed by the Board of Directors. Participating Affiliate shall not include Long Island Electric Utility ServCo LLC.

1.24    “Pension Plan” shall mean the Pension Plan of Public Service Enterprise Group Incorporated and each predecessor, successor or replacement plan.

1.25    “Qualified Benefit” shall mean the aggregate annual benefit payable to a Participant pursuant to the Qualified Plan by reason of the Participant’s termination of employment with PSEG and all Affiliates for any reason other than death.

1.26    “Qualified Plan” shall mean the Final Average Pay Component or the Cash Balance Component.

1.27     “Qualified Surviving Spouse Benefit” shall mean the aggregate annual benefit payable to the Surviving Spouse of a Participant pursuant to the Qualified Plan, in the event of the death of the Participant at any time prior to commencement of payment of the Participant’s Qualified Benefit.

1.28    “Plan Year” shall mean the calendar year.

1.29    “Reinstatement Plan” shall mean the Retirement Income Reinstatement Plan for Non‑Represented Employees of Public Service Enterprise Group Incorporated and its Affiliates.

1.230    “Reinstatement Benefit” shall mean the annual benefit payable to a Participant pursuant to the Reinstatement Plan for any reason other than death.

1.31     “Reinstatement Surviving Spouse Benefit” shall mean the annual benefit payable to the Surviving Spouse of a Participant pursuant to the Reinstatement Plan in the event of the death of the Participant at any time prior to commencement of payment of their Reinstatement Benefit.

1.32    “Retirement” shall mean:

(a) In the case of a Participant who is a participant in the Final Average Pay Component, a Separation from Service either (1) after attaining age 65, (2) following the date when the sum of the Participant’s age and credited service (as defined in the Final Average Pay Component) equals or exceeds 80, or (3) a disability determination under the Final Average Pay Component.

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(b) In the case of a Participant who is a participant in the Cash Balance Component, a Separation from Service after either (1) attaining age 65, (2) attaining age 55 and completing five or more years of credited service (as defined in the Cash Balance Component), or (3) a disability determination under the Cash Balance Component.

1.33    “Retirement Plans” shall mean all qualified defined benefit plans maintained by employers other than PSEG or any of its Affiliates.

1.34    “Separation from Service” shall mean, subject to subsections (a) and (b) below, a Participant’s termination from employment with PSEG and all Affiliates, whether by retirement or resignation from or discharge by PSEG or an Affiliate.

(a) A Separation from Service shall be deemed to have occurred if a Participant and PSEG or any Affiliate reasonably anticipates, based on the facts and circumstances, that either:

(i) The Participant will not provide any additional services for PSEG or an Affiliate after a certain date; or

(ii) The level of bona fide services performed by the Participant after a certain date will permanently decrease to no more than 50 percent of the average level of bona fide services performed by the Participant over the immediately preceding 36 months.

(b) If a Participant is absent from employment due to military leave, sick leave or any other bona fide leave of absence authorized by PSEG or an Affiliate and there is a reasonable expectation that the Participant will return to perform services for PSEG or an Affiliate, a Separation from Service will not occur until the later of:

(i) The first date immediately following the date that is six months after the date that the Participant was first absent from employment; or

(ii) The date the Participant no longer retains a right to reemployment, to the extent the Participant retains a right to reemployment with PSEG or any Affiliates under applicable law or by contract.

If a Participant fails to return to work upon the expiration of any military leave, sick leave or other bona fide leave of absence where such leave is for less than six months, the Separation from Service shall occur as of the date of the expiration of such leave.

1.35     “SERP” shall mean this Supplemental Executive Retirement Income Plan for Non-Represented Employees of Public Service Enterprise Group Incorporated and Its Affiliates.

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1.36    “Specified Employee” shall mean any individual who is a key employee (as defined in Section 416(i) of the Code without regard to Section 416(i)(5) of the Code) of PSEG or an Affiliate at any time during the 12-month period ending on each December 31 (the “identification date”). If an individual is a key employee as of an identification date, the individual shall be treated as a Specified Employee for the 12-month period beginning on the April 1 following the identification date. Notwithstanding the foregoing, an individual shall not be treated as a Specified Employee unless any stock of PSEG or an Affiliate is publicly traded on an established securities market or otherwise.

1.37     “SERP Benefit” shall mean the benefit payable to a Participant pursuant to the SERP by reason of the Participant’s Separation from Service with PSEG and all Affiliates for any reason other than death, which shall include the Mid-Career Hire Benefit and Limited Benefit.

1.38    “Surviving Spouse” shall mean a person who is married to a Participant on date of the Participant’s death.

Section 2. Mid-Career Hire Benefit

2.1    Eligibility. Effective January 1, 2011, participation in the Mid-Career Hire Benefit was closed. Prior to January 1, 2011, the CEO selected Employees who were eligible for a Mid-Career Hire Benefit and who were granted extra Credited Service. These Employees are listed in Schedule A. Upon selection for participation in the SERP, the CEO designated the number of years of additional Credited Service to which such Participant shall be entitled to in the calculation of their Mid-Career Hire Benefit.

Each Participant listed on Schedule A that incurs a Separation from Service after becoming vested in their benefits payable under the Qualified Plan shall be eligible to receive a Mid-Career Hire Benefit. If a Participant described in the preceding sentence dies prior to commencement of payment of their Qualified Benefit, such Participant’s Surviving Spouse shall be eligible to receive a Mid-Career Hire Surviving Spouse Benefit.

2.2    Benefit Formula. The Mid-Career Hire Benefit payable to an eligible Participant shall be equal to (a) or (b), as applicable:

(a) Final Average Pay Component Participant. The Mid-Career Hire Benefit payable to a Final Average Pay Component Participant shall be equal to the excess of (i) over (ii) where:

(i) Is the sum of (A) the amount of the Qualified Benefit, and (B) the amount of Reinstatement Benefit to which the Participant would have been entitled as of their Normal Retirement Date if such benefits were computed using the additional years of Credited Service granted to the Participant; and

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(ii) Is the sum of: (A) the Qualified Benefit, and (B) and Reinstatement Benefit as of their Normal Retirement Date.

The amounts described in (i) and (ii) shall be computed as of the date of Separation from Service of the Participant with PSEG and all Affiliates in the form of a single life annuity commencing on their Normal Retirement Date.

The Mid-Career Hire Benefit shall be calculated as a single life annuity commencing on the Participant’s Normal Retirement Date. If payment of a Participant’s Mid-Career Hire Benefit commences or is paid before their Normal Retirement Date, the benefit amount calculated pursuant to this paragraph (a) shall be reduced for early commencement in accordance with the early retirement reduction factors applicable to calculation of the Participant’s benefit under the Final Average Pay Component.

For Final Average Pay Component Participants who incur a Separation from Service after December 31, 2011, the additional years of Credited Service shall be applied to the 7-year final average pay formula for the Qualified Benefit and Reinstatement Benefit.

(b) Cash Balance Component Participant. The Mid-Career Hire Benefit payable to a Cash Balance Component Participant shall be equal to the excess of (i) over (ii) where:

(i) Is the sum of (A) the amount of the Qualified Benefit, and (B) the amount of Reinstatement Benefit to which the Participant would have been entitled as of their Benefit Commencement Date if such benefits were computed using the additional years of Credited Service; and

(ii) Is the sum of: (A) the Qualified Benefit, and (B) Reinstatement Benefit as of their Benefit Commencement Date.

The Mid-Career Hire Benefit shall be calculated as of a single life annuity commencing on the Participant’s Benefit Commencement Date.

The additional years of Credited Service shall be credited as of the Cash Balance Component Participant’s date of hire once they become effective pursuant to individual agreement under which they were granted.

2.3    Form Payment.

(a) The Mid-Career Hire Benefit payable to a Participant shall be paid as follows:

(i) If the Participant’s Separation from Service occurs prior to Retirement, the Mid-Career Hire Benefit shall be paid in a lump sum distribution (the lump sum amount shall be based on a deferred to age 65 lump sum factor).

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(ii) Except as provided in subsection (c), if the Participant’s Separation from Service occurs on or after their Retirement, the Participant may elect to have the Mid-Career Hire Benefit paid in the form of a single life annuity or a joint and survivor annuity.

(A) The single life annuity option is an annuity providing equal monthly payments for the lifetime of the Participant with no survivor benefits.

(B) The joint and survivor annuity option is a reduced monthly benefit payable to the Participant for life and to a Beneficiary for the lifetime of the Beneficiary in an amount equal to 50 percent, 75 percent, or 100 percent (as elected by the Participant) of the amount payable during the Participant’s lifetime. The pop-up rules under the Qualified Plan shall apply.

(b) A Participant election as to an annuity form of payment pursuant to paragraph (a)(ii) shall also apply to any benefits payable to the Participant under the Reinstatement Plan and the Limited Benefit. If a Participant fails to make a timely election, their Mid-Career Hire Benefit shall be paid in the form of:

(i) A single life annuity, if they are not married as of their Benefit Commencement Date; or

(i) A 50 percent joint and survivor annuity with their spouse as Beneficiary, if they are married as of their Benefit Commencement Date. The pop-up rules under the Qualified Plan shall apply.

If a Participant elects a joint and survivor annuity, but their Beneficiary dies before the Participant’s Benefit Commencement Date, the Participant’s Mid-Career Hire Benefit shall be paid in the form of a single life annuity unless the Participant validly elects a new form of payment pursuant to this subsection.

(c) Notwithstanding paragraphs (a) and (b), if the Participant’s total vested benefit under the SERP and the Reinstatement Plan, as presently valued at the time of commencement of the payment of such benefit, does not exceed $30,000, benefits under the SERP and the Reinstatement Plan shall be paid in a single lump sum distribution. If the Participant does not meet the criteria for Retirement, the lump sum amount shall be based on the deferred to age 65 lump sum factor. If the Participant does meet the criteria for Retirement, the lump sum amount shall be based on the immediate lump sum factor.

2.4    Timing of Payment. Except as otherwise provided, payment of a Participant’s Mid-Career Hire Benefit shall commence or shall be paid within the 90-day period following Benefit Commencement Date, but in no event later than the last day permitted under Section 409A of the

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Code for treating a delayed payment as having been made on such payment date. If a Mid-Career Hire Benefit is payable as a lump sum, no interest shall be paid to the Participant for the period between the Benefit Commencement Date and the actual payment date, except as provided for below with respect to Specified Employees.

If the Participant is a Specified Employee, payment of the Participant’s Mid-Career Hire Benefit shall actually commence or shall be paid as of the last day of the month coinciding with or next following the six-month anniversary of the Participant’s Separation from Service. In any case where the payment of benefits is delayed pursuant to this paragraph, the Participant’s Mid-Career Hire Benefit shall be calculated as of the Benefit Commencement Date. Any annuity payments to which the Participant would be entitled during the first six months after their Separation from Service shall be accumulated and paid to the Participant without interest as of the last day of the month coinciding with or next following the six-month anniversary of their Separation from Service. If the Participant’s Mid-Career Hire Benefit is payable in the form of a lump sum distribution, the benefit shall be increased with interest at the rate of:

(a) The first segment rate as determined pursuant to Section 417(e)(3)(C) and (D) of the Code for the second month preceding the first day of the Plan Year in which the Separation from Service occurs; or

(b) 6 percent, in the case of a Participant who is a participant in the Cash Balance Component.

Payment of the Participant’s Mid-Career Hire Benefit shall not be delayed or accelerated, except as provided in this subsection. If the Employee Benefits Committee determines that a delay or acceleration of a Participant’s Mid-Career Hire Benefit complies with the requirements of Section 409A of the Code (including an acceleration to pay employment taxes), the Employee Benefits Committee may either delay or accelerate the payment of the Mid-Career Hire Benefit in accordance with the terms of Section 409A of the Code as it deems advisable in its sole discretion. If any payment is delayed in accordance with this paragraph, the SERP shall pay such delayed payments without interest following the expiration of the delay.

2.5     A Mid-Career Hire Benefit which is payable in any form other than a single life annuity shall be the actuarial equivalent of the Mid-Career Hire Benefit set forth in Section 2.4 of the SERP, as determined by the same actuarial adjustments as those specified in the Qualified Plan, as applicable, with respect to determination of the amount of Qualified Benefit as of the Benefit Commencement Date, except as necessary to comply with Section 409A of the Code.

2.6     If a Participant who is receiving annuity payments under the SERP is rehired, such annuity payments shall continue during the period of reemployment. Since the Mid-Career Hire Benefit is closed to participation as of January 1, 2011, Participants rehired after such date shall not accrue an additional Mid-Career Hire Benefit.

2.7     Mid-Career Hire Surviving Spouse Benefit.    

(a) Final Average Pay Component Participant. If a married Participant dies prior to commencement of payment of their Mid-Career Hire Benefit, a Mid-Career Hire

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Surviving Spouse Benefit shall be payable to the Participant’s Surviving Spouse. The Mid-Career Hire Surviving Spouse Benefit shall be equal to the excess of (i) over (ii) where:

(i) Is the sum of: the amount of the Qualified Plan Surviving Spouse Benefit and the amount of Reinstatement Plan Surviving Spouse Benefit to which the Surviving Spouse would have been entitled under those plans, as of the Participant’s Normal Retirement Date if such benefits were computed with the additional years of Credited Service; and

(ii) Is the sum of the Qualified Plan Surviving Spouse Benefit Surviving Spouse Benefit and Reinstatement Plan Surviving Spouse Benefit payable to the Surviving Spouse as of the Participant’s Normal Retirement Date.

If applicable, the Mid-Career Hire Surviving Spouse Benefit shall be reduced for early commencement in accordance with the reduction factors applicable to calculation of a Qualified Plan Surviving Spouse Benefit.

(b) Cash Balance Component Participant. If a Participant dies prior to commencement of payment of their Mid-Career Hire Benefit, a Mid-Career Hire Surviving Spouse Benefit shall be payable to the Participant’s Spouse. The Mid-Career Hire Surviving Spouse Benefit shall be equal to the excess of (i) over (ii) where:

(i) Is the sum of the amount of the Cash Balance Component account and the amount of Reinstatement Plan Surviving Spouse Benefit to which the Surviving Spouse would have been entitled under the Qualified Plan and the Reinstatement Plan, as of the Participant’s Normal Retirement Date if such benefits were computed with the additional years of Credited Service; and

(ii) Is the sum of the Qualified Surviving Spouse Benefit and the Reinstatement Plan Surviving Spouse Benefit payable to the Surviving Spouse as of the Participant’s Normal Retirement Date.

2.8    The Mid-Career Hire Surviving Spouse Benefit shall be paid as follows:

(a) If the Participant’s death occurs prior to Retirement, the present value of the Mid-Career Hire Surviving Spouse Benefit shall be paid in a single lump sum distribution.

(b) If the Participant’s death occurs on or after Retirement, the Mid-Career Hire Surviving Spouse Benefit shall be payable in monthly installments over the life of the Surviving Spouse. Notwithstanding the preceding sentence, if the present value of the total benefit payable to the Surviving Spouse under the SERP and the Reinstatement Plan does not exceed $20,000, the benefit payable shall be made in a single lump sum distribution.

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2.9    Payment of the Mid-Career Hire Surviving Spouse Benefit shall commence or shall be paid as of the last day of the month in which the Participant’s death occurs and within 90 days after such date, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date.

2.10    With respect to Participants who had a Separation from Service prior to January 1, 2005, the provisions of the SERP as of December 31, 2004 regarding the timing and form of payment of Mid-Career Hire Benefits or Mid-Career Hire Surviving Spouse Benefits shall apply. The timing and form of payment of such Mid-Career Hire Benefits or Mid-Career Hire Surviving Spouse Benefits are linked to the timing and form of payment of the Qualified Benefits. As such, the SERP is considered “grandfathered” under Section 409A of the Code.

Section 3. Limited Benefits

3.1    Each Employee nominated by the CEO and designated by the Employee Benefits Policy Committee shall be a Schedule B Participant and shall be eligible to a Limited Benefit provided for in this Section 3 of the SERP. The CEO shall nominate such select and key Employees based upon such criteria as they shall deem appropriate due to the Employee’s responsibilities and opportunity to contribute substantially to the financial and operating objectives of PSEG. The names of all Participants designated hereunder shall be listed in Schedule B to the SERP.

3.2    If a Schedule B Participant dies while in the active employment of PSEG or an Affiliate, the Participant’s Beneficiary will receive an amount equal to 150% of the annual rate of salary of the Participant in effect at the date of death, adjusted to the nearest $1,000. Payment shall be made in a lump sum as of the first day of the month following the Participant’s date of death, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date.

3.3    At Retirement, each Schedule B Participant will be eligible for a Limited Benefit calculated as provided in this Section 3 of the SERP.

Notwithstanding any other provision of the SERP to the contrary, the Limited Benefit hereunder payable to Frederick W. Lark and Richard D. Quinn, III, each of whom commenced a phased retirement during 2008, shall be calculated as of December 31, 2008 and shall be paid commencing as of January 31, 2009.

3.4    The Limited Benefit shall be calculated as follows:

(a)    Final Average Pay Component Participants:

(i) The Participant’s Compensation shall be multiplied by an amount equal to one one-hundredth of the sum of (x) the number of the Participant’s years of Credited Service under the Final Average Pay Component at Retirement (including any additional years of age and Credited Service provided to the Participant in accordance with any employment, change in control, or similar arrangement applicable to the Participant so long as the

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Participant incurs a Separation from Service from PSEG and its Affiliates during the two-year period commencing upon the date of a Change in Control), (y) the number of any additional years of Credited Service credit to which the Participant may be entitled under Section 2 of the SERP or any written arrangement with PSEG or an Affiliate (excluding any written arrangement between PSEG or an Affiliate and the Participant relating to a Change in Control), and (z) 30; but, in no event, shall the multiple be greater than 0.75.

(ii) The amount determined under subparagraph (i) of this Section 3.4(a) shall be reduced by the sum of (x) the amount the Participant would be entitled to at Retirement as an annual pension benefit under the Final Average Pay Component, Section 2 of the SERP and the Reinstatement Plan calculated as a single life annuity payable at the Participant’s Normal Retirement Date without reduction for any pre-retirement survivor’s option coverage or any reduction for early retirement, (y) 100% of the amount of the unreduced annual Social Security benefit to which the Participant would be entitled at age 65 (or such other age which may be established by the Social Security Administration from time to time as the earliest age at which a Participant may receive an unreduced benefit thereunder), assuming that the Participant has no earnings from the date of Retirement to age 65 (or such other applicable age), or, if greater, any disability benefit under Social Security to which the Participant may be entitled, and (z) the aggregate of the annual benefits to which the Participant is entitled under all Retirement Plans as of the date the Participant is employed by PSEG or an Affiliate, such Social Security Benefits and benefits under all Retirement Plans to be calculated as single life annuities without any reductions, under rules, procedures and equivalents determined by the Employee Benefits Committee. To determine the amounts referred to under (y) and (z) above, the Participant shall file a declaration of all such amounts with the Corporate Benefits Department in such form as the Employee Benefits Committee may require from time to time. No benefit shall be paid under the SERP until such a declaration, in satisfactory form, shall be so filed. If a Participant is granted a disability Social Security benefit, they shall notify the Corporate Benefits Department thereof within 30 days thereof, and the Participant’s retirement benefit under this section of the SERP shall be adjusted accordingly. The Company shall be entitled to rely on such statements in making payment, and if any such statement is incorrect or is not furnished, the Company shall be entitled to reimbursement from the Participant, the Beneficiary or their legal representatives for any overpayment and may reduce or suspend future payments to recover any such overpayment. In the event it is established to the satisfaction of the Employee Benefits Committee, in its sole discretion, that any such statement was intentionally false or omitted, the Participant or Beneficiary shall be entitled to no further payments under this section of the SERP, and the Company shall be entitled to recover any payments made hereunder.

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(iii) For Participants who incur a Separation from Service after December 31, 2011, the number of any additional years of Credited Service granted to a Participant under Subsection 3.4(a)(i)(y) of the SERP that a Participant may be entitled under Section 2 of the SERP or any written arrangement with PSEG or an Affiliate shall be applied to the 7-year final average pay formula. The 30 points credited to a Participant under Subsection 3.4(a)(i)(z) of the SERP shall be prorated based on the number of actual years of Credited Service that a Participant has as of December 31, 2011 and has during the period beginning on January 1, 2012 and ending on the date they incur a Separation from Service, without regard to any additional years of Credited Service granted to the Participant under Subsection 3.4(a)(i)(y) and without regards to any cap on Credited Service.

(b)    Cash Balance Component Participants:

(i) The Participant’s Compensation shall be multiplied by an amount equal to one one-hundredth of the sum of (x) the number of the Participant’s years of Credited Service under the Final Average Pay Component with which such Participant would have been credited at Retirement had the Participant participated in the Final Average Pay Component from their date of hire and including any additional years of age and Credited Service provided to the Participant in accordance with any employment, change in control, or similar arrangement applicable to the Participant so long as the Participant incurs a termination of service from PSEG and its Affiliates during the two-year period commencing upon the date of a Change in Control, (y) the number of any additional years of Credited Service to which the Participant may be entitled under Section 3 of the SERP or any written arrangement with PSEG or an Affiliate (excluding any written arrangement between PSEG or an Affiliate relating to a Change in Control) and (z) 30; but, in no event, shall the multiple be greater than 0.75.

(ii) The amount determined under subparagraph (i) of this Subsection 3.4(b) shall be reduced by the sum of (x) the amount the Participant would be entitled to at Retirement as an annual pension benefit under the Cash Balance Component, Section 2 of the SERP and the Reinstatement Plan calculated as a single life annuity payable at the Participant’s Normal Retirement Date,(y) 100% of the amount of the unreduced annual Social Security benefit to which the Participant would be entitled at age 65 (or such other age which may be established by the Social Security Administration from time to time as the earliest age at which a Participant may receive an unreduced benefit thereunder), assuming that the Participant has no earnings from the date of Retirement to age 65

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(or such other applicable age), or, if greater, any disability benefit under Social Security to which the Participant may be entitled, and (z) the aggregate of the annual benefits to which the Participant is entitled under all Retirement Plans as of the date the Participant is employed by PSEG or an Affiliate, such Social Security Benefits and benefits under all Retirement Plans to be calculated as single life annuities without any reductions, under rules, procedures and equivalents determined by the Employee Benefits Committee. To determine the amounts referred to under (y) and (z) above, the Participant shall file a declaration of all such amounts with the Corporate Benefits Department in such form as the Employee Benefits Committee may require from time to time. No benefit shall be paid under the SERP until such a declaration, in satisfactory form, shall be filed. If a Participant is granted a disability Social Security benefit, they shall notify the Corporate Benefits Department thereof within 30 days thereof, and the Participant’s retirement benefit under the SERP shall be adjusted accordingly. The Company shall be entitled to rely on such statements in making payment, and if any such statement is incorrect or is not furnished, the Company shall be entitled to reimbursement from the Participant, the Beneficiary or their legal representatives for any overpayment and may reduce or suspend future payments to recover any such overpayment. In the event it is established to the satisfaction of the Employee Benefits Committee, in its sole discretion, that any such statement was intentionally false or omitted, the Participant or Beneficiary shall be entitled to no further payments under this section of the SERP, and the Company shall be entitled to recover any payments made hereunder.

(iii) For Participants who incur a Separation from Service after December 31, 2011, the number of any additional years of Credited Service granted to a Participant under Subsection 3.4(b)(i)(y) of the SERP that a Participant may be entitled under Section 2 of the SERP or any written arrangement with PSEG or an Affiliate shall be applied to the 7-year final average pay formula. The 30 points credited to a Participant under Subsection 3.4(b)(i)(z) of the SERP shall be prorated based on the number of actual years of Credited Service that a Participant has as of December 31, 2011 and has during the period beginning on January 1, 2012 and ending on the date they incur a Separation from Service, without regard to any additional years of Credited Service granted to the Participant under Subsection 3.4(b)(i)(y) and without regards to any cap on Credited Service.

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3.5 Forms of Payment.

(a) The annual amount determined under Section 3.4 shall be paid in the form of a life annuity; either a single life annuity or a joint and survivor annuity, as elected by the Participant.

(a) The single life annuity option is an annuity providing equal monthly payments for the lifetime of the Participant with no survivor benefits.

(i) The joint and survivor annuity option is a reduced monthly benefit payable to the Participant for life and to a surviving named Beneficiary for the lifetime of the Beneficiary in an amount equal to 50%, 75%, or 100% (as elected by the Participant) of the amount payable during the Participant’s lifetime.

Notwithstanding the preceding provisions, if the present value of the Participant’s total vested benefit under the Reinstatement Plan and the SERP does not exceed $30,000, their Limited Benefit shall be paid a single lump sum distribution. The lump sum amount shall be based on the immediate lump sum factor.

(b) A Participant may elect an annuity form of payment pursuant to paragraph (a) at any time before their Benefit Commencement Date. If a Participant fails to make a timely election, their retirement benefit shall be paid in the form of:

(i) A single life annuity, if they are not married as of their benefit commencement date; or

(ii) A 50 percent joint and survivor annuity with their spouse as Beneficiary, if they are married as of their benefit commencement date.

(c) Except as otherwise provided in this paragraph (c), payment of a Participant’s Limited Benefit shall commence or be paid within the 90-day period following Benefit Commencement Date, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date.

If the Participant is a Specified Employee, payment of the Participant’s Limited Benefit shall commence or shall be made as of the last day of the month coinciding with or next following the six-month anniversary of the Participant’s Retirement date. In any case where the payment of benefits is delayed pursuant to this paragraph, the Participant’s Limited Benefit shall be calculated as of the Participant’s Benefit Commence Date. Any annuity payments to which the Participant would be entitled during the first six months after their Retirement shall be accumulated and paid to the Participant without interest as of the last day of the month coinciding with or next following the six‑month anniversary of their Retirement.

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If the Participant’s Limited Benefit is payable in the form of a lump sum distribution, the benefit shall be increased with interest at the first segment rate as determined pursuant to Section 417(e)(3)(C) and (D) of the Code for the second month preceding the first day of the Plan Year in which the Retirement occurs.

Payment of the Participant’s benefit shall not be delayed or accelerated, except as provided in this subsection. If the Employee Benefits Committee determines that a delay or acceleration of a Participant’s benefit complies with the requirements of Section 409A of the Code (including an acceleration to pay employment taxes), the Employee Benefits Committee may either delay or accelerate the payment of the benefit in accordance with the terms of Section 409A of the Code as it deems advisable in its sole discretion. If any payment is delayed in accordance with this paragraph, the SERP shall pay such delayed payments without interest following the expiration of the delay.

(d) If a Participant earns a Limited Benefit after a Retirement, any annuity benefits being paid to the Participant shall be increased to reflect such additional accruals as of the January 1 following the Plan Year in which such Limited Benefit accrues. If the Participant received a lump sum distribution of their Limited Benefit as of the earlier Retirement, the value of the additional accruals shall be paid to them in a lump sum distribution as of the January 1 following the Plan Year in which such additional benefit accrues.

Notwithstanding the foregoing, if a Participant named in Subsection 3.3 earns an additional retirement benefit after December 31, 2008, the additional accruals shall be payable as of the Participant’s Retirement as otherwise provided in this Section 3.

3.6    With respect to Participants who had a Separation from Service prior to January 1, 2005, the provisions of the SERP as of December 31, 2004 regarding the timing and form of payment of Limited Benefits shall apply. The timing and form of payment of such Limited Benefits are linked to the timing and form of payment of the Qualified Benefits. As such, the SERP is considered “grandfathered” under Section 409A of the Code.

Section 4. Administration of the SERP

4.1     The Employee Benefits Committee shall be the named fiduciary of the SERP responsible for the general operation and administration of the SERP and for carrying out the provisions thereof. The Employee Benefits Committee shall have discretionary authority to construe the terms of the SERP and shall be the final arbiter of any questions that may arise under the SERP.

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4.2     The Employee Benefits Committee shall adopt such rules and procedures as it deems necessary and advisable to administer the SERP and to transact its business. Subject to the other requirements of this Section 4, the Employee Benefits Committee may:

(a) Employ agents to carry out non‑fiduciary responsibilities;

(b) Employ agents to carry out fiduciary responsibilities (other than trustee responsibilities as defined in Section 405(c)(3) of ERISA);

(c) Consult with counsel, who may be counsel to PSEG or an Affiliate; and

(d) Provide for the allocation of fiduciary responsibilities (other than trustee responsibilities as defined in Section 405(c)(3) of ERISA) among its members.

However, any action described in paragraphs (b) or (d) of this Subsection 4.2, and any modification or rescission of any such action, may be effected by the Employee Benefits Committee only by a resolution approved by a majority of the Employee Benefits Committee. The Employee Benefits Committee shall be entitled to rely conclusively upon all tables, valuations, certificates, opinions and reports furnished by any actuary, accountant, controller, counsel or other person employed or engaged by the Employee Benefits Committee with respect to the SERP.

4.3    The Employee Benefits Committee shall keep written minutes of all its proceedings, which shall be open to inspection by the Board of Directors. In the case of any decision by the Employee Benefits Committee with respect to a claim for benefits under the SERP, such Employee Benefits Committee shall include in its minutes a brief explanation of the grounds upon which such decision was based.

4.4     In performing their duties, the members of the Employee Benefits Committee shall act solely in the interest of the Participants in the SERP and their Beneficiaries and

(a) For the exclusive purpose of providing benefits to Participants and their Beneficiaries;

(b) With the care, skill, prudence and diligence under the circumstances then prevailing that a prudent person acting in like capacity and familiar with such matters would use in the conduct of an enterprise of alike character and with like aims; and

(c) In accordance with the documents and instruments governing the SERP insofar as such documents and instruments are consistent with the provisions of Title I of ERISA.

4.5     In addition to any other duties the Employee Benefits Committee may have, the Employee Benefits Committee shall review the performance of all persons to whom the

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Employee Benefits Committee shall have delegated or allocated fiduciary duties pursuant to the provisions of this Section 4.

4.6     The Company agrees to indemnify and reimburse, to the fullest extent permitted by law, members of the Employee Benefits Committee, directors and employees of PSEG and its Affiliates, and all such former members, directors and employees, for any and all expenses, liabilities or losses arising out of any act or omission relating to the rendition of services for or the management and administration of the SERP.

4.7     No member of the Employee Benefits Committee nor any delegee thereof shall be personally liable by virtue of any contract, agreement or other instrument made or executed by them or on their behalf in such capacity.

Section 5. Claims Procedure and Status Determination

5.1    Claims for benefits under the SERP and requests for a status determination shall be filed in writing with the Employee Benefits Committee or its delegee.

5.2     In the case of a claim for benefits, written notice shall be given to the claiming Participant or Beneficiary of the disposition of such claim, setting forth specific reasons for any denial of such claim in whole or in part. If a claim is denied in whole or in part, the notice shall state that such Participant or Beneficiary may, within sixty days of the receipt of such denial, request in writing that the decision denying the claim be reviewed by the Employee Benefits Committee and provide the Employee Benefits Committee with information in support of their position by submitting such information in writing to the Secretary of the Employee Benefits Committee.

5.3     The Employee Benefits Committee shall review each claim for benefits which has been denied in whole or in part and for which such review has been requested and shall notify, in writing, the affected Participant or Beneficiary of its decision and the reasons therefor.

5.4     In the case of a request for status determination, written notice shall be given to the requesting person within a reasonable time setting forth specific reasons for the decision.

Section 6. Amendment or Termination

6.1     PSEG reserves the right to amend or terminate the SERP when, in the sole opinion of PSEG, such amendment or termination is advisable. Any such amendment or termination shall be made pursuant to a resolution of the Board or of the Employee Benefits Policy Committee and shall be effective as provided for in such resolution.

6.2     No amendment or termination of the SERP shall directly or indirectly deprive any current or former Participant, Beneficiary or Surviving Spouse of a previously acquired right unless such Participant or Beneficiary or legal representative shall consent to such change. Provided, further, however, that after a Change in Control, the SERP may not be terminated nor the benefit calculation reduced with respect to any Participant in the SERP on the date of such

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Change in Control unless such Participant or their Beneficiary or their legal representative shall consent to such change. No right to a death benefit under Section 3 of the SERP shall accrue until a Schedule B Participant’s death and no right to a Limited Benefit under Section 3 of the SERP shall accrue until a Schedule B Participant’s Retirement.

6.3    In the event of the termination of the SERP, vested benefits hereunder shall be distributed in a single lump sum as soon as practicable after the date the SERP is terminated if such distribution is permitted because the SERP is terminated in accordance with the termination provisions of Section 409A of the Code and related regulations or, in other cases, at the earliest time otherwise permitted under the terms of the SERP in accordance with Section 409A of the Code and related regulations.

Section 7. General Provisions

7.1    The SERP at all times shall be entirely unfunded and no provision shall at any time be made with respect to segregating any assets of PSEG or any Affiliate for payment of any benefits hereunder. No Participant, Beneficiary, Surviving Spouse or any other person shall have any interest in any particular assets of PSEG or any Affiliate by reason of the right to receive a benefit under the SERP and any such Participant, Beneficiary, Surviving Spouse or other person shall have only the rights of a general unsecured creditor with respect to any rights under the SERP.

7.2    Except as otherwise expressly provided herein, all terms and conditions of the Qualified Plan applicable to a Qualified Benefit or a Qualified Surviving Spouse Benefit shall also be applicable to a SERP Benefit or a SERP Surviving Spouse Benefits payable hereunder. Any Qualified Benefit or Qualified Surviving Spouse Benefit, or any other benefit payable under the Qualified Plan shall be paid solely in accordance with the terms and conditions of the Qualified Plan and nothing in the SERP shall operate or be construed in any way to modify, amend or affect the terms and provisions of the Qualified Plan.

7.3     Nothing contained in the SERP shall constitute a guaranty by the Company or any other entity or person that the assets of PSEG or any Affiliate will be sufficient to pay any benefit hereunder.

7.4     No Participant or Surviving Spouse shall have any right to a benefit under the SERP except in accordance with the terms of the SERP. The payment of any death or survivorship benefit under the SERP shall be contingent upon such evidence of death as may be reasonably required by the Employee Benefits Committee.

7.5     The SERP shall not constitute a contract for the continued employment of any Participant by the Company or any Affiliate. PSEG and each Affiliate reserve the right to modify a Participant’s Compensation at any time and from time to time as it considers appropriate and to terminate any Participant’s employment for any reason at any time notwithstanding the SERP.

7.6     No interest of any person or entity in, or right to receive a benefit under, the SERP shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment or

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other alienation or encumbrance of any kind; nor any such interest or right to receive a benefits be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings.

7.7     The SERP shall be construed and administered under the laws of the United States and the State of New Jersey to the extent not superseded by Federal law. The SERP is specifically intended to comply with the provisions of Section 409A of the Code and it shall automatically incorporate all applicable restrictions of Section 409A of the Code and its related regulations, and PSEG will amend the SERP to the extent necessary to comply with those requirements. The timing under which a Participant will have a right to receive any payment under the SERP will be deemed to be automatically modified, and a Participant’s rights under the SERP limited to conform to any requirements under Section 409A of the Code.

7.8     Actuarial assumptions to determine the present value of any benefit hereunder shall be the same as used to determine the present value of benefits under the Qualified Plan.

7.9     If any person entitled to a benefit payment under the SERP is deemed by the Employee Benefits Committee to be incapable of personally receiving and giving a valid receipt for such payment, then, unless and until claim therefor shall have been made by a duly appointed guardian or other legal representative of such person, the Employee Benefits Committee may provide for such payment or any part thereof to be made to any other person or institution then contributing toward or providing for the care and maintenance of such person. Any such payment shall be a payment for the account of such person and a complete discharge of any liability of the Company and the SERP therefor.

7.10     The SERP shall inure to the benefit of and be binding upon the Company, its successors and assigns, including but not limited to any corporation which may acquire all or substantially all of the Company’s assets or businesses or with or into or which the Company may be consolidated or merged.

7.11    Any notice to a Participant, a Beneficiary or any legal representative hereunder shall be given in writing, by personal delivery, overnight express service or by United States mail, postage prepaid, addressed to such person’s last known address. Any notice to the Company or the Employee Benefits Committee hereunder (including the filing of beneficiary designations) shall be given by delivering it in person or by overnight express service, or depositing it in the United States mail, postage prepaid, to the Secretary of the Employee Benefits Committee, Public Service Enterprise Group Incorporated, 80 Park Plaza, T-5, P.O. Box 1171, Newark, New Jersey, 07101.    

7.12    Each Participant shall keep the Company informed of their current address and the current address of their spouse. The Company shall not be obligated to search for the whereabouts of any person. If the location of a Participant is not made known to the Company within three (3) years after the date on which payment of the Participant’s SERP Benefit may first be made, payment may be made as though the Participant had died at the end of the three‑year period. If, within one additional year after such three‑year period has elapsed, or,

24

within three years after the actual death of a Participant, the Company is unable to locate any Surviving Spouse of the Participant, then the Company shall have no further obligation to pay any benefit hereunder to such Participant or Surviving Spouse or any other person and such benefit shall be irrevocably forfeited.

7.13    Failure by the Company or the Employee Benefits Committee to insist upon strict compliance with any of the terms, covenants or conditions hereof shall not be deemed a waiver of any such term, covenant or condition, nor shall any waiver or relinquishment of any right or power hereunder at any one or more times be deemed a waiver or relinquishment of any such right or power at any other time or times.

7.14    The invalidity or unenforceability of any provision hereof shall in no way affect the validity or enforceability of any other provision of the SERP.

7.15     Notwithstanding any of the preceding provisions of the SERP, the Company, the Employee Benefits Committee or any individual acting as an employee or agent of the Company or the Employee Benefits Committee shall be liable to any Participant, former Participant, Surviving Spouse or any other person for any claim, loss, liability or expense incurred in connection with the SERP.

Section 8. Miscellaneous

8.1    As used herein, words in the masculine gender shall include the feminine and the singular shall include the plural, and vice versa, unless otherwise required by the context. Any headings used herein are included for ease of reference only and are not to be construed so as to alter the terms hereof.

*    *    *

_/s/ Margaret M Pego_                        ___July 10, 2017

Signature                                 Date

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MID-CAREER HIRE BENEFITS

SCHEDULE A

PARTICIPANTS

1. Edwin Eilola              Director Projects

2. Davison, Paul J.             VP Nuclear Engineering

3. Izzo, Ralph                Chairman of Board, President & CEO-PSEG

4. Knaide, Kenneth M.            Sr. Dir. Engineering

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LIMITED BENEFITS

SCHEDULE B

PARTICIPANTS

1. Bishop, Craig, J.             Sr. Director - IT Infrastructure & Ops

2. Cardenas, Jorge L.          VP-Asset Mgmt & Centralized Srvs

3. Castellano, Raymond C.         Mgr Application Support

4. Doherty, John F.                Associate Gen. Environ. Counsel

5. Izzo, Ralph                 Chairman of Board, President & CEO-PSEG

6. Krueger, Jr. Robert C.            VP - Assistant Controller - Tax

7. LaRossa, Ralph A.             President & COO PSE&G & COB PSEG LI

8. Leibowitz, Donald S.             Associate Gen. Corp Counsel

9. Levis, William (eff. 1/16/13)        President & COO

10. Leyden, Shawn P.             VP & Deputy General Counsel

11. MacDonald, Joan C.             Project Mgr.

12. Mack, Ronald J.             Exec. Director Medical

13. Mnich, Lorraine                Mgr. Corp Capital Invest

14. Orticelle, Arthur (retired 4/1/17)     Division Manager - Electric

15. Oster, Steven B.             Dir. Asset Portfolio

16. Pego, Margaret M.            SVP - HR & Chief HR Officer

17. Quinn, Kevin J.              VP - Finance Power         

18. Scarlata, John P. (retired 34/4/17_    VP - Gas Supply

19. Schroeder, Brian H.            Principal Enterprise Architect

20. Sugam, Richard J.             Dir. EH&S Compliance & Planning

21. Tripodi, Raymond A.            Mgr. Transmission Permitting

22. Tuosto, Michael R.            General Manager Public Affairs

23. Wernsing, Richard W.            Dir. Strategic Rel & Delivery Planning

24. Weyant, Donald W.            Mgr. Regulatory Compliance

EX-10.2

Exhibit 10.2

RETIREMENT INCOME REINSTATEMENT PLAN

FOR NON‑REPRESENTED EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

Amended January 1, 2017

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RETIREMENT INCOME REINSTATEMENT PLAN

FOR NON‑REPRESENTED EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

Public Service Electric and Gas Company (“PSE&G”) had established, effective January 1, 1995, the Retirement Income Reinstatement Plan for Non‑Represented Employees of Public Service Electric and Gas Company and its Affiliates. Effective December 13, 1999, PSE&G transferred sponsorship of the plan to Public Service Enterprise Group Incorporated (“PSEG”) and renamed the plan the Retirement Income Reinstatement Plan for Non‑Represented Employees of Public Service Enterprise Group Incorporated and its Affiliates (“Reinstatement Plan”).

The Reinstatement Plan was established for the purpose of assisting in attracting and retaining a stable pool of key managerial and professional talent and long‑term key employee commitment by providing certain supplemental retirement benefits for certain of their employees who participate in a Qualified Plan.

The Reinstatement Plan is intended to constitute an unfunded “excess benefit plan” as defined in Section 3(36) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), to the extent it provides benefits that would be paid under the Pension Plan but for the limitations of Section 415 of the Internal Revenue Code of 1974, as amended (“Code”), and an unfunded plan of deferred compensation for a select group of management or highly compensated employees for purposes of Title 1 of ERISA, to the extent it provides other benefits.

The Reinstatement Plan was amended, effective as of January 1, 2005, to comply with the requirements of the American Jobs Creation Act of 2004.

The Reinstatement Plan was amended, effective as of January 1, 2009, to provide for lump sum payments of certain benefits, to revise provisions relating to lump sum payments of de minimis benefits, to align the Reinstatement Plan to certain requirements of Section 409A of the Code, and to make certain other style and conforming changes. The terms contained therein superseded all prior iterations of the Reinstatement Plan.

The Reinstatement Plan was amended effective as of January 1, 2012 to reflect the change in the benefit formula under the Pension Plan from a 5-year final average pay formula to a 7-year final average pay formula.

The Reinstatement Plan is being amended effective January 1, 2017 to make certain administrative clarifications.

Section 1. Definitions

When used herein, the words and phrases hereinafter defined shall have the following meanings unless a different meaning is clearly required by the context of the Reinstatement Plan:

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1.1     “Affiliate” shall mean (a) any organization while it is a member of a controlled group of corporations (as defined in Section 414(b) of the Code) which includes PSEG; or (b) any trades or businesses (whether or not incorporated) while they are under common control (as defined in Section 414(c) of the Code) with PSEG.

1.2     “Beneficiary” shall mean any person or persons designated by a Participant who may become eligible to receive benefits provided under this Reinstatement Plan in the event of such Participant’s death.

1.3     “Benefit Commencement Date” shall mean the date that is the Participant’s last day worked plus one day.

1.4     “Board of Directors” or “Board” shall mean the Board of Directors of Public Service Enterprise Group Incorporated.

1.5     “Cash Balance Component” shall mean the Cash Balance Component of the Pension Plan”. The Cash Balance Component was formerly the Public Service Enterprise Group Incorporated Cash Balance Pension Plan.

1.6     “Code” shall mean the Internal Revenue Code of 1986, as amended. A reference to a section of the Code shall also refer to any regulations and other guidance issued under that section.

1.7     “Company” shall mean Public Service Enterprise Group Incorporated and each Participating Affiliate.

1.8     “Compensation” with respect to any Participant shall mean base salary, bonuses (as described below) and overtime up to 20% of base salary. Compensation shall include amounts deferred to the Deferred Compensation Plan for Certain Employees of Public Service Enterprise Group Incorporated and its Affiliates (“Deferred Compensation Plan”). For the period prior to March 5, 2010, refer to the prior Reinstatement Plan document for the definition Compensation.

For purposes of calculating the Reinstatement Benefit payable to a Participant who is a participant in the Cash Balance Component, Compensation shall not include amounts paid prior to 2006 under the Management Incentive Compensation Plan (“MICP”) or the Senior Management Incentive Compensation Plan (“SMICP”). For Participants who are participants in the Cash Balance Component, Compensation for any such year shall not exceed 150 percent of the Participant’s annual base salary in effect as of January 1 of that year.

For clarification purposes, all bonuses paid under the PSEG Power LLC Incentive Compensation Program for PSEG Energy Resources & Trade LLC Employees (“ER&T Plan”), as limited hereunder, the Performance Incentive Plans (PIPs”) and the PSEG Power LLC Incentive Compensation Program for Certain Employees of PSEG Energy Solutions LLC (“Energy Solutions Plan”) are included in Compensation, except those paid under the Long Island Electric Utility ServCo LLC Performance Incentive Plan.

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Bonuses paid under the PIP, Energy Solutions Plan, MICP, SMICP and the ER&T Plan are included in Compensation only if the bonus is paid prior to the date of the Participant’s Separation from Service.

For the year in which the Participant is hired, the base salary in effect as of the date of hire shall be used. For Participants who are rehired, the base salary as of the date of rehire shall be used for determining Compensation of the year of the rehire.

1.9     “Employee” shall mean any individual in the employ of the Company who is not included within a unit of employees covered by a collective bargaining agreement. The term “Employee” shall not include a director of the Company who serves in no capacity other than as a director, a consultant or independent contractor doing work for the Company or a person employed by a consultant or independent contractor doing work for the Company or a Participating Affiliate (regardless of whether a determination is made by the Internal Revenue Service or other governmental agency or court after the individual is engaged to perform such services that the individual is an employee of the Company for the purposes of the Code or otherwise).

1.10     “Employee Benefits Committee” shall mean the Employee Benefits Committee of Public Service Enterprise Group Incorporated.

1.11    “Employee Benefits Policy Committee” shall mean the Employee Benefits Policy Committee of Public Service Enterprise Group Incorporated.

1.12    “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended. A reference to a section of ERISA shall also refer to any regulations and other guidance issued under that section.

1.13    “Final Average Earnings” with respect to a Participant who is entitled to a benefit under the Final Average Pay Component:

(a) And who incurs a Separation from Service before January 1, 2012, shall mean the annual average of the sum of:

(1) The Participant’s highest five years of Compensation, excluding any amounts received as an award under the MICP or the SMICP, without the application of the base pay cap in Section 1.8; and

(2) The MICP or SMICP awards for the five most recent bonus eligible years (including $0 awards) prior to the Participant’s Separation from Service. If a Participant does not have at least five MICP/SMICP awards, the average shall be determined by using the number of bonus (including PIP bonuses, ER&T Plan bonuses and Energy Solutions Plan bonuses) eligible periods during the five most recent years.

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Notwithstanding the foregoing, Final Average Earnings shall not exceed 150 percent of the average of the Participant’s annual base salary in effect as of January 1 for the five years prior to and including the year in which the Participant’s Separation from Service occurs. However, for a Participant who receives an award under the ER&T Plan, Final Average Earnings shall not be less than their Final Average Earnings determined as of December 31, 2006 in accordance with the preceding paragraph, without applying the 150 percent cap in the preceding sentence.

Bonuses paid under the PIP, Energy Solutions Plan, MICP, SMICP and the ER&T Plan are included in Compensation only if the bonus is paid prior to the date of the Participant’s Separation from Service.

(b) With respect to a Participant who incurs a Separation from Service on or after January 1, 2012 and who is entitled to a benefit under the Final Average Pay Component, Final Average Earnings shall mean:

(1) With respect to periods of service prior to January 1, 2012, Final Average Earnings shall be determined in accordance with subsection (a) above, except that Separation from Service shall be replaced with December 31, 2011.

(2) With respect to periods of service after December 31, 2011, the annual average of the sum, (i) the Participant’s highest seven years of Compensation beginning after December 31, 2011, excluding any MICP and SMICP awards, and (ii) the MICP or SMICP awards for the seven most recent years (including $0 awards) beginning after December 31, 2011 and prior to the Participant’s Separation from Service, without the application of the base pay cap in Section 1.8. If a Participant does not have at least seven MICP/SMICP awards during the seven most recent years after 2011, the average shall be determined by using the number of bonus (including PIP bonuses, ER&T Plan bonuses and Energy Solutions Plan bonuses) eligible periods after 2011 during the seven most recent years.

Notwithstanding the foregoing, Final Average Earnings shall not exceed 150 percent of the average of the Participant’s annual base salary in effect as of January 1 for the seven years prior to and including the year in which the Participant’s Separation from Service occurs (the annual base salary prior to January 1, 2012 shall not be used in such determination).

Bonuses paid under the PIP, Energy Solutions Plan, MICP, SMICP and the ER&T Plan are included in Compensation only if the bonus is paid prior to the date of the Participant’s Separation from Service.

1.14     “Final Average Pay Component” shall mean the Final Average Pay Component of the Pension Plan.

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1.15    “Normal Retirement Date” shall mean the first day of the month coinciding with or next following a Participant’s attainment of age 65. In the case of a Participant who is still employed beyond age 65, Normal Retirement Date shall mean the first day of the month coinciding with or next following the date on which the Participant’s Separation from Service occurs.

1.16    “Participant” shall mean any Employee or former Employee of the Company who meets the requirements of Subsection 2.1 of the Reinstatement Plan.

1.17    “Participating Affiliate” shall mean any Affiliate of PSEG which (a) is the sponsor or a Participating Affiliate of the Qualified Plan; (b) adopts the Reinstatement Plan with the approval of the Board of Directors; (c) authorizes the Board of Directors and the Employee Benefits Committee to act for it in all matters arising under or with respect to the Reinstatement Plan; and (d) complies with such other terms and conditions relating to the Reinstatement Plan as may be imposed by the Board of Directors. Participating Affiliate shall not include Long Island Electric Utility ServCo LLC.

1.18    “Pension Plan” shall mean the Pension Plan of Public Service Enterprise Group Incorporated and each successor or replacement plan.

1.19    “Qualified Benefit” shall mean the aggregate annual benefit payable to a Participant pursuant to the Qualified Plan, by reason of the Participant’s termination of employment with the Company and all Affiliates for any reason other than death.

1.20    “Qualified Plan” shall mean the Final Average Pay Component or the Cash Balance Component.

1.21 “Qualified Surviving Spouse Benefit” shall mean the aggregate annual benefit payable to the Surviving Spouse of a Participant pursuant to the Qualified Plan, as the case may be, in the event of the death of the Participant at any time prior to commencement of payment of the Qualified Benefit.

1.22     “Plan Year” shall mean the calendar year.

1.23     “Reinstatement Plan” shall mean this Retirement Income Reinstatement Plan for Non--Represented Employees of Public Service Enterprise Group Incorporated and its Affiliates.

1.24    “Retirement” shall be defined as follows:

(a) In the case of a Participant who is a participant in the Final Average Pay Component, Retirement shall mean a Separation from Service either (1) after attaining age 65; (2) when the sum of the Participant’s age and credited service (as defined in the Final Average Pay Component) equals or exceeds 80, or (3) a disability determination under the Final Average Pay Component.

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(b) In the case of a Participant who is a participant in the Cash Balance Component, Retirement shall mean a Separation from Service after either (1) attaining age 65, (2) attaining age 55 and completing five or more years of credited service (as defined in the Cash Balance Component), or (3) a disability determination under the Cash Balance Component.

1.25    “Separation from Service” shall mean, subject to subsections (a) and (b), a Participant’s termination from employment with PSEG and all Affiliates, whether by retirement or resignation from or discharge by PSEG or an Affiliate.

(a) A Separation from Service shall be deemed to have occurred if a Participant and PSEG or any Affiliate reasonably anticipates, based on the facts and circumstances, that either:

(1) The Participant will not provide any additional services for PSEG or an Affiliate after a certain date; or

(2) The level of bona fide services performed by the Participant after a certain date will permanently decrease to no more than 50 percent of the average level of bona fide services performed by the Participant over the immediately preceding 36 months.

(b) If a Participant is absent from employment due to military leave, sick leave, or any other bona fide leave of absence authorized by PSEG or an Affiliate and there is a reasonable expectation that the Participant will return to perform services for PSEG or an Affiliate, a Separation from Service will not occur until the later of:

(1) The first date immediately following the date that is six months after the date that the Participant was first absent from employment; or

(2) The date the Participant no longer retains a right to reemployment, to the extent the Participant retains a right to reemployment with PSEG or any Affiliates under applicable law or by contract.

If a Participant fails to return to work upon the expiration of any military leave, sick leave, or other bona fide leave of absence where such leave is for less than six months, the Separation from Service shall occur as of the date of the expiration of such leave.

1.26    “SERP” shall mean the Supplemental Executive Retirement Income Plan for Non-Represented Employees of Public Service Enterprise Group Incorporated and Its Affiliates.

1.27    “Specified Employee” shall mean an individual who is a key employee (as defined in Section 416(i) of the Code without regard to Section 416(i)(5) of the Code) of PSEG or an Affiliate at any time during the 12-month period ending on each December 31 (the “identification date”). If an individual is a key employee as of an identification date, the

8

individual shall be treated as a Specified Employee for the 12-month period beginning on the April 1 following the identification date. Notwithstanding the foregoing, an individual shall not be treated as a Specified Employee unless any stock of PSEG or an Affiliate is publicly traded on an established securities market or otherwise.

1.28     “Reinstatement Benefit” shall mean the benefit payable to a Participant pursuant to the Reinstatement Plan by reason of the Participant’s Separation from Service with PSEG and all Affiliates for any reason other than death.

1.29     “Surviving Spouse” shall mean a person who is married to a Participant at the date of the Participant’s death.

1.30     “Reinstatement Surviving Spouse Benefit” shall mean the benefit payable to a Surviving Spouse pursuant to the Reinstatement Plan.

Section 2. Eligibility

2.1 An Employee may be eligible for a Reinstatement Benefit under the Reinstatement Plan if:

(a) For a Cash Balance Component participant, the Employee’s Compensation for a Plan Year is in excess of the Section 401(a)(17) limit for such Plan Year;

(b) For a Final Average Pay Component participant, the Employee’s Compensation for a twelve month period used in the Final Average Earnings calculation is in excess of the Section 401(a)(17) limit for such twelve month period.

(c) An Employee’s whose Qualified Benefit exceeds the limit under Section 415(b) of the Code.

(d) An Employee who receives a bonus under the MICP or SMICP, or receives an ER&T Plan bonus above 150% of base pay.

(e) An Employee who pursuant to an individual agreement receives additional years of service that is not taken into account under SERP.

(f) Any other circumstances determined by PSEG.

2.2    The Surviving Spouse of a Participant who dies prior to commencement of payment of their Reinstatement Benefit shall be eligible to receive a Reinstatement Surviving Spouse Benefit under the Reinstatement Plan.

2.3    If a Participant was covered under a collective bargaining agreement prior to becoming an Employee, such Participant’s service, Compensation and Qualified Benefit prior to the date the Participant became an Employee shall not be taken into account for purposes of benefit accrual under the Reinstatement Plan, but shall be taken into account for purposes of vesting and Retirement eligibility.

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Section 3. Reinstatement Benefit

3.1     The Reinstatement Benefit payable to an eligible Participant shall be determined as follows:

(a) A Participant in the Final Average Pay Component who incurs a Separation from Service and who is eligible for a Reinstatement Benefit shall be entitled to receive a benefit as of their Normal Retirement Date equal to the excess of (1) over (2) where:

(1) Is the amount of the Qualified Benefit to which the Participant would have been entitled under the Final Average Pay Component as of their Normal Retirement Date if such benefit were computed by applying the definition of Final Average Earnings under the Reinstatement Plan ; and

(2) Is the amount of the Participant’s Qualified Benefit under the Final Average Pay Component as of their Normal Retirement Date.

(b) This Reinstatement Benefit shall be calculated as a single life annuity commencing on the Participant’s Normal Retirement Date. If payment of a Participant’s Reinstatement Benefit commences or is paid before their Normal Retirement Date, the benefit amount calculated pursuant to paragraph (a) or paragraph (b) shall be reduced for early commencement in accordance with the early retirement reduction factors applicable to calculation of the Participant’s benefit under the Final Average Pay Component.

(c) Notwithstanding any other provision of the Reinstatement Plan to the contrary, the Reinstatement Benefit payable to Frederick W. Lark and Richard D. Quinn, III, shall be calculated as of December 31, 2008 and shall be paid commencing as of January 31, 2009.

(d) A Participant in the Cash Balance Component who is eligible for a Reinstatement Benefit shall be entitled to receive a benefit as of their Benefit Commencement Date equal to the excess of (1) over (2) where:

(1) Is the amount of the Qualified Benefit to which the Participant would be entitled under the Cash Balance Component as of their Benefit Commencement Date if such benefit were computed by applying the definition of Compensation under the Reinstatement Plan; and

(2) Is the amount of the Qualified Benefit payable to the Participant under the Cash Balance Component as of their Benefit Commencement Date.

(e) Notwithstanding any other provision of the Reinstatement Plan to the contrary, a Reinstatement Benefit shall be payable to a Participant in the Final Average Pay Component if the amount of the Participant’s QSERP under the Qualified Plan is

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more than the sum of the Participant’s Qualified Plan and Reinstatement Benefit, absent the QSERP. The amount of the Reinstatement Benefit is the difference between the QSERP amount and the sum of the Participant’s Qualified Plan and Reinstatement Benefit, absent the QSERP.

3.2     The Reinstatement Benefit payable to Participant shall be paid:

(a) If the Participant’s Separation from Service occurs prior to Retirement, the present value of their Reinstatement Benefit shall be paid in a single lump sum distribution (the lump sum amount shall be based on the deferred to age 65 lump sum factor);

(b) Except as otherwise provided in paragraph (d), if the Participant’s Separation from Service occurs on or after their Retirement, the Participant may elect to receive their Reinstatement Benefit in the form of a single life annuity or a joint and survivor annuity.

(1) The single life annuity option is an annuity providing equal monthly payments for the lifetime of the Participant with no survivor benefits.

(2) The joint and survivor annuity option is a reduced monthly benefit payable to the Participant for life and to a surviving named Beneficiary for the lifetime of the Beneficiary in an amount equal to 50 percent, 75 percent, or 100 percent (as elected by the Participant) of the amount payable during the Participant’s lifetime. The pop-up rules under the Qualified Plan shall apply to the Reinstatement Benefit.

(c) A Participant election as to an annuity form of payment pursuant to paragraph (b) shall also apply to any benefits payable to the Participant under the SERP. If a Participant fails to make a timely election, their Reinstatement Benefit shall be paid in the form of:

(1) A single life annuity, if they are not married as of their Benefit Commencement Date; or

(2) A 50 percent joint and survivor annuity with their spouse as Beneficiary, if they are married as of their Benefit Commencement Date. The pop-up rules under the Qualified Plan shall apply to the Reinstatement Benefit.

If a Participant elects a joint and survivor annuity, but their Beneficiary dies before the Participant’s Benefit Commencement Date, the Participant’s Reinstatement Benefit shall be paid in the form of a single life annuity unless the Participant validly elects a new form of payment pursuant to this subsection.

(d) Notwithstanding paragraphs (b) and (c), if the Participant’s total vested benefit under the Reinstatement Plan and the SERP, as presently valued at the time of commencement of the payment of such benefit, does not exceed $30,000, their

11

benefit under the Reinstatement Plan and the SERP shall be paid in a single lump sum distribution. If the Participant does not meet the criteria for Retirement, the lump sum amount shall be based on the deferred to age 65 lump sum factor. If the Participant does meet the criteria for Retirement, the lump sum amount shall be based on the immediate lump sum factor.

3.3     Except as otherwise provided in this subsection, payment of a Participant’s Reinstatement Benefit shall commence or shall be paid within the 90-day period following Benefit Commencement Date, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date. Except as provided for below with respect to Specified Employees, if a Reinstatement Benefit is payable as a lump sum, no interest shall be paid to the Participant for the period between the Benefit Commencement Date and the actual payment date.

If the Participant is a Specified Employee, payment of the Participant’s Reinstatement Benefit shall commence or shall be paid as of the last day of the month coinciding with or next following the six-month anniversary of the Participant’s Separation from Service. In any case where the payment of benefits is delayed pursuant to this paragraph, the Participant’s Reinstatement Benefit shall be calculated as of the Benefit Commencement Date. Any annuity payments to which the Participant would be entitled during the first six months after their Separation from Service shall be accumulated and paid to the Participant without interest as of the last day of the month coinciding with or next following the six-month anniversary of their Separation from Service. If the Participant’s Reinstatement Benefit is payable in the form of a lump sum distribution, the benefit shall be increased with interest at the rate of:

(a) The first segment rate as determined pursuant to Section 417(e)(3)(C) and (D) of the Code for the second month preceding the first day of the Plan Year in which the Separation from Service occurs; or

(b) 6 percent, in the case of a Participant who is a participant in the Cash Balance Component.

Payment of the Participant’s Reinstatement Benefit shall not be delayed or accelerated, except as provided in this subsection. If the Employee Benefits Committee determines that a delay or acceleration of a Participant’s Reinstatement Benefit complies with the requirements of Section 409A of the Code (including an acceleration to pay employment taxes), the Employee Benefits Committee may either delay or accelerate the payment of the Reinstatement Benefit in accordance with the terms of Section 409A of the Code as it deems advisable in its sole discretion. If any payment is delayed in accordance with this paragraph, the Reinstatement Plan shall pay such delayed payments without interest following the expiration of the delay.

3.4     A Reinstatement Benefit which is payable in any form other than a single life annuity, shall be the actuarial equivalent of the Reinstatement Benefit set forth in Subsection 3.1 above as determined by the same actuarial adjustments as those specified in the Qualified Plan, as the case may be, with respect to determination of the amount of the Qualified Benefit as of the

12

Benefit Commencement Date, except as otherwise necessary to comply with Section 409A of the Code.

3.5    If a Participant who is receiving annuity payments under the Reinstatement Plan is rehired, such annuity payments shall continue during the period of reemployment. If such Participant accrues an additional Reinstatement Benefit based on their rehired service, the additional Reinstatement Benefit shall be paid the same annuity form (or, if the Participant had elected a joint and annuity survivor annuity and the Beneficiary had died or the Participant was married and is no longer married on the second Benefit Commencement Date, an actuarially equivalent single life annuity).

If a Participant who received a lump sum from the Reinstatement Plan and was not retirement eligible at that time is rehired, and accrues an additional Reinstatement Benefit based on their rehired service, the additional accrual shall be paid in accordance with this Section 3, provided that the payment is in accordance with Section 409A of Code.

If a Participant who received a lump sum from the Reinstatement Plan and was retirement eligible at that time is rehired, and accrues an additional Reinstatement Benefit based on their rehired service, the additional accrual shall be paid in accordance with this Section 3, provided that the payment is in accordance with Section 409A of Code.

3.6    With respect to Participants who had a Separation from Service prior to January 1, 2005, the provisions of the Reinstatement Plan in effect on December 31, 2004 regarding the timing and form of payment of Reinstatement Benefits shall apply. The timing and form of payment of such Reinstatement Benefits are linked to the timing and form of payment of the Qualified Benefits. As such, the Reinstatement Plan is considered “grandfathered” under Section 409A of the Code.

Section 4. Reinstatement Surviving Spouse Benefit

4.1     If a Participant dies prior to commencement of payment of their Qualified Benefit under circumstances in which a Qualified Plan Surviving Spouse Benefit is payable to their Surviving Spouse, then a Reinstatement Surviving Spouse Benefit shall be payable to their Surviving Spouse as follows:.

(a) In the case of a Participant in the Final Average Pay Component, the Reinstatement Surviving Spouse Benefit shall be determined as of the Participant’s Normal Retirement Date equal to the excess of (1) over (2) where:

(1) Is the amount of the Qualified Plan Surviving Spouse Benefit to which the Surviving Spouse would have been entitled under the Final Average Pay Component if such benefit were computed by applying the definition of Final Average Earnings under the Reinstatement Plan; and

(b) Is the amount of the Qualified Plan Surviving Spouse Benefit under the Final

Average Pay Component.

13

The Reinstatement Surviving Spouse Benefit shall be calculated as a single life annuity commencing on the Participant’s Normal Retirement Date. If payment of the Reinstatement Surviving Spouse Benefit commences or is paid before the Participant’s Normal Retirement Date, the benefit amount calculated pursuant to this paragraph (a) shall be reduced for early commencement, if applicable, in accordance with the reduction factors applicable to calculation of a Qualified Plan Surviving Spouse Benefit.

(b) In the case of a Participant in the Cash Balance Component, the Reinstatement Surviving Spouse Benefit shall be equal to the excess of (1) over (2) where:

(1) Is the amount of the Qualified Plan Surviving Spouse Benefit to which the Surviving Spouse would be entitled under the Cash Balance Component as of the Participant’s date of death if such benefit were computed by applying the definition of Compensation under the Reinstatement Plan; and

(2) Is the amount of the Qualified Plan Surviving Spouse Benefit actually payable to the Surviving Spouse under the Cash Balance Component as of the Participant’s date of death.

4.2     The Reinstatement Surviving Spouse Benefit shall be paid as follows:

(a) If the Participant’s death occurs prior to Retirement, the present value of the Reinstatement Surviving Spouse Benefit shall be paid in a lump sum distribution.

(b) If the Participant’s death occurs on or after Retirement, the Reinstatement Surviving Spouse Benefit shall be payable over the lifetime of the Surviving Spouse in monthly installments until the Surviving Spouse’s death. Notwithstanding the preceding sentence, if the present value of the total benefit payable to the Surviving Spouse under the Reinstatement Plan and the SERP does not exceed $20,000, the benefit under the Reinstatement Plan and the SERP shall be paid in a lump sum distribution.

4.3    Payment of the Reinstatement Surviving Spouse Benefit shall commence or shall be paid within the 90-day period following the date of the death, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date.

Section 5. Administration of the Reinstatement Plan

5.1     The Employee Benefits Committee shall be the named fiduciary of the Reinstatement Plan responsible for the general operation and administration of the Reinstatement Plan and for carrying out the provisions thereof. The Employee Benefits Committee shall have discretionary authority to construe the terms of the Reinstatement Plan.

14

5.2     The Employee Benefits Committee shall adopt such rules and procedures as it deems necessary and advisable to administer the Reinstatement Plan and to transact its business. Subject to the other requirements of this Section 5, the Employee Benefits Committee may:

(a) Employ agents to carry out non‑fiduciary responsibilities;

(b) Employ agents to carry out fiduciary responsibilities (other than trustee responsibilities as defined in Section 405(c)(3) of ERISA);

(c) Consult with counsel, who may be counsel to PSEG or an Affiliate; and

(d) Provide for the allocation of fiduciary responsibilities (other than trustee responsibilities as defined in Section 405(c)(3) of ERISA) among its members.

However, any action described in paragraphs (b) or (d) above, and any modification or rescission of any such action, may be effected by the Employee Benefits Committee only by a resolution approved by a majority of the Employee Benefits Committee. The Employee Benefits Committee shall be entitled to rely conclusively upon all tables, valuations, certificates, opinions and reports furnished by any actuary, accountant, controller, counsel or other person employed or engaged by the Employee Benefits Committee with respect to the Reinstatement Plan.

5.3    The Employee Benefits Committee shall keep written minutes of all its proceedings, which shall be open to inspection by the Board of Directors. In the case of any decision by the Employee Benefits Committee with respect to a claim for benefits under the Reinstatement Plan, the Employee Benefits Committee shall include in its minutes a brief explanation of the grounds upon which such decision was based.

5.4     In performing their duties, the members of the Employee Benefits Committee shall act solely in the interest of the Participants in the Reinstatement Plan and their Beneficiaries and

(a) For the exclusive purpose of providing benefits to Participants and their Beneficiaries;

(b) With the care, skill, prudence and diligence under the circumstances then prevailing that a prudent person acting in like capacity and familiar with such matters would use in the conduct of an enterprise of alike character and with like aims; and

(c) In accordance with the documents and instruments governing the Reinstatement Plan insofar as such documents and instruments are consistent with the provisions of Title I of ERISA.

5.5     In addition to any other duties the Employee Benefits Committee may have, the Employee Benefits Committee shall review the performance of all persons to whom the Employee Benefits Committee shall have delegated or allocated fiduciary duties pursuant to the provisions of this Section 5.

15

5.6     The Company agrees to indemnify and reimburse, to the fullest extent permitted by law, members of the Employee Benefits Committee, directors and employees of PSEG and its Affiliates, and all such former members, directors and employees, for any and all expenses, liabilities or losses arising out of any act or omission relating to the rendition of services for or the management and administration of the Reinstatement Plan.

5.7     No member of the Employee Benefits Committee nor any delegee thereof shall be personally liable by virtue of any contract, agreement or other instrument made or executed by them or on their behalf in such capacity.

Section 6. Claims Procedure and Status Determination

6.1    Claims for benefits under the Reinstatement Plan and requests for a status determination shall be filed in writing with the Employee Benefits Committee or its delegee.

6.2     In the case of a claim for benefits, written notice shall be given to the claiming Participant or Beneficiary of the disposition of such claim, setting forth specific reasons for any denial of such claim in whole or in part. If a claim is denied in whole or in part, the notice shall state that such Participant or Beneficiary may, within sixty days of the receipt of such denial, request in writing that the decision denying the claim be reviewed by the Employee Benefits Committee and provide the Employee Benefits Committee with information in support of their position by submitting such information in writing to the Secretary of the Employee Benefits Committee.

6.3     The Employee Benefits Committee shall review each claim for benefits which has been denied in whole or in part and for which such review has been requested and shall notify, in writing, the affected Participant or Beneficiary of its decision and the reasons therefor.

6.4     In the case of a request for status determination, written notice shall be given to the requesting person within a reasonable time setting forth specific reasons for the decision.

Section 7. Amendment or Termination

7.1     PSEG reserves the right to amend or terminate the Reinstatement Plan when, in the sole opinion of PSEG, such amendment or termination is advisable. Any such amendment or termination shall be made pursuant to a resolution of the Board or of the Employee Benefits Policy Committee and shall be effective as provided for in such resolution.

7.2     No amendment or termination of the Reinstatement Plan shall directly or indirectly deprive any current or former Participant, Beneficiary or Surviving Spouse of all or any portion of any Reinstatement Benefit or Reinstatement Surviving Spouse Benefit payment which has commenced prior to the effective date of such amendment or termination or the right to which has accrued on such effective date.

7.3    In the event of a Reinstatement Plan termination, Reinstatement Benefits and Reinstatement Surviving Spouse Benefits shall be distributed in a single lump sum within 90 days

16

after the date the Reinstatement Plan is terminated if such distribution is permitted because the Reinstatement Plan is terminated in accordance with the termination provisions of Section 409A of the Code and related regulations or, in other cases, at the earliest time otherwise permitted under the terms of the Reinstatement Plan in accordance with Section 409A of the Code and related regulations.

Section 8. General Provisions

8.1    The Reinstatement Plan at all times shall be entirely unfunded and no provision shall at any time be made with respect to segregating any assets of the Company or any Affiliate for payment of any benefits hereunder. No Participant, Beneficiary, Surviving Spouse or any other person shall have any interest in any particular assets of the Company or any Affiliate by reason of the right to receive a benefit under the Reinstatement Plan and any such Participant, Beneficiary, Surviving Spouse or other person shall have only the rights of a general unsecured creditor with respect to any rights under the Reinstatement Plan.

8.2    Except as otherwise expressly provided herein, all terms and conditions of the Qualified Plan applicable to a Qualified Benefit or a Qualified Plan Surviving Spouse Benefit shall also be applicable to a Reinstatement Benefit or a Reinstatement Surviving Spouse Benefits payable hereunder. Any Qualified Benefit Qualified Surviving Spouse Benefit, or any other benefit payable under the Qualified Plan, as the case may be, shall be paid solely in accordance with the terms and conditions of the Qualified Plan, as the case may be, and nothing in the Reinstatement Plan shall operate or be construed in any way to modify, amend or affect the terms and provisions of the Qualified Plan.

8.3     Nothing contained in the Reinstatement Plan shall constitute a guaranty by the Company or any other entity or person that the assets of PSEG or any Affiliate will be sufficient to pay any benefit hereunder.

8.4     No Participant or Surviving Spouse shall have any right to a benefit under the Reinstatement Plan except in accordance with the terms of the Reinstatement Plan. Establishment of the Reinstatement Plan shall not be construed to give any Participant the right to be retained in the service of PSEG or any Affiliate.

8.5     No interest of any person or entity in, or right to receive a benefit under, the Reinstatement Plan shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment or other alienation or encumbrance of any kind; nor any such interest or right to receive a benefits be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings.

8.6     The Reinstatement Plan shall be construed and administered under the laws of the United States and the State of New Jersey to the extent not superseded by Federal law. The Reinstatement Plan is specifically intended to comply with Section 409A of the Code and it shall automatically incorporate all applicable restrictions of Section 409A of the Code and its related regulations, and PSEG will amend the Reinstatement Plan to the extent necessary to comply with

17

those requirements. The timing under which a Participant will have a right to receive any payment under the Reinstatement Plan will be deemed to be automatically modified, and a Participant’s rights under the Reinstatement Plan limited to conform to any requirements under the Section 409A of the Code and its related regulations.

8.7     Actuarial assumptions to determine the present value of any benefit hereunder shall be the same as used to determine the present value of benefits under the Qualified Plan.

8.8     If any person entitled to a benefit payment under the Reinstatement Plan is deemed by the Employee Benefits Committee to be incapable of personally receiving and giving a valid receipt for such payment, then, unless and until claim therefor shall have been made by a duly appointed guardian or other legal representative of such person, the Employee Benefits Committee may provide for such payment or any part thereof to be made to any other person or institution then contributing toward or providing for the care and maintenance of such person. Any such payment shall be a payment for the account of such person and a complete discharge of any liability of the Company and the Reinstatement Plan therefor.

8.9     The Reinstatement Plan shall inure to the benefit of and be binding upon the Company, its successors and assigns, including but not limited to any corporation which may acquire all or substantially all of the Company’s assets or businesses or with or into or which the Company may be consolidated or merged.

8.10     Each Participant shall keep the Company informed of their current address and the current address of their spouse. The Company shall not be obligated to search for the whereabouts of any person. If the location of a Participant is not made known to the Company within three (3) years after the date on which payment of the Reinstatement Benefit may first be made, payment may be made as though the Participant had died at the end of the three‑year period. If, within one additional year after such three‑year period has elapsed, or, within three years after the actual death of a Participant, the Company is unable to locate any. Surviving Spouse of the Participant, then the Company shall have no further obligation to pay any benefit hereunder to such Participant or Surviving Spouse or any other person and such benefit shall be irrevocably forfeited.

8.11     Notwithstanding any of the preceding provisions of the Reinstatement Plan, none of the Company, the Employee Benefits Committee or any individual acting as an employee or agent of the Company or the Employee Benefits Committee shall be liable to any Participant, former Participant, Surviving Spouse or any other person for any claim, loss, liability or expense incurred in connection with the Reinstatement Plan.

Section 9. Miscellaneous

9.1    As used herein, words in the masculine gender shall include the feminine and the singular shall include the plural, and vice versa, unless otherwise required by the context. Any headings used herein are included for ease of reference only and are not to be construed so as to alter the terms hereof.

18

*     *     *

/s/ Margaret M. Pego__ July 10, 2017___

Margaret M. Pego                                 Date

EX-12

EXHIBIT 12

PUBLIC SERVICEENTERPRISE GROUP INCORPORATED

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Six Months Ended					Years Ended
	June 30,					December 31,
	2017		2016			2016			2015			2014			2013			2012
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	311	$	1,032		$	1,298		$	2,680		$	2,456		$	2,055		$	2,011
(Income) Loss from Equity Investees, net of Distributions	1		3			7			3			4			(7		)	9
Fixed Charges	245		232			477			457			450			458			479
Capitalized Interest	33		(19		)	(7		)	(18		)	(16		)	(16		)	(19		)
Total Earnings	$	590	$	1,248		$	1,775		$	3,122		$	2,894		$	2,490		$	2,480
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	233	$	221		$	456		$	437		$	430		$	442		$	465
Interest Factor in Rentals	12		11			21			20			20			16			14
Total Fixed Charges	$	245	$	232		$	477		$	457		$	450		$	458		$	479
Ratio of Earnings to Fixed Charges	2.41		5.38			3.72			6.83			6.43			5.44			5.18

(A) The term “earnings” shall be defined as pre-tax Income from Continuing Operations before income or loss from equity investees plus distributed income from equity investees. Add to pre-tax income the amount of fixed charges adjusted to exclude (a) the amount of any interest capitalized during the period and (b) the actual amount of any preferred securities dividend requirements of majority-owned subsidiaries stated on a pre-tax level.

(B) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount, premium and expense, (c) an estimate of interest implicit in rentals, and (d) preferred securities dividend requirements of majority-owned subsidiaries stated on a pre-tax level. There were no preferred stock dividend requirements for any period presented.

EX-12.1

EXHIBIT 12.1

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

Plus Preferred Security Dividend Requirements

	Six Months Ended						Years Ended
	June 30,						December 31,
	2017			2016			2016			2015			2014			2013			2012
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	801		$	690		$	1,404		$	1,257		$	1,174		$	993		$	835
Fixed Charges	157			154			316			306			303			316			314
Capitalized Interest	(9		)	(7		)	(17		)	(17		)	(16		)	(16		)	(13		)
Total Earnings	$	949		$	837		$	1,703		$	1,546		$	1,461		$	1,293		$	1,136
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	153		$	149		$	306		$	297		$	293		$	309		$	308
Interest Factor in Rentals	4			5			10			9			10			7			6
Total Fixed Charges	$	157		$	154		$	316		$	306		$	303		$	316		$	314
Ratio of Earnings to Fixed Charges	6.04			5.44			5.39			5.05			4.82			4.09			3.62

(A) The term "earnings" shall be defined as pre-tax Income from Continuing Operations. Add to pre-tax income the amount of fixed charges adjusted to exclude (a) the amount of any interest capitalized during the period, (b) the actual amount of any preferred securities dividend requirements of majority owned subsidiaries, and (c) preferred stock dividends which were included in such fixed charges amount but not deducted in the determination of pre-tax income.

(B) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount, premium and expense, (c) an estimate of interest implicit in rentals, and (d) preferred securities dividend requirements of majority owned subsidiaries and preferred stock dividends, increased to reflect the pre-tax earnings requirement for PSE&G. There were no preferred stock dividend requirements for any period presented.

EX-12.2

EXHIBIT 12.2

PSEG POWER LLC

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Six Months Ended						Years Ended
	June 30,						December 31,
	2017			2016			2016			2015			2014		2013			2012
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income (Loss) from Continuing Operations	$	(445	)	$	299		$	(43	)	$	1,367		$	1,251	$	1,063		$	1,099
(Income) Loss from Equity Investees, net of Distributions	1			3			7			1			3		(10		)	(6		)
Fixed Charges	67			69			142			152			150		143			164
Capitalized Interest	42			(12		)	11			(1		)	1		1			(6		)
Total Earnings	$	(335	)	$	359		$	117		$	1,519		$	1,405	$	1,197		$	1,251
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	64		$	67		$	138		$	148		$	146	$	139		$	161
Interest Factor in Rentals	3			2			4			4			4		4			3
Total Fixed Charges	$	67		$	69		$	142		$	152		$	150	$	143		$	164
Ratio of Earnings to Fixed Charges (C)	(5.00		)	5.20			0.82			9.99			9.37		8.37			7.63

(A) The term “earnings” shall be defined as pre-tax Income from Continuing Operations before income or loss from equity method investees plus distributed income from equity investees.Add to pre-tax income the amount of fixed charges adjusted to exclude the amount of any interest capitalized during the period.

(B) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount, premium and expense, and (c) an estimate of interest implicit in rentals.

(C) The ratio of earnings to fixed charges for the six months ended June 30, 2017, was (5.00), as noted above, which represents a deficiency of $402 million. The ratio of earnings to fixed charges for the year ended December 31, 2016, was 0.82, as noted above, which represents a deficiency of $25 million.

EX-31

EXHIBIT 31

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Ralph Izzo, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Enterprise Group Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 28, 2017	/s/ Ralph Izzo
		Ralph Izzo
		Public Service Enterprise Group Incorporated
		Chief Executive Officer

EX-31.1

EXHIBIT 31.1

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Daniel J. Cregg, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Enterprise Group Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 28, 2017	/s/ Daniel J. Cregg
		Daniel J. Cregg
		Public Service Enterprise Group Incorporated
		Chief Financial Officer

EX-31.2

EXHIBIT 31.2

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Ralph Izzo, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Electric and Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 28, 2017	/s/ Ralph Izzo
		Ralph Izzo
		Public Service Electric and Gas Company
		Chief Executive Officer

EX-31.3

EXHIBIT 31.3

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Daniel J. Cregg, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Electric and Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 28, 2017	/s/ Daniel J. Cregg
		Daniel J. Cregg
		Public Service Electric and Gas Company
		Chief Financial Officer

EX-31.4

EXHIBIT 31.4

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Ralph Izzo, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PSEG Power LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 28, 2017	/s/ Ralph Izzo
		Ralph Izzo
		PSEG Power LLC
		Chief Executive Officer

EX-31.5

EXHIBIT 31.5

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Daniel J. Cregg, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PSEG Power LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 28, 2017	/s/ Daniel J. Cregg
		Daniel J. Cregg
		PSEG Power LLC
		Chief Financial Officer

EX-32

EXHIBIT 32

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Ralph Izzo, Chief Executive Officer of Public Service Enterprise Group Incorporated, to the best of my knowledge, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that (i) the Quarterly Report of Public Service Enterprise Group Incorporated on Form 10-Q for the quarter ended June 30, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Public Service Enterprise Group Incorporated.

/s/ Ralph Izzo

Ralph Izzo

Public Service Enterprise Group Incorporated

Chief Executive Officer

July 28, 2017

EX-32.1

EXHIBIT 32.1

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Daniel J. Cregg, Chief Financial Officer of Public Service Enterprise Group Incorporated, to the best of my knowledge, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that (i) the Quarterly Report of Public Service Enterprise Group Incorporated on Form 10-Q for the quarter ended June 30, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Public Service Enterprise Group Incorporated.

/s/ Daniel J. Cregg

Daniel J. Cregg

Public Service Enterprise Group Incorporated

Chief Financial Officer

July 28, 2017

EX-32.2

EXHIBIT 32.2

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Ralph Izzo, Chief Executive Officer of Public Service Electric and Gas Company, to the best of my knowledge, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that (i) the Quarterly Report of Public Service Electric and Gas Company on Form 10-Q for the quarter ended June 30, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Public Service Electric and Gas Company.

/s/ Ralph Izzo

Ralph Izzo

Public Service Electric and Gas Company

Chief Executive Officer

July 28, 2017

EX-32.3

EXHIBIT 32.3

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Daniel J. Cregg, Chief Financial Officer of Public Service Electric and Gas Company, to the best of my knowledge, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that (i) the Quarterly Report of Public Service Electric and Gas Company on Form 10-Q for the quarter ended June 30, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Public Service Electric and Gas Company.

/s/ Daniel J. Cregg

Daniel J. Cregg

Public Service Electric and Gas Company

Chief Financial Officer

July 28, 2017

EX-32.4

EXHIBIT 32.4

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Ralph Izzo, Chief Executive Officer of PSEG Power LLC, to the best of my knowledge, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that (i) the Quarterly Report of PSEG Power LLC on Form 10-Q for the quarter ended June 30, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of PSEG Power LLC.

/s/ Ralph Izzo

Ralph Izzo

PSEG Power LLC

Chief Executive Officer

July 28, 2017

EX-32.5

EXHIBIT 32.5

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Daniel J. Cregg, Chief Financial Officer of PSEG Power LLC, to the best of my knowledge, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that (i) the Quarterly Report of PSEG Power LLC on Form 10-Q for the quarter ended June 30, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of PSEG Power LLC.

/s/ Daniel J. Cregg

Daniel J. Cregg

PSEG Power LLC

Chief Financial Officer

July 28, 2017

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Jul. 18, 2017
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
Trading Symbol	PEG
Entity Registrant Name	PUBLIC SERVICE ENTERPRISE GROUP INC
Entity Central Index Key	0000788784
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		505,889,953
PSE And G [Member]
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
Entity Registrant Name	PUBLIC SERVICE ELECTRIC & GAS CO
Entity Central Index Key	0000081033
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		132,450,344
Power [Member]
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
Entity Registrant Name	PSEG POWER LLC
Entity Central Index Key	0001158659
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer

XML

Condensed Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Operating Revenues	$ 2,133	$ 1,905	$ 4,725	$ 4,521
Operating Expenses [Abstract]
Energy Costs	588	624	1,462	1,460
Operation and Maintenance	708	710	1,420	1,439
Depreciation and Amortization	641	224	1,469	448
Total Operating Expenses	1,937	1,558	4,351	3,347
OPERATING INCOME (LOSS)	196	347	374	1,174
Income from Equity Method Investments	5	4	8	6
Other Income	70	44	142	92
Other Deductions	(9)	(10)	(20)	(31)
Other-Than-Temporary Impairments	(3)	(10)	(4)	(20)
Interest Expense	(91)	(97)	(189)	(189)
INCOME (LOSS) BEFORE INCOME TAXES	168	278	311	1,032
Income Tax Benefit (Expense)	(59)	(91)	(88)	(374)
Net Income (Loss)	$ 109	$ 187	$ 223	$ 658
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC (shares)	505	505	505	505
DILUTED (shares)	507	508	507	508
EARNINGS PER SHARE:
BASIC (dollars per share)	$ 0.22	$ 0.37	$ 0.44	$ 1.30
DILUTED (dollars per share)	0.22	0.37	0.44	1.30
DIVIDENDS PAID PER SHARE OF COMMON STOCK (in dollars per share)	$ 0.43	$ 0.41	$ 0.86	$ 0.82
PSE And G [Member]
Operating Revenues	$ 1,368	$ 1,350	$ 3,180	$ 3,062
Operating Expenses [Abstract]
Energy Costs	472	529	1,225	1,258
Operation and Maintenance	351	352	718	734
Depreciation and Amortization	166	136	337	275
Total Operating Expenses	989	1,017	2,280	2,267
OPERATING INCOME (LOSS)	379	333	900	795
Other Income	22	19	47	39
Other Deductions	(1)	(1)	(2)	(2)
Interest Expense	(69)	(74)	(144)	(142)
INCOME (LOSS) BEFORE INCOME TAXES	331	277	801	690
Income Tax Benefit (Expense)	(123)	(98)	(294)	(249)
Net Income (Loss)	208	179	507	441
Power [Member]
Operating Revenues	929	714	2,213	2,027
Operating Expenses [Abstract]
Energy Costs	397	381	1,104	1,019
Operation and Maintenance	254	265	484	518
Depreciation and Amortization	465	80	1,115	159
Total Operating Expenses	1,116	726	2,703	1,696
OPERATING INCOME (LOSS)	(187)	(12)	(490)	331
Income from Equity Method Investments	5	4	8	6
Other Income	46	25	84	51
Other Deductions	(7)	(9)	(14)	(27)
Other-Than-Temporary Impairments	(3)	(10)	(4)	(20)
Interest Expense	(13)	(20)	(29)	(42)
INCOME (LOSS) BEFORE INCOME TAXES	(159)	(22)	(445)	299
Income Tax Benefit (Expense)	62	11	178	(118)
Net Income (Loss)	$ (97)	$ (11)	$ (267)	$ 181

XML

Condensed Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Net Income (Loss)	$ 109	$ 187	$ 223	$ 658
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit	10	10	25	26
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit	0	(1)	0	1
Pension/Other Postretirement Benefit (OPEB) adjustment, net of tax (expense) benefit	6	8	12	16
Other Comprehensive Income (Loss), net of tax	16	17	37	43
COMPREHENSIVE INCOME	125	204	260	701
PSE And G [Member]
Net Income (Loss)	208	179	507	441
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit	0	1	(1)	1
COMPREHENSIVE INCOME	208	180	506	442
Power [Member]
Net Income (Loss)	(97)	(11)	(267)	181
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit	10	9	29	25
Pension/Other Postretirement Benefit (OPEB) adjustment, net of tax (expense) benefit	5	7	10	14
Other Comprehensive Income (Loss), net of tax	15	16	39	39
COMPREHENSIVE INCOME	$ (82)	$ 5	$ (228)	$ 220

XML

Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Unrealized Gains (Losses) on Available-for-Sale Securities, tax	$ (9)	$ (10)	$ (25)	$ (26)
Unrealized Gains (Losses) on Cash Flow Hedges, tax	0	0	0	(1)
Pension/OPEB adjustment, tax	(4)	(6)	(8)	(12)
PSE And G [Member]
Unrealized Gains (Losses) on Available-for-Sale Securities, tax	0	0	1	0
Power [Member]
Unrealized Gains (Losses) on Available-for-Sale Securities, tax	(9)	(9)	(27)	(25)
Unrealized Gains (Losses) on Cash Flow Hedges, tax	0	0	0	0
Pension/OPEB adjustment, tax	$ (3)	$ (5)	$ (7)	$ (10)

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and Cash Equivalents		$ 430	$ 423
Accounts Receivable, net of allowances		1,021	1,161
Tax Receivable		9	78
Unbilled Revenues		210	260
Fuel		270	326
Materials and Supplies, net		577	561
Prepayments		273	76
Derivative Contracts		113	163
Regulatory Assets		276	199
Other		9	7
Total Current Assets		3,188	3,254
PROPERTY, PLANT AND EQUIPMENT		38,794	39,337
Less: Accumulated Depreciation and Amortization		(9,157)	(10,051)
Net Property, Plant and Equipment		29,637	29,286
NONCURRENT ASSETS
Regulatory Assets		3,349	3,319
Long-Term Investments		961	1,050
Nuclear Decommissioning Trust (NDT) Fund		1,968	1,859
Long-Term Tax Receivable		111	104
Long-Term Receivable of Variable Interest Entities (VIEs)		600	589
Other Special Funds		224	217
Goodwill		16	16
Other Intangibles		120	98
Derivative Contracts		90	24
Other		260	254
Total Noncurrent Assets		7,699	7,530
Total Assets		40,524	40,070
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		900	500
Commercial Paper and Loans		0	388
Accounts Payable		1,293	1,459
Derivative Contracts		8	13
Accrued Interest		99	97
Accrued Taxes		46	31
Clean Energy Program		200	142
Obligation to Return Cash Collateral		134	132
Regulatory Liabilities		51	88
Other		433	426
Total Current Liabilities		3,164	3,276
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		8,755	8,658
Regulatory Liabilities		99	118
Clean Energy Program Noncurrent		27	0
Asset Retirement Obligations		744	726
OPEB Costs		1,304	1,324
OPEB Costs of Servco		467	452
Accrued Pension Costs		525	568
Accrued Pension Costs of Servco		124	128
Environmental Costs		378	401
Derivative Contracts		1	3
Long-Term Accrued Taxes		192	180
Other		205	211
Total Noncurrent Liabilities		12,821	12,769
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		11,621	10,895
STOCKHOLDER'S EQUITY
Common Stock		4,929	4,936
Treasury Stock, at cost		(747)	(717)
Retained Earnings		8,962	9,174
Accumulated Other Comprehensive Income (Loss)		(226)	(263)
Total Stockholder's Equity		12,918	13,130
Total Capitalization		24,539	24,025
TOTAL LIABILITIES AND CAPITALIZATION		40,524	40,070
PSE And G [Member]
CURRENT ASSETS
Cash and Cash Equivalents		192	390
Accounts Receivable, net of allowances		755	810
Accounts Receivable-Affiliated Companies		20	76
Unbilled Revenues		210	260
Materials and Supplies, net		198	180
Prepayments		193	9
Regulatory Assets		276	199
Other		6	6
Total Current Assets		1,850	1,930
PROPERTY, PLANT AND EQUIPMENT		27,562	26,347
Less: Accumulated Depreciation and Amortization		(5,930)	(5,760)
Net Property, Plant and Equipment		21,632	20,587
NONCURRENT ASSETS
Regulatory Assets		3,349	3,319
Long-Term Investments		293	299
Other Special Funds		45	43
Other		104	110
Total Noncurrent Assets		3,791	3,771
Total Assets		27,273	26,288
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		400	0
Accounts Payable		587	718
Accounts Payable-Affiliated Companies		146	260
Derivative Contracts		0	5
Accrued Interest		78	76
Clean Energy Program		200	142
Obligation to Return Cash Collateral		134	132
Regulatory Liabilities		51	88
Other		301	296
Total Current Liabilities		1,897	1,717
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		6,232	5,873
Regulatory Liabilities		99	118
Clean Energy Program Noncurrent		27	0
Asset Retirement Obligations		215	213
OPEB Costs		983	1,009
Accrued Pension Costs		223	250
Environmental Costs		310	332
Long-Term Accrued Taxes		115	130
Other		112	116
Total Noncurrent Liabilities		8,316	8,041
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		7,842	7,818
STOCKHOLDER'S EQUITY
Common Stock		892	892
Contributed Capital		945	945
Basis Adjustment		986	986
Retained Earnings		6,395	5,888
Accumulated Other Comprehensive Income (Loss)		0	1
Total Stockholder's Equity		9,218	8,712
Total Capitalization		17,060	16,530
TOTAL LIABILITIES AND CAPITALIZATION		27,273	26,288
Power [Member]
CURRENT ASSETS
Cash and Cash Equivalents		29	11
Accounts Receivable, net of allowances		207	276
Accounts Receivable-Affiliated Companies		139	205
Short-Term Loan to Affiliate		233	87
Fuel		270	326
Materials and Supplies, net		379	381
Prepayments		10	10
Derivative Contracts	[1]	112	162
Other		3	2
Total Current Assets		1,382	1,460
PROPERTY, PLANT AND EQUIPMENT		10,881	12,655
Less: Accumulated Depreciation and Amortization		(3,055)	(4,135)
Net Property, Plant and Equipment		7,826	8,520
NONCURRENT ASSETS
Long-Term Investments		91	102
Nuclear Decommissioning Trust (NDT) Fund		1,968	1,859
Other Special Funds		55	53
Goodwill		16	16
Other Intangibles		120	98
Derivative Contracts	[1]	90	24
Other		71	61
Total Noncurrent Assets		2,411	2,213
Total Assets		11,619	12,193
CURRENT LIABILITIES
Accounts Payable		536	539
Accounts Payable-Affiliated Companies		20	25
Derivative Contracts	[1]	8	8
Accrued Interest		20	20
Other		95	88
Total Current Liabilities		679	680
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		1,979	2,170
Asset Retirement Obligations		526	511
OPEB Costs		256	251
Accrued Pension Costs		179	191
Derivative Contracts	[1]	1	3
Long-Term Accrued Taxes		93	77
Other		126	129
Total Noncurrent Liabilities		3,160	3,332
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		2,384	2,382
STOCKHOLDER'S EQUITY
Contributed Capital		2,214	2,214
Basis Adjustment		(986)	(986)
Retained Earnings		4,340	4,782
Accumulated Other Comprehensive Income (Loss)		(172)	(211)
Total Stockholder's Equity		5,396	5,799
TOTAL LIABILITIES AND CAPITALIZATION		$ 11,619	$ 12,193

[1] Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Accounts Receivable, allowances	$ 61	$ 68
Common Stock, issued	534	534
Common Stock, authorized	1,000	1,000
Treasury Stock, Shares	29	29
PSE And G [Member]
Accounts Receivable, allowances	$ 61	$ 68
Common Stock, issued	132	132
Common Stock, outstanding	132	132
Common Stock, authorized	150	150

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Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ 223	$ 658
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,469	448
Amortization of Nuclear Fuel	101	105
Renewable Energy Credit Compliance Accrual	51	50
Provision for Deferred Income Taxes and ITC	91	334
Non-Cash Employee Benefit Plan Costs	45	63
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(30)	(30)
Loss on Leases, net of tax	45	0
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(42)	153
Net Change in Other Regulatory Assets and Liabilities	(124)	(125)
Cost of Removal	(47)	(74)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(58)	(2)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	69	301
Accrued Taxes	15	94
Margin Deposit	59	(46)
Other Current Assets and Liabilities	(56)	(120)
Employee Benefit Plan Funding and Related Payments	(49)	(78)
Other	(6)	(9)
Net Cash Provided By (Used In) Operating Activities	1,756	1,722
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,981)	(1,971)
Purchase of Emissions Allowances and RECs	(29)	(36)
Proceeds from Sale of Available-for-Sale Securities	711	392
Investments in Available-for-Sale Securities	(726)	(407)
Other	36	18
Net Cash Provided By (Used In) Investing Activities	(1,989)	(2,004)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(388)	(364)
Issuance of Long-Term Debt	1,125	1,550
Redemption of Long-Term Debt	0	(171)
Cash Dividends Paid on Common Stock	(435)	(415)
Other	(62)	(64)
Net Cash Provided By (Used In) Financing Activities	240	536
Net Increase (Decrease) In Cash and Cash Equivalents	7	254
Cash and Cash Equivalents at Beginning of Period	423	394
Cash and Cash Equivalents at End of Period	430	648
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	(30)	(276)
Interest Paid, Net of Amounts Capitalized	189	176
Accrued Property, Plant and Equipment Expenditures	513	513
PSE And G [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	507	441
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	337	275
Provision for Deferred Income Taxes and ITC	330	290
Non-Cash Employee Benefit Plan Costs	25	36
Net Change in Other Regulatory Assets and Liabilities	(124)	(125)
Cost of Removal	(47)	(74)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	108	50
Fuel, Materials and Supplies	(15)	(14)
Prepayments	(184)	(165)
Accounts Payable	(30)	(29)
Accounts Receivable/Payable-Affiliated Companies, net	(72)	181
Other Current Assets and Liabilities	16	17
Employee Benefit Plan Funding and Related Payments	(42)	(62)
Other	(39)	(13)
Net Cash Provided By (Used In) Operating Activities	770	808
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,389)	(1,355)
Proceeds from Sale of Available-for-Sale Securities	28	12
Investments in Available-for-Sale Securities	(29)	(13)
Change in Loan Principle for Solar Investments	(3)	2
Other	5	0
Net Cash Provided By (Used In) Investing Activities	(1,388)	(1,354)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	0	(153)
Issuance of Long-Term Debt	425	850
Redemption of Long-Term Debt	0	(171)
Other	(5)	(10)
Net Cash Provided By (Used In) Financing Activities	420	516
Net Increase (Decrease) In Cash and Cash Equivalents	(198)	(30)
Cash and Cash Equivalents at Beginning of Period	390	198
Cash and Cash Equivalents at End of Period	192	168
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	(75)	(255)
Interest Paid, Net of Amounts Capitalized	144	134
Accrued Property, Plant and Equipment Expenditures	319	381
Power [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	(267)	181
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,115	159
Amortization of Nuclear Fuel	101	105
Renewable Energy Credit Compliance Accrual	51	50
Provision for Deferred Income Taxes and ITC	(226)	37
Interest Accretion on Asset Retirement Obligations	15	13
Non-Cash Employee Benefit Plan Costs	14	19
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(42)	153
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(58)	(2)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	58	86
Margin Deposit	59	(46)
Accounts Receivable	36	(12)
Accounts Payable	(14)	(10)
Accounts Receivable/Payable-Affiliated Companies, net	75	179
Other Current Assets and Liabilities	7	11
Employee Benefit Plan Funding and Related Payments	(4)	(10)
Other	12	4
Net Cash Provided By (Used In) Operating Activities	932	917
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(576)	(598)
Purchase of Emissions Allowances and RECs	(29)	(36)
Proceeds from Sale of Available-for-Sale Securities	602	346
Investments in Available-for-Sale Securities	(616)	(359)
Short-Term Loan-Affiliated Company, net	(146)	(972)
Other	30	12
Net Cash Provided By (Used In) Investing Activities	(735)	(1,607)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	0	700
Cash Dividends Paid on Common Stock	(175)	0
Other	(4)	(6)
Net Cash Provided By (Used In) Financing Activities	(179)	694
Net Increase (Decrease) In Cash and Cash Equivalents	18	4
Cash and Cash Equivalents at Beginning of Period	11	12
Cash and Cash Equivalents at End of Period	29	16
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	66	(53)
Interest Paid, Net of Amounts Capitalized	29	38
Accrued Property, Plant and Equipment Expenditures	$ 194	$ 132

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Organization and Basis of Presentation

6 Months Ended

Jun. 30, 2017

Organization and Basis of Presentation

Organization and Basis of Presentation

Organization

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 solar generation projects and has implemented energy efficiency and demand response 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 through competitive energy sales in well-developed energy markets and fuel supply functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; 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); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2016.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.

PSE And G [Member]

Organization and Basis of Presentation

Organization and Basis of Presentation

Organization

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 solar generation projects and has implemented energy efficiency and demand response 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 through competitive energy sales in well-developed energy markets and fuel supply functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; 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); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2016.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.

Power [Member]

Organization and Basis of Presentation

Organization and Basis of Presentation

Organization

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 solar generation projects and has implemented energy efficiency and demand response 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 through competitive energy sales in well-developed energy markets and fuel supply functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; 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); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2016.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.

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Recent Accounting Standards

6 Months Ended

Jun. 30, 2017

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Recent Accounting Standards

Recent Accounting Standards

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

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

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possible changes in presentation.

PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the transmission and distribution of electricity and distribution of gas to retail residential and commercial and industrial customers, is in scope of the new accounting standard. PSEG expects no change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. Revenue from contracts with customers will be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. Upon formal resolution of the implementation issues noted above, and upon completion of contract evaluations, PSEG will elect its transition method.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

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

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.

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

Measurement of Credit Losses on Financial Instruments

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

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

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.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements including its future disclosure requirements.

Business Combinations: Clarifying the Definition of a Business

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.

Simplifying the Test for Goodwill Impairment

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

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)

This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.

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 will be eligible for capitalization, when applicable.

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

Premium Amortization on Purchased Callable Debt Securities

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

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

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

PSEG is currently analyzing the impact of this standard on its financial statements.

Stock Compensation - Scope of Modification Accounting

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

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

PSE And G [Member]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Recent Accounting Standards

Recent Accounting Standards

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

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

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possible changes in presentation.

PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the transmission and distribution of electricity and distribution of gas to retail residential and commercial and industrial customers, is in scope of the new accounting standard. PSEG expects no change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. Revenue from contracts with customers will be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. Upon formal resolution of the implementation issues noted above, and upon completion of contract evaluations, PSEG will elect its transition method.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

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

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.

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

Measurement of Credit Losses on Financial Instruments

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

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

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.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements including its future disclosure requirements.

Business Combinations: Clarifying the Definition of a Business

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.

Simplifying the Test for Goodwill Impairment

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

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)

This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.

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 will be eligible for capitalization, when applicable.

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

Premium Amortization on Purchased Callable Debt Securities

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

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

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

PSEG is currently analyzing the impact of this standard on its financial statements.

Stock Compensation - Scope of Modification Accounting

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

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

Power [Member]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Recent Accounting Standards

Recent Accounting Standards

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

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

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possible changes in presentation.

PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the transmission and distribution of electricity and distribution of gas to retail residential and commercial and industrial customers, is in scope of the new accounting standard. PSEG expects no change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. Revenue from contracts with customers will be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. Upon formal resolution of the implementation issues noted above, and upon completion of contract evaluations, PSEG will elect its transition method.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

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

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.

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

Measurement of Credit Losses on Financial Instruments

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

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

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.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements including its future disclosure requirements.

Business Combinations: Clarifying the Definition of a Business

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.

Simplifying the Test for Goodwill Impairment

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

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)

This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.

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 will be eligible for capitalization, when applicable.

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

Premium Amortization on Purchased Callable Debt Securities

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

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

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

PSEG is currently analyzing the impact of this standard on its financial statements.

Stock Compensation - Scope of Modification Accounting

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

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

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Early Plant Retirements Early Plant Retirements

6 Months Ended

Jun. 30, 2017

Early Plant Retirements [Line Items]

Early Plant Retirements

Early Plant Retirements

Fossil

In October 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Both units were available to operate through May 31, 2017 and were subsequently retired from operation on June 1, 2017.

In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.

In the three and six months ended June 30, 2017, Power recognized total D&A of $390 million and $964 million, respectively, for the Hudson and Mercer units. In the three and six months ended June 30, 2017, Power also recognized pre-tax charges in Energy Costs of $2 million and $9 million, respectively, primarily for coal inventory lower of cost or market adjustments. For the three and six months ended June 30, 2017, Power also recognized pre-tax charges in O&M of $4 million of shut down costs and an increase in the ARO liability due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material.

As of December 31, 2016, Power had reduced the estimated useful life of Bridgeport Harbor Station unit 3 (BH3) from 2025 to the summer of 2021 as it was more likely than not it will retire the unit by this time. The change in the estimated useful life did not have a material impact on Power’s 2017 financial results.

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

Nuclear

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

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

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

	As of June 30, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	83		$	80		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	453			561			208		758
Nuclear Fuel In-Service, net of Accumulated Depreciation	136			113			—		125
Construction Work in Progress (including nuclear fuel)	168			109			9		31
Total Assets	$	840		$	863		$	217	$	955
Liability
Asset Retirement Obligation	$	146		$	159		$	—	$	162
Total Liabilities	$	146		$	159		$	—	$	162
Net Assets	$	694		$	704		$	217	$	793
NRC License Renewal Term	2046			2036/2040			—		2033/2034
% Owned	100		%	57		%	—		50		%

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

The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments and decommissioning trust fund requirements and other commitments, as well as future energy prices. Power maintains a NDT Fund that funds its decommissioning obligations. See Note 7. Available-for-Sale Securities.

Power [Member]

Early Plant Retirements [Line Items]

Early Plant Retirements

Early Plant Retirements

Fossil

In October 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Both units were available to operate through May 31, 2017 and were subsequently retired from operation on June 1, 2017.

In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.

In the three and six months ended June 30, 2017, Power recognized total D&A of $390 million and $964 million, respectively, for the Hudson and Mercer units. In the three and six months ended June 30, 2017, Power also recognized pre-tax charges in Energy Costs of $2 million and $9 million, respectively, primarily for coal inventory lower of cost or market adjustments. For the three and six months ended June 30, 2017, Power also recognized pre-tax charges in O&M of $4 million of shut down costs and an increase in the ARO liability due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material.

As of December 31, 2016, Power had reduced the estimated useful life of Bridgeport Harbor Station unit 3 (BH3) from 2025 to the summer of 2021 as it was more likely than not it will retire the unit by this time. The change in the estimated useful life did not have a material impact on Power’s 2017 financial results.

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

Nuclear

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

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

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

	As of June 30, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	83		$	80		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	453			561			208		758
Nuclear Fuel In-Service, net of Accumulated Depreciation	136			113			—		125
Construction Work in Progress (including nuclear fuel)	168			109			9		31
Total Assets	$	840		$	863		$	217	$	955
Liability
Asset Retirement Obligation	$	146		$	159		$	—	$	162
Total Liabilities	$	146		$	159		$	—	$	162
Net Assets	$	694		$	704		$	217	$	793
NRC License Renewal Term	2046			2036/2040			—		2033/2034
% Owned	100		%	57		%	—		50		%

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

The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments and decommissioning trust fund requirements and other commitments, as well as future energy prices. Power maintains a NDT Fund that funds its decommissioning obligations. See Note 7. Available-for-Sale Securities.

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Variable Interest Entities (VIEs)

6 Months Ended

Jun. 30, 2017

Variable Interest Entity [Line Items]

Variable Interest Entities (VIEs)

Variable Interest Entity (VIE)

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary 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, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. Servco recorded $112 million and $101 million for the three months and $224 million and $199 million for the six months ended June 30, 2017 and 2016, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Condensed Consolidated Statement of Operations.

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Rate Filings

6 Months Ended

Jun. 30, 2017

Regulatory Assets [Line Items]

Rate Filings

Rate Filings

This Note should be read in conjunction with Note 6. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2016.

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

Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June 2017, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2017 which represents estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. The petition requests rates to be effective September 1, 2017, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.

Basic Gas Supply Services (BGSS)—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase of $61 million in annual BGSS revenues. If approved, the BGSS rate would be increased from approximately 34 cents to 37 cents per therm for residential gas customers effective October 1, 2017. This matter is pending.

Green Program Recovery Charges (GPRC)—Each year PSE&G files with the BPU for annual recovery of its Green Program investments which include a return on its investment and recovery of expenses. In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery for the ten combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2017 through September 30, 2018 designed to recover approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU-approved programs. This matter is pending.

In March 2017, the BPU gave final approval to PSE&G’s petition to recover approximately $37 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved GPRC programs. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge. 

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

In June 2017, PSE&G filed a petition requesting approval to collect $55 million in total net deficiency revenues comprised of $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and the remaining carryover balance of $24 million in net deficiency gas revenue from the 2015-2016 Winter Period. The deficiency gas revenue would be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). This matter is pending.

Transmission Formula Rate Filings—In June 2017, PSE&G filed its 2016 true-up adjustment pertaining to its transmission formula rates in effect for 2016. This resulted in an adjustment of $12 million more than the 2016 originally filed revenues.

Remediation Adjustment Charge (RAC)—In June 2017, the BPU approved PSE&G's filing with respect to its RAC 24 petition allowing recovery of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016.

Gas System Modernization Program (GSMP)—In July 2017, PSE&G filed its annual GSMP cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $28 million effective January 1, 2018. This increase represents the return of and on investment for GSMP investments expected to be in service through September 30, 2017. This request will be updated in October 2017 for actual costs.

PSE And G [Member]

Regulatory Assets [Line Items]

Rate Filings

Rate Filings

This Note should be read in conjunction with Note 6. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2016.

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

Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June 2017, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2017 which represents estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. The petition requests rates to be effective September 1, 2017, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.

Basic Gas Supply Services (BGSS)—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase of $61 million in annual BGSS revenues. If approved, the BGSS rate would be increased from approximately 34 cents to 37 cents per therm for residential gas customers effective October 1, 2017. This matter is pending.

Green Program Recovery Charges (GPRC)—Each year PSE&G files with the BPU for annual recovery of its Green Program investments which include a return on its investment and recovery of expenses. In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery for the ten combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2017 through September 30, 2018 designed to recover approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU-approved programs. This matter is pending.

In March 2017, the BPU gave final approval to PSE&G’s petition to recover approximately $37 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved GPRC programs. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge. 

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

In June 2017, PSE&G filed a petition requesting approval to collect $55 million in total net deficiency revenues comprised of $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and the remaining carryover balance of $24 million in net deficiency gas revenue from the 2015-2016 Winter Period. The deficiency gas revenue would be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). This matter is pending.

Transmission Formula Rate Filings—In June 2017, PSE&G filed its 2016 true-up adjustment pertaining to its transmission formula rates in effect for 2016. This resulted in an adjustment of $12 million more than the 2016 originally filed revenues.

Remediation Adjustment Charge (RAC)—In June 2017, the BPU approved PSE&G's filing with respect to its RAC 24 petition allowing recovery of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016.

Gas System Modernization Program (GSMP)—In July 2017, PSE&G filed its annual GSMP cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $28 million effective January 1, 2018. This increase represents the return of and on investment for GSMP investments expected to be in service through September 30, 2017. This request will be updated in October 2017 for actual costs.

XML

Financing Receivables

6 Months Ended

Jun. 30, 2017

Schedule of Financial Receivables [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. The loans are generally paid back with solar renewable energy certificates generated from the installed solar electric system. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”

Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	June 30, 2017		December 31, 2016
	Millions
Commercial/Industrial	$	167	$	164
Residential	11		11
Total	$	178	$	175

Energy Holdings

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

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

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

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

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

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

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	559		$	629
Estimated Residual Value of Leased Assets	333			346
Total Investment in Rental Receivables	892			975
Unearned and Deferred Income	(315		)	(326		)
Gross Investment in Leases	577			649
Deferred Tax Liabilities	(619		)	(674		)
Net Investment in Leases	$	(42	)	$	(25	)

The corresponding receivables associated with the lease portfolio are reflected in the following table, 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 June 30, 2017
	As of June 30, 2017
	Millions
AA	$	15
BBB+ — BBB-	317
BB-	133
CC	94
Total	$	559

The “BB-” and the “CC” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of June 30, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $348 million ($(159) million, net of deferred taxes). A more detailed description of such assets under lease, as of June 30, 2017, is presented in the following table.

Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	83	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Shawville Station Units 1, 2, 3 and 4	PA	$	91	100	%	596	Gas	CC (A)	REMA

(A) REMA’s parent company, GenOn, and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. On June 16, 2017, Moody’s downgraded the GenOn Corporate Family Rating to D-PD and provided a rating of Caa1 for REMA.

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. 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 wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service.

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 And G [Member]

Schedule of Financial Receivables [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. The loans are generally paid back with solar renewable energy certificates generated from the installed solar electric system. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”

Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	June 30, 2017		December 31, 2016
	Millions
Commercial/Industrial	$	167	$	164
Residential	11		11
Total	$	178	$	175

Energy Holdings

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

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

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

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

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

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

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	559		$	629
Estimated Residual Value of Leased Assets	333			346
Total Investment in Rental Receivables	892			975
Unearned and Deferred Income	(315		)	(326		)
Gross Investment in Leases	577			649
Deferred Tax Liabilities	(619		)	(674		)
Net Investment in Leases	$	(42	)	$	(25	)

The corresponding receivables associated with the lease portfolio are reflected in the following table, 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 June 30, 2017
	As of June 30, 2017
	Millions
AA	$	15
BBB+ — BBB-	317
BB-	133
CC	94
Total	$	559

The “BB-” and the “CC” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of June 30, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $348 million ($(159) million, net of deferred taxes). A more detailed description of such assets under lease, as of June 30, 2017, is presented in the following table.

Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	83	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Shawville Station Units 1, 2, 3 and 4	PA	$	91	100	%	596	Gas	CC (A)	REMA

(A) REMA’s parent company, GenOn, and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. On June 16, 2017, Moody’s downgraded the GenOn Corporate Family Rating to D-PD and provided a rating of Caa1 for REMA.

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. 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 wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service.

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.

XML

Available-for-Sale Securities

6 Months Ended

Jun. 30, 2017

Schedule of Available-for-sale Securities [Line Items]

Available-for-Sale Securities

Available-for-Sale Securities

NDT Fund

Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power.

Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	699	$	305	$	(5	)	$	999
Debt Securities
Government	551		10		(4		)	557
Corporate	356		6		(1		)	361
Total Debt Securities	907		16		(5		)	918
Other Securities	51		—		—			51
Total NDT Available-for-Sale Securities	$	1,657	$	321	$	(10	)	$	1,968

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858

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

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	25	$	8
Accounts Payable	$	22	$	5

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

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	63	$	(5	)	$	—	$	—	$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	279		(4		)	7		—		276		(6		)	4		—
Corporate (C)	94		(1		)	7		—		139		(3		)	15		(1		)
Total Debt Securities	373		(5		)	14		—		415		(9		)	19		(1		)
Other Securities	51		—			—		—		—		—			—		—
NDT Available-for-Sale Securities	$	487	$	(10	)	$	14	$	—	$	535	$	(19	)	$	27	$	(2	)

(A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2017.

(B) Debt Securities (Government)—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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from NDT Fund Sales (A)	$	320		$	154		$	567		$	331
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	32		$	10		$	53		$	25
Gross Realized Losses	(5		)	(6		)	(9		)	(22		)
Net Realized Gains (Losses) on NDT Fund	$	27		$	4		$	44		$	3

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $158 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of June 30, 2017.

The NDT available-for-sale debt securities held as of June 30, 2017 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	29
1 - 5 years	239
6 - 10 years	223
11 - 15 years	65
16 - 20 years	66
Over 20 years	296
Total NDT Available-for-Sale Debt Securities	$	918

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

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, 2017, Other-Than-Temporary Impairments (OTTI) of $4 million were recognized on securities in the NDT Fund. 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.”

PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	—	$	—		$	22
Debt Securities
Government	85		1		(1		)	85
Corporate	113		2		—			115
Total Debt Securities	198		3		(1		)	200
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	222	$	3	$	(1	)	$	224

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	11	$	—		$	22
Debt Securities
Government	105		—		(2		)	103
Corporate	92		1		(2		)	91
Total Debt Securities	197		1		(4		)	194
Other Securities	1		—		—			1
Total Rabbi Trust Available-for-Sale Securities	$	209	$	12	$	(4	)	$	217

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	—	$	3

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

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government (B)	29		(1		)	1		—		60		(2		)	1		—
Corporate (C)	19		—			3		—		46		(2		)	3		—
Total Debt Securities	48		(1		)	4		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	48	$	(1	)	$	4	$	—	$	106	$	(4	)	$	4	$	—

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

(B) Debt Securities (Government)—Unrealized 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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)	$	93		$	36		$	144		$	61
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2		$	17		$	3
Gross Realized Losses	(1		)	(1		)	(4		)	(2		)
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	1		$	13		$	1

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains/losses in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets were immaterial as of June 30, 2017.

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

Time Frame	Fair Value
	Millions
Less than one year	$	1
1 - 5 years	35
6 - 10 years	29
11 - 15 years	6
16 - 20 years	18
Over 20 years	111
Total Rabbi Trust Available-for-Sale Debt Securities	$	200

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

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in an indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, 2017, no OTTIs were recognized on securities in the Rabbi Trust. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
PSE&G	$	45	$	43
Power	55		53
Other	124		121
Total Rabbi Trust Available-for-Sale Securities	$	224	$	217

PSE And G [Member]

Schedule of Available-for-sale Securities [Line Items]

Available-for-Sale Securities

Available-for-Sale Securities

NDT Fund

Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power.

Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	699	$	305	$	(5	)	$	999
Debt Securities
Government	551		10		(4		)	557
Corporate	356		6		(1		)	361
Total Debt Securities	907		16		(5		)	918
Other Securities	51		—		—			51
Total NDT Available-for-Sale Securities	$	1,657	$	321	$	(10	)	$	1,968

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858

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

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	25	$	8
Accounts Payable	$	22	$	5

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

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	63	$	(5	)	$	—	$	—	$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	279		(4		)	7		—		276		(6		)	4		—
Corporate (C)	94		(1		)	7		—		139		(3		)	15		(1		)
Total Debt Securities	373		(5		)	14		—		415		(9		)	19		(1		)
Other Securities	51		—			—		—		—		—			—		—
NDT Available-for-Sale Securities	$	487	$	(10	)	$	14	$	—	$	535	$	(19	)	$	27	$	(2	)

(A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2017.

(B) Debt Securities (Government)—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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from NDT Fund Sales (A)	$	320		$	154		$	567		$	331
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	32		$	10		$	53		$	25
Gross Realized Losses	(5		)	(6		)	(9		)	(22		)
Net Realized Gains (Losses) on NDT Fund	$	27		$	4		$	44		$	3

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $158 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of June 30, 2017.

The NDT available-for-sale debt securities held as of June 30, 2017 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	29
1 - 5 years	239
6 - 10 years	223
11 - 15 years	65
16 - 20 years	66
Over 20 years	296
Total NDT Available-for-Sale Debt Securities	$	918

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

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, 2017, Other-Than-Temporary Impairments (OTTI) of $4 million were recognized on securities in the NDT Fund. 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.”

PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	—	$	—		$	22
Debt Securities
Government	85		1		(1		)	85
Corporate	113		2		—			115
Total Debt Securities	198		3		(1		)	200
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	222	$	3	$	(1	)	$	224

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	11	$	—		$	22
Debt Securities
Government	105		—		(2		)	103
Corporate	92		1		(2		)	91
Total Debt Securities	197		1		(4		)	194
Other Securities	1		—		—			1
Total Rabbi Trust Available-for-Sale Securities	$	209	$	12	$	(4	)	$	217

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	—	$	3

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

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government (B)	29		(1		)	1		—		60		(2		)	1		—
Corporate (C)	19		—			3		—		46		(2		)	3		—
Total Debt Securities	48		(1		)	4		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	48	$	(1	)	$	4	$	—	$	106	$	(4	)	$	4	$	—

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

(B) Debt Securities (Government)—Unrealized 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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)	$	93		$	36		$	144		$	61
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2		$	17		$	3
Gross Realized Losses	(1		)	(1		)	(4		)	(2		)
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	1		$	13		$	1

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains/losses in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets were immaterial as of June 30, 2017.

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

Time Frame	Fair Value
	Millions
Less than one year	$	1
1 - 5 years	35
6 - 10 years	29
11 - 15 years	6
16 - 20 years	18
Over 20 years	111
Total Rabbi Trust Available-for-Sale Debt Securities	$	200

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

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in an indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, 2017, no OTTIs were recognized on securities in the Rabbi Trust. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
PSE&G	$	45	$	43
Power	55		53
Other	124		121
Total Rabbi Trust Available-for-Sale Securities	$	224	$	217

Power [Member]

Schedule of Available-for-sale Securities [Line Items]

Available-for-Sale Securities

Available-for-Sale Securities

NDT Fund

Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power.

Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	699	$	305	$	(5	)	$	999
Debt Securities
Government	551		10		(4		)	557
Corporate	356		6		(1		)	361
Total Debt Securities	907		16		(5		)	918
Other Securities	51		—		—			51
Total NDT Available-for-Sale Securities	$	1,657	$	321	$	(10	)	$	1,968

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858

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

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	25	$	8
Accounts Payable	$	22	$	5

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

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	63	$	(5	)	$	—	$	—	$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	279		(4		)	7		—		276		(6		)	4		—
Corporate (C)	94		(1		)	7		—		139		(3		)	15		(1		)
Total Debt Securities	373		(5		)	14		—		415		(9		)	19		(1		)
Other Securities	51		—			—		—		—		—			—		—
NDT Available-for-Sale Securities	$	487	$	(10	)	$	14	$	—	$	535	$	(19	)	$	27	$	(2	)

(A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2017.

(B) Debt Securities (Government)—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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from NDT Fund Sales (A)	$	320		$	154		$	567		$	331
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	32		$	10		$	53		$	25
Gross Realized Losses	(5		)	(6		)	(9		)	(22		)
Net Realized Gains (Losses) on NDT Fund	$	27		$	4		$	44		$	3

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $158 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of June 30, 2017.

The NDT available-for-sale debt securities held as of June 30, 2017 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	29
1 - 5 years	239
6 - 10 years	223
11 - 15 years	65
16 - 20 years	66
Over 20 years	296
Total NDT Available-for-Sale Debt Securities	$	918

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

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, 2017, Other-Than-Temporary Impairments (OTTI) of $4 million were recognized on securities in the NDT Fund. 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.”

PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	—	$	—		$	22
Debt Securities
Government	85		1		(1		)	85
Corporate	113		2		—			115
Total Debt Securities	198		3		(1		)	200
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	222	$	3	$	(1	)	$	224

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	11	$	—		$	22
Debt Securities
Government	105		—		(2		)	103
Corporate	92		1		(2		)	91
Total Debt Securities	197		1		(4		)	194
Other Securities	1		—		—			1
Total Rabbi Trust Available-for-Sale Securities	$	209	$	12	$	(4	)	$	217

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	—	$	3

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

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government (B)	29		(1		)	1		—		60		(2		)	1		—
Corporate (C)	19		—			3		—		46		(2		)	3		—
Total Debt Securities	48		(1		)	4		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	48	$	(1	)	$	4	$	—	$	106	$	(4	)	$	4	$	—

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

(B) Debt Securities (Government)—Unrealized 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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)	$	93		$	36		$	144		$	61
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2		$	17		$	3
Gross Realized Losses	(1		)	(1		)	(4		)	(2		)
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	1		$	13		$	1

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains/losses in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets were immaterial as of June 30, 2017.

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

Time Frame	Fair Value
	Millions
Less than one year	$	1
1 - 5 years	35
6 - 10 years	29
11 - 15 years	6
16 - 20 years	18
Over 20 years	111
Total Rabbi Trust Available-for-Sale Debt Securities	$	200

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

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in an indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, 2017, no OTTIs were recognized on securities in the Rabbi Trust. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
PSE&G	$	45	$	43
Power	55		53
Other	124		121
Total Rabbi Trust Available-for-Sale Securities	$	224	$	217

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Pension and OPEB

6 Months Ended

Jun. 30, 2017

Defined Benefit Plan Disclosure [Line Items]

Pension and Other Postretirement Benefits (OPEB)

Pension and Other Postretirement Benefits (OPEB)

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

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $12 million and $24 million for the three months and six months, ended June 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.

The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco.

	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Six Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2017			2016			2017			2016			2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	28		$	27		$	4		$	4		$	57		$	54		$	8		$	8
Interest Cost	51			51			16			14			102			101			32			29
Expected Return on Plan Assets	(99		)	(99		)	(9		)	(7		)	(197		)	(197		)	(17		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(4		)	(5		)	(2		)	(4		)	(9		)	(9		)	(5		)	(7		)
Actuarial Loss	25			40			12			10			49			79			25			20
Total Benefit Costs	$	1		$	14		$	21		$	17		$	2		$	28		$	43		$	35

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

	Pension Benefits					OPEB				Pension Benefits					OPEB
	Three Months Ended					Three Months Ended				Six Months Ended					Six Months Ended
	June 30,					June 30,				June 30,					June 30,
	2017			2016		2017		2016		2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	7	$	13	$	11	$	(2	)	$	14	$	27	$	22
Power	1			4		6		5		1			8		13		11
Other	1			3		2		1		3			6		3		2
Total Benefit Costs	$	1		$	14	$	21	$	17	$	2		$	28	$	43	$	35

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

Servco Pension and OPEB

At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco plans to contribute $35 million into its pension plan trusts during 2017. Servco’s pension-related revenues and costs were $8 million and $6 million for the three months ended June 30, 2017 and 2016, respectively, and $17 million and $12 million for the six months ended June 30, 2017and 2016, respectively. The OPEB-related revenues earned and costs incurred were $1 million and $2 million for the three months and six months ended June 30, 2017. The OPEB-related revenues earned and costs incurred were immaterial for the three months and six months ended June 30, 2016.

PSE And G [Member]

Defined Benefit Plan Disclosure [Line Items]

Pension and Other Postretirement Benefits (OPEB)

Pension and Other Postretirement Benefits (OPEB)

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

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $12 million and $24 million for the three months and six months, ended June 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.

The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco.

	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Six Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2017			2016			2017			2016			2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	28		$	27		$	4		$	4		$	57		$	54		$	8		$	8
Interest Cost	51			51			16			14			102			101			32			29
Expected Return on Plan Assets	(99		)	(99		)	(9		)	(7		)	(197		)	(197		)	(17		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(4		)	(5		)	(2		)	(4		)	(9		)	(9		)	(5		)	(7		)
Actuarial Loss	25			40			12			10			49			79			25			20
Total Benefit Costs	$	1		$	14		$	21		$	17		$	2		$	28		$	43		$	35

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

	Pension Benefits					OPEB				Pension Benefits					OPEB
	Three Months Ended					Three Months Ended				Six Months Ended					Six Months Ended
	June 30,					June 30,				June 30,					June 30,
	2017			2016		2017		2016		2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	7	$	13	$	11	$	(2	)	$	14	$	27	$	22
Power	1			4		6		5		1			8		13		11
Other	1			3		2		1		3			6		3		2
Total Benefit Costs	$	1		$	14	$	21	$	17	$	2		$	28	$	43	$	35

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

Servco Pension and OPEB

At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco plans to contribute $35 million into its pension plan trusts during 2017. Servco’s pension-related revenues and costs were $8 million and $6 million for the three months ended June 30, 2017 and 2016, respectively, and $17 million and $12 million for the six months ended June 30, 2017and 2016, respectively. The OPEB-related revenues earned and costs incurred were $1 million and $2 million for the three months and six months ended June 30, 2017. The OPEB-related revenues earned and costs incurred were immaterial for the three months and six months ended June 30, 2016.

Power [Member]

Defined Benefit Plan Disclosure [Line Items]

Pension and Other Postretirement Benefits (OPEB)

Pension and Other Postretirement Benefits (OPEB)

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

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $12 million and $24 million for the three months and six months, ended June 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.

The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco.

	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Six Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2017			2016			2017			2016			2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	28		$	27		$	4		$	4		$	57		$	54		$	8		$	8
Interest Cost	51			51			16			14			102			101			32			29
Expected Return on Plan Assets	(99		)	(99		)	(9		)	(7		)	(197		)	(197		)	(17		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(4		)	(5		)	(2		)	(4		)	(9		)	(9		)	(5		)	(7		)
Actuarial Loss	25			40			12			10			49			79			25			20
Total Benefit Costs	$	1		$	14		$	21		$	17		$	2		$	28		$	43		$	35

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

	Pension Benefits					OPEB				Pension Benefits					OPEB
	Three Months Ended					Three Months Ended				Six Months Ended					Six Months Ended
	June 30,					June 30,				June 30,					June 30,
	2017			2016		2017		2016		2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	7	$	13	$	11	$	(2	)	$	14	$	27	$	22
Power	1			4		6		5		1			8		13		11
Other	1			3		2		1		3			6		3		2
Total Benefit Costs	$	1		$	14	$	21	$	17	$	2		$	28	$	43	$	35

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

Servco Pension and OPEB

At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco plans to contribute $35 million into its pension plan trusts during 2017. Servco’s pension-related revenues and costs were $8 million and $6 million for the three months ended June 30, 2017 and 2016, respectively, and $17 million and $12 million for the six months ended June 30, 2017and 2016, respectively. The OPEB-related revenues earned and costs incurred were $1 million and $2 million for the three months and six months ended June 30, 2017. The OPEB-related revenues earned and costs incurred were immaterial for the three months and six months ended June 30, 2016.

XML

Commitments and Contingent Liabilities

6 Months Ended

Jun. 30, 2017

Loss Contingencies [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 June 30, 2017 and December 31, 2016.

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,898		$	1,806
Exposure under Current Guarantees	$	137		$	139
Letters of Credit Margin Posted	$	142		$	157
Letters of Credit Margin Received	$	98		$	99
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(1	)
Net Broker Balance Deposited (Received)	$	(2	)	$	57
Additional Amounts Posted:
Other Letters of Credit	$	61		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 11. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.

Environmental Matters

Passaic River

Historic operations 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)

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

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

In early 2007, 73 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. At such time, the CPG also 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 seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.

In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

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

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

The CPG, which consisted of 51 members as of June 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million, which the CPG continues to incur. Of the estimated $190 million, as of June 30, 2017, the CPG had spent approximately $163 million, of which PSEG’s total share was approximately $12 million.

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

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

Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of June 30, 2017, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”

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

In March 2017, the EPA sent a letter to 20 PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements in return for payments by each PRP of $280,600. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. It is unclear how the EPA made that determination or how many PRPs will accept the proposal. The settlement is subject to a 30 day public comment period that has not yet commenced. The impact of this settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

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 operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

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 $373 million and $430 million through2021, 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 $373 million as ofJune 30, 2017. Of this amount, $74 million was recorded in Other Current Liabilities and $299 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $373 millionRegulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether 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.

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

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

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

Clean Water Act (CWA) Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), 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 rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing

power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing

adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range

of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for

review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental

organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the

Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by

mid-2017.

In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. 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 intake structures 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 BH3. To address compliance with the EPA’s CWA Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would 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. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements.

Separately, Power has also negotiated 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 its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. 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 BH5. All major environmental permits have been obtained. Operations are expected to begin in mid-2019.

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

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

Jersey City, New Jersey Subsurface Feeder Cable Matter

In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the actions necessary to address the leak and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs was extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s initial debris removal activities were completed in May 2017. Since then, efforts have been ongoing to inspect portions of the pipe-type cables. As of mid-July 2017, the immediate vicinity of the leak appears to have been located and efforts are ongoing to identify the precise leak location and attempt repairs. If the leak cannot be located or if repairs cannot be effectuated at a reasonable cost and within a reasonable time frame, retirement of the affected facilities may be an option to address the leakage.

Steam Electric Effluent Guidelines

In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations and pretreatment standards for the aforementioned waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Basic Generation Service (BGS) 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, 2016 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $335.33 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
	2014	2015	2016	2017
36-Month Terms Ending	May 2017	May 2018	May 2019	May 2020	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$97.39	$99.54	$96.38	$90.78

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

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 (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.

PSE&G has a full-requirements contract with 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 18. 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 2018 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

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

Power also has various long-term fuel purchase commitments for coal through 2021 to support its Keystone and Conemaugh fossil generation stations.

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

Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	301
Enrichment	$	340
Fabrication	$	184
Natural Gas	$	1,040
Coal	$	331

Regulatory Proceedings

FERC Compliance

PJM Bidding Matter

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

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

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

Financial Transmission Rights (FTR) Auction Matter

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in PJM’s annual FTR auction for the 2016-2017 planning year and the monthly PJM FTR auctions for February, March and April 2016. PSEG is cooperating with FERC in this matter. PSEG cannot predict the outcome of this matter at this time.

PSE And G [Member]

Loss Contingencies [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 June 30, 2017 and December 31, 2016.

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,898		$	1,806
Exposure under Current Guarantees	$	137		$	139
Letters of Credit Margin Posted	$	142		$	157
Letters of Credit Margin Received	$	98		$	99
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(1	)
Net Broker Balance Deposited (Received)	$	(2	)	$	57
Additional Amounts Posted:
Other Letters of Credit	$	61		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 11. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.

Environmental Matters

Passaic River

Historic operations 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)

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

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

In early 2007, 73 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. At such time, the CPG also 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 seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.

In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

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

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

The CPG, which consisted of 51 members as of June 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million, which the CPG continues to incur. Of the estimated $190 million, as of June 30, 2017, the CPG had spent approximately $163 million, of which PSEG’s total share was approximately $12 million.

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

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

Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of June 30, 2017, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”

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

In March 2017, the EPA sent a letter to 20 PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements in return for payments by each PRP of $280,600. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. It is unclear how the EPA made that determination or how many PRPs will accept the proposal. The settlement is subject to a 30 day public comment period that has not yet commenced. The impact of this settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

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 operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

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 $373 million and $430 million through2021, 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 $373 million as ofJune 30, 2017. Of this amount, $74 million was recorded in Other Current Liabilities and $299 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $373 millionRegulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether 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.

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

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

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

Clean Water Act (CWA) Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), 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 rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing

power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing

adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range

of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for

review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental

organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the

Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by

mid-2017.

In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. 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 intake structures 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 BH3. To address compliance with the EPA’s CWA Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would 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. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements.

Separately, Power has also negotiated 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 its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. 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 BH5. All major environmental permits have been obtained. Operations are expected to begin in mid-2019.

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

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

Jersey City, New Jersey Subsurface Feeder Cable Matter

In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the actions necessary to address the leak and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs was extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s initial debris removal activities were completed in May 2017. Since then, efforts have been ongoing to inspect portions of the pipe-type cables. As of mid-July 2017, the immediate vicinity of the leak appears to have been located and efforts are ongoing to identify the precise leak location and attempt repairs. If the leak cannot be located or if repairs cannot be effectuated at a reasonable cost and within a reasonable time frame, retirement of the affected facilities may be an option to address the leakage.

Steam Electric Effluent Guidelines

In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations and pretreatment standards for the aforementioned waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Basic Generation Service (BGS) 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, 2016 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $335.33 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
	2014	2015	2016	2017
36-Month Terms Ending	May 2017	May 2018	May 2019	May 2020	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$97.39	$99.54	$96.38	$90.78

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

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 (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.

PSE&G has a full-requirements contract with 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 18. 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 2018 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

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

Power also has various long-term fuel purchase commitments for coal through 2021 to support its Keystone and Conemaugh fossil generation stations.

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

Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	301
Enrichment	$	340
Fabrication	$	184
Natural Gas	$	1,040
Coal	$	331

Regulatory Proceedings

FERC Compliance

PJM Bidding Matter

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

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

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

Financial Transmission Rights (FTR) Auction Matter

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in PJM’s annual FTR auction for the 2016-2017 planning year and the monthly PJM FTR auctions for February, March and April 2016. PSEG is cooperating with FERC in this matter. PSEG cannot predict the outcome of this matter at this time.

Power [Member]

Loss Contingencies [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 June 30, 2017 and December 31, 2016.

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,898		$	1,806
Exposure under Current Guarantees	$	137		$	139
Letters of Credit Margin Posted	$	142		$	157
Letters of Credit Margin Received	$	98		$	99
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(1	)
Net Broker Balance Deposited (Received)	$	(2	)	$	57
Additional Amounts Posted:
Other Letters of Credit	$	61		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 11. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.

Environmental Matters

Passaic River

Historic operations 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)

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

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

In early 2007, 73 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. At such time, the CPG also 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 seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.

In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

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

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

The CPG, which consisted of 51 members as of June 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million, which the CPG continues to incur. Of the estimated $190 million, as of June 30, 2017, the CPG had spent approximately $163 million, of which PSEG’s total share was approximately $12 million.

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

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

Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of June 30, 2017, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”

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

In March 2017, the EPA sent a letter to 20 PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements in return for payments by each PRP of $280,600. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. It is unclear how the EPA made that determination or how many PRPs will accept the proposal. The settlement is subject to a 30 day public comment period that has not yet commenced. The impact of this settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

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 operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

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 $373 million and $430 million through2021, 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 $373 million as ofJune 30, 2017. Of this amount, $74 million was recorded in Other Current Liabilities and $299 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $373 millionRegulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether 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.

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

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

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

Clean Water Act (CWA) Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), 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 rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing

power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing

adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range

of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for

review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental

organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the

Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by

mid-2017.

In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. 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 intake structures 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 BH3. To address compliance with the EPA’s CWA Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would 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. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements.

Separately, Power has also negotiated 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 its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. 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 BH5. All major environmental permits have been obtained. Operations are expected to begin in mid-2019.

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

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

Jersey City, New Jersey Subsurface Feeder Cable Matter

In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the actions necessary to address the leak and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs was extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s initial debris removal activities were completed in May 2017. Since then, efforts have been ongoing to inspect portions of the pipe-type cables. As of mid-July 2017, the immediate vicinity of the leak appears to have been located and efforts are ongoing to identify the precise leak location and attempt repairs. If the leak cannot be located or if repairs cannot be effectuated at a reasonable cost and within a reasonable time frame, retirement of the affected facilities may be an option to address the leakage.

Steam Electric Effluent Guidelines

In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations and pretreatment standards for the aforementioned waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Basic Generation Service (BGS) 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, 2016 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $335.33 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
	2014	2015	2016	2017
36-Month Terms Ending	May 2017	May 2018	May 2019	May 2020	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$97.39	$99.54	$96.38	$90.78

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

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 (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.

PSE&G has a full-requirements contract with 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 18. 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 2018 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

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

Power also has various long-term fuel purchase commitments for coal through 2021 to support its Keystone and Conemaugh fossil generation stations.

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

Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	301
Enrichment	$	340
Fabrication	$	184
Natural Gas	$	1,040
Coal	$	331

Regulatory Proceedings

FERC Compliance

PJM Bidding Matter

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

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

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

Financial Transmission Rights (FTR) Auction Matter

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in PJM’s annual FTR auction for the 2016-2017 planning year and the monthly PJM FTR auctions for February, March and April 2016. PSEG is cooperating with FERC in this matter. PSEG cannot predict the outcome of this matter at this time.

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Debt and Credit Facilities

6 Months Ended

Jun. 30, 2017

Debt Instrument [Line Items]

Debt and Credit Facilities

Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transaction occurred in the six months ended June 30, 2017:

PSEG

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

PSE&G

• issued $425 million of 3.00% Secured Medium-Term Notes, Series L due May 2027.

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.

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

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of June 30, 2017, the total available credit capacity was $4.0 billion.

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

As of June 30, 2017, total credit capacity was in excess of the total anticipated maximum liquidity requirements of PSEG, PSE&G and Power.

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of June 30, 2017 were as follows:

	As of June 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	13	$	1,487	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	13	$	1,487
PSE&G
5-year Credit Facility (A)	$	600	$	15	$	585	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	15	$	585
Power
3-year LC Facilities	$	200	$	140	$	60	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		50		1,850		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	190	$	1,910
Total	$	4,200	$	218	$	3,982

(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 June 30, 2017, neither PSEG nor PSE&G had amounts outstanding.

PSE And G [Member]

Debt Instrument [Line Items]

Debt and Credit Facilities

Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transaction occurred in the six months ended June 30, 2017:

PSEG

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

PSE&G

• issued $425 million of 3.00% Secured Medium-Term Notes, Series L due May 2027.

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.

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

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of June 30, 2017, the total available credit capacity was $4.0 billion.

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

As of June 30, 2017, total credit capacity was in excess of the total anticipated maximum liquidity requirements of PSEG, PSE&G and Power.

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of June 30, 2017 were as follows:

	As of June 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	13	$	1,487	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	13	$	1,487
PSE&G
5-year Credit Facility (A)	$	600	$	15	$	585	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	15	$	585
Power
3-year LC Facilities	$	200	$	140	$	60	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		50		1,850		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	190	$	1,910
Total	$	4,200	$	218	$	3,982

(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 June 30, 2017, neither PSEG nor PSE&G had amounts outstanding.

Power [Member]

Debt Instrument [Line Items]

Debt and Credit Facilities

Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transaction occurred in the six months ended June 30, 2017:

PSEG

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

PSE&G

• issued $425 million of 3.00% Secured Medium-Term Notes, Series L due May 2027.

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.

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

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of June 30, 2017, the total available credit capacity was $4.0 billion.

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

As of June 30, 2017, total credit capacity was in excess of the total anticipated maximum liquidity requirements of PSEG, PSE&G and Power.

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of June 30, 2017 were as follows:

	As of June 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	13	$	1,487	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	13	$	1,487
PSE&G
5-year Credit Facility (A)	$	600	$	15	$	585	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	15	$	585
Power
3-year LC Facilities	$	200	$	140	$	60	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		50		1,850		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	190	$	1,910
Total	$	4,200	$	218	$	3,982

(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 June 30, 2017, neither PSEG nor PSE&G had amounts outstanding.

XML

Financial Risk Management Activities

6 Months Ended

Jun. 30, 2017

Derivative Instruments and Hedging Activities Disclosures [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 normal purchases and normal sales (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 and PSE&G enter 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 relating primarily to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. 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.

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 June 30, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $4 million for the three months and six months ended June 30, 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, related primarily to variable-rate debt instruments. As of June 30, 2017 and December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of June 30, 2017 and December 31, 2016, the fair value of these hedges was $1 million. There was no ineffectiveness as of June 30, 2017 and December 31, 2016.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of June 30, 2017 and December 31, 2016. The after-tax unrealized gain expected to be reclassified to earnings during the next 12 months is $1 million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Condensed Consolidated Balance Sheets of Power and PSEG.

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

	As of June 30, 2017
	Power (A)									PSEG (A)		Consolidated
	Not Designated									Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	479		$	(367	)	$	112		$	1	$	113
Noncurrent Assets	268			(178		)	90			—		90
Total Mark-to-Market Derivative Assets	$	747		$	(545	)	$	202		$	1	$	203
Derivative Contracts
Current Liabilities	$	(373	)	$	365		$	(8	)	$	—	$	(8	)
Noncurrent Liabilities	(170		)	169			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(543	)	$	534		$	(9	)	$	—	$	(9	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	204		$	(11	)	$	193		$	1	$	194

	As of December 31, 2016
	Power (A)									PSE&G (A)			PSEG (A)		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	435		$	(273	)	$	162		$	—		$	1	$	163
Noncurrent Assets	122			(98		)	24			—			—		24
Total Mark-to-Market Derivative Assets	$	557		$	(371	)	$	186		$	—		$	1	$	187
Derivative Contracts
Current Liabilities	$	(285	)	$	277		$	(8	)	$	(5	)	$	—	$	(13	)
Noncurrent Liabilities	(98		)	95			(3		)	—			—		(3		)
Total Mark-to-Market Derivative (Liabilities)	$	(383	)	$	372		$	(11	)	$	(5	)	$	—	$	(16	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	174		$	1		$	175		$	(5	)	$	1	$	171

(A) Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. 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 Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(4) million was netted against current assets, $(9) million was netted against noncurrent assets, and $2 million was netted against current liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities.

Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $16 million and $19 million as of June 30, 2017 and December 31, 2016, respectively. As of June 30, 2017 and December 31, 2016, Power had the contractual right of offset of $11 million and $9 million, respectively, related to derivative instruments that are assets with the same counterparty under 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 $5 million and $10 million as of June 30, 2017 and December 31, 2016, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months and six months ended June 30, 2017 and 2016.

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2017		2016				2017		2016
	Millions						Millions
PSEG
Interest Rate Swaps	$	—	$	(1	)	Interest Expense	$	—	$	—
Total PSEG	$	—	$	(1	)		$	—	$	—

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Six Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	—		2		Interest Expense	—		—
Total PSEG	$	—	$	2		$	—	$	—

There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of June 30, 2017 and 2016.

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

Accumulated Other Comprehensive Income	Pre-Tax		After-Tax
	Millions
Balance as of December 31, 2015	$	—	$	—
Gain Recognized in AOCI	3		2
Less: Gain Reclassified into Income	—		—
Balance as of December 31, 2016	$	3	$	2
Gain Recognized in AOCI	—		—
Less: Gain Reclassified into Income	—		—
Balance as of June 30, 2017	$	3	$	2

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and six months ended June 30, 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 for 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						Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2017			2016			2017			2016
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	113		$	(86	)	$	196		$	130
Energy-Related Contracts	Energy Costs	(11		)	6			(16		)	8
Total PSEG and Power		$	102		$	(80	)	$	180		$	138

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2017 and December 31, 2016.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2017
Natural Gas	Dekatherm (Dth)	321	—	321	—
Electricity	MWh	349	—	349	—
Financial Transmission Rights (FTRs)	MWh	6	—	6	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—
As of December 31, 2016
Natural Gas	Dth	357	—	348	9
Electricity	MWh	323	—	323	—
FTRs	MWh	9	—	9	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—

Credit Risk

Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of June 30, 2017, 97% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2017. 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.

Rating	Current Exposure		Collateral Held		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	420	$	92	$	328	1	$	130	(A)
Non-Investment Grade	9		—		9		—	—
Total	$	429	$	92	$	337	1	$	130

(A) Represents net exposure of $130 million with PSE&G.

As of June 30, 2017, collateral held from counterparties where Power had credit exposure included $92 million in letters of credit.

As of June 30, 2017, Power had 152 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 June 30, 2017, 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 June 30, 2017, 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 And G [Member]

Derivative Instruments and Hedging Activities Disclosures [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 normal purchases and normal sales (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 and PSE&G enter 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 relating primarily to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. 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.

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 June 30, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $4 million for the three months and six months ended June 30, 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, related primarily to variable-rate debt instruments. As of June 30, 2017 and December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of June 30, 2017 and December 31, 2016, the fair value of these hedges was $1 million. There was no ineffectiveness as of June 30, 2017 and December 31, 2016.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of June 30, 2017 and December 31, 2016. The after-tax unrealized gain expected to be reclassified to earnings during the next 12 months is $1 million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Condensed Consolidated Balance Sheets of Power and PSEG.

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

	As of June 30, 2017
	Power (A)									PSEG (A)		Consolidated
	Not Designated									Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	479		$	(367	)	$	112		$	1	$	113
Noncurrent Assets	268			(178		)	90			—		90
Total Mark-to-Market Derivative Assets	$	747		$	(545	)	$	202		$	1	$	203
Derivative Contracts
Current Liabilities	$	(373	)	$	365		$	(8	)	$	—	$	(8	)
Noncurrent Liabilities	(170		)	169			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(543	)	$	534		$	(9	)	$	—	$	(9	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	204		$	(11	)	$	193		$	1	$	194

	As of December 31, 2016
	Power (A)									PSE&G (A)			PSEG (A)		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	435		$	(273	)	$	162		$	—		$	1	$	163
Noncurrent Assets	122			(98		)	24			—			—		24
Total Mark-to-Market Derivative Assets	$	557		$	(371	)	$	186		$	—		$	1	$	187
Derivative Contracts
Current Liabilities	$	(285	)	$	277		$	(8	)	$	(5	)	$	—	$	(13	)
Noncurrent Liabilities	(98		)	95			(3		)	—			—		(3		)
Total Mark-to-Market Derivative (Liabilities)	$	(383	)	$	372		$	(11	)	$	(5	)	$	—	$	(16	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	174		$	1		$	175		$	(5	)	$	1	$	171

(A) Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. 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 Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(4) million was netted against current assets, $(9) million was netted against noncurrent assets, and $2 million was netted against current liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities.

Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $16 million and $19 million as of June 30, 2017 and December 31, 2016, respectively. As of June 30, 2017 and December 31, 2016, Power had the contractual right of offset of $11 million and $9 million, respectively, related to derivative instruments that are assets with the same counterparty under 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 $5 million and $10 million as of June 30, 2017 and December 31, 2016, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months and six months ended June 30, 2017 and 2016.

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2017		2016				2017		2016
	Millions						Millions
PSEG
Interest Rate Swaps	$	—	$	(1	)	Interest Expense	$	—	$	—
Total PSEG	$	—	$	(1	)		$	—	$	—

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Six Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	—		2		Interest Expense	—		—
Total PSEG	$	—	$	2		$	—	$	—

There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of June 30, 2017 and 2016.

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

Accumulated Other Comprehensive Income	Pre-Tax		After-Tax
	Millions
Balance as of December 31, 2015	$	—	$	—
Gain Recognized in AOCI	3		2
Less: Gain Reclassified into Income	—		—
Balance as of December 31, 2016	$	3	$	2
Gain Recognized in AOCI	—		—
Less: Gain Reclassified into Income	—		—
Balance as of June 30, 2017	$	3	$	2

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and six months ended June 30, 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 for 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						Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2017			2016			2017			2016
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	113		$	(86	)	$	196		$	130
Energy-Related Contracts	Energy Costs	(11		)	6			(16		)	8
Total PSEG and Power		$	102		$	(80	)	$	180		$	138

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2017 and December 31, 2016.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2017
Natural Gas	Dekatherm (Dth)	321	—	321	—
Electricity	MWh	349	—	349	—
Financial Transmission Rights (FTRs)	MWh	6	—	6	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—
As of December 31, 2016
Natural Gas	Dth	357	—	348	9
Electricity	MWh	323	—	323	—
FTRs	MWh	9	—	9	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—

Credit Risk

Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of June 30, 2017, 97% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2017. 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.

Rating	Current Exposure		Collateral Held		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	420	$	92	$	328	1	$	130	(A)
Non-Investment Grade	9		—		9		—	—
Total	$	429	$	92	$	337	1	$	130

(A) Represents net exposure of $130 million with PSE&G.

As of June 30, 2017, collateral held from counterparties where Power had credit exposure included $92 million in letters of credit.

As of June 30, 2017, Power had 152 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 June 30, 2017, 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 June 30, 2017, 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 Instruments and Hedging Activities Disclosures [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 normal purchases and normal sales (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 and PSE&G enter 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 relating primarily to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. 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.

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 June 30, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $4 million for the three months and six months ended June 30, 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, related primarily to variable-rate debt instruments. As of June 30, 2017 and December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of June 30, 2017 and December 31, 2016, the fair value of these hedges was $1 million. There was no ineffectiveness as of June 30, 2017 and December 31, 2016.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of June 30, 2017 and December 31, 2016. The after-tax unrealized gain expected to be reclassified to earnings during the next 12 months is $1 million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Condensed Consolidated Balance Sheets of Power and PSEG.

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

	As of June 30, 2017
	Power (A)									PSEG (A)		Consolidated
	Not Designated									Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	479		$	(367	)	$	112		$	1	$	113
Noncurrent Assets	268			(178		)	90			—		90
Total Mark-to-Market Derivative Assets	$	747		$	(545	)	$	202		$	1	$	203
Derivative Contracts
Current Liabilities	$	(373	)	$	365		$	(8	)	$	—	$	(8	)
Noncurrent Liabilities	(170		)	169			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(543	)	$	534		$	(9	)	$	—	$	(9	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	204		$	(11	)	$	193		$	1	$	194

	As of December 31, 2016
	Power (A)									PSE&G (A)			PSEG (A)		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	435		$	(273	)	$	162		$	—		$	1	$	163
Noncurrent Assets	122			(98		)	24			—			—		24
Total Mark-to-Market Derivative Assets	$	557		$	(371	)	$	186		$	—		$	1	$	187
Derivative Contracts
Current Liabilities	$	(285	)	$	277		$	(8	)	$	(5	)	$	—	$	(13	)
Noncurrent Liabilities	(98		)	95			(3		)	—			—		(3		)
Total Mark-to-Market Derivative (Liabilities)	$	(383	)	$	372		$	(11	)	$	(5	)	$	—	$	(16	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	174		$	1		$	175		$	(5	)	$	1	$	171

(A) Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. 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 Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(4) million was netted against current assets, $(9) million was netted against noncurrent assets, and $2 million was netted against current liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities.

Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $16 million and $19 million as of June 30, 2017 and December 31, 2016, respectively. As of June 30, 2017 and December 31, 2016, Power had the contractual right of offset of $11 million and $9 million, respectively, related to derivative instruments that are assets with the same counterparty under 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 $5 million and $10 million as of June 30, 2017 and December 31, 2016, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months and six months ended June 30, 2017 and 2016.

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2017		2016				2017		2016
	Millions						Millions
PSEG
Interest Rate Swaps	$	—	$	(1	)	Interest Expense	$	—	$	—
Total PSEG	$	—	$	(1	)		$	—	$	—

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Six Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	—		2		Interest Expense	—		—
Total PSEG	$	—	$	2		$	—	$	—

There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of June 30, 2017 and 2016.

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

Accumulated Other Comprehensive Income	Pre-Tax		After-Tax
	Millions
Balance as of December 31, 2015	$	—	$	—
Gain Recognized in AOCI	3		2
Less: Gain Reclassified into Income	—		—
Balance as of December 31, 2016	$	3	$	2
Gain Recognized in AOCI	—		—
Less: Gain Reclassified into Income	—		—
Balance as of June 30, 2017	$	3	$	2

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and six months ended June 30, 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 for 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						Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2017			2016			2017			2016
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	113		$	(86	)	$	196		$	130
Energy-Related Contracts	Energy Costs	(11		)	6			(16		)	8
Total PSEG and Power		$	102		$	(80	)	$	180		$	138

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2017 and December 31, 2016.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2017
Natural Gas	Dekatherm (Dth)	321	—	321	—
Electricity	MWh	349	—	349	—
Financial Transmission Rights (FTRs)	MWh	6	—	6	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—
As of December 31, 2016
Natural Gas	Dth	357	—	348	9
Electricity	MWh	323	—	323	—
FTRs	MWh	9	—	9	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—

Credit Risk

Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of June 30, 2017, 97% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2017. 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.

Rating	Current Exposure		Collateral Held		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	420	$	92	$	328	1	$	130	(A)
Non-Investment Grade	9		—		9		—	—
Total	$	429	$	92	$	337	1	$	130

(A) Represents net exposure of $130 million with PSE&G.

As of June 30, 2017, collateral held from counterparties where Power had credit exposure included $92 million in letters of credit.

As of June 30, 2017, Power had 152 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 June 30, 2017, 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 June 30, 2017, 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.

XML

Fair Value Measurements

6 Months Ended

Jun. 30, 2017

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [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 June 30, 2017, 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 June 30, 2017 and December 31, 2016, 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 June 30, 2017
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	367		$	—		$	367		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	51		$	—		$	—		$	51		$	—
Debt Securities—Govt Other	$	34		$	—		$	—		$	34		$	—
Debt Securities—Corporate	$	115		$	—		$	—		$	115		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—
Interest Rate Swaps (C)	$	—		$	—		$	—		$	—		$	—
PSE&G
Assets:
Cash Equivalents (A)	$	169		$	—		$	169		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	10		$	—		$	—		$	10		$	—
Debt Securities—Govt Other	$	7		$	—		$	—		$	7		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	29		$	—		$	—		$	29		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—

	Recurring Fair Value Measurements as of December 31, 2016
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	37		$	—		$	—		$	37		$	—
Debt Securities—Govt Other	$	66		$	—		$	—		$	66		$	—
Debt Securities—Corporate	$	91		$	—		$	—		$	91		$	—
Other Securities	$	1		$	—		$	1		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(16	)	$	372		$	(18	)	$	(364	)	$	(6	)
PSE&G
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	13		$	—		$	—		$	13		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(5	)	$	—		$	—		$	—		$	(5	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	16		$	—		$	—		$	16		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	372		$	(18	)	$	(364	)	$	(1	)

(A) Represents money market mutual funds.

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

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from 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) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(D) The fair value measurement tables exclude an immaterial amount of cash as of June 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of June 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities include primarily investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(13) million of cash collateral was netted against assets, and $2 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

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 approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

For PSE&G, the natural gas supply contract was measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of June 30, 2017 and December 31, 2016.

	Quantitative Information About Level 3 Fair Value Measurements
							Significant
		Fair Value as of				Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2017				Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Load Contracts	$	5	$	—	Discounted Cash flow	Historic Load Variability	0% to +10%
Gas (A)	Other	1		—
Total Power		$	6	$	—
Total PSEG		$	6	$	—

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)

(A) Includes gas positions which were immaterial as of June 30, 2017 and December 31, 2016.

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.

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

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

	Three Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	3		$	7	$	(1	)	$	—	$	(3	)	$	—		$	6
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	—	$	(1	)	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	2		$	7	$	—		$	—	$	(3	)	$	—		$	6
	Six Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	26	$	5		$	—	$	(25	)	$	(1	)	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	5		$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	26	$	—		$	—	$	(25	)	$	(1	)	$	6

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

for the Three MonthsandSix Months EndedJune 30, 2016

	Three Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21	$	1	$	(12	)	$	—	$	(5	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	10	$	—	$	(12	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	1	$	—		$	—	$	(5	)	$	—	$	7
	Six Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
PSEG
Net Derivative Assets (Liabilities)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

(A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $7 million and $26 million in Operating Income for the three months and six months ended June 30, 2017, respectively. Of the $7 million in Operating Income, $4 million is unrealized. Of the $26 million in Operating Income, $1 million is unrealized.

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

(C) Represents $(3) million and $(25) million in settlements for the three months and six months ended June 30, 2017, respectively. Represents $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively.

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

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1 million and $16 million in Operating Income for the three months and six months ended June 30, 2016, respectively. Of the $1 million in Operating Income, $(4) million is unrealized. Of the $16 million in Operating Income, $(4) million is unrealized.

As of June 30, 2017, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $6 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of June 30, 2016, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $5 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

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

	As of				As of
	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	1,895	$	1,888	$	1,195	$	1,185
PSE&G (B)	8,242		8,900		7,818		8,240
Power - Recourse Debt (B)	2,384		2,646		2,382		2,578
Total Long-Term Debt	$	12,521	$	13,434	$	11,395	$	12,003

(A) As of June 30, 2017, fair value includes a $700 million floating rate term loan term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016. The fair values of the term loan debt (Level 2 measurement) were considered to be equal to the carrying values because the interest payments are based on LIBOR rates that are reset monthly.

(B) Given that most bonds do not trade, 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 And G [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [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 June 30, 2017, 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 June 30, 2017 and December 31, 2016, 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 June 30, 2017
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	367		$	—		$	367		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	51		$	—		$	—		$	51		$	—
Debt Securities—Govt Other	$	34		$	—		$	—		$	34		$	—
Debt Securities—Corporate	$	115		$	—		$	—		$	115		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—
Interest Rate Swaps (C)	$	—		$	—		$	—		$	—		$	—
PSE&G
Assets:
Cash Equivalents (A)	$	169		$	—		$	169		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	10		$	—		$	—		$	10		$	—
Debt Securities—Govt Other	$	7		$	—		$	—		$	7		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	29		$	—		$	—		$	29		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—

	Recurring Fair Value Measurements as of December 31, 2016
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	37		$	—		$	—		$	37		$	—
Debt Securities—Govt Other	$	66		$	—		$	—		$	66		$	—
Debt Securities—Corporate	$	91		$	—		$	—		$	91		$	—
Other Securities	$	1		$	—		$	1		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(16	)	$	372		$	(18	)	$	(364	)	$	(6	)
PSE&G
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	13		$	—		$	—		$	13		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(5	)	$	—		$	—		$	—		$	(5	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	16		$	—		$	—		$	16		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	372		$	(18	)	$	(364	)	$	(1	)

(A) Represents money market mutual funds.

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

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from 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) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(D) The fair value measurement tables exclude an immaterial amount of cash as of June 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of June 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities include primarily investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(13) million of cash collateral was netted against assets, and $2 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

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 approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

For PSE&G, the natural gas supply contract was measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of June 30, 2017 and December 31, 2016.

	Quantitative Information About Level 3 Fair Value Measurements
							Significant
		Fair Value as of				Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2017				Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Load Contracts	$	5	$	—	Discounted Cash flow	Historic Load Variability	0% to +10%
Gas (A)	Other	1		—
Total Power		$	6	$	—
Total PSEG		$	6	$	—

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)

(A) Includes gas positions which were immaterial as of June 30, 2017 and December 31, 2016.

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.

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

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

	Three Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	3		$	7	$	(1	)	$	—	$	(3	)	$	—		$	6
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	—	$	(1	)	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	2		$	7	$	—		$	—	$	(3	)	$	—		$	6
	Six Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	26	$	5		$	—	$	(25	)	$	(1	)	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	5		$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	26	$	—		$	—	$	(25	)	$	(1	)	$	6

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

for the Three MonthsandSix Months EndedJune 30, 2016

	Three Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21	$	1	$	(12	)	$	—	$	(5	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	10	$	—	$	(12	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	1	$	—		$	—	$	(5	)	$	—	$	7
	Six Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
PSEG
Net Derivative Assets (Liabilities)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

(A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $7 million and $26 million in Operating Income for the three months and six months ended June 30, 2017, respectively. Of the $7 million in Operating Income, $4 million is unrealized. Of the $26 million in Operating Income, $1 million is unrealized.

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

(C) Represents $(3) million and $(25) million in settlements for the three months and six months ended June 30, 2017, respectively. Represents $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively.

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

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1 million and $16 million in Operating Income for the three months and six months ended June 30, 2016, respectively. Of the $1 million in Operating Income, $(4) million is unrealized. Of the $16 million in Operating Income, $(4) million is unrealized.

As of June 30, 2017, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $6 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of June 30, 2016, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $5 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

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

	As of				As of
	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	1,895	$	1,888	$	1,195	$	1,185
PSE&G (B)	8,242		8,900		7,818		8,240
Power - Recourse Debt (B)	2,384		2,646		2,382		2,578
Total Long-Term Debt	$	12,521	$	13,434	$	11,395	$	12,003

(A) As of June 30, 2017, fair value includes a $700 million floating rate term loan term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016. The fair values of the term loan debt (Level 2 measurement) were considered to be equal to the carrying values because the interest payments are based on LIBOR rates that are reset monthly.

(B) Given that most bonds do not trade, 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]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [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 June 30, 2017, 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 June 30, 2017 and December 31, 2016, 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 June 30, 2017
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	367		$	—		$	367		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	51		$	—		$	—		$	51		$	—
Debt Securities—Govt Other	$	34		$	—		$	—		$	34		$	—
Debt Securities—Corporate	$	115		$	—		$	—		$	115		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—
Interest Rate Swaps (C)	$	—		$	—		$	—		$	—		$	—
PSE&G
Assets:
Cash Equivalents (A)	$	169		$	—		$	169		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	10		$	—		$	—		$	10		$	—
Debt Securities—Govt Other	$	7		$	—		$	—		$	7		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	29		$	—		$	—		$	29		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—

	Recurring Fair Value Measurements as of December 31, 2016
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	37		$	—		$	—		$	37		$	—
Debt Securities—Govt Other	$	66		$	—		$	—		$	66		$	—
Debt Securities—Corporate	$	91		$	—		$	—		$	91		$	—
Other Securities	$	1		$	—		$	1		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(16	)	$	372		$	(18	)	$	(364	)	$	(6	)
PSE&G
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	13		$	—		$	—		$	13		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(5	)	$	—		$	—		$	—		$	(5	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	16		$	—		$	—		$	16		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	372		$	(18	)	$	(364	)	$	(1	)

(A) Represents money market mutual funds.

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

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from 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) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(D) The fair value measurement tables exclude an immaterial amount of cash as of June 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of June 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities include primarily investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(13) million of cash collateral was netted against assets, and $2 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

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 approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

For PSE&G, the natural gas supply contract was measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of June 30, 2017 and December 31, 2016.

	Quantitative Information About Level 3 Fair Value Measurements
							Significant
		Fair Value as of				Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2017				Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Load Contracts	$	5	$	—	Discounted Cash flow	Historic Load Variability	0% to +10%
Gas (A)	Other	1		—
Total Power		$	6	$	—
Total PSEG		$	6	$	—

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)

(A) Includes gas positions which were immaterial as of June 30, 2017 and December 31, 2016.

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.

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

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

	Three Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	3		$	7	$	(1	)	$	—	$	(3	)	$	—		$	6
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	—	$	(1	)	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	2		$	7	$	—		$	—	$	(3	)	$	—		$	6
	Six Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	26	$	5		$	—	$	(25	)	$	(1	)	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	5		$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	26	$	—		$	—	$	(25	)	$	(1	)	$	6

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

for the Three MonthsandSix Months EndedJune 30, 2016

	Three Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21	$	1	$	(12	)	$	—	$	(5	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	10	$	—	$	(12	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	1	$	—		$	—	$	(5	)	$	—	$	7
	Six Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
PSEG
Net Derivative Assets (Liabilities)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

(A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $7 million and $26 million in Operating Income for the three months and six months ended June 30, 2017, respectively. Of the $7 million in Operating Income, $4 million is unrealized. Of the $26 million in Operating Income, $1 million is unrealized.

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

(C) Represents $(3) million and $(25) million in settlements for the three months and six months ended June 30, 2017, respectively. Represents $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively.

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

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1 million and $16 million in Operating Income for the three months and six months ended June 30, 2016, respectively. Of the $1 million in Operating Income, $(4) million is unrealized. Of the $16 million in Operating Income, $(4) million is unrealized.

As of June 30, 2017, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $6 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of June 30, 2016, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $5 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

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

	As of				As of
	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	1,895	$	1,888	$	1,195	$	1,185
PSE&G (B)	8,242		8,900		7,818		8,240
Power - Recourse Debt (B)	2,384		2,646		2,382		2,578
Total Long-Term Debt	$	12,521	$	13,434	$	11,395	$	12,003

(A) As of June 30, 2017, fair value includes a $700 million floating rate term loan term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016. The fair values of the term loan debt (Level 2 measurement) were considered to be equal to the carrying values because the interest payments are based on LIBOR rates that are reset monthly.

(B) Given that most bonds do not trade, 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.

XML

Other Income and Deductions

6 Months Ended

Jun. 30, 2017

Component of Other Income [Line Items]

Other Income and Deductions

Other Income and Deductions

Other Income	PSE&G		Power		Other (A)			Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	45	$	—		$	45
Allowance for Funds Used During Construction	14		—		—			14
Rabbi Trust Realized Gains, Interest and Dividends	1		1		2			$	4
Solar Loan Interest	5		—		—			5
Other	2		—		—			2
Total Other Income	$	22	$	46	$	2		$	70
Six Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	76	$	—		$	76
Allowance for Funds Used During Construction	28		—		—			28
Rabbi Trust Realized Gains, Interest and Dividends	4		5		11			20
Solar Loan Interest	10		—		—			10
Other	5		3		—			8
Total Other Income	$	47	$	84	$	11		$	142
Three Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—		$	23
Allowance for Funds Used During Construction	10		—		—			10
Rabbi Trust Realized Gains, Interest and Dividends	1		1		1			$	3
Solar Loan Interest	5		—		—			5
Other	3		1		(1		)	3
Total Other Income	$	19	$	25	$	—		$	44
Six Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	48	$	—		$	48
Allowance for Funds Used During Construction	21		—		—			21
Rabbi Trust Realized Gains, Interest and Dividends	1		2		3			6
Solar Loan Interest	11		—		—			11
Other	6		1		(1		)	6
Total Other Income	$	39	$	51	$	2		$	92

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		1		3
Total Other Deductions	$	1	$	7	$	1	$	9
Six Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	13	$	—	$	13
Other	2		1		4		7
Total Other Deductions	$	2	$	14	$	4	$	20
Three Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	8	$	—	$	8
Other	1		1		—		2
Total Other Deductions	$	1	$	9	$	—	$	10
Six Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	26	$	—	$	26
Other	2		1		2		5
Total Other Deductions	$	2	$	27	$	2	$	31

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

PSE And G [Member]

Component of Other Income [Line Items]

Other Income and Deductions

Other Income and Deductions

Other Income	PSE&G		Power		Other (A)			Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	45	$	—		$	45
Allowance for Funds Used During Construction	14		—		—			14
Rabbi Trust Realized Gains, Interest and Dividends	1		1		2			$	4
Solar Loan Interest	5		—		—			5
Other	2		—		—			2
Total Other Income	$	22	$	46	$	2		$	70
Six Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	76	$	—		$	76
Allowance for Funds Used During Construction	28		—		—			28
Rabbi Trust Realized Gains, Interest and Dividends	4		5		11			20
Solar Loan Interest	10		—		—			10
Other	5		3		—			8
Total Other Income	$	47	$	84	$	11		$	142
Three Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—		$	23
Allowance for Funds Used During Construction	10		—		—			10
Rabbi Trust Realized Gains, Interest and Dividends	1		1		1			$	3
Solar Loan Interest	5		—		—			5
Other	3		1		(1		)	3
Total Other Income	$	19	$	25	$	—		$	44
Six Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	48	$	—		$	48
Allowance for Funds Used During Construction	21		—		—			21
Rabbi Trust Realized Gains, Interest and Dividends	1		2		3			6
Solar Loan Interest	11		—		—			11
Other	6		1		(1		)	6
Total Other Income	$	39	$	51	$	2		$	92

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		1		3
Total Other Deductions	$	1	$	7	$	1	$	9
Six Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	13	$	—	$	13
Other	2		1		4		7
Total Other Deductions	$	2	$	14	$	4	$	20
Three Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	8	$	—	$	8
Other	1		1		—		2
Total Other Deductions	$	1	$	9	$	—	$	10
Six Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	26	$	—	$	26
Other	2		1		2		5
Total Other Deductions	$	2	$	27	$	2	$	31

(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 and Deductions

Other Income	PSE&G		Power		Other (A)			Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	45	$	—		$	45
Allowance for Funds Used During Construction	14		—		—			14
Rabbi Trust Realized Gains, Interest and Dividends	1		1		2			$	4
Solar Loan Interest	5		—		—			5
Other	2		—		—			2
Total Other Income	$	22	$	46	$	2		$	70
Six Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	76	$	—		$	76
Allowance for Funds Used During Construction	28		—		—			28
Rabbi Trust Realized Gains, Interest and Dividends	4		5		11			20
Solar Loan Interest	10		—		—			10
Other	5		3		—			8
Total Other Income	$	47	$	84	$	11		$	142
Three Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—		$	23
Allowance for Funds Used During Construction	10		—		—			10
Rabbi Trust Realized Gains, Interest and Dividends	1		1		1			$	3
Solar Loan Interest	5		—		—			5
Other	3		1		(1		)	3
Total Other Income	$	19	$	25	$	—		$	44
Six Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	48	$	—		$	48
Allowance for Funds Used During Construction	21		—		—			21
Rabbi Trust Realized Gains, Interest and Dividends	1		2		3			6
Solar Loan Interest	11		—		—			11
Other	6		1		(1		)	6
Total Other Income	$	39	$	51	$	2		$	92

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		1		3
Total Other Deductions	$	1	$	7	$	1	$	9
Six Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	13	$	—	$	13
Other	2		1		4		7
Total Other Deductions	$	2	$	14	$	4	$	20
Three Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	8	$	—	$	8
Other	1		1		—		2
Total Other Deductions	$	1	$	9	$	—	$	10
Six Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	26	$	—	$	26
Other	2		1		2		5
Total Other Deductions	$	2	$	27	$	2	$	31

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

XML

Income Taxes

6 Months Ended

Jun. 30, 2017

Income Taxes [Line Items]

Income Taxes

Income Taxes

PSEG’s, PSE&G’s and Power’s effective tax rates for the three months and six months ended June 30, 2017 and 2016 were as

follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2017	2016	2017	2016
PSEG	35.1%	32.7%	28.3%	36.2%
PSE&G	37.2%	35.4%	36.7%	36.1%
Power	39.0%	50.0%	40.0%	39.5%

For the three months and six months ended June 30, 2017, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items. For the six months ended June 30, 2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.

For the three months and six months ended June 30, 2017, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items.

For the three months ended June 30, 2017, the differences in Power’s effective tax rate as compared to the same period in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, ITC and manufacturing deduction.

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

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

PSE And G [Member]

Income Taxes [Line Items]

Income Taxes

Income Taxes

PSEG’s, PSE&G’s and Power’s effective tax rates for the three months and six months ended June 30, 2017 and 2016 were as

follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2017	2016	2017	2016
PSEG	35.1%	32.7%	28.3%	36.2%
PSE&G	37.2%	35.4%	36.7%	36.1%
Power	39.0%	50.0%	40.0%	39.5%

For the three months and six months ended June 30, 2017, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items. For the six months ended June 30, 2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.

For the three months and six months ended June 30, 2017, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items.

For the three months ended June 30, 2017, the differences in Power’s effective tax rate as compared to the same period in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, ITC and manufacturing deduction.

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

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

Power [Member]

Income Taxes [Line Items]

Income Taxes

Income Taxes

PSEG’s, PSE&G’s and Power’s effective tax rates for the three months and six months ended June 30, 2017 and 2016 were as

follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2017	2016	2017	2016
PSEG	35.1%	32.7%	28.3%	36.2%
PSE&G	37.2%	35.4%	36.7%	36.1%
Power	39.0%	50.0%	40.0%	39.5%

For the three months and six months ended June 30, 2017, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items. For the six months ended June 30, 2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.

For the three months and six months ended June 30, 2017, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow-through items.

For the three months ended June 30, 2017, the differences in Power’s effective tax rate as compared to the same period in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, ITC and manufacturing deduction.

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

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

XML

Accumulated Other Comprehensive Income (Loss), Net of Tax

6 Months Ended

Jun. 30, 2017

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)
	Three Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2017	$	2		$	(392	)	$	148		$	(242	)
Other Comprehensive Income before Reclassifications	—			—			23			23
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			6			(13		)	(7		)
Net Current Period Other Comprehensive Income (Loss)	—			6			10			16
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
PSEG	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	2		$	(378	)	$	107		$	(269	)
Other Comprehensive Income before Reclassifications	(1		)	—			8			7
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			2			10
Net Current Period Other Comprehensive Income (Loss)	(1		)	8			10			17
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	2		$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—			—			53			53
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			12			(28		)	(16		)
Net Current Period Other Comprehensive Income (Loss)	—			12			25			37
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	1			—			18			19
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			16			8			24
Net Current Period Other Comprehensive Income (Loss)	1			16			26			43
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)

Power	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2017	$	—	$	(335	)	$	148		$	(187	)
Other Comprehensive Income before Reclassifications	—		—			22			22
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		5			(12		)	(7		)
Net Current Period Other Comprehensive Income (Loss)	—		5			10			15
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Power	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	—	$	(320	)	$	103		$	(217	)
Other Comprehensive Income before Reclassifications	—		—			6			6
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		7			3			10
Net Current Period Other Comprehensive Income (Loss)	—		7			9			16
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	—	$	(340	)	$	129		$	(211	)
Other Comprehensive Income before Reclassifications	—		—			50			50
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		10			(21		)	(11		)
Net Current Period Other Comprehensive Income (Loss)	—		10			29			39
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—	$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications	—		—			16			16
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		14			9			23
Net Current Period Other Comprehensive Income (Loss)	—		14			25			39
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2017									June 30, 2017
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	4		$	(2	)	$	2
Amortization of Actuarial Loss	O&M Expense	(12		)	5			(7		)	(24		)	10			(14		)
Total Pension and OPEB Plans		(10		)	4			(6		)	(20		)	8			(12		)
Available-for-Sale Securities
Realized Gains	Other Income	34			(17		)	17			70			(34		)	36
Realized Losses	Other Deductions	(6		)	4			(2		)	(13		)	7			(6		)
OTTI	OTTI	(3		)	1			(2		)	(4		)	2			(2		)
Total Available-for-Sale Securities		25			(12		)	13			53			(25		)	28
Total		$	15		$	(8	)	$	7		$	33		$	(17	)	$	16

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	3		$	(1	)	$	2		$	6		$	(2	)	$	4
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)	(34		)	14			(20		)
Total Pension and OPEB Plans		(14		)	6			(8		)	(28		)	12			(16		)
Available-for-Sale Securities
Realized Gains	Other Income	12			(6		)	6			28			(14		)	14
Realized Losses	Other Deductions	(7		)	4			(3		)	(24		)	12			(12		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(5		)	3			(2		)	(16		)	8			(8		)
Total		$	(19	)	$	9		$	(10	)	$	(44	)	$	20		$	(24	)

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2017									June 30, 2017
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	4		$	(2	)	$	2
Amortization of Actuarial Loss	O&M Expense	(10		)	4			(6		)	(21		)	9			(12		)
Total Pension and OPEB Plans		(8		)	3			(5		)	(17		)	7			(10		)
Available-for-Sale Securities
Realized Gains	Other Income	32			(16		)	16			57			(29		)	28
Realized Losses	Other Deductions	(5		)	3			(2		)	(10		)	5			(5		)
OTTI	OTTI	(3		)	1			(2		)	(4		)	2			(2		)
Total Available-for-Sale Securities		24			(12		)	12			43			(22		)	21
Total		$	16		$	(9	)	$	7		$	26		$	(15	)	$	11

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	5		$	(2	)	$	3
Amortization of Actuarial Loss	O&M Expense	(14		)	6			(8		)	(29		)	12			(17		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	10			(5		)	5			25			(13		)	12
Realized Losses	Other Deductions	(6		)	3			(3		)	(22		)	11			(11		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(6		)	3			(3		)	(17		)	8			(9		)
Total		$	(18	)	$	8		$	(10	)	$	(41	)	$	18		$	(23	)

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)
	Three Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2017	$	2		$	(392	)	$	148		$	(242	)
Other Comprehensive Income before Reclassifications	—			—			23			23
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			6			(13		)	(7		)
Net Current Period Other Comprehensive Income (Loss)	—			6			10			16
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
PSEG	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	2		$	(378	)	$	107		$	(269	)
Other Comprehensive Income before Reclassifications	(1		)	—			8			7
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			2			10
Net Current Period Other Comprehensive Income (Loss)	(1		)	8			10			17
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	2		$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—			—			53			53
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			12			(28		)	(16		)
Net Current Period Other Comprehensive Income (Loss)	—			12			25			37
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	1			—			18			19
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			16			8			24
Net Current Period Other Comprehensive Income (Loss)	1			16			26			43
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)

Power	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2017	$	—	$	(335	)	$	148		$	(187	)
Other Comprehensive Income before Reclassifications	—		—			22			22
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		5			(12		)	(7		)
Net Current Period Other Comprehensive Income (Loss)	—		5			10			15
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Power	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	—	$	(320	)	$	103		$	(217	)
Other Comprehensive Income before Reclassifications	—		—			6			6
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		7			3			10
Net Current Period Other Comprehensive Income (Loss)	—		7			9			16
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	—	$	(340	)	$	129		$	(211	)
Other Comprehensive Income before Reclassifications	—		—			50			50
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		10			(21		)	(11		)
Net Current Period Other Comprehensive Income (Loss)	—		10			29			39
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—	$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications	—		—			16			16
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		14			9			23
Net Current Period Other Comprehensive Income (Loss)	—		14			25			39
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2017									June 30, 2017
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	4		$	(2	)	$	2
Amortization of Actuarial Loss	O&M Expense	(12		)	5			(7		)	(24		)	10			(14		)
Total Pension and OPEB Plans		(10		)	4			(6		)	(20		)	8			(12		)
Available-for-Sale Securities
Realized Gains	Other Income	34			(17		)	17			70			(34		)	36
Realized Losses	Other Deductions	(6		)	4			(2		)	(13		)	7			(6		)
OTTI	OTTI	(3		)	1			(2		)	(4		)	2			(2		)
Total Available-for-Sale Securities		25			(12		)	13			53			(25		)	28
Total		$	15		$	(8	)	$	7		$	33		$	(17	)	$	16

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	3		$	(1	)	$	2		$	6		$	(2	)	$	4
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)	(34		)	14			(20		)
Total Pension and OPEB Plans		(14		)	6			(8		)	(28		)	12			(16		)
Available-for-Sale Securities
Realized Gains	Other Income	12			(6		)	6			28			(14		)	14
Realized Losses	Other Deductions	(7		)	4			(3		)	(24		)	12			(12		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(5		)	3			(2		)	(16		)	8			(8		)
Total		$	(19	)	$	9		$	(10	)	$	(44	)	$	20		$	(24	)

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2017									June 30, 2017
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	4		$	(2	)	$	2
Amortization of Actuarial Loss	O&M Expense	(10		)	4			(6		)	(21		)	9			(12		)
Total Pension and OPEB Plans		(8		)	3			(5		)	(17		)	7			(10		)
Available-for-Sale Securities
Realized Gains	Other Income	32			(16		)	16			57			(29		)	28
Realized Losses	Other Deductions	(5		)	3			(2		)	(10		)	5			(5		)
OTTI	OTTI	(3		)	1			(2		)	(4		)	2			(2		)
Total Available-for-Sale Securities		24			(12		)	12			43			(22		)	21
Total		$	16		$	(9	)	$	7		$	26		$	(15	)	$	11

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	5		$	(2	)	$	3
Amortization of Actuarial Loss	O&M Expense	(14		)	6			(8		)	(29		)	12			(17		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	10			(5		)	5			25			(13		)	12
Realized Losses	Other Deductions	(6		)	3			(3		)	(22		)	11			(11		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(6		)	3			(3		)	(17		)	8			(9		)
Total		$	(18	)	$	8		$	(10	)	$	(41	)	$	18		$	(23	)

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Earnings Per Share (EPS) and Dividends

6 Months Ended

Jun. 30, 2017

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	109	$	109	$	187	$	187	$	223	$	223	$	658	$	658
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505		505		505		505		505
Effect of Stock Based Compensation Awards	—		2		—		3		—		2		—		3
Total Shares	505		507		505		508		505		507		505		508
EPS
Net Income	$	0.22	$	0.22	$	0.37	$	0.37	$	0.44	$	0.44	$	1.30	$	1.30

There were approximately 0.3 million of stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for each of the three month and six month periods ended June 30, 2017 and June 30, 2016.

Dividends

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2017		2016		2017		2016
Per Share	$	0.43	$	0.41	$	0.86	$	0.82
In Millions	$	217	$	208	$	435	$	415

On July 18, 2017, PSEG’s Board of Directors approved a $0.43 per share common stock dividend for the third quarter of 2017.

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Financial Information By Business Segments

6 Months Ended

Jun. 30, 2017

Segment Reporting Information [Line Items]

Financial Information By Business Segments

Financial Information by Business Segment

	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Three Months Ended June 30, 2017
Total Operating Revenues	$	1,368	$	929		$	116		$	(280	)	$	2,133
Net Income (Loss)	208		(97		)	(2		)	—			109
Gross Additions to Long-Lived Assets	641		269			9			—			919
Six Months Ended June 30, 2017
Operating Revenues	$	3,180	$	2,213		$	199		$	(867	)	$	4,725
Net Income (Loss)	507		(267		)	(17		)	—			223
Gross Additions to Long-Lived Assets	1,389		576			16			—			1,981
Three Months Ended June 30, 2016
Total Operating Revenues	$	1,350	$	714		$	127		$	(286	)	$	1,905
Net Income (Loss)	179		(11		)	19			—			187
Gross Additions to Long-Lived Assets	631		265			10			—			906
Six Months Ended June 30, 2016
Operating Revenues	$	3,062	$	2,027		$	249		$	(817	)	$	4,521
Net Income (Loss)	441		181			36			—			658
Gross Additions to Long-Lived Assets	1,355		598			18			—			1,971
As of June 30, 2017
Total Assets	$	27,273	$	11,619		$	2,425		$	(793	)	$	40,524
Investments in Equity Method Subsidiaries	$	—	$	91		$	—		$	—		$	91
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 relate primarily to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 18. Related-Party Transactions.

PSE And G [Member]

Segment Reporting Information [Line Items]

Financial Information By Business Segments

Financial Information by Business Segment

	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Three Months Ended June 30, 2017
Total Operating Revenues	$	1,368	$	929		$	116		$	(280	)	$	2,133
Net Income (Loss)	208		(97		)	(2		)	—			109
Gross Additions to Long-Lived Assets	641		269			9			—			919
Six Months Ended June 30, 2017
Operating Revenues	$	3,180	$	2,213		$	199		$	(867	)	$	4,725
Net Income (Loss)	507		(267		)	(17		)	—			223
Gross Additions to Long-Lived Assets	1,389		576			16			—			1,981
Three Months Ended June 30, 2016
Total Operating Revenues	$	1,350	$	714		$	127		$	(286	)	$	1,905
Net Income (Loss)	179		(11		)	19			—			187
Gross Additions to Long-Lived Assets	631		265			10			—			906
Six Months Ended June 30, 2016
Operating Revenues	$	3,062	$	2,027		$	249		$	(817	)	$	4,521
Net Income (Loss)	441		181			36			—			658
Gross Additions to Long-Lived Assets	1,355		598			18			—			1,971
As of June 30, 2017
Total Assets	$	27,273	$	11,619		$	2,425		$	(793	)	$	40,524
Investments in Equity Method Subsidiaries	$	—	$	91		$	—		$	—		$	91
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 relate primarily to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 18. Related-Party Transactions.

Power [Member]

Segment Reporting Information [Line Items]

Financial Information By Business Segments

Financial Information by Business Segment

	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Three Months Ended June 30, 2017
Total Operating Revenues	$	1,368	$	929		$	116		$	(280	)	$	2,133
Net Income (Loss)	208		(97		)	(2		)	—			109
Gross Additions to Long-Lived Assets	641		269			9			—			919
Six Months Ended June 30, 2017
Operating Revenues	$	3,180	$	2,213		$	199		$	(867	)	$	4,725
Net Income (Loss)	507		(267		)	(17		)	—			223
Gross Additions to Long-Lived Assets	1,389		576			16			—			1,981
Three Months Ended June 30, 2016
Total Operating Revenues	$	1,350	$	714		$	127		$	(286	)	$	1,905
Net Income (Loss)	179		(11		)	19			—			187
Gross Additions to Long-Lived Assets	631		265			10			—			906
Six Months Ended June 30, 2016
Operating Revenues	$	3,062	$	2,027		$	249		$	(817	)	$	4,521
Net Income (Loss)	441		181			36			—			658
Gross Additions to Long-Lived Assets	1,355		598			18			—			1,971
As of June 30, 2017
Total Assets	$	27,273	$	11,619		$	2,425		$	(793	)	$	40,524
Investments in Equity Method Subsidiaries	$	—	$	91		$	—		$	—		$	91
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 relate primarily to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 18. Related-Party Transactions.

XML

Related-Party Transactions

6 Months Ended

Jun. 30, 2017

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 as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Administrative Billings from Services (B)	79		82		144		151
Total Billings from Affiliates	$	375	$	379	$	1,039	$	993

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSEG (C)	$	20	$	76
Payable to Power (A)	$	90	$	193
Payable to Services (B)	56		67
Accounts Payable—Affiliated Companies	$	146	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	115	$	130

Power

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Billings from Affiliates:
Administrative Billings from Services (B)	$	42	$	45	$	78	$	90

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSE&G (A)	$	90	$	193
Receivables from PSEG (C)	49		12
Accounts Receivable—Affiliated Companies	$	139	$	205
Payable to Services (B)	$	20	$	25
Accounts Payable—Affiliated Companies	$	20	$	25
Short-Term Loan Due (to) from Affiliate (E)	$	233	$	87
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	93	$	77

(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. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.

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

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

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

(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 And 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 as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Administrative Billings from Services (B)	79		82		144		151
Total Billings from Affiliates	$	375	$	379	$	1,039	$	993

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSEG (C)	$	20	$	76
Payable to Power (A)	$	90	$	193
Payable to Services (B)	56		67
Accounts Payable—Affiliated Companies	$	146	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	115	$	130

Power

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Billings from Affiliates:
Administrative Billings from Services (B)	$	42	$	45	$	78	$	90

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSE&G (A)	$	90	$	193
Receivables from PSEG (C)	49		12
Accounts Receivable—Affiliated Companies	$	139	$	205
Payable to Services (B)	$	20	$	25
Accounts Payable—Affiliated Companies	$	20	$	25
Short-Term Loan Due (to) from Affiliate (E)	$	233	$	87
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	93	$	77

(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. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.

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

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

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

(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 as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Administrative Billings from Services (B)	79		82		144		151
Total Billings from Affiliates	$	375	$	379	$	1,039	$	993

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSEG (C)	$	20	$	76
Payable to Power (A)	$	90	$	193
Payable to Services (B)	56		67
Accounts Payable—Affiliated Companies	$	146	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	115	$	130

Power

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Billings from Affiliates:
Administrative Billings from Services (B)	$	42	$	45	$	78	$	90

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSE&G (A)	$	90	$	193
Receivables from PSEG (C)	49		12
Accounts Receivable—Affiliated Companies	$	139	$	205
Payable to Services (B)	$	20	$	25
Accounts Payable—Affiliated Companies	$	20	$	25
Short-Term Loan Due (to) from Affiliate (E)	$	233	$	87
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	93	$	77

(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. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.

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

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

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

(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.

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Guarantees of Debt

6 Months Ended

Jun. 30, 2017

Debt Instrument [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 June 30, 2017 and December 31, 2016 and for the three months and six months ended June 30, 2017 and 2016.

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2017
Operating Revenues	$	—		$	910		$	47		$	(28	)	$	929
Operating Expenses	(2		)	1,103			43			(28		)	1,116
Operating Income (Loss)	2			(193		)	4			—			(187		)
Equity Earnings (Losses) of Subsidiaries	(93		)	(4		)	5			97			5
Other Income	22			56			2			(34		)	46
Other Deductions	—			(7		)	—			—			(7		)
Other-Than-Temporary Impairments	—			(3		)	—			—			(3		)
Interest Expense	(34		)	(9		)	(4		)	34			(13		)
Income Tax Benefit (Expense)	6			60			(4		)	—			62
Net Income (Loss)	$	(97	)	$	(100	)	$	3		$	97		$	(97	)
Comprehensive Income (Loss)	$	(82	)	$	(91	)	$	3		$	88		$	(82	)
Six Months Ended June 30, 2017
Operating Revenues	$	—		$	2,180		$	99		$	(66	)	$	2,213
Operating Expenses	2			2,672			95			(66		)	2,703
Operating Income (Loss)	(2		)	(492		)	4			—			(490		)
Equity Earnings (Losses) of Subsidiaries	(254		)	(5		)	8			259			8
Other Income	47			97			2			(62		)	84
Other Deductions	(1		)	(13		)	—			—			(14		)
Other-Than-Temporary Impairments	—			(4		)	—			—			(4		)
Interest Expense	(64		)	(18		)	(9		)	62			(29		)
Income Tax Benefit (Expense)	7			171			—			—			178
Net Income (Loss)	$	(267	)	$	(264	)	$	5		$	259		$	(267	)
Comprehensive Income (Loss)	$	(228	)	$	(234	)	$	5		$	229		$	(228	)
Six Months Ended June 30, 2017
Net Cash Provided By (Used In)    Operating Activities	$	(32	)	$	802		$	111		$	51		$	932
Net Cash Provided By (Used In)    Investing Activities	$	683		$	178		$	(241	)	$	(1,355	)	$	(735	)
Net Cash Provided By (Used In)    Financing Activities	$	(651	)	$	(978	)	$	146		$	1,304		$	(179	)

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2016
Operating Revenues	$	—		$	700		$	46		$	(32	)	$	714
Operating Expenses	2			716			40			(32		)	726
Operating Income (Loss)	(2		)	(16		)	6			—			(12		)
Equity Earnings (Losses) of Subsidiaries	(1		)	1			4			—			4
Other Income	17			30			—			(22		)	25
Other Deductions	—			(9		)	—			—			(9		)
Other-Than-Temporary Impairments	—			(10		)	—			—			(10		)
Interest Expense	(31		)	(7		)	(4		)	22			(20		)
Income Tax Benefit (Expense)	6			3			2			—			11
Net Income (Loss)	$	(11	)	$	(8	)	$	8		$	—		$	(11	)
Comprehensive Income (Loss)	$	5		$	1		$	8		$	(9	)	$	5
Six Months Ended June 30, 2016
Operating Revenues	$	—		$	2,002		$	88		$	(63	)	$	2,027
Operating Expenses	12			1,668			79			(63		)	1,696
Operating Income (Loss)	(12		)	334			9			—			331
Equity Earnings (Losses) of Subsidiaries	204			—			6			(204		)	6
Other Income	34			62			—			(45		)	51
Other Deductions	—			(27		)	—			—			(27		)
Other-Than-Temporary Impairments	—			(20		)	—			—			(20		)
Interest Expense	(61		)	(17		)	(9		)	45			(42		)
Income Tax Benefit (Expense)	16			(137		)	3			—			(118		)
Net Income (Loss)	$	181		$	195		$	9		$	(204	)	$	181
Comprehensive Income (Loss)	$	220		$	220		$	9		$	(229	)	$	220
Six Months Ended June 30, 2016
Net Cash Provided By (Used In)    Operating Activities	$	337		$	777		$	159		$	(356	)	$	917
Net Cash Provided By (Used In)    Investing Activities	$	(1,287	)	$	(504	)	$	(395	)	$	579		$	(1,607	)
Net Cash Provided By (Used In)    Financing Activities	$	951		$	(273	)	$	239		$	(223	)	$	694

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2017
Current Assets	$	4,156	$	1,257	$	182	$	(4,213	)	$	1,382
Property, Plant and Equipment, net	56		5,244		2,526		—			7,826
Investment in Subsidiaries	4,015		340		—		(4,355		)	—
Noncurrent Assets	184		2,225		119		(117		)	2,411
Total Assets	$	8,411	$	9,066	$	2,827	$	(8,685	)	$	11,619
Current Liabilities	$	88	$	3,156	$	1,648	$	(4,213	)	$	679
Noncurrent Liabilities	543		2,195		539		(117		)	3,160
Long-Term Debt	2,384		—		—		—			2,384
Member’s Equity	5,396		3,715		640		(4,355		)	5,396
Total Liabilities and Member’s Equity	$	8,411	$	9,066	$	2,827	$	(8,685	)	$	11,619
As of December 31, 2016
Current Assets	$	4,412	$	1,593	$	152	$	(4,697	)	$	1,460
Property, Plant and Equipment, net	55		6,145		2,320		—			8,520
Investment in Subsidiaries	4,249		344		—		(4,593		)	—
Noncurrent Assets	168		2,016		129		(100		)	2,213
Total Assets	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193
Current Liabilities	$	171	$	3,752	$	1,454	$	(4,697	)	$	680
Noncurrent Liabilities	532		2,398		502		(100		)	3,332
Long-Term Debt	2,382		—		—		—			2,382
Member’s Equity	5,799		3,948		645		(4,593		)	5,799
Total Liabilities and Member’s Equity	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193

Power [Member]

Debt Instrument [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 June 30, 2017 and December 31, 2016 and for the three months and six months ended June 30, 2017 and 2016.

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2017
Operating Revenues	$	—		$	910		$	47		$	(28	)	$	929
Operating Expenses	(2		)	1,103			43			(28		)	1,116
Operating Income (Loss)	2			(193		)	4			—			(187		)
Equity Earnings (Losses) of Subsidiaries	(93		)	(4		)	5			97			5
Other Income	22			56			2			(34		)	46
Other Deductions	—			(7		)	—			—			(7		)
Other-Than-Temporary Impairments	—			(3		)	—			—			(3		)
Interest Expense	(34		)	(9		)	(4		)	34			(13		)
Income Tax Benefit (Expense)	6			60			(4		)	—			62
Net Income (Loss)	$	(97	)	$	(100	)	$	3		$	97		$	(97	)
Comprehensive Income (Loss)	$	(82	)	$	(91	)	$	3		$	88		$	(82	)
Six Months Ended June 30, 2017
Operating Revenues	$	—		$	2,180		$	99		$	(66	)	$	2,213
Operating Expenses	2			2,672			95			(66		)	2,703
Operating Income (Loss)	(2		)	(492		)	4			—			(490		)
Equity Earnings (Losses) of Subsidiaries	(254		)	(5		)	8			259			8
Other Income	47			97			2			(62		)	84
Other Deductions	(1		)	(13		)	—			—			(14		)
Other-Than-Temporary Impairments	—			(4		)	—			—			(4		)
Interest Expense	(64		)	(18		)	(9		)	62			(29		)
Income Tax Benefit (Expense)	7			171			—			—			178
Net Income (Loss)	$	(267	)	$	(264	)	$	5		$	259		$	(267	)
Comprehensive Income (Loss)	$	(228	)	$	(234	)	$	5		$	229		$	(228	)
Six Months Ended June 30, 2017
Net Cash Provided By (Used In)    Operating Activities	$	(32	)	$	802		$	111		$	51		$	932
Net Cash Provided By (Used In)    Investing Activities	$	683		$	178		$	(241	)	$	(1,355	)	$	(735	)
Net Cash Provided By (Used In)    Financing Activities	$	(651	)	$	(978	)	$	146		$	1,304		$	(179	)

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2016
Operating Revenues	$	—		$	700		$	46		$	(32	)	$	714
Operating Expenses	2			716			40			(32		)	726
Operating Income (Loss)	(2		)	(16		)	6			—			(12		)
Equity Earnings (Losses) of Subsidiaries	(1		)	1			4			—			4
Other Income	17			30			—			(22		)	25
Other Deductions	—			(9		)	—			—			(9		)
Other-Than-Temporary Impairments	—			(10		)	—			—			(10		)
Interest Expense	(31		)	(7		)	(4		)	22			(20		)
Income Tax Benefit (Expense)	6			3			2			—			11
Net Income (Loss)	$	(11	)	$	(8	)	$	8		$	—		$	(11	)
Comprehensive Income (Loss)	$	5		$	1		$	8		$	(9	)	$	5
Six Months Ended June 30, 2016
Operating Revenues	$	—		$	2,002		$	88		$	(63	)	$	2,027
Operating Expenses	12			1,668			79			(63		)	1,696
Operating Income (Loss)	(12		)	334			9			—			331
Equity Earnings (Losses) of Subsidiaries	204			—			6			(204		)	6
Other Income	34			62			—			(45		)	51
Other Deductions	—			(27		)	—			—			(27		)
Other-Than-Temporary Impairments	—			(20		)	—			—			(20		)
Interest Expense	(61		)	(17		)	(9		)	45			(42		)
Income Tax Benefit (Expense)	16			(137		)	3			—			(118		)
Net Income (Loss)	$	181		$	195		$	9		$	(204	)	$	181
Comprehensive Income (Loss)	$	220		$	220		$	9		$	(229	)	$	220
Six Months Ended June 30, 2016
Net Cash Provided By (Used In)    Operating Activities	$	337		$	777		$	159		$	(356	)	$	917
Net Cash Provided By (Used In)    Investing Activities	$	(1,287	)	$	(504	)	$	(395	)	$	579		$	(1,607	)
Net Cash Provided By (Used In)    Financing Activities	$	951		$	(273	)	$	239		$	(223	)	$	694

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2017
Current Assets	$	4,156	$	1,257	$	182	$	(4,213	)	$	1,382
Property, Plant and Equipment, net	56		5,244		2,526		—			7,826
Investment in Subsidiaries	4,015		340		—		(4,355		)	—
Noncurrent Assets	184		2,225		119		(117		)	2,411
Total Assets	$	8,411	$	9,066	$	2,827	$	(8,685	)	$	11,619
Current Liabilities	$	88	$	3,156	$	1,648	$	(4,213	)	$	679
Noncurrent Liabilities	543		2,195		539		(117		)	3,160
Long-Term Debt	2,384		—		—		—			2,384
Member’s Equity	5,396		3,715		640		(4,355		)	5,396
Total Liabilities and Member’s Equity	$	8,411	$	9,066	$	2,827	$	(8,685	)	$	11,619
As of December 31, 2016
Current Assets	$	4,412	$	1,593	$	152	$	(4,697	)	$	1,460
Property, Plant and Equipment, net	55		6,145		2,320		—			8,520
Investment in Subsidiaries	4,249		344		—		(4,593		)	—
Noncurrent Assets	168		2,016		129		(100		)	2,213
Total Assets	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193
Current Liabilities	$	171	$	3,752	$	1,454	$	(4,697	)	$	680
Noncurrent Liabilities	532		2,398		502		(100		)	3,332
Long-Term Debt	2,382		—		—		—			2,382
Member’s Equity	5,799		3,948		645		(4,593		)	5,799
Total Liabilities and Member’s Equity	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193

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Organization and Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2017

Basis of Presentation

Basis of Presentation

The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2016.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.

Power [Member]

Basis of Presentation

Basis of Presentation

The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2016.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.

PSE And G [Member]

Basis of Presentation

Basis of Presentation

The financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2016.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.

XML

Recent Accounting Standards (Policies)

6 Months Ended

Jun. 30, 2017

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

New Standards Issued But Not Yet Adopted

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

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

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possible changes in presentation.

PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the transmission and distribution of electricity and distribution of gas to retail residential and commercial and industrial customers, is in scope of the new accounting standard. PSEG expects no change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. Revenue from contracts with customers will be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. Upon formal resolution of the implementation issues noted above, and upon completion of contract evaluations, PSEG will elect its transition method.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

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

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.

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

Measurement of Credit Losses on Financial Instruments

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

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

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.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements including its future disclosure requirements.

Business Combinations: Clarifying the Definition of a Business

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.

Simplifying the Test for Goodwill Impairment

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

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)

This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.

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 will be eligible for capitalization, when applicable.

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

Premium Amortization on Purchased Callable Debt Securities

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

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

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

PSEG is currently analyzing the impact of this standard on its financial statements.

Stock Compensation - Scope of Modification Accounting

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

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

PSE And G [Member]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

New Standards Issued But Not Yet Adopted

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

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

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possible changes in presentation.

PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the transmission and distribution of electricity and distribution of gas to retail residential and commercial and industrial customers, is in scope of the new accounting standard. PSEG expects no change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. Revenue from contracts with customers will be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. Upon formal resolution of the implementation issues noted above, and upon completion of contract evaluations, PSEG will elect its transition method.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

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

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.

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

Measurement of Credit Losses on Financial Instruments

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

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

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.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements including its future disclosure requirements.

Business Combinations: Clarifying the Definition of a Business

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.

Simplifying the Test for Goodwill Impairment

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

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)

This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.

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 will be eligible for capitalization, when applicable.

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

Premium Amortization on Purchased Callable Debt Securities

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

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

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

PSEG is currently analyzing the impact of this standard on its financial statements.

Stock Compensation - Scope of Modification Accounting

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

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

Power [Member]

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

New Standards Issued But Not Yet Adopted

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

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

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possible changes in presentation.

PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the transmission and distribution of electricity and distribution of gas to retail residential and commercial and industrial customers, is in scope of the new accounting standard. PSEG expects no change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. Revenue from contracts with customers will be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. Upon formal resolution of the implementation issues noted above, and upon completion of contract evaluations, PSEG will elect its transition method.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

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

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.

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

Measurement of Credit Losses on Financial Instruments

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

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

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.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

Statement of Cash Flows: Restricted Cash

This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements including its future disclosure requirements.

Business Combinations: Clarifying the Definition of a Business

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

The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.

Simplifying the Test for Goodwill Impairment

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

An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)

This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.

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 will be eligible for capitalization, when applicable.

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

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. PSEG is currently analyzing the impact of this standard on its financial statements.

Premium Amortization on Purchased Callable Debt Securities

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

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

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

PSEG is currently analyzing the impact of this standard on its financial statements.

Stock Compensation - Scope of Modification Accounting

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

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

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Early Plant Retirements Early Plant Retirements (Tables)

6 Months Ended

Jun. 30, 2017

Early Plant Retirements [Line Items]

Schedule of Balance Sheet Amounts by Generating Station

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

	As of June 30, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	83		$	80		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	453			561			208		758
Nuclear Fuel In-Service, net of Accumulated Depreciation	136			113			—		125
Construction Work in Progress (including nuclear fuel)	168			109			9		31
Total Assets	$	840		$	863		$	217	$	955
Liability
Asset Retirement Obligation	$	146		$	159		$	—	$	162
Total Liabilities	$	146		$	159		$	—	$	162
Net Assets	$	694		$	704		$	217	$	793
NRC License Renewal Term	2046			2036/2040			—		2033/2034
% Owned	100		%	57		%	—		50		%

XML

Financing Receivables (Tables)

6 Months Ended

Jun. 30, 2017

PSE And G [Member]

Schedule of Financial Receivables [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 are considered “non-performing.”

Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	June 30, 2017		December 31, 2016
	Millions
Commercial/Industrial	$	167	$	164
Residential	11		11
Total	$	178	$	175

Energy Holdings [Member]

Schedule of Financial Receivables [Line Items]

Schedule Of Gross And Net Lease Investment

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

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	559		$	629
Estimated Residual Value of Leased Assets	333			346
Total Investment in Rental Receivables	892			975
Unearned and Deferred Income	(315		)	(326		)
Gross Investment in Leases	577			649
Deferred Tax Liabilities	(619		)	(674		)
Net Investment in Leases	$	(42	)	$	(25	)

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 in the following table, 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 June 30, 2017
	As of June 30, 2017
	Millions
AA	$	15
BBB+ — BBB-	317
BB-	133
CC	94
Total	$	559

Schedule Of Assets Under Lease Receivables

A more detailed description of such assets under lease, as of June 30, 2017, is presented in the following table.

Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	83	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Shawville Station Units 1, 2, 3 and 4	PA	$	91	100	%	596	Gas	CC (A)	REMA

(A) REMA’s parent company, GenOn, and certain of its subsidiaries (which did not include REMA) filed voluntary

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Available-for-Sale Securities (Tables)

6 Months Ended

Jun. 30, 2017

Schedule of Available-for-sale Securities [Line Items]

Fair Values And Gross Unrealized Gains And Losses For The Securities Held In The NDT Fund

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

	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	699	$	305	$	(5	)	$	999
Debt Securities
Government	551		10		(4		)	557
Corporate	356		6		(1		)	361
Total Debt Securities	907		16		(5		)	918
Other Securities	51		—		—			51
Total NDT Available-for-Sale Securities	$	1,657	$	321	$	(10	)	$	1,968

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858

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

Schedule Of Accounts Receivable And Accounts Payable in the NDT Funds

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	25	$	8
Accounts Payable	$	22	$	5

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 June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	63	$	(5	)	$	—	$	—	$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	279		(4		)	7		—		276		(6		)	4		—
Corporate (C)	94		(1		)	7		—		139		(3		)	15		(1		)
Total Debt Securities	373		(5		)	14		—		415		(9		)	19		(1		)
Other Securities	51		—			—		—		—		—			—		—
NDT Available-for-Sale Securities	$	487	$	(10	)	$	14	$	—	$	535	$	(19	)	$	27	$	(2	)

(A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2017.

(B) Debt Securities (Government)—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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

Proceeds From The Sales Of And The Net Realized Gains On Securities In The NDT Funds And Rabbi Trusts

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from NDT Fund Sales (A)	$	320		$	154		$	567		$	331
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	32		$	10		$	53		$	25
Gross Realized Losses	(5		)	(6		)	(9		)	(22		)
Net Realized Gains (Losses) on NDT Fund	$	27		$	4		$	44		$	3

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

Amount Of Available-For-Sale Debt Securities By Maturity Periods

The NDT available-for-sale debt securities held as of June 30, 2017 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	29
1 - 5 years	239
6 - 10 years	223
11 - 15 years	65
16 - 20 years	66
Over 20 years	296
Total NDT Available-for-Sale Debt Securities	$	918

Rabbi Trust [Member]

Schedule of Available-for-sale Securities [Line Items]

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 12 months and greater than 12 months.

	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government (B)	29		(1		)	1		—		60		(2		)	1		—
Corporate (C)	19		—			3		—		46		(2		)	3		—
Total Debt Securities	48		(1		)	4		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	48	$	(1	)	$	4	$	—	$	106	$	(4	)	$	4	$	—

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

(B) Debt Securities (Government)—Unrealized 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 June 30, 2017.

(C) Debt Securities (Corporate)—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 June 30, 2017.

Securities Held In The Rabbi Trusts

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 June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	—	$	—		$	22
Debt Securities
Government	85		1		(1		)	85
Corporate	113		2		—			115
Total Debt Securities	198		3		(1		)	200
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	222	$	3	$	(1	)	$	224

	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	11	$	—		$	22
Debt Securities
Government	105		—		(2		)	103
Corporate	92		1		(2		)	91
Total Debt Securities	197		1		(4		)	194
Other Securities	1		—		—			1
Total Rabbi Trust Available-for-Sale Securities	$	209	$	12	$	(4	)	$	217

Schedule of Accounts Receivable and Accounts Payable in the Rabbi Trust Funds [Table Text Block]

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	—	$	3

Proceeds From The Sales Of And The Net Realized Gains On Securities In The NDT Funds And Rabbi Trusts

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)	$	93		$	36		$	144		$	61
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2		$	17		$	3
Gross Realized Losses	(1		)	(1		)	(4		)	(2		)
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	1		$	13		$	1

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

Amount Of Available-For-Sale Debt Securities By Maturity Periods

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

Time Frame	Fair Value
	Millions
Less than one year	$	1
1 - 5 years	35
6 - 10 years	29
11 - 15 years	6
16 - 20 years	18
Over 20 years	111
Total Rabbi Trust Available-for-Sale Debt Securities	$	200

Fair Value Of The Rabbi Trusts

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

	As of		As of
	June 30, 2017		December 31, 2016
	Millions
PSE&G	$	45	$	43
Power	55		53
Other	124		121
Total Rabbi Trust Available-for-Sale Securities	$	224	$	217

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Pension and OPEB (Tables)

6 Months Ended

Jun. 30, 2017

Compensation and Retirement Disclosure [Abstract]

Components Of Net Periodic Benefit Cost

The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco.

	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Six Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2017			2016			2017			2016			2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	28		$	27		$	4		$	4		$	57		$	54		$	8		$	8
Interest Cost	51			51			16			14			102			101			32			29
Expected Return on Plan Assets	(99		)	(99		)	(9		)	(7		)	(197		)	(197		)	(17		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(4		)	(5		)	(2		)	(4		)	(9		)	(9		)	(5		)	(7		)
Actuarial Loss	25			40			12			10			49			79			25			20
Total Benefit Costs	$	1		$	14		$	21		$	17		$	2		$	28		$	43		$	35

Schedule Of Pension And OPEB Costs

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

	Pension Benefits					OPEB				Pension Benefits					OPEB
	Three Months Ended					Three Months Ended				Six Months Ended					Six Months Ended
	June 30,					June 30,				June 30,					June 30,
	2017			2016		2017		2016		2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	7	$	13	$	11	$	(2	)	$	14	$	27	$	22
Power	1			4		6		5		1			8		13		11
Other	1			3		2		1		3			6		3		2
Total Benefit Costs	$	1		$	14	$	21	$	17	$	2		$	28	$	43	$	35

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Commitments and Contingent Liabilities (Tables)

6 Months Ended

Jun. 30, 2017

Power [Member]

Loss Contingencies [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 June 30, 2017 and December 31, 2016.

	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,898		$	1,806
Exposure under Current Guarantees	$	137		$	139
Letters of Credit Margin Posted	$	142		$	157
Letters of Credit Margin Received	$	98		$	99
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(1	)
Net Broker Balance Deposited (Received)	$	(2	)	$	57
Additional Amounts Posted:
Other Letters of Credit	$	61		$	51

Total Minimum Purchase Commitments

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

Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	301
Enrichment	$	340
Fabrication	$	184
Natural Gas	$	1,040
Coal	$	331

PSE And G [Member]

Loss Contingencies [Line Items]

Contract For Anticipated BGS-Fixed Price Eligible Load

	Auction Year
	2014	2015	2016	2017
36-Month Terms Ending	May 2017	May 2018	May 2019	May 2020	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$97.39	$99.54	$96.38	$90.78

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

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Debt and Credit Facilities Debt and Credit Facilities (Tables)

6 Months Ended

Jun. 30, 2017

Debt and Credit Facilities [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of June 30, 2017 were as follows:

	As of June 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	13	$	1,487	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	13	$	1,487
PSE&G
5-year Credit Facility (A)	$	600	$	15	$	585	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	15	$	585
Power
3-year LC Facilities	$	200	$	140	$	60	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		50		1,850		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	190	$	1,910
Total	$	4,200	$	218	$	3,982

(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 June 30, 2017, neither PSEG nor PSE&G had amounts outstanding.

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Financial Risk Management Activities (Tables)

6 Months Ended

Jun. 30, 2017

Derivative Instruments and Hedging Activities Disclosures [Line Items]

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 June 30, 2017
	Power (A)									PSEG (A)		Consolidated
	Not Designated									Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	479		$	(367	)	$	112		$	1	$	113
Noncurrent Assets	268			(178		)	90			—		90
Total Mark-to-Market Derivative Assets	$	747		$	(545	)	$	202		$	1	$	203
Derivative Contracts
Current Liabilities	$	(373	)	$	365		$	(8	)	$	—	$	(8	)
Noncurrent Liabilities	(170		)	169			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(543	)	$	534		$	(9	)	$	—	$	(9	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	204		$	(11	)	$	193		$	1	$	194

	As of December 31, 2016
	Power (A)									PSE&G (A)			PSEG (A)		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	435		$	(273	)	$	162		$	—		$	1	$	163
Noncurrent Assets	122			(98		)	24			—			—		24
Total Mark-to-Market Derivative Assets	$	557		$	(371	)	$	186		$	—		$	1	$	187
Derivative Contracts
Current Liabilities	$	(285	)	$	277		$	(8	)	$	(5	)	$	—	$	(13	)
Noncurrent Liabilities	(98		)	95			(3		)	—			—		(3		)
Total Mark-to-Market Derivative (Liabilities)	$	(383	)	$	372		$	(11	)	$	(5	)	$	—	$	(16	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	174		$	1		$	175		$	(5	)	$	1	$	171

(A) Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. 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 Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(4) million was netted against current assets, $(9) million was netted against noncurrent assets, and $2 million was netted against current liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities.

Schedule Of Derivative Instruments Designated As Cash Flow Hedges

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months and six months ended June 30, 2017 and 2016.

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2017		2016				2017		2016
	Millions						Millions
PSEG
Interest Rate Swaps	$	—	$	(1	)	Interest Expense	$	—	$	—
Total PSEG	$	—	$	(1	)		$	—	$	—

Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Six Months Ended					Six Months Ended
	June 30,					June 30,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	—		2		Interest Expense	—		—
Total PSEG	$	—	$	2		$	—	$	—

Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block]

Accumulated Other Comprehensive Income	Pre-Tax		After-Tax
	Millions
Balance as of December 31, 2015	$	—	$	—
Gain Recognized in AOCI	3		2
Less: Gain Reclassified into Income	—		—
Balance as of December 31, 2016	$	3	$	2
Gain Recognized in AOCI	—		—
Less: Gain Reclassified into Income	—		—
Balance as of June 30, 2017	$	3	$	2

Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Impact On Results Of Operations

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and six months ended June 30, 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 for 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						Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2017			2016			2017			2016
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	113		$	(86	)	$	196		$	130
Energy-Related Contracts	Energy Costs	(11		)	6			(16		)	8
Total PSEG and Power		$	102		$	(80	)	$	180		$	138

Schedule Of Gross Volume, On Absolute Value Basis For Derivative Contracts

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2017 and December 31, 2016.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2017
Natural Gas	Dekatherm (Dth)	321	—	321	—
Electricity	MWh	349	—	349	—
Financial Transmission Rights (FTRs)	MWh	6	—	6	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—
As of December 31, 2016
Natural Gas	Dth	357	—	348	9
Electricity	MWh	323	—	323	—
FTRs	MWh	9	—	9	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—

Power [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule Providing Credit Risk From Others, Net Of Collateral

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2017. 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.

Rating	Current Exposure		Collateral Held		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	420	$	92	$	328	1	$	130	(A)
Non-Investment Grade	9		—		9		—	—
Total	$	429	$	92	$	337	1	$	130

(A) Represents net exposure of $130 million with PSE&G.

As of June 30, 2017, collateral held from counterparties where Power had credit exposure included $92 million in letters of credit.

As of June 30, 2017, Power had 152 active counterparties.

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

PSEG's, Power's And PSE&G's Respective Assets And (Liabilities) Measured At Fair Value On A 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 June 30, 2017 and December 31, 2016, 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 June 30, 2017
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	367		$	—		$	367		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	51		$	—		$	—		$	51		$	—
Debt Securities—Govt Other	$	34		$	—		$	—		$	34		$	—
Debt Securities—Corporate	$	115		$	—		$	—		$	115		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—
Interest Rate Swaps (C)	$	—		$	—		$	—		$	—		$	—
PSE&G
Assets:
Cash Equivalents (A)	$	169		$	—		$	169		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	10		$	—		$	—		$	10		$	—
Debt Securities—Govt Other	$	7		$	—		$	—		$	7		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	202		$	(545	)	$	9		$	732		$	6
NDT Fund (D)
Equity Securities	$	999		$	—		$	997		$	2		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	330		$	—		$	—		$	330		$	—
Debt Securities—Corporate	$	361		$	—		$	—		$	361		$	—
Other Securities	$	51		$	—		$	51		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	29		$	—		$	—		$	29		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(9	)	$	534		$	(6	)	$	(537	)	$	—

	Recurring Fair Value Measurements as of December 31, 2016
Description	Total			Netting  (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	37		$	—		$	—		$	37		$	—
Debt Securities—Govt Other	$	66		$	—		$	—		$	66		$	—
Debt Securities—Corporate	$	91		$	—		$	—		$	91		$	—
Other Securities	$	1		$	—		$	1		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(16	)	$	372		$	(18	)	$	(364	)	$	(6	)
PSE&G
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	13		$	—		$	—		$	13		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(5	)	$	—		$	—		$	—		$	(5	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	16		$	—		$	—		$	16		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	372		$	(18	)	$	(364	)	$	(1	)

(A) Represents money market mutual funds.

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

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from 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) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(D) The fair value measurement tables exclude an immaterial amount of cash as of June 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of June 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities include primarily investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(13) million of cash collateral was netted against assets, and $2 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

Schedule of Quantitative Information About Level 3 Fair Value Measurements

The following tables provide details surrounding significant Level 3 valuations as of June 30, 2017 and December 31, 2016.

	Quantitative Information About Level 3 Fair Value Measurements
							Significant
		Fair Value as of				Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2017				Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Load Contracts	$	5	$	—	Discounted Cash flow	Historic Load Variability	0% to +10%
Gas (A)	Other	1		—
Total Power		$	6	$	—
Total PSEG		$	6	$	—

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)

(A) Includes gas positions which were immaterial as of June 30, 2017 and December 31, 2016.

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.

Changes In Level 3 Assets And (Liabilities) Measured At Fair Value On A Recurring Basis

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

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

	Three Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	3		$	7	$	(1	)	$	—	$	(3	)	$	—		$	6
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	—	$	(1	)	$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	2		$	7	$	—		$	—	$	(3	)	$	—		$	6
	Six Months Ended June 30, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	26	$	5		$	—	$	(25	)	$	(1	)	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	5		$	—	$	—		$	—		$	—
Power
Net Derivative Assets (Liabilities)	$	6		$	26	$	—		$	—	$	(25	)	$	(1	)	$	6

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

for the Three MonthsandSix Months EndedJune 30, 2016

	Three Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21	$	1	$	(12	)	$	—	$	(5	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	10	$	—	$	(12	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	1	$	—		$	—	$	(5	)	$	—	$	7
	Six Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
PSEG
Net Derivative Assets (Liabilities)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

(A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $7 million and $26 million in Operating Income for the three months and six months ended June 30, 2017, respectively. Of the $7 million in Operating Income, $4 million is unrealized. Of the $26 million in Operating Income, $1 million is unrealized.

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

(C) Represents $(3) million and $(25) million in settlements for the three months and six months ended June 30, 2017, respectively. Represents $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively.

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

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1 million and $16 million in Operating Income for the three months and six months ended June 30, 2016, respectively. Of the $1 million in Operating Income, $(4) million is unrealized. Of the $16 million in Operating Income, $(4) million is unrealized.

Schedule of Fair Value of Debt

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

	As of				As of
	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	1,895	$	1,888	$	1,195	$	1,185
PSE&G (B)	8,242		8,900		7,818		8,240
Power - Recourse Debt (B)	2,384		2,646		2,382		2,578
Total Long-Term Debt	$	12,521	$	13,434	$	11,395	$	12,003

(A) As of June 30, 2017, fair value includes a $700 million floating rate term loan term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016. The fair values of the term loan debt (Level 2 measurement) were considered to be equal to the carrying values because the interest payments are based on LIBOR rates that are reset monthly.

(B) Given that most bonds do not trade, 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.

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Other Income and Deductions (Tables)

6 Months Ended

Jun. 30, 2017

Other Income and Expenses [Abstract]

Schedule Of Other Income

Other Income	PSE&G		Power		Other (A)			Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	45	$	—		$	45
Allowance for Funds Used During Construction	14		—		—			14
Rabbi Trust Realized Gains, Interest and Dividends	1		1		2			$	4
Solar Loan Interest	5		—		—			5
Other	2		—		—			2
Total Other Income	$	22	$	46	$	2		$	70
Six Months Ended June 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	76	$	—		$	76
Allowance for Funds Used During Construction	28		—		—			28
Rabbi Trust Realized Gains, Interest and Dividends	4		5		11			20
Solar Loan Interest	10		—		—			10
Other	5		3		—			8
Total Other Income	$	47	$	84	$	11		$	142
Three Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—		$	23
Allowance for Funds Used During Construction	10		—		—			10
Rabbi Trust Realized Gains, Interest and Dividends	1		1		1			$	3
Solar Loan Interest	5		—		—			5
Other	3		1		(1		)	3
Total Other Income	$	19	$	25	$	—		$	44
Six Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	48	$	—		$	48
Allowance for Funds Used During Construction	21		—		—			21
Rabbi Trust Realized Gains, Interest and Dividends	1		2		3			6
Solar Loan Interest	11		—		—			11
Other	6		1		(1		)	6
Total Other Income	$	39	$	51	$	2		$	92

Schedule Of Other Deductions

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		1		3
Total Other Deductions	$	1	$	7	$	1	$	9
Six Months Ended June 30, 2017
NDT Fund Realized Losses and Expenses	$	—	$	13	$	—	$	13
Other	2		1		4		7
Total Other Deductions	$	2	$	14	$	4	$	20
Three Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	8	$	—	$	8
Other	1		1		—		2
Total Other Deductions	$	1	$	9	$	—	$	10
Six Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	26	$	—	$	26
Other	2		1		2		5
Total Other Deductions	$	2	$	27	$	2	$	31

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

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2017

Income Tax Disclosure [Abstract]

Schedule Of Effective Tax Rates

PSEG’s, PSE&G’s and Power’s effective tax rates for the three months and six months ended June 30, 2017 and 2016 were as

follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2017	2016	2017	2016
PSEG	35.1%	32.7%	28.3%	36.2%
PSE&G	37.2%	35.4%	36.7%	36.1%
Power	39.0%	50.0%	40.0%	39.5%

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Accumulated Other Comprehensive Income (Loss), Net of Tax (Tables)

6 Months Ended

Jun. 30, 2017

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Schedule of Changes in Accumulated Other Comprehensive Income by Component

PSEG	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2017	$	2		$	(392	)	$	148		$	(242	)
Other Comprehensive Income before Reclassifications	—			—			23			23
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			6			(13		)	(7		)
Net Current Period Other Comprehensive Income (Loss)	—			6			10			16
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
PSEG	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	2		$	(378	)	$	107		$	(269	)
Other Comprehensive Income before Reclassifications	(1		)	—			8			7
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			2			10
Net Current Period Other Comprehensive Income (Loss)	(1		)	8			10			17
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	2		$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—			—			53			53
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			12			(28		)	(16		)
Net Current Period Other Comprehensive Income (Loss)	—			12			25			37
Balance as of June 30, 2017	$	2		$	(386	)	$	158		$	(226	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	1			—			18			19
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			16			8			24
Net Current Period Other Comprehensive Income (Loss)	1			16			26			43
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)

Power	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2017	$	—	$	(335	)	$	148		$	(187	)
Other Comprehensive Income before Reclassifications	—		—			22			22
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		5			(12		)	(7		)
Net Current Period Other Comprehensive Income (Loss)	—		5			10			15
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Power	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	—	$	(320	)	$	103		$	(217	)
Other Comprehensive Income before Reclassifications	—		—			6			6
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		7			3			10
Net Current Period Other Comprehensive Income (Loss)	—		7			9			16
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	—	$	(340	)	$	129		$	(211	)
Other Comprehensive Income before Reclassifications	—		—			50			50
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		10			(21		)	(11		)
Net Current Period Other Comprehensive Income (Loss)	—		10			29			39
Balance as of June 30, 2017	$	—	$	(330	)	$	158		$	(172	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—	$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications	—		—			16			16
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		14			9			23
Net Current Period Other Comprehensive Income (Loss)	—		14			25			39
Balance as of June 30, 2016	$	—	$	(313	)	$	112		$	(201	)

Reclassifications out of Accumulated Other Comprehensive Income

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2017									June 30, 2017
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	4		$	(2	)	$	2
Amortization of Actuarial Loss	O&M Expense	(12		)	5			(7		)	(24		)	10			(14		)
Total Pension and OPEB Plans		(10		)	4			(6		)	(20		)	8			(12		)
Available-for-Sale Securities
Realized Gains	Other Income	34			(17		)	17			70			(34		)	36
Realized Losses	Other Deductions	(6		)	4			(2		)	(13		)	7			(6		)
OTTI	OTTI	(3		)	1			(2		)	(4		)	2			(2		)
Total Available-for-Sale Securities		25			(12		)	13			53			(25		)	28
Total		$	15		$	(8	)	$	7		$	33		$	(17	)	$	16

PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	3		$	(1	)	$	2		$	6		$	(2	)	$	4
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)	(34		)	14			(20		)
Total Pension and OPEB Plans		(14		)	6			(8		)	(28		)	12			(16		)
Available-for-Sale Securities
Realized Gains	Other Income	12			(6		)	6			28			(14		)	14
Realized Losses	Other Deductions	(7		)	4			(3		)	(24		)	12			(12		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(5		)	3			(2		)	(16		)	8			(8		)
Total		$	(19	)	$	9		$	(10	)	$	(44	)	$	20		$	(24	)

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2017									June 30, 2017
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	4		$	(2	)	$	2
Amortization of Actuarial Loss	O&M Expense	(10		)	4			(6		)	(21		)	9			(12		)
Total Pension and OPEB Plans		(8		)	3			(5		)	(17		)	7			(10		)
Available-for-Sale Securities
Realized Gains	Other Income	32			(16		)	16			57			(29		)	28
Realized Losses	Other Deductions	(5		)	3			(2		)	(10		)	5			(5		)
OTTI	OTTI	(3		)	1			(2		)	(4		)	2			(2		)
Total Available-for-Sale Securities		24			(12		)	12			43			(22		)	21
Total		$	16		$	(9	)	$	7		$	26		$	(15	)	$	11

Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	5		$	(2	)	$	3
Amortization of Actuarial Loss	O&M Expense	(14		)	6			(8		)	(29		)	12			(17		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	10			(5		)	5			25			(13		)	12
Realized Losses	Other Deductions	(6		)	3			(3		)	(22		)	11			(11		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(6		)	3			(3		)	(17		)	8			(9		)
Total		$	(18	)	$	8		$	(10	)	$	(41	)	$	18		$	(23	)

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Earnings Per Share (EPS) and Dividends (Tables)

6 Months Ended

Jun. 30, 2017

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:

	Three Months Ended June 30,								Six Months Ended June 30,
	2017				2016				2017				2016
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	109	$	109	$	187	$	187	$	223	$	223	$	658	$	658
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505		505		505		505		505
Effect of Stock Based Compensation Awards	—		2		—		3		—		2		—		3
Total Shares	505		507		505		508		505		507		505		508
EPS
Net Income	$	0.22	$	0.22	$	0.37	$	0.37	$	0.44	$	0.44	$	1.30	$	1.30

There were approximately 0.3 million of stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for each of the three month and six month periods ended June 30, 2017 and June 30, 2016.

Dividend Payments On Common Stock

Dividends

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2017		2016		2017		2016
Per Share	$	0.43	$	0.41	$	0.86	$	0.82
In Millions	$	217	$	208	$	435	$	415

On July 18, 2017, PSEG’s Board of Directors approved a $0.43 per share common stock dividend for the third quarter of 2017.

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Financial Information By Business Segments (Tables)

6 Months Ended

Jun. 30, 2017

Segment Reporting [Abstract]

Financial Information By Business Segments

	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Three Months Ended June 30, 2017
Total Operating Revenues	$	1,368	$	929		$	116		$	(280	)	$	2,133
Net Income (Loss)	208		(97		)	(2		)	—			109
Gross Additions to Long-Lived Assets	641		269			9			—			919
Six Months Ended June 30, 2017
Operating Revenues	$	3,180	$	2,213		$	199		$	(867	)	$	4,725
Net Income (Loss)	507		(267		)	(17		)	—			223
Gross Additions to Long-Lived Assets	1,389		576			16			—			1,981
Three Months Ended June 30, 2016
Total Operating Revenues	$	1,350	$	714		$	127		$	(286	)	$	1,905
Net Income (Loss)	179		(11		)	19			—			187
Gross Additions to Long-Lived Assets	631		265			10			—			906
Six Months Ended June 30, 2016
Operating Revenues	$	3,062	$	2,027		$	249		$	(817	)	$	4,521
Net Income (Loss)	441		181			36			—			658
Gross Additions to Long-Lived Assets	1,355		598			18			—			1,971
As of June 30, 2017
Total Assets	$	27,273	$	11,619		$	2,425		$	(793	)	$	40,524
Investments in Equity Method Subsidiaries	$	—	$	91		$	—		$	—		$	91
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 relate primarily to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 18. Related-Party Transactions.

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Related-Party Transactions (Tables)

6 Months Ended

Jun. 30, 2017

PSE And G [Member]

Related Party Transaction [Line Items]

Schedule Of Related Party Transactions, Revenue

PSE&G

The financial statements for PSE&G include transactions with related parties as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Administrative Billings from Services (B)	79		82		144		151
Total Billings from Affiliates	$	375	$	379	$	1,039	$	993

Schedule Of Related Party Transactions, Payables

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSEG (C)	$	20	$	76
Payable to Power (A)	$	90	$	193
Payable to Services (B)	56		67
Accounts Payable—Affiliated Companies	$	146	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	115	$	130

Power [Member]

Related Party Transaction [Line Items]

Schedule Of Related Party Transactions, Revenue

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2017		2016		2017		2016
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	296	$	297	$	895	$	842
Billings from Affiliates:
Administrative Billings from Services (B)	$	42	$	45	$	78	$	90

Schedule Of Related Party Transactions, Receivables

	As of		As of
Related-Party Transactions	June 30, 2017		December 31, 2016
	Millions
Receivables from PSE&G (A)	$	90	$	193
Receivables from PSEG (C)	49		12
Accounts Receivable—Affiliated Companies	$	139	$	205
Payable to Services (B)	$	20	$	25
Accounts Payable—Affiliated Companies	$	20	$	25
Short-Term Loan Due (to) from Affiliate (E)	$	233	$	87
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	93	$	77

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Guarantees of Debt (Tables)

6 Months Ended

Jun. 30, 2017

Power [Member]

Debt Instrument [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 June 30, 2017 and December 31, 2016 and for the three months and six months ended June 30, 2017 and 2016.

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2017
Operating Revenues	$	—		$	910		$	47		$	(28	)	$	929
Operating Expenses	(2		)	1,103			43			(28		)	1,116
Operating Income (Loss)	2			(193		)	4			—			(187		)
Equity Earnings (Losses) of Subsidiaries	(93		)	(4		)	5			97			5
Other Income	22			56			2			(34		)	46
Other Deductions	—			(7		)	—			—			(7		)
Other-Than-Temporary Impairments	—			(3		)	—			—			(3		)
Interest Expense	(34		)	(9		)	(4		)	34			(13		)
Income Tax Benefit (Expense)	6			60			(4		)	—			62
Net Income (Loss)	$	(97	)	$	(100	)	$	3		$	97		$	(97	)
Comprehensive Income (Loss)	$	(82	)	$	(91	)	$	3		$	88		$	(82	)
Six Months Ended June 30, 2017
Operating Revenues	$	—		$	2,180		$	99		$	(66	)	$	2,213
Operating Expenses	2			2,672			95			(66		)	2,703
Operating Income (Loss)	(2		)	(492		)	4			—			(490		)
Equity Earnings (Losses) of Subsidiaries	(254		)	(5		)	8			259			8
Other Income	47			97			2			(62		)	84
Other Deductions	(1		)	(13		)	—			—			(14		)
Other-Than-Temporary Impairments	—			(4		)	—			—			(4		)
Interest Expense	(64		)	(18		)	(9		)	62			(29		)
Income Tax Benefit (Expense)	7			171			—			—			178
Net Income (Loss)	$	(267	)	$	(264	)	$	5		$	259		$	(267	)
Comprehensive Income (Loss)	$	(228	)	$	(234	)	$	5		$	229		$	(228	)
Six Months Ended June 30, 2017
Net Cash Provided By (Used In)    Operating Activities	$	(32	)	$	802		$	111		$	51		$	932
Net Cash Provided By (Used In)    Investing Activities	$	683		$	178		$	(241	)	$	(1,355	)	$	(735	)
Net Cash Provided By (Used In)    Financing Activities	$	(651	)	$	(978	)	$	146		$	1,304		$	(179	)

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2016
Operating Revenues	$	—		$	700		$	46		$	(32	)	$	714
Operating Expenses	2			716			40			(32		)	726
Operating Income (Loss)	(2		)	(16		)	6			—			(12		)
Equity Earnings (Losses) of Subsidiaries	(1		)	1			4			—			4
Other Income	17			30			—			(22		)	25
Other Deductions	—			(9		)	—			—			(9		)
Other-Than-Temporary Impairments	—			(10		)	—			—			(10		)
Interest Expense	(31		)	(7		)	(4		)	22			(20		)
Income Tax Benefit (Expense)	6			3			2			—			11
Net Income (Loss)	$	(11	)	$	(8	)	$	8		$	—		$	(11	)
Comprehensive Income (Loss)	$	5		$	1		$	8		$	(9	)	$	5
Six Months Ended June 30, 2016
Operating Revenues	$	—		$	2,002		$	88		$	(63	)	$	2,027
Operating Expenses	12			1,668			79			(63		)	1,696
Operating Income (Loss)	(12		)	334			9			—			331
Equity Earnings (Losses) of Subsidiaries	204			—			6			(204		)	6
Other Income	34			62			—			(45		)	51
Other Deductions	—			(27		)	—			—			(27		)
Other-Than-Temporary Impairments	—			(20		)	—			—			(20		)
Interest Expense	(61		)	(17		)	(9		)	45			(42		)
Income Tax Benefit (Expense)	16			(137		)	3			—			(118		)
Net Income (Loss)	$	181		$	195		$	9		$	(204	)	$	181
Comprehensive Income (Loss)	$	220		$	220		$	9		$	(229	)	$	220
Six Months Ended June 30, 2016
Net Cash Provided By (Used In)    Operating Activities	$	337		$	777		$	159		$	(356	)	$	917
Net Cash Provided By (Used In)    Investing Activities	$	(1,287	)	$	(504	)	$	(395	)	$	579		$	(1,607	)
Net Cash Provided By (Used In)    Financing Activities	$	951		$	(273	)	$	239		$	(223	)	$	694

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2017
Current Assets	$	4,156	$	1,257	$	182	$	(4,213	)	$	1,382
Property, Plant and Equipment, net	56		5,244		2,526		—			7,826
Investment in Subsidiaries	4,015		340		—		(4,355		)	—
Noncurrent Assets	184		2,225		119		(117		)	2,411
Total Assets	$	8,411	$	9,066	$	2,827	$	(8,685	)	$	11,619
Current Liabilities	$	88	$	3,156	$	1,648	$	(4,213	)	$	679
Noncurrent Liabilities	543		2,195		539		(117		)	3,160
Long-Term Debt	2,384		—		—		—			2,384
Member’s Equity	5,396		3,715		640		(4,355		)	5,396
Total Liabilities and Member’s Equity	$	8,411	$	9,066	$	2,827	$	(8,685	)	$	11,619
As of December 31, 2016
Current Assets	$	4,412	$	1,593	$	152	$	(4,697	)	$	1,460
Property, Plant and Equipment, net	55		6,145		2,320		—			8,520
Investment in Subsidiaries	4,249		344		—		(4,593		)	—
Noncurrent Assets	168		2,016		129		(100		)	2,213
Total Assets	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193
Current Liabilities	$	171	$	3,752	$	1,454	$	(4,697	)	$	680
Noncurrent Liabilities	532		2,398		502		(100		)	3,332
Long-Term Debt	2,382		—		—		—			2,382
Member’s Equity	5,799		3,948		645		(4,593		)	5,799
Total Liabilities and Member’s Equity	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193

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Early Plant Retirements Early Plant Retirements (Details) - USD ($) $ in Millions		3 Months Ended	6 Months Ended	12 Months Ended
		Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
Early Plant Retirements [Line Items]
Total Assets		$ 40,524	$ 40,524	$ 40,070
Asset Retirement Obligations		744	744	726
Power [Member]
Early Plant Retirements [Line Items]
Total Assets		11,619	11,619	12,193
Asset Retirement Obligations		526	526	511
Power [Member] | Energy Costs [Member]
Early Plant Retirements [Line Items]
Coal Inventory Lower of Cost or Market Adjustments		2	9	62
Power [Member] | Operating Expense [Member]
Early Plant Retirements [Line Items]
Operation and Maintenance charges		4	4	53
Power [Member] | Depreciation And Amortization [Domain]
Early Plant Retirements [Line Items]
Accelerated Depreciation including Asset Retirement Costs		390	964	$ 571
Hope Creek [Member] | Nuclear Plant [Member]
Early Plant Retirements [Line Items]
Materials and Supplies Inventory		83	83
Nuclear Production, net of Accumulated Depreciation		453	453
Nuclear Fuel In-Service, net of Accumulated Depreciation		136	136
Construction Work in Progress (including nuclear fuel)		168	168
Total Assets		840	840
Asset Retirement Obligations		146	146
Total Liabilities		146	146
Net Assets		$ 694	$ 694
% Owned		100.00%	100.00%
Salem [Member] | Nuclear Plant [Member]
Early Plant Retirements [Line Items]
Materials and Supplies Inventory		$ 80	$ 80
Nuclear Production, net of Accumulated Depreciation		561	561
Nuclear Fuel In-Service, net of Accumulated Depreciation		113	113
Construction Work in Progress (including nuclear fuel)		109	109
Total Assets		863	863
Asset Retirement Obligations		159	159
Total Liabilities		159	159
Net Assets		$ 704	$ 704
% Owned		57.00%	57.00%
Nuclear Support Facilities [Member] | Nuclear Plant [Member]
Early Plant Retirements [Line Items]
Materials and Supplies Inventory	[1]	$ 0	$ 0
Nuclear Production, net of Accumulated Depreciation	[1]	208	208
Nuclear Fuel In-Service, net of Accumulated Depreciation	[1]	0	0
Construction Work in Progress (including nuclear fuel)	[1]	9	9
Total Assets	[1]	217	217
Asset Retirement Obligations	[1]	0	0
Total Liabilities	[1]	0	0
Net Assets	[1]	$ 217	$ 217
% Owned	[1]	0.00%	0.00%
Peach Bottom [Member] | Nuclear Plant [Member]
Early Plant Retirements [Line Items]
Materials and Supplies Inventory		$ 41	$ 41
Nuclear Production, net of Accumulated Depreciation		758	758
Nuclear Fuel In-Service, net of Accumulated Depreciation		125	125
Construction Work in Progress (including nuclear fuel)		31	31
Total Assets		955	955
Asset Retirement Obligations		162	162
Total Liabilities		162	162
Net Assets		$ 793	$ 793
% Owned		50.00%	50.00%

[1] Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.

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Variable Interest Entities (VIEs) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Variable Interest Entity [Line Items]
Operating Revenues	$ 2,133	$ 1,905	$ 4,725	$ 4,521
Operation and Maintenance	708	710	1,420	1,439
Long Island ServCo [Member]
Variable Interest Entity [Line Items]
Operating Revenues	112	101	224	199
Operation and Maintenance	$ 112	$ 101	$ 224	$ 199

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Rate Filings (Details) - PSE And G [Member] $ in Millions	1 Months Ended			6 Months Ended
	Jul. 31, 2017 USD ($)	Jun. 30, 2017 USD ($)	Apr. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Oct. 01, 2017
Regulatory Assets And Liabilities [Line Items]
Current BGSS rate per therm		0.34		0.34
True-up adjustment for Transmission Formula Rate Revenues		$ (12)		$ (12)
Electric Distribution [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				16
Gas Distribution [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				2
Overrecovered Gas Costs Basic Gas Supply Service [Member]
Regulatory Assets And Liabilities [Line Items]
BGSS Revenue Reduction				61
Electric Green Program Recovery [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				47
Gas Green Program Recovery [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				13
Gas Weather Normalization Deferral [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		55
Remediation Adjustment Clause Other Sbc [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		41
Subsequent Event [Member]
Regulatory Assets And Liabilities [Line Items]
Proposed BGSS rate per therm					0.37
Subsequent Event [Member] | Gas System Modernization Program [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 28
Solar or EE Recovery Charge (RRC) [Member] | Electric Distribution [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				37
Solar or EE Recovery Charge (RRC) [Member] | Gas Distribution [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				13
Stranded Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ (5)
2016 to 2017 [Member] | Gas Weather Normalization Deferral [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		31
2015 to 2016 [Member] | Gas Weather Normalization Deferral [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 24
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 54

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Financing Receivables (Outstanding Loans by Class of Customer) (Detail) - PSE And G [Member] - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Concentration Risk [Line Items]
Outstanding Loans by Class of Customer	$ 178	$ 175
Commercial/Industrial [Member]
Concentration Risk [Line Items]
Outstanding Loans by Class of Customer	167	164
Residential [Member]
Concentration Risk [Line Items]
Outstanding Loans by Class of Customer	$ 11	$ 11

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Financing Receivables (Gross And Net Lease Investment) (Detail) - Energy Holdings [Member] - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	$ 559	$ 629
Estimated Residual Value of Leased Assets	333	346
Total Investment in Rental Receivables	892	975
Unearned and Deferred Income	(315)	(326)
Gross Investment in Leases	577	649
Deferred Tax Liabilities	(619)	(674)
Net Investment in Leases	$ (42)	$ (25)

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Financing Receivables (Schedule Of Lease Receivables, Net Of Nonrecourse Debt, Associated With Leveraged Lease Portfolio Based On Counterparty Credit Rating) (Detail) - Energy Holdings [Member] - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	$ 559	$ 629
Standard & Poor's, AA Rating [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	15
Standard & Poor's, BBB plus - BBB - Rating [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	317
Standard & Poor's, BB- Rating [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	133
Standard & Poor's, CCC minus Rating [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	$ 94

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Financing Receivables (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2017
Schedule of Financial Receivables [Line Items]
Lease Receivable adjustment	$ 15	$ 55	$ 10
Residual Value Adjustment	7			$ 137
Lease investment with non-investment grade counterparties, gross	348				$ 348
Lease investment with non-investment grade counterparties, net of deferred taxes	$ (159)				$ (159)
Powerton Station [Member]
Schedule of Financial Receivables [Line Items]
Counterparties’ S&P Credit Ratings					BB-

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Financing Receivables (Schedule Of Assets Under Lease Receivables) (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2017 USD ($) MW
Powerton Station Units 5 And 6 [Member]
Schedule of Financial Receivables [Line Items]
Location	IL
Gross Investment | $	$ 134
% Owned	64.00%
Total MW | MW	1,538
Fuel Type	Coal
Counterparties’ S&P Credit Ratings	BB-
Counterparty	NRG Energy, Inc.
Joliet Station Units 7 And 8 [Member]
Schedule of Financial Receivables [Line Items]
Location	IL
Gross Investment | $	$ 83
% Owned	64.00%
Total MW | MW	1,036
Fuel Type	Gas
Counterparties’ S&P Credit Ratings	BB-
Counterparty	NRG Energy, Inc.
Keystone Station Units 1 And 2 [Member]
Schedule of Financial Receivables [Line Items]
Location	PA
Gross Investment | $	$ 20
% Owned	17.00%
Total MW | MW	1,711
Fuel Type	Coal
Counterparties’ S&P Credit Ratings	CC (A)	[1]
Counterparty	REMA
Conemaugh Station Units 1 And 2 [Member]
Schedule of Financial Receivables [Line Items]
Location	PA
Gross Investment | $	$ 20
% Owned	17.00%
Total MW | MW	1,711
Fuel Type	Coal
Counterparties’ S&P Credit Ratings	CC (A)	[1]
Counterparty	REMA
Shawville Station Units 1, 2, 3 And 4 [Member]
Schedule of Financial Receivables [Line Items]
Location	PA
Gross Investment | $	$ 91
% Owned	100.00%
Total MW | MW	596
Fuel Type	Gas
Counterparties’ S&P Credit Ratings	CC (A)	[1]
Counterparty	REMA

[1] y

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Available-For-Sale Securities (Fair Values And Gross Unrealized Gains And Losses For The Securities Held) (Detail) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		$ 1,657	$ 1,604
Gross Unrealized Gains		321	275
Gross Unrealized Losses		(10)	(21)
Fair Value	[1]	1,968	1,858
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		699	705
Gross Unrealized Gains		305	263
Gross Unrealized Losses		(5)	(11)
Fair Value		999	957
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		551	518
Gross Unrealized Gains		10	8
Gross Unrealized Losses		(4)	(6)
Fair Value		557	520
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Corporate [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		356	337
Gross Unrealized Gains		6	4
Gross Unrealized Losses		(1)	(4)
Fair Value		361	337
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Total Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		907	855
Gross Unrealized Gains		16	12
Gross Unrealized Losses		(5)	(10)
Fair Value		918	857
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Other Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		51	44
Gross Unrealized Gains		0	0
Gross Unrealized Losses		0	0
Fair Value		51	44
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		222	209
Gross Unrealized Gains		3	12
Gross Unrealized Losses		(1)	(4)
Fair Value		224	217
Rabbi Trust [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		22	11
Gross Unrealized Gains		0	11
Gross Unrealized Losses		0	0
Fair Value		22	22
Rabbi Trust [Member] | Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		85	105
Gross Unrealized Gains		1	0
Gross Unrealized Losses		(1)	(2)
Fair Value		85	103
Rabbi Trust [Member] | Corporate [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		113	92
Gross Unrealized Gains		2	1
Gross Unrealized Losses		0	(2)
Fair Value		115	91
Rabbi Trust [Member] | Total Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		198	197
Gross Unrealized Gains		3	1
Gross Unrealized Losses		(1)	(4)
Fair Value		200	194
Rabbi Trust [Member] | Other Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost		2	1
Gross Unrealized Gains		0	0
Gross Unrealized Losses		0	0
Fair Value		2	1
Rabbi Trust [Member] | Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value		$ 55	$ 53

[1] The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund.

XML

Available-For-Sale Securities (Schedule Of Accounts Receivable And Accounts Payable) (Detail) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Accounts Receivable	$ 25	$ 8
Accounts Payable	22	5
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Accounts Receivable	2	5
Accounts Payable	$ 0	$ 3

XML

Available-For-Sale Securities (Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months) (Detail) - USD ($) $ in Millions		Jun. 30, 2017		Dec. 31, 2016
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value		$ 487		$ 535
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		(10)		(19)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value		14		27
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses		0		(2)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[1]	63		120
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		(5)	[1]	(10)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[1]	0		8
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[1]	0		(1)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[2]	279		276
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[2]	(4)		(6)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[2]	7		4
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[2]	0		0
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Corporate [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[3]	94		139
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[3]	(1)		(3)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[3]	7		15
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[3]	0		(1)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Total Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value		373		415
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		(5)		(9)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value		14		19
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses		0		(1)
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value		48		106
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		(1)		(4)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value		4		4
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses		0		0
Rabbi Trust [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[4]	0		0
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[4]	0		0
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[4]	0		0
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[4]	0		0
Rabbi Trust [Member] | Government [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[5]	29		60
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[5]	(1)		(2)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[5]	1		1
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[5]	0		0
Rabbi Trust [Member] | Corporate [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[6]	19		46
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[6]	0		(2)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[6]	3		3
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[6]	0		0
Rabbi Trust [Member] | Total Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value		48		106
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		(1)		(4)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value		4		4
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses		$ 0		$ 0

[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. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2017.

[2] Debt Securities (Government)—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 June 30, 2017.

[3] Debt Securities (Corporate)—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 June 30, 2017.

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

[5] Debt Securities (Government)—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 June 30, 2017.

[6] Debt Securities (Corporate)—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 June 30, 2017.

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Available-For-Sale Securities (Proceeds From The Sales Of And The Net Realized Gains On Securities in the NDT and Rabbi Trusts) (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Proceeds from Sales	[1]	$ 93	$ 36	$ 144	$ 61
Gross Realized Gains		2	2	17	3
Gross Realized Losses		(1)	(1)	(4)	(2)
Net Realized Gains (Losses)		1	1	13	1
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Proceeds from Sales	[1]	320	154	567	331
Gross Realized Gains		32	10	53	25
Gross Realized Losses		(5)	(6)	(9)	(22)
Net Realized Gains (Losses)		$ 27	$ 4	$ 44	$ 3

[1] Includes activity in accounts related to the liquidation of funds being transitioned to new managers.

XML

Available-For-Sale Securities (Amount Of Available-For-Sale Debt Securities By Maturity Periods) (Detail) $ in Millions	Jun. 30, 2017 USD ($)
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Less than one year	$ 1
1 - 5 years	35
6 - 10 years	29
11 - 15 years	6
16 - 20 years	18
Over 20 years	111
Total Available-for-Sale Debt Securities	200
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Less than one year	29
1 - 5 years	239
6 - 10 years	223
11 - 15 years	65
16 - 20 years	66
Over 20 years	296
Total Available-for-Sale Debt Securities	$ 918

XML

Available-For-Sale Securities (Fair Value Of Rabbi Trust) (Detail) - Rabbi Trust [Member] - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Total Rabbi Trust Available-for-Sale Securities	$ 224	$ 217
Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Total Rabbi Trust Available-for-Sale Securities	55	53
PSE And G [Member]
Schedule of Available-for-sale Securities [Line Items]
Total Rabbi Trust Available-for-Sale Securities	45	43
Other Entity [Member]
Schedule of Available-for-sale Securities [Line Items]
Total Rabbi Trust Available-for-Sale Securities	$ 124	$ 121

XML

Available-For-Sale Securities (Narrative) (Detail) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2017 USD ($) Facility	Jun. 30, 2016 USD ($)
Schedule of Available-for-sale Securities [Line Items]
Other-Than-Temporary Impairments	$ 3	$ 10	$ 4	$ 20
Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Number of Nuclear Facilities | Facility			5
Other-Than-Temporary Impairments	$ 3	$ 10	$ 4	$ 20
Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Other-Than-Temporary Impairments			4
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Available-for-sale Securities [Line Items]
After tax amount of net unrealized gains recognized in AOCI			$ 158

XML

Pension And OPEB (Components Of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 28	$ 27	$ 57	$ 54
Interest Cost	51	51	102	101
Expected Return on Plan Assets	(99)	(99)	(197)	(197)
Amortization of Prior Service Cost	(4)	(5)	(9)	(9)
Amortization of Actuarial Loss	25	40	49	79
Total Benefit Costs	1	14	2	28
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	4	4	8	8
Interest Cost	16	14	32	29
Expected Return on Plan Assets	(9)	(7)	(17)	(15)
Amortization of Prior Service Cost	(2)	(4)	(5)	(7)
Amortization of Actuarial Loss	12	10	25	20
Total Benefit Costs	$ 21	$ 17	$ 43	$ 35

XML

Pension And OPEB (Schedule Of Pension And OPEB Costs) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 1	$ 14	$ 2	$ 28
Pension Benefits [Member] | PSE And G [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	(1)	7	(2)	14
Pension Benefits [Member] | Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	1	4	1	8
Pension Benefits [Member] | Other Entity [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	1	3	3	6
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	21	17	43	35
OPEB [Member] | PSE And G [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	13	11	27	22
OPEB [Member] | Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	6	5	13	11
OPEB [Member] | Other Entity [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 2	$ 1	$ 3	$ 2

XML

Pension And OPEB (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 1	$ 14	$ 2	$ 28
Postretirement Healthcare Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions			14
Total Benefit Costs	21	17	43	35
Long Island Electric Utility Servco LLC Pension and OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			35
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	8	$ 6	17	$ 12
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Postretirement Healthcare Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	1		2
Cost Reduction related to change in estimate [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 12		$ 24

XML

Commitments And Contingent Liabilities (Guaranteed Obligations) (Detail) - Power [Member] - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Face Value of Outstanding Guarantees	$ 1,898	$ 1,806
Exposure under Current Guarantees	137	139
Letters of Credit Margin Posted	142	157
Letters of Credit Margin Received	98	99
Counterparty Cash Margin Deposited	0	0
Counterparty Cash Margin Received	(1)	(1)
Net Broker Balance Deposited (Received)	(2)	57
Other Letters of Credit	61	$ 51
PennEast Natural Gas Pipeline [Member]
Loss Contingencies [Line Items]
Terminated Guarantee obligation following PennEast sale	106
755 MW Gas-Fired Combined Cycle Generating Station [Member]
Loss Contingencies [Line Items]
Face Value of Outstanding Guarantees	$ 21

XML

Commitments And Contingent Liabilities (Environmental Matters) (Detail)	6 Months Ended
	Jun. 30, 2017 USD ($) Potentially_Responsible_Party entity site Station Plant mi	Mar. 31, 2007 Potentially_Responsible_Party
Site Contingency [Line Items]
Number of miles related to the Passaic River constituting a facility as determined by the US Environmental Protection Agency | mi	17
Number of miles on Passaic River tidal reach required to be studied as determined by the US Environmental Protection Agency | mi	8
Cash out settlement offer for PRPs with minimal responsibility	$ 280,600
Number of additional 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
PSE And G [Member]
Site Contingency [Line Items]
Percentage of cost attributable to potentially responsible party	7.00%
Power [Member]
Site Contingency [Line Items]
Ownership percentage of Keystone Coal fired plant in Pennsylvania	23.00%
Psd Nsr Regulations Site Contingency [Member] | Power [Member]
Site Contingency [Line Items]
Penalty per day from date of violation-minimum	$ 25,000
Penalty per day from date of violation-maximum	$ 37,500
Pse G S Former Mgp Sites [Member]
Site Contingency [Line Items]
Number of potentially responsible parties ("PRPs") in connection with environmental liabilities for operations conducted near Passaic River | Potentially_Responsible_Party	51	73
Loss Contingency, Estimate of Possible Loss	$ 190,000,000
Total Spend of Study to date	163,000,000
Company Share of Total Spend of Study to date	$ 12,000,000
Pse G S Former Mgp Sites [Member] | Power [Member]
Site Contingency [Line Items]
Percentage of cost attributable to potentially responsible party	1.00%
Passaic River Site Contingency [Member]
Site Contingency [Line Items]
Estimated Cleanup Costs EPA Preferred Method	$ 2,300,000,000
Accrual for Environmental Loss Contingencies	$ 57,000,000
Number Of Additional Potentially Responsible Parties Directed By New Jersey Department Of Environmental Protection To Arrange Damage Assessment For Lower Passaic River | Potentially_Responsible_Party	56
Estimated cleanup costs agreed to by two potentially responsible parties	$ 80,000,000
Estimated cost of interim natural resource injury restoration	$ 950,000,000
Passaic River Site Contingency [Member] | PSE And 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, Period Increase (Decrease)	$ 36,000,000
Accrual for Environmental Loss Contingencies	46,000,000
CPG Targeted Method Cleanup Costs Low Estimate	10,000,000
Passaic River Site Contingency [Member] | Power [Member]
Site Contingency [Line Items]
Accrual for Environmental Loss Contingencies, Period Increase (Decrease)	8,000,000
Accrual for Environmental Loss Contingencies	11,000,000
CPG Targeted Method Cleanup Costs Low Estimate	3,000,000
Mgp Remediation Site Contingency [Member] | PSE And G [Member]
Site Contingency [Line Items]
Remediation Liability Recorded As Other Current Liabilities	74,000,000
Remediation Liability Recorded As Other Noncurrent Liabilities	299,000,000
Regulatory Assets	373,000,000
Remedial Investigation And Feasibility Study [Member]
Site Contingency [Line Items]
Estimated, total cost of the study	30,000,000
Estimated Total Cost Of Study Low End of Range	$ 25,000,000
Passaic River mile 10.9 contaminant removal [Member]
Site Contingency [Line Items]
Percentage of cost attributable to potentially responsible party	3.00%
Minimum [Member] | Passaic River Site Contingency [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 518,000,000
Minimum [Member] | Passaic River Site targeted remedy [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	518,000,000
Minimum [Member] | Mgp Remediation Site Contingency [Member] | PSE And G [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	373,000,000
Accrual for Environmental Loss Contingencies	373,000,000
Maximum [Member] | Passaic River Site Contingency [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	3,200,000,000
Maximum [Member] | Passaic River Site targeted remedy [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	772,000,000
Maximum [Member] | Mgp Remediation Site Contingency [Member] | PSE And G [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 430,000,000

XML

Commitments And Contingent Liabilities (Basic Generation Service (BGS) And Basic Gas Supply Service (BGSS)) (Detail) cf in Billions	6 Months Ended
	Jun. 30, 2017 cf $ / mwh $ / mwd MW
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%
Number of cubic feet to be hedged | cf	70
Percentage of annual residential gas supply requirements to be hedged	50.00%
PSE And G [Member] | Auction Year 2014 [Member]
Long-term Purchase Commitment [Line Items]
36-Month Terms Ending	May 31, 2017
Load (MW) | MW	2,800
Dollars Per Megawatt Hour | $ / mwh	97.39
PSE And G [Member] | Auction Year 2015 [Member]
Long-term Purchase Commitment [Line Items]
36-Month Terms Ending	May 31, 2018
Load (MW) | MW	2,900
Dollars Per Megawatt Hour | $ / mwh	99.54
PSE And G [Member] | Auction Year 2016 [Member]
Long-term Purchase Commitment [Line Items]
Dollars Per Megawatt-Day | $ / mwd	335.33
36-Month Terms Ending	May 31, 2019
Load (MW) | MW	2,800
Dollars Per Megawatt Hour | $ / mwh	96.38
PSE And G [Member] | Auction Year 2017 [Member]
Long-term Purchase Commitment [Line Items]
Dollars Per Megawatt-Day | $ / mwd	276.83
36-Month Terms Ending	May 31, 2020
Load (MW) | MW	2,800
Dollars Per Megawatt Hour | $ / mwh	90.78

XML

Commitments And Contingent Liabilities (Minimum Fuel Purchase Requirements) (Detail) - Power [Member] $ in Millions	6 Months Ended
	Jun. 30, 2017 USD ($)
Long-term Purchase Commitment [Line Items]
Coverage percentage of nuclear fuel commitments of uranium, enrichment, and fabrication requirements	100.00%
Nuclear Fuel Uranium [Member]
Long-term Purchase Commitment [Line Items]
Total five-year minimum purchase requirements	$ 301
Nuclear Fuel Enrichment [Member]
Long-term Purchase Commitment [Line Items]
Total five-year minimum purchase requirements	340
Nuclear Fuel Fabrication [Member]
Long-term Purchase Commitment [Line Items]
Total five-year minimum purchase requirements	184
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Total five-year minimum purchase requirements	1,040
Coal [Member]
Long-term Purchase Commitment [Line Items]
Total five-year minimum purchase requirements	$ 331

XML

Commitments And Contingent Liabilities (Regulatory Proceedings) (Detail) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2014	Jun. 30, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Clean Energy Program, current portion		$ 200	$ 142
PSE And G [Member]
Loss Contingencies [Line Items]
Clean Energy Program, current portion		200	$ 142
Power [Member] | FERC Compliance [Domain]
Loss Contingencies [Line Items]
Loss Contingency related to bidding errors	$ 25	10
Maximum [Member] | Power [Member] | FERC Compliance [Domain]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss		135
Minimum [Member] | Power [Member] | FERC Compliance [Domain]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss		$ 35

XML

Debt and Credit Facilities (Changes in Long-Term Debt) (Detail) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Variable Rate [Domain] | PSEG [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 700	$ 500
Medium Term Notes Three Point Zero Percent Due In Two Thousand Twenty Seven [Member] | PSE And G [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 425
Debt Instrument, Interest Rate, Stated Percentage	3.00%

XML

Debt and Credit Facilities Debt and Credit Facilities (Short-Term Liquidity) (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2017	Dec. 31, 2016
Commercial Paper		$ 0	$ 388
Commitments of Single Institution as Percentage of Total Commitments		8.00%
Line of Credit Facility, Remaining Borrowing Capacity		$ 3,982
Line of Credit Facility, Maximum Borrowing Capacity		4,200
Line of Credit Facility, Fair Value of Amount Outstanding		218
PSEG [Member]
Line of Credit Facility, Remaining Borrowing Capacity		1,487
Line of Credit Facility, Maximum Borrowing Capacity		1,500	1,000
Line of Credit Facility, Fair Value of Amount Outstanding	[1]	13
PSE And G [Member]
Line of Credit Facility, Remaining Borrowing Capacity		585
Line of Credit Facility, Maximum Borrowing Capacity		600
Line of Credit Facility, Fair Value of Amount Outstanding	[1]	15
Power [Member]
Line of Credit Facility, Remaining Borrowing Capacity		1,910
Line of Credit Facility, Maximum Borrowing Capacity		2,100	$ 2,600
Line of Credit Facility, Fair Value of Amount Outstanding		190
Five Year Credit Facility Maturing March 2022 [Member] | PSEG [Member]
Line of Credit Facility, Remaining Borrowing Capacity		$ 1,487
Debt Instrument, Maturity Date, Description		Mar 2022
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,500
Line of Credit Facility, Fair Value of Amount Outstanding		13
Five Year Credit Facility Maturing March 2022 [Member] | PSE And G [Member]
Line of Credit Facility, Remaining Borrowing Capacity		$ 585
Debt Instrument, Maturity Date, Description		Mar 2022
Line of Credit Facility, Maximum Borrowing Capacity		$ 600
Line of Credit Facility, Fair Value of Amount Outstanding		15
Five Year Credit Facility Maturing March 2022 [Member] | Power [Member]
Line of Credit Facility, Remaining Borrowing Capacity		$ 1,850
Debt Instrument, Maturity Date, Description		Mar 2022
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,900
Line of Credit Facility, Fair Value of Amount Outstanding		50
Three Year Credit Facilities Maturing March 2020 [Member] | Power [Member]
Line of Credit Facility, Remaining Borrowing Capacity		$ 60
Debt Instrument, Maturity Date, Description		Mar 2020
Line of Credit Facility, Maximum Borrowing Capacity		$ 200
Line of Credit Facility, Fair Value of Amount Outstanding		$ 140

[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 June 30, 2017, neither PSEG nor PSE&G had amounts outstanding.

XML

Financial Risk Management Activities (Narrative) (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Interest Rate Cash Flow Hedge Derivative at Fair Value, Net	$ 1
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	2		$ 2
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	1
Power [Member]
Derivatives, Fair Value [Line Items]
Fair Value of Derivatives with credit-risk related contingent features	16		19
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral	11		9
Additional collateral aggregate fair value	5		$ 10
PSEG [Member]
Derivatives, Fair Value [Line Items]
Amount of reduction in interest expense attributed to interest rate swaps designated as fair value hedges		$ (4)
PSEG [Member] | Loans Payable [Member]
Derivatives, Fair Value [Line Items]
Long-term Debt, Gross	$ 500
Investment Grade - External Rating [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Credit exposure, percentage	97.00%
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

XML

Financial Risk Management Activities (Schedule Of Derivative Instruments Fair Value In Balance Sheets) (Detail) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets		$ 113	$ 163
Derivative Contracts, Noncurrent Assets		90	24
Total Mark-to-Market Derivative Assets		203	187
Derivative Contracts, Current Liabilities		(8)	(13)
Derivative Contracts, Noncurrent Liabilities		(1)	(3)
Total Mark-to-Market Derivative (Liabilities)		(9)	(16)
Net Mark-to-Market Derivative Assets (Liabilities)		194	171
Derivative, Fair Value, Amount Offset Against Collateral, Net		(11)	1
Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	[1]	112	162
Derivative Contracts, Noncurrent Assets	[1]	90	24
Total Mark-to-Market Derivative Assets	[1]	202	186
Derivative Contracts, Current Liabilities	[1]	(8)	(8)
Derivative Contracts, Noncurrent Liabilities	[1]	(1)	(3)
Total Mark-to-Market Derivative (Liabilities)	[1]	(9)	(11)
Net Mark-to-Market Derivative Assets (Liabilities)	[1]	193	175
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1],[2]	(11)	1
PSE And G [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Liabilities		0	(5)
Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		(13)	(3)
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		(4)
Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		(9)	(3)
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		2	4
Other Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		2	4
Energy-Related Contracts [Member] | Not Designated as Hedging Instrument [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	[1]	479	435
Derivative Contracts, Noncurrent Assets	[1]	268	122
Total Mark-to-Market Derivative Assets	[1]	747	557
Derivative Contracts, Current Liabilities	[1]	(373)	(285)
Derivative Contracts, Noncurrent Liabilities	[1]	(170)	(98)
Total Mark-to-Market Derivative (Liabilities)	[1]	(543)	(383)
Net Mark-to-Market Derivative Assets (Liabilities)	[1]	204	174
Energy-Related Contracts [Member] | Not Designated as Hedging Instrument [Member] | PSE And G [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	[1]		0
Derivative Contracts, Noncurrent Assets	[1]		0
Total Mark-to-Market Derivative Assets	[1]		0
Derivative Contracts, Current Liabilities	[1]		(5)
Derivative Contracts, Noncurrent Liabilities	[1]		0
Total Mark-to-Market Derivative (Liabilities)	[1]		(5)
Net Mark-to-Market Derivative Assets (Liabilities)	[1]		(5)
Energy-Related Contracts [Member] | Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[3]	(545)	(371)
Energy-Related Contracts [Member] | Assets [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1],[2],[3]	(545)	(371)
Energy-Related Contracts [Member] | Assets [Member] | PSE And G [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[3]		0
Energy-Related Contracts [Member] | Current Assets [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1],[2]	(367)	(273)
Energy-Related Contracts [Member] | Non Current Assets [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1],[2]	(178)	(98)
Energy-Related Contracts [Member] | Current Liabilities [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1],[2]	365	277
Energy-Related Contracts [Member] | Noncurrent Liabilities [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1],[2]	169	95
Energy-Related Contracts [Member] | Other Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[3]	534	372
Energy-Related Contracts [Member] | Other Liabilities [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1],[2],[3]	534	372
Energy-Related Contracts [Member] | Other Liabilities [Member] | PSE And G [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[3]		0
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[3]		0
Interest Rate Swap [Member] | PSEG [Member] | Fair Value Hedging [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	[1]	1	1
Derivative Contracts, Noncurrent Assets	[1]	0	0
Total Mark-to-Market Derivative Assets	[1]	1	1
Derivative Contracts, Current Liabilities	[1]	0	0
Derivative Contracts, Noncurrent Liabilities	[1]	0	0
Total Mark-to-Market Derivative (Liabilities)	[1]	0	0
Net Mark-to-Market Derivative Assets (Liabilities)	[1]	1	$ 1
Interest Rate Swap [Member] | Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[3]	0
Interest Rate Swap [Member] | Other Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[3]	$ 0

[1] Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. 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 Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(4) million was netted against current assets, $(9) million was netted against noncurrent assets, and $2 million was netted against current liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities.

[3] Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(13) million of cash collateral was netted against assets, and $2 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

XML

Financial Risk Management Activities (Schedule Of Derivative Instruments Designated As Cash Flow Hedges) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 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)	$ 0	$ (1)	$ 0	$ 2
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	0	0	0	0
Interest Expense [Member] | Interest Rate Swap [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)	0	(1)	0	2
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	$ 0	$ 0	$ 0	$ 0

XML

Financial Risk Management Activities (Schedule Of Reconciliation For Derivative Activity Included In Accumulated Other Comprehensive Loss) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) in AOCI	$ 23	$ 7	$ 53	$ 19
(Gain) Loss into Income	(7)	10	(16)	24
Cash Flow Hedges [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Pre-Tax Balance at Beginning of Period			3	0	$ 0
Gain (Loss) in AOCI			0		3
(Gain) Loss into Income			0		0
Pre-Tax Balance at End of Period	3		3		3
After-Tax Balance at Beginning of Period			2	0	0
Gain (Loss) in AOCI	0	(1)	0	1	2
(Gain) Loss into Income	0	$ 0	0	$ 0	0
After-Tax Balance at End of Period	$ 2		$ 2		$ 2

XML

Financial Risk Management Activities (Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Impact On Results Of Operations) (Detail) - Energy-Related Contracts [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	$ 102	$ (80)	$ 180	$ 138
Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	113	(86)	196	130
Energy Costs [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	$ (11)	$ 6	$ (16)	$ 8

XML

Financial Risk Management Activities (Schedule Of Gross Volume, On Absolute Basis For Derivative Contracts) (Detail) $ / mwh in Millions, $ / Derivative in Millions, $ / DTH in Millions	6 Months Ended
	Jun. 30, 2017 $ / mwh $ / Derivative $ / DTH	Jun. 30, 2016 $ / mwh $ / Derivative $ / DTH
Natural Gas Dth [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / DTH	321	357
Electricity MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	349	323
FTRs MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	6	9
Interest Rate Swaps [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / Derivative	500	500
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	0
PSEG [Member] | FTRs MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	0	0
PSEG [Member] | Interest Rate Swaps [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / Derivative	500	500
Power [Member] | Natural Gas Dth [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / DTH	321	348
Power [Member] | Electricity MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	349	323
Power [Member] | FTRs MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	6	9
Power [Member] | Interest Rate Swaps [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / Derivative	0	0
PSE And G [Member] | Natural Gas Dth [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / DTH	0	9
PSE And G [Member] | Electricity MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	0	0
PSE And G [Member] | FTRs MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	0	0
PSE And G [Member] | Interest Rate Swaps [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / Derivative	0	0

XML

Financial Risk Management Activities (Schedule Providing Credit Risk From Others, Net Of Collateral) (Detail) - Power [Member] $ in Millions	Jun. 30, 2017 USD ($) Counterparty
Derivative [Line Items]
Current Exposure	$ 429
Securities held as Collateral	92
Net exposure	337
Number of Counterparties greater than 10%	1
Amount Of Net Credit Exposure Greater Than Ten Percent	$ 130
Number Of Active Counterparties On Credit Risk Derivatives | Counterparty	152
Investment Grade [Member]
Derivative [Line Items]
Current Exposure	$ 420
Securities held as Collateral	92
Net exposure	328
Number of Counterparties greater than 10%	1
Amount Of Net Credit Exposure Greater Than Ten Percent	130	[1]
Non-Investment Grade [Member]
Derivative [Line Items]
Current Exposure	9
Securities held as Collateral	0
Net exposure	9
Number of Counterparties greater than 10%	0
Amount Of Net Credit Exposure Greater Than Ten Percent	0
Letter of Credit [Member]
Derivative [Line Items]
Securities held as Collateral	$ 92

[1] Represents net exposure of $130 million with PSE&G.

XML

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		Jun. 30, 2017		Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets		$ 203		$ 187
Total Mark-to-Market Derivative (Liabilities)		(9)		(16)
Collateral netted against assets and liabilities		11		(1)
Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[2]	202		186
Total Mark-to-Market Derivative (Liabilities)	[2]	(9)		(11)
Collateral netted against assets and liabilities	[2],[3]	11		(1)
Power [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Power [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
PSE And G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
PSE And G [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
PSE And G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
PSE And G [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
PSE And G [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents, Fair Value Disclosure	[4]	367		365
Quoted Market Prices of 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	[5]	997		954
Quoted Market Prices of Identical Assets (Level 1) [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	51		44
Quoted Market Prices of 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	[5]	22		22
Quoted Market Prices of 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	[5]	0		0
Quoted Market Prices of 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	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	2		1
Quoted Market Prices of 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	[5]	997		954
Quoted Market Prices of Identical Assets (Level 1) [Member] | Power [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Power [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Power [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Power [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	51		44
Quoted Market Prices of 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	[5]	5		5
Quoted Market Prices of 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	[5]	0		0
Quoted Market Prices of 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	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents, Fair Value Disclosure	[4]	169		365
Quoted Market Prices of Identical Assets (Level 1) [Member] | PSE And 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	[5]	5		5
Quoted Market Prices of Identical Assets (Level 1) [Member] | PSE And 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	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | PSE And 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	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | PSE And G [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | PSE And G [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents, Fair Value Disclosure	[4]	0		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	[5]	2		3
Significant Other Observable Inputs (Level 2) [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	330		293
Significant Other Observable Inputs (Level 2) [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	227		227
Significant Other Observable Inputs (Level 2) [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	361		337
Significant Other Observable Inputs (Level 2) [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
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	[5]	0		0
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	[5]	51		37
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	[5]	34		66
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	115		91
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
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	[5]	2		3
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	330		293
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	227		227
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	361		337
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
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	[5]	0		0
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	[5]	13		9
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	[5]	8		16
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	29		23
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Other Observable Inputs (Level 2) [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents, Fair Value Disclosure	[4]	0		0
Significant Other Observable Inputs (Level 2) [Member] | PSE And 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	[5]	0		0
Significant Other Observable Inputs (Level 2) [Member] | PSE And 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	[5]	10		7
Significant Other Observable Inputs (Level 2) [Member] | PSE And 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	[5]	7		13
Significant Other Observable Inputs (Level 2) [Member] | PSE And G [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	23		18
Significant Other Observable Inputs (Level 2) [Member] | PSE And G [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents, Fair Value Disclosure	[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	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	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	[5]	0		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	[5]	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	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	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	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	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	[5]	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	[5]	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	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents, Fair Value Disclosure	[4]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE And 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	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE And 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	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE And 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	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE And G [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE And G [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Total Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents, Fair Value Disclosure	[4]	367		365
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	[5]	999		957
Total Estimate Of Fair Value [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	330		293
Total Estimate Of Fair Value [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	227		227
Total Estimate Of Fair Value [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	361		337
Total Estimate Of Fair Value [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	51		44
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	[5]	22		22
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	[5]	51		37
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	[5]	34		66
Total Estimate Of Fair Value [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	115		91
Total Estimate Of Fair Value [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	2		1
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	[5]	999		957
Total Estimate Of Fair Value [Member] | Power [Member] | Government [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	330		293
Total Estimate Of Fair Value [Member] | Power [Member] | US Treasury Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	227		227
Total Estimate Of Fair Value [Member] | Power [Member] | Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	361		337
Total Estimate Of Fair Value [Member] | Power [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	51		44
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	[5]	5		5
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	[5]	13		9
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	[5]	8		16
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	29		23
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Total Estimate Of Fair Value [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents, Fair Value Disclosure	[4]	169		365
Total Estimate Of Fair Value [Member] | PSE And 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	[5]	5		5
Total Estimate Of Fair Value [Member] | PSE And 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	[5]	10		7
Total Estimate Of Fair Value [Member] | PSE And 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	[5]	7		13
Total Estimate Of Fair Value [Member] | PSE And G [Member] | Rabbi Trust - Debt Securities-Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	23		18
Total Estimate Of Fair Value [Member] | PSE And G [Member] | Rabbi Trust - Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[5]	0		0
Energy-Related Contracts [Member] | Quoted Market Prices of Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[6]	9		17
Total Mark-to-Market Derivative (Liabilities)		(6)	[6]	18
Energy-Related Contracts [Member] | Quoted Market Prices of 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	[6]	9		17
Total Mark-to-Market Derivative (Liabilities)	[6]	(6)		18
Energy-Related Contracts [Member] | Quoted Market Prices of Identical Assets (Level 1) [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[6]			0
Total Mark-to-Market Derivative (Liabilities)	[6]			0
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	[6]	732		533
Total Mark-to-Market Derivative (Liabilities)		(537)	[6]	(364)
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	[6]	732		533
Total Mark-to-Market Derivative (Liabilities)	[6]	(537)		364
Energy-Related Contracts [Member] | Significant Other Observable Inputs (Level 2) [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[6]			0
Total Mark-to-Market Derivative (Liabilities)	[6]			0
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	[6]	6		7
Total Mark-to-Market Derivative (Liabilities)		0	[6]	(6)
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	[6]	6		7
Total Mark-to-Market Derivative (Liabilities)	[6]	0		1
Energy-Related Contracts [Member] | Significant Unobservable Inputs (Level 3) [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[6]			0
Total Mark-to-Market Derivative (Liabilities)	[6]			5
Energy-Related Contracts [Member] | Total Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[6]	202		186
Total Mark-to-Market Derivative (Liabilities)		(9)	[6]	(16)
Energy-Related Contracts [Member] | Total Estimate Of Fair Value [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[6]	202		186
Total Mark-to-Market Derivative (Liabilities)	[6]	(9)		(11)
Energy-Related Contracts [Member] | Total Estimate Of Fair Value [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[6]			0
Total Mark-to-Market Derivative (Liabilities)	[6]			(5)
Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]			0
Interest Rate Swap [Member] | Quoted Market Prices of Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[7]	0		0
Total Mark-to-Market Derivative (Liabilities)	[7]	0
Interest Rate Swap [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	[7]	1		1
Total Mark-to-Market Derivative (Liabilities)	[7]	0
Interest Rate Swap [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	[7]	0		0
Total Mark-to-Market Derivative (Liabilities)	[7]	0
Interest Rate Swap [Member] | Total Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[7]	1		1
Total Mark-to-Market Derivative (Liabilities)	[7]	0
Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Cash and Cash Equivalents [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0		0
Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities		13		3
Assets [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	545		371
Assets [Member] | Energy-Related Contracts [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2],[3]	545		371
Assets [Member] | Energy-Related Contracts [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]			0
Assets [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	0
Other Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities		(2)		(4)
Other Liabilities [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	(534)		(372)
Other Liabilities [Member] | Energy-Related Contracts [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2],[3]	(534)		(372)
Other Liabilities [Member] | Energy-Related Contracts [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]			$ 0
Other Liabilities [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1]	$ 0

[1] Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(13) million of cash collateral was netted against assets, and $2 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.

[2] Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

[3] Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(4) million was netted against current assets, $(9) million was netted against noncurrent assets, and $2 million was netted against current liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities.

[4] Represents money market mutual funds.

[5] The fair value measurement tables exclude an immaterial amount of cash as of June 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of June 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.Level 2—NDT and Rabbi Trust fixed income securities include primarily investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US 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.

[6] Level 1— During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from 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—

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

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Fair Value Measurements (Schedule Of Quantitative Information About Level 3 Fair Value Measurements) (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	$ 6		$ 7
Liabilities, Fair Value	0		(1)
PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value			0
Liabilities, Fair Value			(5)
PSEG [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	6		7
Liabilities, Fair Value	0		(6)
Various [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	1		0	[1]
Liabilities, Fair Value	0		0	[1]
Electric Load Contracts [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	5		7
Liabilities, Fair Value	$ 0		(1)
Valuation Technique (s)	Discounted Cash flow	Discounted Cash Flow
Significant Unobservable Inputs	Historic Load Variability	Historic Load Variability
Electric Load Contracts [Member] | Minimum [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Historic Load Variability	10.00%	10.00%
Electric Load Contracts [Member] | Maximum [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Historic Load Variability	0.00%	0.00%
Natural Gas Supply Contracts [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value			0
Liabilities, Fair Value			$ (5)
Valuation Technique (s)		Discounted Cash Flow
Significant Unobservable Inputs		Transportation Costs
Natural Gas Supply Contracts [Member] | Minimum [Member] | MWh [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transportation Costs		0.60
Natural Gas Supply Contracts [Member] | Maximum [Member] | MWh [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transportation Costs		0.80

[1] (A)Includes gas positions which were immaterial as of June 30, 2017 and December 31, 2016.

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Fair Value Measurements (Changes In Level 3 Assets And (Liabilities) Measured At Fair Value On A Recurring Basis) (Detail) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2017		Jun. 30, 2016	Jun. 30, 2017		Jun. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gains and losses attributable to changes in net derivative assets and liabilities, unrealized				$ (4)			$ (4)
Settlements		$ (3)		(5)	$ (25)		(20)
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gains and losses attributable to changes in net derivative assets and liabilities, included in Operating Income		7		1	26		16
Gains and losses attributable to changes in net derivative assets and liabilities, unrealized					1
Net Derivative Assets (Liabilities) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Opening Balance		3		21	1		13
Included in Income		7	[1]	1	(26)	[1]	(16)	[1]
Included in Regulatory Assets/Liabilities	[2]	(1)		(12)	5		(4)
Purchases, (Sales)		0		0	0		0
Issuances (Settlements)	[3]	(3)		(5)	(25)		(20)
Transfers In (Out)	[4]	0		0	(1)		0
Closing Balance		6		5	6		5
Net Derivative Assets (Liabilities) [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Opening Balance		2		11	6		11
Included in Income		7	[1]	1	(26)	[1]	(16)	[1]
Included in Regulatory Assets/Liabilities	[2]	0		0	0		0
Purchases, (Sales)		0		0	0		0
Issuances (Settlements)	[3]	(3)		(5)	(25)		(20)
Transfers In (Out)	[4]	0		0	(1)		0
Closing Balance		6		7	6		7
Net Derivative Assets (Liabilities) [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Opening Balance		1		10	(5)		2
Included in Income		0	[1]	0	0	[1]	0	[1]
Included in Regulatory Assets/Liabilities	[2]	(1)		(12)	5		(4)
Purchases, (Sales)		0		0	0		0
Issuances (Settlements)	[3]	0		0	0		0
Transfers In (Out)	[4]	0		0	0		0
Closing Balance		$ 0		$ (2)	$ 0		$ (2)

[1] PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $7 million and $26 million in Operating Income for the three months and six months ended June 30, 2017, respectively. Of the $7 million in Operating Income, $4 million is unrealized. Of the $26 million in Operating Income, $1 million is unrealized.

[2] 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.

[3] Represents $(3) million and $(25) million in settlements for the three months and six months ended June 30, 2017, respectively.

[4] During the three months ended June 30, 2017 there were no transfers in to or out of Level 3. During the six months ended June 30, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in to or out of Level 3 during three months and six months ended June 30, 2016.

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Fair Value Measurements (Narrative) (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Mar. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		$ (11)		$ (11)		$ 1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements		3	$ 5	25	$ 20
Net assets measured at fair value on a recurring basis		2,800		2,800			$ 2,800
Net assets measured at fair value on a recurring basis measured using unobservable input and as Level 3		6		6		5
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1],[2]	(11)		(11)		$ 1
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Trading Revenue		7	1	26	16
Net Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	[3]	0	0	(1)	0
Net Derivative Assets [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	[3]	$ 0	$ 0	$ (1)	$ 0

[1] Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Condensed Consolidated Balance Sheets. As of June 30, 2017, net cash collateral (received) paid of $(11) million was netted against the corresponding net derivative contract positions. Of the $(11) million as of June 30, 2017, $(4) million was netted against current assets, $(9) million was netted against noncurrent assets, and $2 million was netted against current liabilities. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities.

[2] Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, 2017 and December 31, 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

[3] During the three months ended June 30, 2017 there were no transfers in to or out of Level 3. During the six months ended June 30, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in to or out of Level 3 during three months and six months ended June 30, 2016.

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Fair Value Measurements (Fair Value Of Debt) (Detail) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount		$ 12,521	$ 11,395
Long-Term Debt, Fair Value		13,434	12,003
Power - Recourse Debt [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount	[1]	2,384	2,382
Long-Term Debt, Fair Value	[1]	2,646	2,578
PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount	[1]	8,242	7,818
Long-Term Debt, Fair Value	[1]	8,900	8,240
PSEG [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount	[2]	1,895	1,195
Long-Term Debt, Fair Value	[2]	1,888	1,185
Variable Rate [Domain] | PSEG [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Instrument, Face Amount		$ 700	$ 500

[1] Given that most bonds do not trade, 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.

[2] As of June 30, 2017, fair value includes a $700 million floating rate term loan term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016. The fair values of the term loan debt (Level 2 measurement) were considered to be equal to the carrying values because the interest payments are based on LIBOR rates that are reset monthly.

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Other Income And Deductions (Schedule Of Other Income) (Detail) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016		Jun. 30, 2017		Jun. 30, 2016
Component of Other Income [Line Items]
NDT Fund Gains, Interest, Dividend and Other Income		$ 45	$ 23		$ 76		$ 48
Allowance for Funds Used During Construction		14	10		28		21
Rabbi Trust Gains Interest Dividend and Other Income		4	3		20		6
Solar Loan Interest		5	5		10		11
Other		2	3		8		6
Total Other Income		70	44		142		92
PSE And G [Member]
Component of Other Income [Line Items]
NDT Fund Gains, Interest, Dividend and Other Income		0	0		0		0
Allowance for Funds Used During Construction		14	10		28		21
Rabbi Trust Gains Interest Dividend and Other Income		1	1		4		1
Solar Loan Interest		5	5		10		11
Other		2	3		5		6
Total Other Income		22	19		47		39
Power [Member]
Component of Other Income [Line Items]
NDT Fund Gains, Interest, Dividend and Other Income		45	23		76		48
Allowance for Funds Used During Construction		0	0		0		0
Rabbi Trust Gains Interest Dividend and Other Income		1	1		5		2
Solar Loan Interest		0	0		0		0
Other		0	1		3		1
Total Other Income		46	25		84		51
Other Entities [Member]
Component of Other Income [Line Items]
NDT Fund Gains, Interest, Dividend and Other Income	[1]	0	0		0		0
Allowance for Funds Used During Construction	[1]	0	0		0		0
Rabbi Trust Gains Interest Dividend and Other Income		2	1	[1]	11	[1]	3	[1]
Solar Loan Interest	[1]	0	0		0		0
Other	[1]	0	(1)		0		(1)
Total Other Income	[1]	$ 2	$ 0		$ 11		$ 2

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

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Other Income And Deductions (Schedule Of Other Deductions) (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Component of Other Deductions [Line Items]
NDT Fund Realized Losses and Expenses		$ 6	$ 8	$ 13	$ 26
Other		3	2	7	5
Total Other Deductions		9	10	20	31
PSE And G [Member]
Component of Other Deductions [Line Items]
NDT Fund Realized Losses and Expenses		0	0	0	0
Other		1	1	2	2
Total Other Deductions		1	1	2	2
Power [Member]
Component of Other Deductions [Line Items]
NDT Fund Realized Losses and Expenses		6	8	13	26
Other		1	1	1	1
Total Other Deductions		7	9	14	27
Other Entities [Member]
Component of Other Deductions [Line Items]
NDT Fund Realized Losses and Expenses	[1]	0	0	0	0
Other	[1]	1	0	4	2
Total Other Deductions	[1]	$ 1	$ 0	$ 4	$ 2

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

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Income Taxes (Schedule Of Effective Tax Rates) (Detail)	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Taxes [Line Items]
Effective tax rate	35.10%	32.70%	28.30%	36.20%
PSE And G [Member]
Income Taxes [Line Items]
Effective tax rate	37.20%	35.40%	36.70%	36.10%
Power [Member]
Income Taxes [Line Items]
Effective tax rate	39.00%	50.00%	40.00%	39.50%

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Income Taxes (Narrative) (Detail)	6 Months Ended
	Jun. 30, 2017
Income Taxes [Line Items]
Bonus Depreciation For Tax Purposes	50.00%
Bonus Depreciation for Tax Purposes 2018	40.00%
Bonus Depreciation for Tax Purposes 2019	30.00%
Current ITC rate for qualified property	30.00%
2020 ITC rate for qualified property	26.00%
2021 ITC rate for qualified property	22.00%
Long production property [Member]
Income Taxes [Line Items]
Bonus Depreciation for Tax Purposes 2018	50.00%
Bonus Depreciation for Tax Purposes 2019	40.00%

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Accumulated Other Comprehensive Income (Loss), Net of Tax (Changes of AOCI) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	$ (242)	$ (269)	$ (263)	$ (295)	$ (295)
Other Comprehensive Income before Reclassifications	23	7	53	19
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(7)	10	(16)	24
Other Comprehensive Income (Loss), net of tax	16	17	37	43
Accumulated Other Comprehensive Income (Loss), Ending Balance	(226)	(252)	(226)	(252)	(263)
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	2	2	2	0	0
Other Comprehensive Income before Reclassifications	0	(1)	0	1	2
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	0	0	0	0	0
Other Comprehensive Income (Loss), net of tax	0	(1)	0	1
Accumulated Other Comprehensive Income (Loss), Ending Balance	2	1	2	1	2
Pension and OPEB Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	(392)	(378)	(398)	(386)	(386)
Other Comprehensive Income before Reclassifications	0	0	0	0
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	6	8	12	16
Other Comprehensive Income (Loss), net of tax	6	8	12	16
Accumulated Other Comprehensive Income (Loss), Ending Balance	(386)	(370)	(386)	(370)	(398)
Available-for-Sale Securities [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	148	107	133	91	91
Other Comprehensive Income before Reclassifications	23	8	53	18
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(13)	2	(28)	8
Other Comprehensive Income (Loss), net of tax	10	10	25	26
Accumulated Other Comprehensive Income (Loss), Ending Balance	158	117	158	117	133
Power [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	(187)	(217)	(211)	(240)	(240)
Other Comprehensive Income before Reclassifications	22	6	50	16
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(7)	10	(11)	23
Other Comprehensive Income (Loss), net of tax	15	16	39	39
Accumulated Other Comprehensive Income (Loss), Ending Balance	(172)	(201)	(172)	(201)	(211)
Power [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	0	0	0	0	0
Other Comprehensive Income before Reclassifications	0	0	0	0
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	0	0	0	0
Other Comprehensive Income (Loss), net of tax	0	0	0	0
Accumulated Other Comprehensive Income (Loss), Ending Balance	0	0	0	0	0
Power [Member] | Pension and OPEB Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	(335)	(320)	(340)	(327)	(327)
Other Comprehensive Income before Reclassifications	0	0	0	0
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	5	7	10	14
Other Comprehensive Income (Loss), net of tax	5	7	10	14
Accumulated Other Comprehensive Income (Loss), Ending Balance	(330)	(313)	(330)	(313)	(340)
Power [Member] | Available-for-Sale Securities [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	148	103	129	87	87
Other Comprehensive Income before Reclassifications	22	6	50	16
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(12)	3	(21)	9
Other Comprehensive Income (Loss), net of tax	10	9	29	25
Accumulated Other Comprehensive Income (Loss), Ending Balance	$ 158	$ 112	$ 158	$ 112	$ 129

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Accumulated Other Comprehensive Income (Loss), Net of Tax (Reclassifications of AOCI) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	$ 15	$ (19)	$ 33	$ (44)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Tax	(8)	9	(17)	20
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	7	(10)	16	(24)
Cash Flow Hedges [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0	0	0	$ 0
Pension and OPEB Plans [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification Adjustment from AOCI, Pension and OPEB, Pre-Tax	(10)	(14)	(20)	(28)
Reclassification Adjustment from AOCI, Pension and OPEB, Tax	4	6	8	12
Reclassification Adjustment from AOCI, Pension and OPEB, After-Tax	(6)	(8)	(12)	(16)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(6)	(8)	(12)	(16)
Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	25	(5)	53	(16)
Reclassification for Available for Sale Securities, Tax	(12)	3	(25)	8
Reclassification for Available for Sale Securities, After-Tax	13	(2)	28	(8)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	13	(2)	28	(8)
Power [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	16	(18)	26	(41)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Tax	(9)	8	(15)	18
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	7	(10)	11	(23)
Power [Member] | Cash Flow Hedges [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0	0	0
Power [Member] | Pension and OPEB Plans [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification Adjustment from AOCI, Pension and OPEB, Pre-Tax	(8)	(12)	(17)	(24)
Reclassification Adjustment from AOCI, Pension and OPEB, Tax	3	5	7	10
Reclassification Adjustment from AOCI, Pension and OPEB, After-Tax	(5)	(7)	(10)	(14)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(5)	(7)	(10)	(14)
Power [Member] | Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	24	(6)	43	(17)
Reclassification for Available for Sale Securities, Tax	(12)	3	(22)	8
Reclassification for Available for Sale Securities, After-Tax	12	(3)	21	(9)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	12	(3)	21	(9)
Operating Expense [Member] | Pension and OPEB Plans [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of Prior Service (Cost) Credit, Pre-Tax	2	3	4	6
Amortization of Prior Service (Cost) Credit, Tax	(1)	(1)	(2)	(2)
Amortization of Prior Service (Cost) Credit, After-Tax	1	2	2	4
Amortization of Actuarial Loss, Pre-Tax	(12)	(17)	(24)	(34)
Amortization of Actuarial Loss, Tax	5	7	10	14
Amortization of Actuarial Loss, After-Tax	(7)	(10)	(14)	(20)
Operating Expense [Member] | Power [Member] | Pension and OPEB Plans [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of Prior Service (Cost) Credit, Pre-Tax	2	2	4	5
Amortization of Prior Service (Cost) Credit, Tax	(1)	(1)	(2)	(2)
Amortization of Prior Service (Cost) Credit, After-Tax	1	1	2	3
Amortization of Actuarial Loss, Pre-Tax	(10)	(14)	(21)	(29)
Amortization of Actuarial Loss, Tax	4	6	9	12
Amortization of Actuarial Loss, After-Tax	(6)	(8)	(12)	(17)
Other Income [Member] | Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	34	12	70	28
Reclassification for Available for Sale Securities, Tax	(17)	(6)	(34)	(14)
Reclassification for Available for Sale Securities, After-Tax	17	6	36	14
Other Income [Member] | Power [Member] | Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	32	10	57	25
Reclassification for Available for Sale Securities, Tax	(16)	(5)	(29)	(13)
Reclassification for Available for Sale Securities, After-Tax	16	5	28	12
Other Expense [Member] | Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	(6)	(7)	(13)	(24)
Reclassification for Available for Sale Securities, Tax	4	4	7	12
Reclassification for Available for Sale Securities, After-Tax	(2)	(3)	(6)	(12)
Other Expense [Member] | Power [Member] | Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	(5)	(6)	(10)	(22)
Reclassification for Available for Sale Securities, Tax	3	3	5	11
Reclassification for Available for Sale Securities, After-Tax	(2)	(3)	(5)	(11)
Other-Than-Temporary Impairments [Member] | Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	(3)	(10)	(4)	(20)
Reclassification for Available for Sale Securities, Tax	1	5	2	10
Reclassification for Available for Sale Securities, After-Tax	(2)	(5)	(2)	(10)
Other-Than-Temporary Impairments [Member] | Power [Member] | Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	(3)	(10)	(4)	(20)
Reclassification for Available for Sale Securities, Tax	1	5	2	10
Reclassification for Available for Sale Securities, After-Tax	$ (2)	$ (5)	$ (2)	$ (10)

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Earnings Per Share (EPS) And Dividends (Basic And Diluted Earnings Per Share Computation) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0.3		0.3	0.3
Net Income (Loss)	$ 109	$ 187	$ 223	$ 658
Weighted Average Common Shares Outstanding, Basic (shares)	505.0	505.0	505.0	505.0
Effect of Stock Based Compensation Awards, Basic (shares)	0.0	0.0	0.0	0.0
Total Shares, Basic (shares)	505.0	505.0	505.0	505.0
Net Income, Basic (dollars per share)	$ 0.22	$ 0.37	$ 0.44	$ 1.30
Weighted Average Common Shares Outstanding, Diluted (shares)	505.0	505.0	505.0	505.0
Effect of Stock Based Compensation Awards, Diluted (shares)	2.0	3.0	2.0	3.0
Total Shares, Diluted (shares)	507.0	508.0	507.0	508.0
Net Income, Diluted (dollars per share)	$ 0.22	$ 0.37	$ 0.44	$ 1.30

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Earnings Per Share (EPS) And Dividends (Dividend Payments On Common Stock) (Detail) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		6 Months Ended
	Jul. 18, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
DIVIDENDS PAID PER SHARE OF COMMON STOCK (in dollars per share)		$ 0.43	$ 0.41	$ 0.86	$ 0.82
Dividend Payments on Common Stock		$ 217	$ 208	$ 435	$ 415
Subsequent Event [Member]
Common Stock, Dividends, Per Share, Declared	$ 0.43

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Financial Information By Business Segments (Financial Information By Business Segments) (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Operating Revenues		$ 2,133	$ 1,905	$ 4,725	$ 4,521
Net Income (Loss)		109	187	223	658
Property, Plant and Equipment, Additions		919	906	1,981	1,971
Total Assets		40,524		40,524		$ 40,070
Investments in Equity Method Subsidiaries		91		91		102
Operating Segments [Member] | PSE And G [Member]
Segment Reporting Information [Line Items]
Operating Revenues		1,368	1,350	3,180	3,062
Net Income (Loss)		208	179	507	441
Property, Plant and Equipment, Additions		641	631	1,389	1,355
Total Assets		27,273		27,273		26,288
Investments in Equity Method Subsidiaries		0		0		0
Operating Segments [Member] | Power [Member]
Segment Reporting Information [Line Items]
Operating Revenues		929	714	2,213	2,027
Net Income (Loss)		(97)	(11)	(267)	181
Property, Plant and Equipment, Additions		269	265	576	598
Total Assets		11,619		11,619		12,193
Investments in Equity Method Subsidiaries		91		91		102
Operating Segments [Member] | Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]	116	127	199	249
Net Income (Loss)	[1]	(2)	19	(17)	36
Property, Plant and Equipment, Additions	[1]	9	10	16	18
Total Assets	[1]	2,425		2,425		2,373
Investments in Equity Method Subsidiaries	[1]	0		0		0
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[2]	(280)	(286)	(867)	(817)
Net Income (Loss)	[2]	0	0	0
Property, Plant and Equipment, Additions	[2]	0	$ 0	0	$ 0
Total Assets	[2]	(793)		(793)		(784)
Investments in Equity Method Subsidiaries	[2]	$ 0		$ 0		$ 0

[1] 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.

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

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Related-Party Transactions (Schedule Of Related Party Transactions, Revenue) (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017		Jun. 30, 2016
PSE And G [Member]
Related Party Transaction [Line Items]
Billings from Power through BGS and BGSS	[1]	$ 296	$ 297	$ 895		$ 842
Administrative Billings from Services	[2]	79	82	144		151
Total Billings from Affiliates		375	379	1,039		993
Power [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties		296	297	895	[1]	842	[1]
Administrative Billings from Services		$ 42	$ 45	$ 78	[2]	$ 90	[2]

[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. 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.

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Related-Party Transactions (Schedule Of Related Party Transactions, Payables) (Detail) - PSE And G [Member] - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Receivable From PSEG	[1]	$ 20	$ 76
Payable To Power	[2]	90	193
Payable To Services	[3]	56	67
Accounts Payable - Affiliated Companies		146	260
Working Capital Advances to Services	[4]	33	33
Long-Term Accrued Taxes Payable		$ 115	$ 130

[1] 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.

[2] 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. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.

[3] 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.

[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 Condensed Consolidated Balance Sheets.

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Related-Party Transactions (Schedule Of Related Party Transactions, Receivables) (Detail) - Power [Member] - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Receivable from PSE&G	[1]	$ 90	$ 193
Receivable From PSEG		49	12	[2]
Due from Affiliate, Current		139	205
Payable To Services	[3]	20	25
Accounts Payable - Affiliated Companies		20	25
Short Term Loan To Affiliate	[4]	233	87
Working Capital Advances to Services	[5]	17	17
Long-Term Accrued Taxes Payable		$ 93	$ 77

[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. 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] 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.

[3] 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.

[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 Condensed Consolidated Balance Sheets.

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Guarantees Of Debt (Schedule Of Financial Statements Of Guarantors) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Debt Instrument [Line Items]
Operating Revenues	$ 2,133	$ 1,905	$ 4,725	$ 4,521
Operating Expenses	1,937	1,558	4,351	3,347
Operating Income (Loss)	196	347	374	1,174
Equity Earnings (Losses) of Subsidiaries	5	4	8	6
Other Income	70	44	142	92
Other Deductions	(9)	(10)	(20)	(31)
Other-Than-Temporary Impairments	(3)	(10)	(4)	(20)
Interest Expense	(91)	(97)	(189)	(189)
Income Tax Benefit (Expense)	(59)	(91)	(88)	(374)
Net Income (Loss)	109	187	223	658
Net Cash Provided By (Used In) Operating Activities			1,756	1,722
Net Cash Provided By (Used In) Investing Activities			(1,989)	(2,004)
Net Cash Provided By (Used In) Financing Activities			240	536
Current Assets	3,188		3,188		$ 3,254
Property, Plant and Equipment, net	29,637		29,637		29,286
Noncurrent Assets	7,699		7,699		7,530
Total Assets	40,524		40,524		40,070
Current Liabilities	3,164		3,164		3,276
Noncurrent Liabilities	12,821		12,821		12,769
Long-Term Debt	11,621		11,621		10,895
Member's Equity	12,918		12,918		13,130
TOTAL LIABILITIES AND CAPITALIZATION	40,524		40,524		40,070
Power [Member]
Debt Instrument [Line Items]
Operating Revenues	929	714	2,213	2,027
Operating Expenses	1,116	726	2,703	1,696
Operating Income (Loss)	(187)	(12)	(490)	331
Equity Earnings (Losses) of Subsidiaries	5	4	8	6
Other Income	46	25	84	51
Other Deductions	(7)	(9)	(14)	(27)
Other-Than-Temporary Impairments	(3)	(10)	(4)	(20)
Interest Expense	(13)	(20)	(29)	(42)
Income Tax Benefit (Expense)	62	11	178	(118)
Net Income (Loss)	(97)	(11)	(267)	181
Net Cash Provided By (Used In) Operating Activities			932	917
Net Cash Provided By (Used In) Investing Activities			(735)	(1,607)
Net Cash Provided By (Used In) Financing Activities			(179)	694
Current Assets	1,382		1,382		1,460
Property, Plant and Equipment, net	7,826		7,826		8,520
Noncurrent Assets	2,411		2,411		2,213
Total Assets	11,619		11,619		12,193
Current Liabilities	679		679		680
Noncurrent Liabilities	3,160		3,160		3,332
Long-Term Debt	2,384		2,384		2,382
Member's Equity	5,396		5,396		5,799
TOTAL LIABILITIES AND CAPITALIZATION	11,619		11,619		12,193
Power Senior Notes [Member] | Consolidating Adjustments [Member]
Debt Instrument [Line Items]
Operating Revenues	(28)	(32)	(66)	(63)
Operating Expenses	(28)	(32)	(66)	(63)
Operating Income (Loss)	0	0	0	0
Equity Earnings (Losses) of Subsidiaries	97	0	259	(204)
Other Income	(34)	(22)	(62)	(45)
Other Deductions	0	0	0	0
Other-Than-Temporary Impairments	0	0	0	0
Interest Expense	34	22	62	45
Income Tax Benefit (Expense)	0	0	0	0
Net Income (Loss)	97	0	259	(204)
Comprehensive Income (Loss)	88	(9)	229	(229)
Net Cash Provided By (Used In) Operating Activities			51	(356)
Net Cash Provided By (Used In) Investing Activities			(1,355)	579
Net Cash Provided By (Used In) Financing Activities			1,304	(223)
Current Assets	(4,213)		(4,213)		(4,697)
Property, Plant and Equipment, net	0		0		0
Investment in Subsidiaries	(4,355)		(4,355)		(4,593)
Noncurrent Assets	(117)		(117)		(100)
Total Assets	(8,685)		(8,685)		(9,390)
Current Liabilities	(4,213)		(4,213)		(4,697)
Noncurrent Liabilities	(117)		(117)		(100)
Long-Term Debt	0		0		0
Member's Equity	(4,355)		(4,355)		(4,593)
TOTAL LIABILITIES AND CAPITALIZATION	(8,685)		(8,685)		(9,390)
Power Senior Notes [Member] | Power Parent [Member]
Debt Instrument [Line Items]
Operating Revenues	0	0	0	0
Operating Expenses	(2)	2	2	12
Operating Income (Loss)	2	(2)	(2)	(12)
Equity Earnings (Losses) of Subsidiaries	(93)	(1)	(254)	204
Other Income	22	17	47	34
Other Deductions	0	0	(1)	0
Other-Than-Temporary Impairments	0	0	0	0
Interest Expense	(34)	(31)	(64)	(61)
Income Tax Benefit (Expense)	6	6	7	16
Net Income (Loss)	(97)	(11)	(267)	181
Comprehensive Income (Loss)	(82)	5	(228)	220
Net Cash Provided By (Used In) Operating Activities			(32)	337
Net Cash Provided By (Used In) Investing Activities			683	(1,287)
Net Cash Provided By (Used In) Financing Activities			(651)	951
Current Assets	4,156		4,156		4,412
Property, Plant and Equipment, net	56		56		55
Investment in Subsidiaries	4,015		4,015		4,249
Noncurrent Assets	184		184		168
Total Assets	8,411		8,411		8,884
Current Liabilities	88		88		171
Noncurrent Liabilities	543		543		532
Long-Term Debt	2,384		2,384		2,382
Member's Equity	5,396		5,396		5,799
TOTAL LIABILITIES AND CAPITALIZATION	8,411		8,411		8,884
Power Senior Notes [Member] | Guarantor Subsidiaries [Member]
Debt Instrument [Line Items]
Operating Revenues	910	700	2,180	2,002
Operating Expenses	1,103	716	2,672	1,668
Operating Income (Loss)	(193)	(16)	(492)	334
Equity Earnings (Losses) of Subsidiaries	(4)	1	(5)	0
Other Income	56	30	97	62
Other Deductions	(7)	(9)	(13)	(27)
Other-Than-Temporary Impairments	(3)	(10)	(4)	(20)
Interest Expense	(9)	(7)	(18)	(17)
Income Tax Benefit (Expense)	60	3	171	(137)
Net Income (Loss)	(100)	(8)	(264)	195
Comprehensive Income (Loss)	(91)	1	(234)	220
Net Cash Provided By (Used In) Operating Activities			802	777
Net Cash Provided By (Used In) Investing Activities			178	(504)
Net Cash Provided By (Used In) Financing Activities			(978)	(273)
Current Assets	1,257		1,257		1,593
Property, Plant and Equipment, net	5,244		5,244		6,145
Investment in Subsidiaries	340		340		344
Noncurrent Assets	2,225		2,225		2,016
Total Assets	9,066		9,066		10,098
Current Liabilities	3,156		3,156		3,752
Noncurrent Liabilities	2,195		2,195		2,398
Long-Term Debt	0		0		0
Member's Equity	3,715		3,715		3,948
TOTAL LIABILITIES AND CAPITALIZATION	9,066		9,066		10,098
Power Senior Notes [Member] | Non-Guarantor Subsidiaries [Member]
Debt Instrument [Line Items]
Operating Revenues	47	46	99	88
Operating Expenses	43	40	95	79
Operating Income (Loss)	4	6	4	9
Equity Earnings (Losses) of Subsidiaries	5	4	8	6
Other Income	2	0	2	0
Other Deductions	0	0	0	0
Other-Than-Temporary Impairments	0	0	0	0
Interest Expense	(4)	(4)	(9)	(9)
Income Tax Benefit (Expense)	(4)	2	0	3
Net Income (Loss)	3	8	5	9
Comprehensive Income (Loss)	3	8	5	9
Net Cash Provided By (Used In) Operating Activities			111	159
Net Cash Provided By (Used In) Investing Activities			(241)	(395)
Net Cash Provided By (Used In) Financing Activities			146	239
Current Assets	182		182		152
Property, Plant and Equipment, net	2,526		2,526		2,320
Investment in Subsidiaries	0		0		0
Noncurrent Assets	119		119		129
Total Assets	2,827		2,827		2,601
Current Liabilities	1,648		1,648		1,454
Noncurrent Liabilities	539		539		502
Long-Term Debt	0		0		0
Member's Equity	640		640		645
TOTAL LIABILITIES AND CAPITALIZATION	2,827		2,827		2,601
Power Senior Notes [Member] | Power [Member]
Debt Instrument [Line Items]
Operating Revenues	929	714	2,213	2,027
Operating Expenses	1,116	726	2,703	1,696
Operating Income (Loss)	(187)	(12)	(490)	331
Equity Earnings (Losses) of Subsidiaries	5	4	8	6
Other Income	46	25	84	51
Other Deductions	(7)	(9)	(14)	(27)
Other-Than-Temporary Impairments	(3)	(10)	(4)	(20)
Interest Expense	(13)	(20)	(29)	(42)
Income Tax Benefit (Expense)	62	11	178	(118)
Net Income (Loss)	(97)	(11)	(267)	181
Comprehensive Income (Loss)	(82)	$ 5	(228)	220
Net Cash Provided By (Used In) Operating Activities			932	917
Net Cash Provided By (Used In) Investing Activities			(735)	(1,607)
Net Cash Provided By (Used In) Financing Activities			(179)	$ 694
Current Assets	1,382		1,382		1,460
Property, Plant and Equipment, net	7,826		7,826		8,520
Investment in Subsidiaries	0		0		0
Noncurrent Assets	2,411		2,411		2,213
Total Assets	11,619		11,619		12,193
Current Liabilities	679		679		680
Noncurrent Liabilities	3,160		3,160		3,332
Long-Term Debt	2,384		2,384		2,382
Member's Equity	5,396		5,396		5,799
TOTAL LIABILITIES AND CAPITALIZATION	$ 11,619		$ 11,619		$ 12,193