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, 2016

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 or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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
Public Service Electric and Gas Company	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o
PSEG Power LLC	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o

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 19, 2016, Public Service Enterprise Group Incorporated had outstanding 505,916,520 shares of its sole class of Common Stock, without par value.

As of July 19, 2016, 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. Variable Interest Entities (VIEs)	18
	Note 4. Rate Filings	18
	Note 5. Financing Receivables	19
	Note 6. Available-for-Sale Securities	21
	Note 7. Pension and Other Postretirement Benefits (OPEB)	26
	Note 8. Commitments and Contingent Liabilities	28
	Note 9. Debt and Credit Facilities	35
	Note 10. Financial Risk Management Activities	36
	Note 11. Fair Value Measurements	43
	Note 12. Other Income and Deductions	51
	Note 13. Income Taxes	52
	Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax	53
	Note 15. Earnings Per Share (EPS) and Dividends	57
	Note 16. Financial Information by Business Segments	58
	Note 17. Related-Party Transactions	59
	Note 18. Guarantees of Debt	61
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	64
	Executive Overview of 2016 and Future Outlook	64
	Results of Operations	70
	Liquidity and Capital Resources	75
	Capital Requirements	77
	Accounting Matters	77
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	78
Item 4.	Controls and Procedures	79
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	79
Item 1A.	Risk Factors	79
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	79
Item 5.	Other Information	79
Item 6.	Exhibits	83
	Signatures	84

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 and available on our website: http://www.pseg.com. These factors include, but are not limited to:

• adverse changes in the demand for or ongoing low pricing of the capacity and energy that we sell into wholesale electricity markets,

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

• any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators, including prudency reviews, disallowances and changes in authorized returns,

• any deterioration in our credit quality or the credit quality of our counterparties,

• changes in federal and state environmental regulations and enforcement that could increase our costs or limit our operations,

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

• changes in nuclear regulation and/or general developments in the nuclear power industry, including various impacts from any accidents or incidents experienced at our facilities or by others in the industry, that could limit operations or increase the cost of our nuclear generating units,

• actions or activities at one of our nuclear units located on a multi-unit site that might adversely affect our ability to continue to operate that unit or other units located at the same site,

• any inability to manage our energy obligations, available supply and risks,

• delays or unforeseen cost escalations in our construction and development activities, or the inability to recover the carrying amount of our assets,

• availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs,

• increases in competition in energy supply markets as well as for transmission projects,

• changes in technology, such as distributed generation, storage and micro grids, and greater reliance on these technologies,

• changes in customer behaviors, including increases in energy efficiency, net-metering and demand response,

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

• any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers, and any inability to obtain sufficient insurance coverage or recover proceeds of insurance with respect to such events,

• acts of terrorism, cybersecurity attacks or intrusions that could adversely impact our businesses,

• delays in receipt of necessary permits and approvals for our construction and development activities,

• any inability to achieve, or continue to sustain, our expected levels of operating performance,

• changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units,

• an extended economic recession,

• an inability to realize anticipated tax benefits or retain tax credits,

• challenges associated with recruitment and/or retention of a qualified workforce, and

• changes in the credit quality and the ability of lessees to meet their obligations under our domestic leveraged leases.

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

ii

consequences to, or effects on, us or our business prospects, financial condition or results of operations. 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 if internal estimates change, 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,
	2016			2015			2016			2015
OPERATING REVENUES	$	1,905		$	2,314		$	4,521		$	5,449
OPERATING EXPENSES
Energy Costs	624			668			1,460			1,762
Operation and Maintenance	710			761			1,439			1,424
Depreciation and Amortization	224			317			448			647
Total Operating Expenses	1,558			1,746			3,347			3,833
OPERATING INCOME	347			568			1,174			1,616
Income from Equity Method Investments	4			4			6			7
Other Income	44			76			92			124
Other Deductions	(10		)	(10		)	(31		)	(22		)
Other-Than-Temporary Impairments	(10		)	(10		)	(20		)	(15		)
Interest Expense	(97		)	(97		)	(189		)	(195		)
INCOME BEFORE INCOME TAXES	278			531			1,032			1,515
Income Tax Expense	(91		)	(186		)	(374		)	(584		)
NET INCOME	$	187		$	345		$	658		$	931
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			506			505			506
DILUTED	508			508			508			508
NET INCOME PER SHARE:
BASIC	$	0.37		$	0.68		$	1.30		$	1.84
DILUTED	$	0.37		$	0.68		$	1.30		$	1.83
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.41		$	0.39		$	0.82		$	0.78

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,
	2016			2015			2016		2015
NET INCOME	$	187		$	345		$	658	$	931
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(10), $15, $(26) and $2 for the three and six months ended 2016 and 2015, respectively	10			(15		)	26		(1		)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $(1) and $7 for the three and six months ended 2016 and 2015, respectively	(1		)	—			1		(9		)
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(6), $(6), $(12) and $(12) for the three and six months ended 2016 and 2015, respectively	8			8			16		16
Other Comprehensive Income (Loss), net of tax	17			(7		)	43		6
COMPREHENSIVE INCOME	$	204		$	338		$	701	$	937

See Notes to Condensed Consolidated Financial Statements.

2

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	June 30, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	648		$	394
Accounts Receivable, net of allowances of $65 and $67 in 2016 and 2015, respectively	988			1,068
Tax Receivable	4			305
Unbilled Revenues	202			197
Fuel	351			463
Materials and Supplies, net	554			513
Prepayments	271			135
Derivative Contracts	152			242
Regulatory Assets	310			164
Other	9			13
Total Current Assets	3,489			3,494
PROPERTY, PLANT AND EQUIPMENT	37,285			35,494
Less: Accumulated Depreciation and Amortization	(9,271		)	(8,955		)
Net Property, Plant and Equipment	28,014			26,539
NONCURRENT ASSETS
Regulatory Assets	3,120			3,196
Long-Term Investments	1,218			1,233
Nuclear Decommissioning Trust (NDT) Fund	1,797			1,754
Long-Term Tax Receivable	183			171
Long-Term Receivable of Variable Interest Entity (VIE)	513			495
Other Special Funds	246			227
Goodwill	16			16
Other Intangibles	131			102
Derivative Contracts	76			77
Other	242			231
Total Noncurrent Assets	7,542			7,502
TOTAL ASSETS	$	39,045		$	37,535

See Notes to Condensed Consolidated Financial Statements.

3

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	June 30, 2016			December 31, 2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	662		$	734
Commercial Paper and Loans	—			364
Accounts Payable	1,308			1,369
Derivative Contracts	20			76
Accrued Interest	103			96
Accrued Taxes	107			42
Clean Energy Program	200			142
Obligation to Return Cash Collateral	128			128
Regulatory Liabilities	74			123
Regulatory Liabilities of VIEs	22			42
Other	496			459
Total Current Liabilities	3,120			3,575
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,545			8,166
Regulatory Liabilities	165			175
Asset Retirement Obligations	693			679
OPEB Costs	1,199			1,228
OPEB Costs of Servco	389			375
Accrued Pension Costs	429			487
Accrued Pension Costs of Servco	118			114
Clean Energy Program	27			—
Environmental Costs	402			415
Derivative Contracts	14			27
Long-Term Accrued Taxes	171			212
Other	181			181
Total Noncurrent Liabilities	12,333			12,059
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT	10,273			8,834
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2016 and 2015—534 shares	4,919			4,915
Treasury Stock, at cost, 2016—29 shares; 2015—28 shares	(709		)	(671		)
Retained Earnings	9,360			9,117
Accumulated Other Comprehensive Loss	(252		)	(295		)
Total Common Stockholders’ Equity	13,318			13,066
Noncontrolling Interest	1			1
Total Stockholders’ Equity	13,319			13,067
Total Capitalization	23,592			21,901
TOTAL LIABILITIES AND CAPITALIZATION	$	39,045		$	37,535

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	658		$	931
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	448			647
Amortization of Nuclear Fuel	105			106
Provision for Deferred Income Taxes (Other than Leases) and ITC	334			170
Non-Cash Employee Benefit Plan Costs	63			81
Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes	(30		)	(22		)
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	153			(9		)
Change in Accrued Storm Costs	(1		)	15
Net Change in Other Regulatory Assets and Liabilities	(124		)	(53		)
Cost of Removal	(74		)	(58		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(2		)	(21		)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	301			188
Accrued Taxes	94			71
Margin Deposit	(46		)	69
Other Current Assets and Liabilities	(120		)	98
Employee Benefit Plan Funding and Related Payments	(78		)	(67		)
Other	41			88
Net Cash Provided By (Used In) Operating Activities	1,722			2,234
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,971		)	(1,743		)
Proceeds from Sales of Available-for-Sale Securities	392			885
Investments in Available-for-Sale Securities	(407		)	(918		)
Other	(18		)	3
Net Cash Provided By (Used In) Investing Activities	(2,004		)	(1,773		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(364		)	—
Issuance of Long-Term Debt	1,550			600
Redemption of Long-Term Debt	(171		)	(300		)
Redemption of Securitization Debt	—			(125		)
Cash Dividends Paid on Common Stock	(415		)	(394		)
Other	(64		)	(47		)
Net Cash Provided By (Used In) Financing Activities	536			(266		)
Net Increase (Decrease) in Cash and Cash Equivalents	254			195
Cash and Cash Equivalents at Beginning of Period	394			402
Cash and Cash Equivalents at End of Period	$	648		$	597
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(276	)	$	184
Interest Paid, Net of Amounts Capitalized	$	176		$	195
Accrued Property, Plant and Equipment Expenditures	$	513		$	324

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,
	2016			2015			2016			2015
OPERATING REVENUES	$	1,350		$	1,466		$	3,062		$	3,468
OPERATING EXPENSES
Energy Costs	529			544			1,258			1,436
Operation and Maintenance	352			368			734			780
Depreciation and Amortization	136			234			275			481
Total Operating Expenses	1,017			1,146			2,267			2,697
OPERATING INCOME	333			320			795			771
Other Income	19			19			39			37
Other Deductions	(1		)	(1		)	(2		)	(2		)
Interest Expense	(74		)	(67		)	(142		)	(136		)
INCOME BEFORE INCOME TAXES	277			271			690			670
Income Tax Expense	(98		)	(104		)	(249		)	(261		)
NET INCOME	$	179		$	167		$	441		$	409

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,
	2016		2015			2016		2015
NET INCOME	$	179	$	167		$	441	$	409
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 and $0 for the three and six months ended 2016 and 2015, respectively	1		(1		)	1		(1		)
COMPREHENSIVE INCOME	$	180	$	166		$	442	$	408

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, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	168		$	198
Accounts Receivable, net of allowances of $65 and $67 in 2016 and 2015, respectively	736			787
Accounts Receivable—Affiliated Companies	—			222
Unbilled Revenues	202			197
Materials and Supplies	162			148
Prepayments	196			31
Regulatory Assets	310			164
Derivative Contracts	—			13
Other	8			9
Total Current Assets	1,782			1,769
PROPERTY, PLANT AND EQUIPMENT	24,976			23,732
Less: Accumulated Depreciation and Amortization	(5,627		)	(5,504		)
Net Property, Plant and Equipment	19,349			18,228
NONCURRENT ASSETS
Regulatory Assets	3,120			3,196
Long-Term Investments	316			330
Other Special Funds	57			49
Other	113			105
Total Noncurrent Assets	3,606			3,680
TOTAL ASSETS	$	24,737		$	23,677

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, 2016		December 31, 2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	100	$	171
Commercial Paper and Loans	—		153
Accounts Payable	680		724
Accounts Payable—Affiliated Companies	179		292
Accrued Interest	73		70
Clean Energy Program	200		142
Derivative Contracts	2		—
Obligation to Return Cash Collateral	127		128
Regulatory Liabilities	74		123
Regulatory Liabilities of VIEs	22		42
Other	339		297
Total Current Liabilities	1,796		2,142
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	5,503		5,181
OPEB Costs	904		937
Accrued Pension Costs	165		202
Regulatory Liabilities	165		175
Clean Energy Program	27		—
Environmental Costs	336		365
Asset Retirement Obligations	220		218
Derivative Contracts	—		11
Long-Term Accrued Taxes	99		109
Other	113		114
Total Noncurrent Liabilities	7,532		7,312
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT	7,394		6,650
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2016 and 2015—132 shares	892		892
Contributed Capital	695		695
Basis Adjustment	986		986
Retained Earnings	5,440		4,999
Accumulated Other Comprehensive Income	2		1
Total Stockholder’s Equity	8,015		7,573
Total Capitalization	15,409		14,223
TOTAL LIABILITIES AND CAPITALIZATION	$	24,737	$	23,677

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	441		$	409
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	275			481
Provision for Deferred Income Taxes and ITC	290			79
Non-Cash Employee Benefit Plan Costs	36			48
Cost of Removal	(74		)	(58		)
Change in Accrued Storm Costs	(1		)	15
Net Change in Other Regulatory Assets and Liabilities	(124		)	(53		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	50			53
Materials and Supplies	(14		)	(10		)
Prepayments	(165		)	(162		)
Accounts Payable	(29		)	48
Accounts Receivable/Payable—Affiliated Companies, net	181			154
Other Current Assets and Liabilities	17			(27		)
Employee Benefit Plan Funding and Related Payments	(62		)	(55		)
Other	(13		)	(13		)
Net Cash Provided By (Used In) Operating Activities	808			909
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,355		)	(1,230		)
Proceeds from Sales of Available-for-Sale Securities	12			12
Investments in Available-for-Sale Securities	(13		)	(14		)
Other	2			12
Net Cash Provided By (Used In) Investing Activities	(1,354		)	(1,220		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	(153		)	—
Issuance of Long-Term Debt	850			600
Redemption of Long-Term Debt	(171		)	(300		)
Redemption of Securitization Debt	—			(125		)
Other	(10		)	(8		)
Net Cash Provided By (Used In) Financing Activities	516			167
Net Increase (Decrease) In Cash and Cash Equivalents	(30		)	(144		)
Cash and Cash Equivalents at Beginning of Period	198			310
Cash and Cash Equivalents at End of Period	$	168		$	166
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(255	)	$	(74	)
Interest Paid, Net of Amounts Capitalized	$	134		$	131
Accrued Property, Plant and Equipment Expenditures	$	381		$	282

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,
	2016			2015			2016			2015
OPERATING REVENUES	$	714		$	1,025		$	2,027		$	2,750
OPERATING EXPENSES
Energy Costs	381			409			1,019			1,302
Operation and Maintenance	265			313			518			485
Depreciation and Amortization	80			75			159			151
Total Operating Expenses	726			797			1,696			1,938
OPERATING INCOME (LOSS)	(12		)	228			331			812
Income from Equity Method Investments	4			5			6			8
Other Income	25			55			51			84
Other Deductions	(9		)	(7		)	(27		)	(18		)
Other-Than-Temporary Impairments	(10		)	(10		)	(20		)	(15		)
Interest Expense	(20		)	(33		)	(42		)	(64		)
INCOME (LOSS) BEFORE INCOME TAXES	(22		)	238			299			807
Income Tax Benefit (Expense)	11			(72		)	(118		)	(306		)
NET INCOME (LOSS)	$	(11	)	$	166		$	181		$	501

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

Millions

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016		2015
NET INCOME (LOSS)	$	(11	)	$	166		$	181	$	501
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(9), $14, $(25) and $1 for the three and six months ended 2016 and 2015, respectively	9			(14		)	25		—
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $0 and $7 for the three and six months ended 2016 and 2015, respectively	—			—			—		(9		)
Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(5), $(10) and $(10) for the three and six months ended 2016 and 2015, respectively	7			7			14		14
Other Comprehensive Income (Loss), net of tax	16			(7		)	39		5
COMPREHENSIVE INCOME	$	5		$	159		$	220	$	506

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, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	16		$	12
Accounts Receivable	202			217
Accounts Receivable—Affiliated Companies	94			276
Short-Term Loan to Affiliate	1,335			363
Fuel	351			463
Materials and Supplies, net	389			363
Derivative Contracts	150			223
Prepayments	7			25
Other	4			7
Total Current Assets	2,548			1,949
PROPERTY, PLANT AND EQUIPMENT	11,969			11,354
Less: Accumulated Depreciation and Amortization	(3,491		)	(3,227		)
Net Property, Plant and Equipment	8,478			8,127
NONCURRENT ASSETS
NDT Fund	1,797			1,754
Long-Term Investments	112			119
Goodwill	16			16
Other Intangibles	131			102
Other Special Funds	60			55
Derivative Contracts	76			77
Other	60			51
Total Noncurrent Assets	2,252			2,174
TOTAL ASSETS	$	13,278		$	12,250

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, 2016			December 31, 2015
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	553		$	553
Accounts Payable	466			432
Accounts Payable—Affiliated Companies	102			33
Derivative Contracts	17			76
Accrued Interest	29			25
Other	96			107
Total Current Liabilities	1,263			1,226
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	2,418			2,347
Asset Retirement Obligations	470			457
OPEB Costs	234			230
Derivative Contracts	14			16
Accrued Pension Costs	151			166
Long-Term Accrued Taxes	22			35
Other	104			87
Total Noncurrent Liabilities	3,413			3,338
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT	2,380			1,684
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	5,195			5,014
Accumulated Other Comprehensive Loss	(201		)	(240		)
Total Member’s Equity	6,222			6,002
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	13,278		$	12,250

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	181		$	501
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	159			151
Amortization of Nuclear Fuel	105			106
Provision for Deferred Income Taxes and ITC	37			64
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	153			(9		)
Non-Cash Employee Benefit Plan Costs	19			24
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(2		)	(21		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	86			209
Margin Deposit	(46		)	69
Accounts Receivable	(12		)	76
Accounts Payable	(10		)	(62		)
Accounts Receivable/Payable—Affiliated Companies, net	179			123
Other Current Assets and Liabilities	11			(21		)
Employee Benefit Plan Funding and Related Payments	(10		)	(7		)
Other	67			89
Net Cash Provided By (Used In) Operating Activities	917			1,292
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(598		)	(487		)
Proceeds from Sales of Available-for-Sale Securities	346			837
Investments in Available-for-Sale Securities	(359		)	(854		)
Short-Term Loan—Affiliated Company, net	(972		)	(366		)
Other	(24		)	(17		)
Net Cash Provided By (Used In) Investing Activities	(1,607		)	(887		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	700			—
Cash Dividend Paid	—			(400		)
Other	(6		)	(2		)
Net Cash Provided By (Used In) Financing Activities	694			(402		)
Net Increase (Decrease) in Cash and Cash Equivalents	4			3
Cash and Cash Equivalents at Beginning of Period	12			9
Cash and Cash Equivalents at End of Period	$	16		$	12
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(53	)	$	218
Interest Paid, Net of Amounts Capitalized	$	38		$	62
Accrued Property, Plant and Equipment Expenditures	$	132		$	42

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

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Table of Contents (UNAUDITED)

Note 1. Organization and Basis of Presentation

Organization

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:

• 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.

• Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. 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) 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, 2015.

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, 2015.

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 was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements.

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Table of Contents (UNAUDITED)

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 is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (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.

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.

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.

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. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. 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.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Note 3. Variable Interest Entities (VIEs)

VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which was pledged as collateral to a trustee. PSE&G acted as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds were remitted to Transition Funding and Transition Funding II and were used for interest and principal payments on the transition bonds and related costs. During 2015, Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained with these VIEs. Effective January 1, 2016, PSE&G commenced refunding the overcollections from customers associated with these VIEs and expects to fully refund these liabilities in 2016.

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 Operation and Maintenance (O&M) Expense, respectively. Servco recorded $101 million and $84 million for the three months and $199 million and $166 million for the six months ended June 30, 2016 and 2015, 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 4. Rate Filings

This Note should be read in conjunction with Note 5. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

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:

Remediation Adjustment Charge (RAC)—In April 2016, the BPU approved PSE&G's filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015.

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 2016, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million, respectively. The petition requests rates to be effective September 1, 2016, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.

Basic Gas Supply Service (BGSS)—In June 2016, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $87 million in annual BGSS revenues. If approved, the BGSS rate would be reduced from approximately 40 cents to 34 cents per therm effective October 1, 2016. This matter is pending.

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Transmission Formula Rate Filings—In June 2016, PSE&G filed its 2015 true-up adjustment pertaining to its transmission formula rates in effect for 2015. This resulted in an adjustment of $34 million less than the 2015 originally filed revenues primarily due to the impact of bonus depreciation legislation enacted after PSE&G filed its 2015 formula rate requirement in October 2014. PSE&G had recognized the majority of this adjustment in its Consolidated Statement of Operations for the year ended December 31, 2015.

Weather Normalization Clause—On July 1, 2016, PSE&G filed a petition requesting approval to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period. The deficiency gas revenues would be collected from customers over the 2016-2017 and 2017-2018 Winter Periods (October 1 through May 31). This matter is pending.

Solar and Energy Efficiency - 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. On July 1, 2016, PSE&G filed its 2016 GPRC cost recovery petition requesting recovery for the nine combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2016 through September 30, 2017 designed to recover approximately $44 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.

Gas System Modernization Program (GSMP)—On July 29, 2016, PSE&G filed its initial annual GSMP cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $13 million effective January 1, 2017. This increase represents the return of and on investment for GSMP investments expected to be in service through September 30, 2016. This request will be updated in October 2016 for actual costs.  

Note 5. 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, 2016		December 31, 2015
	Millions
Commercial/Industrial	$	174	$	177
Residential	12		12
Total	$	186	$	189

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’ investments in the leases are comprised of the total expected lease receivables on its investments 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. 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

The following table shows Energy Holdings’ gross and net lease investment as of June 30, 2016 and December 31, 2015, respectively.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	630		$	631
Estimated Residual Value of Leased Assets	519			519
Total Investment in Rental Receivables	1,149			1,150
Unearned and Deferred Income	(359		)	(366		)
Gross Investment in Leases	790			784
Deferred Tax Liabilities	(694		)	(724		)
Net Investment in Leases	$	96		$	60

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, 2016
	As of June 30, 2016
	Millions
AA	$	16
BBB+ — BBB-	316
BB-	134
CCC	164
Total	$	630

The “BB-” and the "CCC" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of June 30, 2016, the gross investment in the leases of such assets, net of non-recourse debt, was $573 million ($(5) million, net of deferred taxes). A more detailed description of such assets under lease, as of June 30, 2016, 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	$	84	64	%	1,044	Coal (A)	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC (C)	NRG REMA, LLC
Conemaugh Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC (C)	NRG REMA, LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	113	100	%	603	Coal (B)	CCC (C)	NRG REMA, LLC

(A) The Joliet facility is currently in the process of converting to natural gas.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

(B) NRG REMA, LLC (NRG REMA) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the fall of 2016 with the ability to use natural gas.

(C) On May 24, 2016, S&P lowered its corporate credit rating on GenOn Energy Inc. and affiliates (including NRG REMA) to "CCC" from "CCC+" due to a weaker forward power curve, milder weather patterns and weakening financial measures. PSEG continues to monitor any changes to GenOn's status and potential impacts on Energy Holdings' lease investments.

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. 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 attempt to 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 investments and trigger certain material tax obligations which could be mitigated by tax indemnification claims with 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. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities to the Internal Revenue Service.

Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which 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 the quality and condition of assets under lease.

Note 6. Available-for-Sale Securities

NDT Fund

Power maintains an external master NDT to fund its share of decommissioning 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 trust funds are managed by third party investment advisers 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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	679	$	198	$	(12	)	$	865
Debt Securities
Government Obligations	503		23		—			526
Other	348		12		(3		)	357
Total Debt Securities	851		35		(3		)	883
Other Securities	49		—		—			49
Total NDT Available-for-Sale Securities	$	1,579	$	233	$	(15	)	$	1,797

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Table of Contents (UNAUDITED)

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	693	$	185	$	(13	)	$	865
Debt Securities
Government Obligations	483		8		(3		)	488
Other	366		3		(10		)	359
Total Debt Securities	849		11		(13		)	847
Other Securities	42		—		—			42
Total NDT Available-for-Sale Securities	$	1,584	$	196	$	(26	)	$	1,754

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	18	$	17
Accounts Payable	$	10	$	10

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, 2016										As of December 31, 2015
	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)	$	108	$	(12	)	$	5	$	—		$	151	$	(13	)	$	1	$	—
Debt Securities
Government Obligations (B)	12		—			6		—			245		(2		)	19		(1		)
Other (C)	12		—			43		(3		)	222		(7		)	36		(3		)
Total Debt Securities	24		—			49		(3		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	132	$	(12	)	$	54	$	(3	)	$	618	$	(22	)	$	56	$	(4	)

(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, 2016.

(B) Debt Securities (Government Obligations)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be

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more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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,
	2016			2015			2016			2015
	Millions
Proceeds from NDT Fund Sales (A)	$	154		$	232		$	331		$	822
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	10			14			25			33
Gross Realized Losses	(6		)	(4		)	(22		)	(13		)
Net Realized Gains (Losses) on NDT Fund	$	4		$	10		$	3		$	20

(A) 2015 proceeds include 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 $110 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of June 30, 2016.

The NDT available-for-sale debt securities held as of June 30, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	19
1 - 5 years	216
6 - 10 years	220
11 - 15 years	54
16 - 20 years	61
Over 20 years	313
Total NDT Available-for-Sale Debt Securities	$	883

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, 2016, other-than-temporary impairments of $20 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.

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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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	10	$	—		$	21
Debt Securities
Government Obligations	104		2		—			106
Other	90		1		(1		)	90
Total Debt Securities	194		3		(1		)	196
Other Securities	5		—		—			5
Total Rabbi Trust Available-for-Sale Securities	$	210	$	13	$	(1	)	$	222

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	10	$	—		$	22
Debt Securities
Government Obligations	108		1		(1		)	108
Other	82		—		(1		)	81
Total Debt Securities	190		1		(2		)	189
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	204	$	11	$	(2	)	$	213

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	2	$	1
Accounts Payable	$	4	$	—

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

	As of June 30, 2016									As of December 31, 2015
	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 Obligations (B)	14		—		3		—			53		(1		)	2		—
Other (C)	14		—		11		(1		)	46		(1		)	9		—
Total Debt Securities	28		—		14		(1		)	99		(2		)	11		—
Rabbi Trust Available-for-Sale Securities	$	28	$	—	$	14	$	(1	)	$	99	$	(2	)	$	11	$	—

(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 Obligations)—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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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,
	2016			2015		2016			2015
	Millions
Proceeds from Rabbi Trust Sales (A)	$	36		$	44	$	61		$	63
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2	$	3		$	2
Gross Realized Losses	(1		)	—		(2		)	—
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	2	$	1		$	2

(A) 2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers.

Gross realized gains disclosed in the preceding table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of $7 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of June 30, 2016.

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The Rabbi Trust available-for-sale debt securities held as of June 30, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	8
1 - 5 years	45
6 - 10 years	48
11 - 15 years	6
16 - 20 years	7
Over 20 years	82
Total Rabbi Trust Available-for-Sale Debt Securities	$	196

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 a commingled 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). 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 assets in the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:

	As of		As of
	June 30, 2016		December 31, 2015
	Millions
PSE&G	$	44	$	42
Power	54		52
Other	124		119
Total Rabbi Trust Available-for-Sale Securities	$	222	$	213

Note 7. Pension and Other Postretirement Benefits (OPEB)

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

Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change is being reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $8 million and $3 million, for the three months ended June 30, 2016 respectively, and $17 million and $6 million for the six months ended June 30, 2016, respectively, as compared to the 2016 amounts that would have been derived from applying PSEG's 2015 and prior years' methodology.

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.

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Pension and OPEB costs for PSEG, except for 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,
	2016			2015			2016			2015			2016			2015			2016			2015
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	27		$	31		$	4		$	6		$	54		$	62		$	8		$	11
Interest Cost	51			58			14			17			101			117			29			34
Expected Return on Plan Assets	(99		)	(104		)	(7		)	(8		)	(197		)	(207		)	(15		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(4		)	(4		)	(4		)	(9		)	(9		)	(7		)	(7		)
Actuarial Loss	40			37			10			11			79			74			20			21
Total Benefit Costs	$	14		$	18		$	17		$	22		$	28		$	37		$	35		$	44

Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, except for 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,
	2016		2015		2016		2015		2016		2015		2016		2015
	Millions
PSE&G	$	7	$	10	$	11	$	14	$	14	$	20	$	22	$	28
Power	4		5		5		6		8		11		11		13
Other	3		3		1		2		6		6		2		3
Total Benefit Costs	$	14	$	18	$	17	$	22	$	28	$	37	$	35	$	44

During the three months ended March 31, 2016, PSEG contributed its entire planned contributions for the year 2016 of $21 million into its pension plans and $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 3. Variable Interest Entities. 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 $28 million into its pension plan during 2016. Servco's pension-related revenues and costs were $6 million and $7 million for the three months ended June 30, 2016 and 2015, respectively, and $12 million and $13 million for the six months ended June 30, 2016 and 2015, respectively. The OPEB-related revenues earned and costs incurred for each of the three months and six months ended June 30, 2016 and 2015 were immaterial.

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Note 8. 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.

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.

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

• all 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. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Power is subject to

• counterparty collateral calls related to commodity contracts, and

• certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

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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The following table shows the face value of Power's outstanding guarantees, current exposure and margin positions as of June 30, 2016 and December 31, 2015.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Face Value of Outstanding Guarantees	$	1,809		$	1,734
Exposure under Current Guarantees	$	136		$	172
Letters of Credit Margin Posted	$	160		$	122
Letters of Credit Margin Received	$	130		$	192
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(4	)	$	(15	)
Net Broker Balance Deposited (Received)	$	30		$	(5	)
Additional Amounts Posted:
Other Letters of Credit	$	51		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. 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 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 had posted letters of credit to support Power's various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power's payment obligations related to its equity interest in the PennEast natural gas pipeline and 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.

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

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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 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 contemplated 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 set forth various alternatives for remediating this portion of the Passaic River.

The CPG, which consisted of 53 members as of June 30, 2016, 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 for the preparation of the RI/FS is approximately $163 million, which the CPG continues to incur. Of the estimated $163 million, as of June 30, 2016, the CPG had spent approximately $150 million, of which PSE&G's and Power's combined share was approximately $11 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, 2016, 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 Chemicals 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, will voluntarily perform the remedial design for the ROD Remedy. If the EPA secures a commitment to perform the

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Remedial Design from OCC, the EPA plans to 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. "Major PRP" is undefined in the letter.

On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG's share of the costs.

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 $426 million and $491 million through2021, including its $46 million share for the Passaic River accrued as of June 30, 2016, as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $426 million as ofJune 30, 2016. Of this amount, $99 million was recorded in Other Current Liabilities and $327 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $426 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. 

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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 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.

On May 19, 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. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule.

On June 10, 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 Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. On July 8, 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.

State permitting decisions could have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants, including Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1.0 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power's future capital requirements, financial condition or results of operations.

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act 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

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intake structure and retire BH3 in 2021, which is four years earlier than the current 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 late 2016.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. 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 will seek to operate BH3 through the current estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. 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.

Steam Electric Effluent Guidelines

On September 30, 2015, the EPA issued a new Effluent Guidelines Limitation 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. 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 Mercer and Bridgeport Harbor stations and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this 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.

Coal Combustion Residuals (CCRs)

On December 19, 2014, the EPA issued a final rule which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power's Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.

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 $335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

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PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:

	Auction Year
	2013	2014	2015	2016
36-Month Terms Ending	May 2016	May 2017	May 2018	May 2019	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$92.18	$97.39	$99.54	$96.38

(A) Prices set in the 2016 BGS auction year became effective on June 1, 2016 when the 2013 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 17. 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 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom.

Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G's customers, Power can use the gas to supply its fossil generating stations.

Power also has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations.

As of June 30, 2016, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Power's Share of Commitments through 2020
	Millions
Nuclear Fuel
Uranium	$	454
Enrichment	$	358
Fabrication	$	180
Natural Gas	$	972
Coal	$	265

Regulatory Proceedings

FERC Compliance

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

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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 continues to implement procedures to help mitigate the risk of similar issues occurring in the future.

During the three month period ended March 31, 2014, based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has responded to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.

PSEG is unable to reasonably estimate the range of possible loss for this matter; however, the amounts of potential disgorgement and other potential penalties that Power may incur span a wide range depending on the success of PSEG's legal arguments. These arguments include that Power’s energy market bids in a substantial majority of the hours were below the allowed rate under the Tariff and therefore any errors in those hours were immaterial and that it is unclear whether the quantity of the bids violated any legal requirement. If PSEG's legal arguments do not prevail in whole or in part with FERC or in ajudicial challenge that PSEG may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to PSEG’s and Power’s Consolidated Statements of Operations in the quarterly and annual periods in which they are recorded.

Nuclear Insurance Coverages

The following should be read in conjunction with Note 12. Commitments and Contingent Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

Based upon a review of its nuclear insurance, Power made changes to its Nuclear Electric Insurance Limited (NEIL) insurance coverage of the excess layer for property damage which became effective on April 1, 2016. The excess layer provides coverage above the primary layer of NEIL insurance coverage for property damage of $1.5 billion. For the excess layer at the Salem/Hope Creek site, Power purchased coverage for property damage of $300 million due to a nuclear event and $300 million due to a non-nuclear event. For the excess layer at the Peach Bottom site, Power purchased coverage for its ownership interest for property damage of $300 million due to a nuclear event. For the excess layer at the Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ownership interest of Power. 

Note 9. Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transactions occurred in the six months ended June 30, 2016:

PSE&G

• issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021,

• issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046, and

• retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds, Series VV at maturity.

Power

• issued $700 million of 3.00% Senior Notes due June 2021.

PSE&G

On July 1, 2016, PSE&G repurchased at par $100 million aggregate principal amount of Pollution Control Financing Authority of Salem County Bonds (Salem Bonds) and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds.

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Short-Term Liquidity

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

The commitments under PSEG's $4.2 billion credit facilities are provided by a diverse bank group with no single institution representing more than 7% of the total commitments in PSEG's credit facilities. As of June 30, 2016, PSEG's total available credit capacity of $3.9 billion was in excess of its anticipated maximum liquidity requirements.

Each of PSEG's 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. PSEG's total credit facilities and available liquidity as of June 30, 2016 were as follows:

	As of June 30, 2016
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	10	$	490	Apr 2019	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—		500		Apr 2020	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	10	$	990
PSE&G
5-year Credit Facility (B)	$	600	$	14	$	586	Apr 2020	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
5-year Credit Facility	$	1,600	$	189	$	1,411	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	953		13		940		Apr 2020	Funding/Letters of Credit
Total Power	$	2,553	$	202	$	2,351
Total	$	4,153	$	226	$	3,927

(A) PSEG facility will be reduced by $12 million in March 2018.

(B) PSE&G facility will be reduced by $14 million in March 2018.

(C)Power facility will be reduced by $24 million in March 2018.

(D) The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs. PSEG and PSE&G had no amounts outstanding under their respective CP Programs as of June 30, 2016.

Note 10. Financial Risk Management Activities

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

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 purchase normal sale (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. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in

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Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. 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 price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. PSEG had no commodity derivative transactions designated as cash flow or fair value hedges as of June 30, 2016 and December 31, 2015.

Economic Hedges

Power enters into derivative contracts that are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of Power's expected generation. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract tooptimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities.

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. As of June 30, 2016, PSEG had interest rate swaps outstanding totaling $550 million. These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of June 30, 2016 and December 31, 2015, the fair value of all the underlying hedges was $2 million and $6 million, respectively. The effect of these hedges reduced interest expense by $2 million and $5 million for the three months ended June 30, 2016 and 2015, respectively, and $4 million and $10 million for the six months ended June 30, 2016 and 2015, respectively.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of June 30, 2016, PSEG had interest rate hedges outstanding totaling $500 million. The hedge ineffectiveness associated with these hedges was immaterial. The total fair value of these interest rate hedges was $(1) million as of June 30, 2016. PSEG interest rate hedges totaling $400 million were terminated during the second quarter and a gain of $2 million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power's $700 million of 3% Senior Notes due June 2021. For additional information see Note 9. Debt and Credit Facilities. There were no outstanding interest rate cash flow hedges as of December 31, 2015. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $1 million as of June 30, 2016 and was immaterial as of December 31, 2015. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months are immaterial. The expiration date of the longest-dated interest rate hedge is in May 2021.

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

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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 have been offset on the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables.

	As of June 30, 2016 (A)
	Power									PSE&G			PSEG			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	$	460		$	(310	)	$	150		$	—		$	2		$	152
Noncurrent Assets	264			(188		)	76			—			—			76
Total Mark-to-Market Derivative Assets	$	724		$	(498	)	$	226		$	—		$	2		$	228
Derivative Contracts
Current Liabilities	$	(334	)	$	317		$	(17	)	$	(2	)	$	(1	)	$	(20	)
Noncurrent Liabilities	(203		)	189			(14		)	—			—			(14		)
Total Mark-to-Market Derivative (Liabilities)	$	(537	)	$	506		$	(31	)	$	(2	)	$	(1	)	$	(34	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	187		$	8		$	195		$	(2	)	$	1		$	194

	As of December 31, 2015 (A)
	Power									PSE&G			PSEG		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	$	700		$	(477	)	$	223		$	13		$	6	$	242
Noncurrent Assets	208			(131		)	77			—			—		77
Total Mark-to-Market Derivative Assets	$	908		$	(608	)	$	300		$	13		$	6	$	319
Derivative Contracts
Current Liabilities	$	(513	)	$	437		$	(76	)	$	—		$	—	$	(76	)
Noncurrent Liabilities	(132		)	116			(16		)	(11		)	—		(27		)
Total Mark-to-Market Derivative (Liabilities)	$	(645	)	$	553		$	(92	)	$	(11	)	$	—	$	(103	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	263		$	(55	)	$	208		$	2		$	6	$	216

(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, 2016 and December 31, 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

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(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, 2016 and December 31, 2015, net cash collateral (received) paid of $8 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against current assets, and $10 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

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, 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 and 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, and contracts designated as NPNS) was $26 million and $78 million as of June 30, 2016 and December 31, 2015, respectively. As of June 30, 2016 and December 31, 2015, Power had the contractual right of offset of $18 million and $12 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 $8 million and $66 million as of June 30, 2016 and December 31, 2015, 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 ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Three Months Ended						Three Months Ended					Three Months Ended
	June 30,						June 30,					June 30,
	2016			2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Interest Rate Swaps	(1		)	—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	(1	)	$	—		$	—	$	—		$	—	$	—
Power
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total Power	$	—		$	—		$	—	$	—		$	—	$	—

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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 six months ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Six Months Ended					Six Months Ended					Six Months Ended
	June 30,					June 30,					June 30,
	2016		2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Interest Rate Swaps	2		—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	2	$	1		$	—	$	17		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	17		$	—	$	—

The following reconciles the Accumulated Other Comprehensive Income 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, 2014	$	17			$	10
Gain Recognized in AOCI	3				2
Less: Gain Reclassified into Income	(20		)		(12		)
Balance as of December 31, 2015	$	—			$	—
Gain Recognized in AOCI	3			—	2
Less: Gain Reclassified into Income	—				—
Balance as of March 31, 2016	$	3			$	2
Loss Recognized in AOCI	(1		)		(1		)
Less: Gain Reclassified into Income	—				—
Balance as of June 30, 2016	$	2			$	1

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The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS, such as its BGS contracts and certain other energy supply contracts, for the three months and six months ended June 30, 2016 and 2015. Power's derivative contracts reflected in these tables include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel.

Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2016			2015			2016		2015
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	(86	)	$	124		$	130	$	48
Energy-Related Contracts	Energy Costs	6			(10		)	8		—
Total PSEG and Power		$	(80	)	$	114		$	138	$	48

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2016 and December 31, 2015.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2016
Natural Gas	Dekatherm (Dth)	347	—	327	20
Electricity	MWh	326	—	326	—
Financial Transmission Rights (FTRs)	MWh	21	—	21	—
Interest Rate Swaps	U.S. Dollars	1,050	1,050	—	—
As of December 31, 2015
Natural Gas	Dth	201	—	168	33
Electricity	MWh	299	—	299	—
FTRs	MWh	23	—	23	—
Interest Rate Swaps	U.S. Dollars	550	550	—	—

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe 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, 2016, 90% of the 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 and non-derivatives and normal purchases/normal sales).

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The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2016. It further delineates that exposure by the credit rating of the counterparties and 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		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade—External Rating	$	334	$	129	$	205	2	$	125	(A)
Non-Investment Grade—External Rating	20		—		20		—	—
Investment Grade—No External Rating	8		1		7		—	—
Non-Investment Grade—No External Rating	3		—		3		—	—
Total	$	365	$	130	$	235	2	$	125

(A) Represents net exposure of $94 million with PSE&G. The remaining net exposure of $31 million is with a non-affiliated power purchaser which is an investment grade counterparty.

As of June 30, 2016, collateral held from counterparties where Power had credit exposure included $3 million in cash collateral and $127 million in letters of credit.

As of June 30, 2016, Power had 140 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, 2016, 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 suppliers’ credit exposure is calculated each business day. As of June 30, 2016, 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.

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Note 11. 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.

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, 2016, these consisted primarily of long-term gas supply contracts and certain electric load contracts.

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, 2016 and December 31, 2015, 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.

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	Recurring Fair Value Measurements as of June 30, 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)	$	570		$	—		$	570	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
Interest Rate Swaps (C)	$	2		$	—		$	—	$	2		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	21		$	—		$	21	$	—		$	—
Debt Securities—Govt Obligations	$	106		$	—		$	—	$	106		$	—
Debt Securities—Other	$	90		$	—		$	—	$	90		$	—
Other Securities	$	5		$	—		$	5	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(33	)	$	506		$	—	$	(537	)	$	(2	)
Interest Rate Swaps (C)	$	(1	)	$	—		$	—	$	(1	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	125		$	—		$	125	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	4		$	—		$	4	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(2	)	$	—		$	—	$	—		$	(2	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	22		$	—		$	—	$	22		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(31	)	$	506		$	—	$	(537	)	$	—

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	Recurring Fair Value Measurements as of December 31, 2015
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)	$	326		$	—		$	326	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	313		$	(608	)	$	—	$	896		$	25
Interest Rate Swaps (C)	$	6		$	—		$	—	$	6		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22	$	—		$	—
Debt Securities—Govt Obligations	$	108		$	—		$	—	$	108		$	—
Debt Securities—Other	$	81		$	—		$	—	$	81		$	—
Other Securities	$	2		$	—		$	2	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(103	)	$	553		$	—	$	(644	)	$	(12	)
PSE&G
Assets:
Cash Equivalents (A)	$	160		$	—		$	160	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	13		$	—		$	—	$	—		$	13
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	—		$	—	$	—		$	(11	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	300		$	(608	)	$	—	$	896		$	12
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	20		$	—		$	—	$	20		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(92	)	$	553		$	—	$	(644	)	$	(1	)

(A) Represents money market mutual funds.

(B) 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 the average of the bid/ask

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midpoints from multiple broker or dealer quotes 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—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.

(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 NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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, 2016, net cash collateral (received) paid of $8 million was netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against assets, and $10 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets, and $14 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 Audit Committee 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.

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For PSE&G, natural gas supply contracts are 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, 2016 and December 31, 2015.

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	—	$	(2	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(2	)
Power
Electricity	Electric Load Contracts	$	7	$	—		Discounted Cash flow	Historic Load Variability	0% to +10%
Total Power		$	7	$	—
Total PSEG		$	7	$	(2	)

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2015					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	13	$	(11	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	13	$	(11	)
Power
Electricity	Electric Load Contracts	$	11	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Electricity	Other	1		—
Total Power		$	12	$	(1	)
Total PSEG		$	25	$	(12	)

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 gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value.

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A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and six months ended June 30, 2016 and June 30, 2015, respectively, follows:

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

for the Three Months andSix 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 (A)		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 (A)		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)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

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Table of Contents (UNAUDITED)

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

for the Three Months and Six Months EndedJune 30, 2015

	Three Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	9	$	5	$	(2	)	$	—	$	(4	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	7	$	—	$	(2	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	2	$	5	$	—		$	—	$	(4	)	$	—	$	3
	Six Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	8	$	(21	)	$	—	$	(16	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(21	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	11	$	8	$	—		$	—	$	(16	)	$	—	$	3

(A) 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.

(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.

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(C) Represents $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively. Represents $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015, respectively.

(D) There were no transfers among levels during the three months and six months ended June 30, 2016 and 2015.

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $5 million and $8 million in Operating Income for the three months and six months ended June 30, 2015, respectively. The $5 million in Operating Income is realized. Of the $8 million in Operating Income, $(9) million is unrealized.

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.

As of June 30, 2015, PSEG carried $2.7 billion of net assets that are measured at fair value on a recurring basis, of which $8 million of net liabilities 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, 2016 and December 31, 2015.

	As of				As of
	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	501	$	502	$	503	$	506
PSE&G (B)	7,494		8,624		6,821		7,235
Power - Recourse Debt (B)	2,933		3,274		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	7		7		7		7
Total Long-Term Debt	$	10,935	$	12,407	$	9,568	$	10,256

(A) Fair value includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(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.

(C) Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

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Note 12. Other Income and Deductions

Other Income	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—	$	23
Allowance for Funds Used During Construction	10		—		—		10
Solar Loan Interest	5		—		—		5
Other	4		2		—		6
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
Solar Loan Interest	11		—		—		11
Other	7		3		2		12
Total Other Income	$	39	$	51	$	2	$	92
Three Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	12		—		—		12
Solar Loan Interest	6		—		—		6
Gain on Insurance Recovery	—		28		—		28
Other	1		2		2		5
Total Other Income	$	19	$	55	$	2	$	76
Six Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	54	$	—	$	54
Allowance for Funds Used During Construction	22		—		—		22
Solar Loan Interest	12		—		—		12
Gain on Insurance Recovery	—		28		—		28
Other	3		2		3		8
Total Other Income	$	37	$	84	$	3	$	124

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
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
Three Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		2		4
Total Other Deductions	$	1	$	7	$	2	$	10
Six Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	17	$	—	$	17
Other	2		1		2		5
Total Other Deductions	$	2	$	18	$	2	$	22

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

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Table of Contents (UNAUDITED)

Note 13. Income Taxes

PSEG’s, PSE&G’s and Power's effective tax rates for the three months and six months ended June 30, 2016 and 2015 were as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
PSEG	32.7%	35.0%	36.2%	38.5%
PSE&G	35.4%	38.4%	36.1%	39.0%
Power	50.0%	30.3%	39.5%	37.9%

For the three months and six months ended June 30, 2016, the overall decreases 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, offset by the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

For the three months and six months ended June 30, 2016, the overall decreases 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 and plant and other flow through items.

For the three months ended June 30, 2016, the increase 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%, was due primarily to the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

The Tax Increase Prevention Act of 2014 extended the 50% bonus depreciation rules for qualified property placed in service before January 1, 2015 and for long production property placed in service in 2015.

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. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. 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.

These provisions have 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.

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Table of Contents (UNAUDITED)

Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax

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)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	1		$	(403	)	$	132		$	(270	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			(1		)	7
Net Current Period Other Comprehensive Income (Loss)	—			8			(15		)	(7		)
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)
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	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	10		$	(411	)	$	118		$	(283	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	16			(3		)	3
Net Current Period Other Comprehensive Income (Loss)	(9		)	16			(1		)	6
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)

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Table of Contents (UNAUDITED)

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)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	2		$	(344	)	$	126		$	(216	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			7			—			7
Net Current Period Other Comprehensive Income (Loss)	—			7			(14		)	(7		)
Balance as of June 30, 2015	$	2		$	(337	)	$	112		$	(223	)
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	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	11		$	(351	)	$	112		$	(228	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	14			(2		)	2
Net Current Period Other Comprehensive Income (Loss)	(9		)	14			—			5
Balance as of June 30, 2015	$	2		$	(337	)	$	112		$	(223	)

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Table of Contents (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, 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		)
Other-Than-Temporary Impairments (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	)

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, 2015									June 30, 2015
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
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	16			(8		)	8			35			(18		)	17
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		2			(1		)	1			7			(4		)	3
Total		$	(12	)	$	5		$	(7	)	$	(4	)	$	1		$	(3	)

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Table of Contents (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, 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		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, 2015									June 30, 2015
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
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	(15		)	6			(9		)	(30		)	12			(18		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	14			(7		)	7			33			(17		)	16
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		—			—			—			5			(3		)	2
Total		$	(12	)	$	5		$	(7	)	$	(2	)	$	—		$	(2	)

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Table of Contents (UNAUDITED)

Note 15. Earnings Per Share (EPS) and Dividends

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,
	2016				2015				2016				2015
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	187	$	187	$	345	$	345	$	658	$	658	$	931	$	931
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		506		506		505		505		506		506
Effect of Stock Based Compensation Awards	—		3		—		2		—		3		—		2
Total Shares	505		508		506		508		505		508		506		508
EPS
Net Income	$	0.37	$	0.37	$	0.68	$	0.68	$	1.30	$	1.30	$	1.84	$	1.83

There were approximately 0.3 million and 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months and six months ended June 30, 2016 and 2015, respectively.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2016		2015		2016		2015
Per Share	$	0.41	$	0.39	$	0.82	$	0.78
In Millions	$	208	$	197	$	415	$	394

On July 19, 2016, PSEG's Board of Directors approved a $0.41 per share common stock dividend for the third quarter of 2016.

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Note 16. Financial Information by Business Segment

	PSE&G		Power			Other (A)		Eliminations (B)			Consolidated
	Millions
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
Three Months Ended June 30, 2015
Total Operating Revenues	$	1,466	$	1,025		$	108	$	(285	)	$	2,314
Net Income (Loss)	167		166			12		—			345
Gross Additions to Long-Lived Assets	631		348			17		—			996
Six Months Ended June 30, 2015
Operating Revenues	$	3,468	$	2,750		$	206	$	(975	)	$	5,449
Net Income (Loss)	409		501			21		—			931
Gross Additions to Long-Lived Assets	1,230		487			26		—			1,743
As of June 30, 2016
Total Assets	$	24,737	$	13,278		$	2,873	$	(1,843	)	$	39,045
Investments in Equity Method Subsidiaries	$	—	$	112		$	—	$	—		$	112
As of December 31, 2015
Total Assets	$	23,677	$	12,250		$	2,810	$	(1,202	)	$	37,535
Investments in Equity Method Subsidiaries	$	—	$	119		$	—	$	—		$	119

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

(B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. 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 17. Related-Party Transactions.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Note 17. 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	2016		2015		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Administrative Billings from Services (B)	82		65		151		131
Total Billings from Affiliates	$	379	$	362	$	993	$	1,124

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSEG (C)	$	—	$	222
Payable to Power (A)	$	94	$	212
Payable to Services (B)	79		80
Payable to PSEG (C)	6		—
Accounts Payable—Affiliated Companies	$	179	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	99	$	109

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	2016		2015		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Billings from Affiliates:
Administrative Billings from Services (B)	$	45	$	46	$	90	$	91

59

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSE&G (A)	$	94	$	212
Receivables from PSEG (C)	—		64
Accounts Receivable—Affiliated Companies	$	94	$	276
Payable to Services (B)	$	28	$	33
Payable to PSEG (C)	74		—
Accounts Payable—Affiliated Companies	$	102	$	33
Short-Term Loan Due (to) from Affiliate (E)	$	1,335	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	22	$	35

(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 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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Note 18. Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities 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, 2016 and December 31, 2015 and for the three months and six months ended June 30, 2016 and 2015.

	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

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Table of Contents (UNAUDITED)

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2015
Operating Revenues	$	—		$	1,012		$	39		$	(26	)	$	1,025
Operating Expenses	(1		)	787			37			(26		)	797
Operating Income (Loss)	1			225			2			—			228
Equity Earnings (Losses) of Subsidiaries	186			(1		)	5			(185		)	5
Other Income	12			55			—			(12		)	55
Other Deductions	(1		)	(6		)	—			—			(7		)
Other-Than-Temporary    Impairments	—			(10		)	—			—			(10		)
Interest Expense	(33		)	(7		)	(5		)	12			(33		)
Income Tax Benefit (Expense)	1			(73		)	—			—			(72		)
Net Income (Loss)	$	166		$	183		$	2		$	(185	)	$	166
Comprehensive Income (Loss)	$	159		$	169		$	2		$	(171	)	$	159
Six Months Ended June 30, 2015
Operating Revenues	$	—		$	2,727		$	107		$	(84	)	$	2,750
Operating Expenses	4			1,918			100			(84		)	1,938
Operating Income (Loss)	(4		)	809			7			—			812
Equity Earnings (Losses) of Subsidiaries	535			(2		)	8			(533		)	8
Other Income	23			85			—			(24		)	84
Other Deductions	(1		)	(17		)	—			—			(18		)
Other-Than-Temporary Impairments	—			(15		)	—			—			(15		)
Interest Expense	(62		)	(16		)	(10		)	24			(64		)
Income Tax Benefit (Expense)	10			(315		)	(1		)	—			(306		)
Net Income (Loss)	$	501		$	529		$	4		$	(533	)	$	501
Comprehensive Income (Loss)	$	506		$	520		$	4		$	(524	)	$	506
Six Months Ended June 30, 2015
Net Cash Provided By (Used In)    Operating Activities	$	410		$	1,508		$	61		$	(687	)	$	1,292
Net Cash Provided By (Used In)    Investing Activities	$	(480	)	$	(963	)	$	(210	)	$	766		$	(887	)
Net Cash Provided By (Used In)    Financing Activities	$	70		$	(543	)	$	150		$	(79	)	$	(402	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2016
Current Assets	$	5,490	$	1,655	$	231	$	(4,828	)	$	2,548
Property, Plant and Equipment, net	58		6,476		1,944		—			8,478
Investment in Subsidiaries	4,419		345		—		(4,764		)	—
Noncurrent Assets	134		2,041		128		(51		)	2,252
Total Assets	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
Current Liabilities	$	1,079	$	3,719	$	1,293	$	(4,828	)	$	1,263
Noncurrent Liabilities	420		2,652		392		(51		)	3,413
Long-Term Debt	2,380		—		—		—			2,380
Member's Equity	6,222		4,146		618		(4,764		)	6,222
Total Liabilities and Member's Equity	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
As of December 31, 2015
Current Assets	$	4,501	$	1,912	$	364	$	(4,828	)	$	1,949
Property, Plant and Equipment, net	83		6,502		1,542		—			8,127
Investment in Subsidiaries	4,501		346		—		(4,847		)	—
Noncurrent Assets	155		1,959		136		(76		)	2,174
Total Assets	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250
Current Liabilities	$	1,112	$	3,866	$	1,076	$	(4,828	)	$	1,226
Noncurrent Liabilities	442		2,597		375		(76		)	3,338
Long-Term Debt	1,684		—		—		—			1,684
Member's Equity	6,002		4,256		591		(4,847		)	6,002
Total Liabilities and Member's Equity	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250

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

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

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

• PSE&G, our public utility company which is 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, our multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA), and the states in which they operate.

PSEG's other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority's (LIPA) transmission and distribution (T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and these operating subsidiaries with certain management, administrative and general services at cost.

Our business discussion in Part I, Item 1. Business of our 2015 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 2015 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2016 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 2015 Form 10-K.

EXECUTIVE OVERVIEW OF 2016 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 growth in investment in T&D and other infrastructure projects designed to enhance resiliency, and

• 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, 2016 and 2015 are presented as follows:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Earnings	2016			2015		2016		2015
	Millions
PSE&G	$	179		$	167	$	441	$	409
Power (A)	(11		)	166		181		501
Other (B)	19			12		36		21
PSEG Net Income	$	187		$	345	$	658	$	931
PSEG Net Income Per Share (Diluted)	$	0.37		$	0.68	$	1.30	$	1.83

(A) Includes an after-tax insurance recovery for Superstorm Sandy of $27 million and $102 million in the three months and six months ended June 30, 2015, respectively.

(B) Other includes activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations.

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,
	2016			2015		2016			2015
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	(1	)	$	1	$	(6	)	$	3
Non-Trading MTM Gains (Losses) (C)	$	(101	)	$	28	$	(88	)	8

(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 Expense.

(B) Net of tax (expense) benefit of $(1) million, $(2) million, $2 million and $(7) million for the three and six months ended June 30, 2016 and 2015, respectively.

(C) Net of tax (expense) benefit of $70 million, $(20) million, $61 million and $(6) million for the three and six months ended June 30, 2016 and 2015, respectively.

Our $158 million decrease in Net Income for the three months ended June 30, 2016 was driven primarily by

• MTM losses in 2016 as compared to MTM gains in 2015,

• lower volumes of energy sold at lower average realized prices primarily in the PJM Interconnection, L.L.C. (PJM) region,

• higher congestion costs in PJM resulting from credits received in 2015 due to the colder than normal weather, and

• insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy.

These decreases were partially offset by

• higher revenues due to increased investments in transmission projects,

• lower generation costs driven by lower natural gas prices and reduced generation output, and

65

• lower O&M expense at Power due to higher costs incurred in 2015 for planned major outages.

Our $273 million decrease in Net Income for the six months ended June 30, 2016 was driven primarily by

• MTM losses in 2016 as compared to MTM gains in 2015,

• lower volumes of energy sold at lower average realized sales primarily in the PJM region and lower volumes of energy sold under wholesale load contracts,

• lower operating reserve revenues and capacity revenues in PJM,

• lower volumes of gas sold at lower average prices under the Basic Gas Supply Service (BGSS) contract, and

• insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy.

These decreases were partially offset by

•lower generation costs driven by lower fuel costs and reduced generation output at Power,

•a decrease in O&M expense at Power due to higher costs incurred for planned outages in 2015, and

• higher revenues due to increased investments in transmission projects.

During the first half of 2016, 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 and allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our multi-year, 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, our merchant generator, 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, in 2016 we continued to make investments and seek recovery on such investments made 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. We also commenced modernizing 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.

Despite the unseasonable weather patterns during the first six months of 2016, Power’s results benefited from access to natural gas supplies through its 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 days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third party sales and 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 strategic hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business.

Our recent investments in the latter half of 2015 and early 2016 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 contribute to the overall efficiency of operations.

Since 2013, eight nuclear generating stations in the United States totaling over 8,300 MW of capacity have closed or announced early retirement due to economic reasons. Four additional stations totaling nearly 5,300 MW of capacity have been announced as being at risk for early retirement. This situation is generally due to low natural gas prices resulting from the growth of shale gas production since 2007, the continuing cost of regulatory compliance for nuclear facilities and both federal and state-level policies that provide credits to renewable energy such as wind and solar, but do not apply to nuclear generating stations. These trends have significantly reduced the revenues to nuclear generating stations while simultaneously raising 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 greater reliance on natural gas pipelines for delivery and less diversity of the generation fleet. Additionally, we believe that the early retirement of nuclear plants will lead to an increase in replacement energy and environmental costs.

While our nuclear generating units are not currently at risk of early retirement, we continue to advocate for sound policies that recognize nuclear power as a source of clean energy and an important part of a diverse and reliable energy portfolio.

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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 2013, PJM initiated its first "open window" solicitation process to allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues in New Jersey. In April 2016, PSE&G accepted construction responsibility for the three components of the Artificial Island project that PJM assigned to it, based on having reached agreement with PJM regarding an estimate for the project base cost of $273 million, plus risk and contingency for a total project cost of up to $340 million. PSE&G continues to work with PJM to optimize the scope and cost of the project.

In April 2016, PJM filed at FERC to incorporate a voltage threshold into PJM’s Regional Transmission Expansion Plan (RTEP) process to exempt, except under certain circumstances, reliability violations on facilities below 200 kV from PJM’s proposal window process. We generally support this reform as a measure to improve the efficiency of the open window procedure that will permit transmission developers to focus on the projects most likely to benefit from a competitive process. 

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 and may cause increased scrutiny regarding PSE&G's future capital investments. 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 an adjustment, 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. While we are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, 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

In an important development in the proceedings concerning the actions that had been taken by the states of New Jersey and Maryland to subsidize new generation that is above market cost, in April 2016, the United States Supreme Court affirmed the decision of the lower courts that had held the action in Maryland to be unconstitutional. The Supreme Court’s ruling upholds FERC’s authority to foster competitive wholesale electricity markets and provides guidance to states in balancing their interests to encourage and support the development of renewables and other generating facilities. 

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. In June 2015, FERC conditionally accepted a proposal from PJM for a capacity performance (CP) product to include generators, Demand Response and energy efficiency providers, which will be required to perform during emergency conditions, as a supplement to the base capacity product. The proposal included enhanced performance-based incentives and penalties. We believe that the auction pricing adequately reflects the increased costs that could result from operating under more stringent rules for generation availability. Based on the auction results, the CP mechanism appears to have provided the opportunity for enhanced capacity market revenue streams for Power, but future impacts cannot be assured. Further, there may be requirements for additional investment and there are additional performance and financial risks. Appeals of FERC's CP orders are pending.

In May 2016, PJM announced the results of the RPM capacity auction for the 2019-2020 delivery year. Power cleared 8,895 MW of its generating capacity at an average price of $116 per MW-day for the 2019-2020 delivery period. Of the cleared capacity, Power believes that nearly all is compliant with PJM's CP requirements. In the two prior capacity auctions covering the 2017-2018 and 2018-2019 delivery years, Power cleared approximately 8,700 MW at average prices of $177 per MW-day and $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.

An emerging issue in PJM involves the impact of subsidized existing generation on RPM market outcomes. These subsidies would likely enable the affected generators to submit bids into PJM capacity markets that are not reflective of their actual costs of operation and may prevent uneconomic generating facilities from retiring. Either of these conditions could artificially

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suppress capacity market prices, especially given that PJM’s currently effective “minimum offer price rule” (MOPR) which applies only to new gas-fired units, would not apply to these plants. Given the uncertainty surrounding these possible subsidies, we cannot predict the effects this might have on capacity prices and the corresponding impact on our business. See Item 5. Other Information—Federal Regulation—Capacity Market Issues—PJM for additional information.

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. See Item 1. Note 8. Commitments and Contingent Liabilities for further information.

In October 2015, the EPA published the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act (CAA) for existing power plants. The regulation establishes state-specific emission targets based on implementation of the best systems of emission reduction. We continue to work with FERC and other federal and state regulators, as well as industry partners, to determine the potential impact of these regulations.

The U.S. Supreme Court’s February 2016 decision to stay the implementation of the CPP will delay deadlines for submission of state requests for extensions and final plans. If the CPP is upheld, new deadlines will need to be established and the effective date of the compliance period may be impacted.

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 8. 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. This investigation is ongoing. The amounts of potential disgorgement and other potential penalties that we may incur span a wide range depending on the success of our legal arguments. If our legal arguments do not prevail, in whole or in part with FERC or in a judicial challenge that we may choose to pursue, it is likely that Power would record losses that would be material to PSEG's and Power's results of operations in the quarterly and annual periods in which they are recorded. For additional information, see Item 1. Note 8. Commitments and Contingent Liabilities.

Salem Operations

In April 2016, during a scheduled refueling outage at Salem Unit 1, a visual inspection revealed degradation to a number of bolts inside the reactor vessel. The bolt replacement has been completed and the unit is in the process of returning to service. We expect to continue to inspect and replace degraded bolts at both Salem units over the next several refueling outage cycles and a strategic solution to maintain the long-term health of both reactor vessel internals is under review. Production and margin effects for the second quarter of 2016 were largely offset by the increased production at Peach Bottom as a result of the Extended Power Uprates made in 2015 being fully operational. Extension of the Salem Unit 1 outage into July and an unplanned outage at Salem Unit 2 will have a continuing effect on third quarter performance.

Operational Excellence

We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of market opportunities presented during the year as we remain diligent in managing costs. For the first six months of 2016, our

• total nuclear fleet achieved an average capacity factor of 91.2%, and

• diverse fuel mix and dispatch flexibility allowed us to generate approximately 26 terra-watt hours while addressing unit outages and balancing fuel availability and price volatility.

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Financial Strength

Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first six months of 2016 as we

• had cash on hand of $648 million as of June 30, 2016,

• maintained solid investment grade credit ratings, and

• increased our indicative annual dividend for 2016 to $1.64 per share.

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, without the issuance of new equity.

Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first half of 2016, we

• made additional investments in transmission infrastructure projects,

• began executing our GSMP and continued executing Energy Strong and other existing BPU-approved utility programs,

• commenced construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and announced our plan to construct BH5 and commence operations in mid-2019, and

• acquired three solar energy projects totaling 100 MW-direct current in North Carolina and Colorado expected to go into service during 2016.

Future Outlook    

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a slow-growing economy and 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,

• 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 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 2016 and beyond, the key issues and challenges we expect our business to confront include:

• regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other 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 base rate case which must be filed with the BPU no later than November 1, 2017,

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

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• 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,

• delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory approvals, and

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

Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators 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, such as retail energy marketing,

• 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 and modernizing existing infrastructure.

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 17. Related-Party Transactions.

	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,									June 30,
	2016		2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,905	$	2,314	$	(409	)	(18	)	$	4,521	$	5,449	$	(928	)	(17	)
Energy Costs	624		668		(44		)	(7	)	1,460		1,762		(302		)	(17	)
Operation and Maintenance	710		761		(51		)	(7	)	1,439		1,424		15			1
Depreciation and Amortization	224		317		(93		)	(29	)	448		647		(199		)	(31	)
Income from Equity Method Investments	4		4		—			—		6		7		(1		)	(14	)
Other Income (Deductions)	34		66		(32		)	(48	)	61		102		(41		)	(40	)
Other-Than-Temporary Impairments	10		10		—			—		20		15		5			33
Interest Expense	97		97		—			—		189		195		(6		)	(3	)
Income Tax Expense	91		186		(95		)	(51	)	374		584		(210		)	(36	)

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,
	2016		2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,350	$	1,466	$	(116	)	(8	)	$	3,062	$	3,468	$	(406	)	(12	)
Energy Costs	529		544		(15		)	(3	)	1,258		1,436		(178		)	(12	)
Operation and Maintenance	352		368		(16		)	(4	)	734		780		(46		)	(6	)
Depreciation and Amortization	136		234		(98		)	(42	)	275		481		(206		)	(43	)
Other Income (Deductions)	18		18		—			—		37		35		2			6
Interest Expense	74		67		7			10		142		136		6			4
Income Tax Expense	98		104		(6		)	(6	)	249		261		(12		)	(5	)

Three Months EndedJune 30, 2016 as Compared to 2015

Operating Revenuesdecreased$116 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenuesincreased$28 million due primarily to an increase in transmission revenues.

• Transmission revenues were $48 millionhigher due to increased capital investments.

• Electric distribution revenues decreased$19 million due primarily to lower Green Program Recovery Charges (GPRC) of $14 million and $5 million in lower sales volumes.

Commodity Revenuedecreased$15 million as a result of $30 million of lower Electric revenues, partially offset by $15 million in higher Gas revenues. Commodity revenue for both electric and gas is entirely offset with the change in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

• Electric revenues decreased$30 million due primarily to $15 million of lower revenues from collections of Non-Utility Generation Charges (NGC), a $7 million or 2% decrease in BGS revenues due to lower sales volumes, and a decrease of $8 million due to lower volumes of Non-Utility Generation (NUG) energy sold.

• Gas revenues increased$15 million due to higher BGSS sales volumes.

Clause Revenuesdecreased$128 million due primarily to lower Securitization Transition Charges (STC) of $122 million and lower Societal Benefit Charges (SBC) of $5 million. The STC reduction is a result of rate reductions due to the completion of securitization collections in 2015. The changes in the STC and SBC amounts are entirely offset by decreases in the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC or SBC collections.

Operating Expenses

Energy Costsdecreased$15 million. This is entirely offset by the change in Commodity Revenue.

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

• a $28 million net reduction in costs related to various clause mechanisms and GPRC,

• partially offset by a $7 million increase in distribution maintenance, due to increases of $4 million for vegetation management and $3 million for corrective maintenance.

Depreciation and Amortizationdecreased$98 million due to a decrease of $116 million in amortization of Regulatory Assets primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by a $17 millionincrease in depreciation due to additional plant in service.

Interest Expenseincreased$7 million due primarily to an increase of $8 million due to net debt issuances in 2015 and 2016.

Income Tax Expensedecreased$6 million due primarily to plant and other flow through items and uncertain tax positions, partially offset by higher pre-tax income.

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Six Months EndedJune 30, 2016 as Compared to 2015

Operating Revenuesdecreased$406 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenuesincreased$57 million due primarily to an increase in transmission revenues.

• Transmission revenues were $102 millionhigher due to increased capital investments.

• Electric distribution revenues decreased$42 million due primarily to lower GPRC of $26 million and $16 million in lower sales volumes.

• Gas distribution revenues decreased$3 million due primarily to $68 million of lower delivery volumes and lower GPRC of $7 million due to lower sales volumes from warmer winter weather. These decreases were almost entirely offset by $62 million in higher Weather Normalization Clause revenue and $10 million due to the roll in of Energy Strong into base rates effective September 1, 2015.

Commodity Revenuedecreased$178 million as a result of lower Gas and Electric revenues. Commodity revenue for both gas and electric is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGSS and BGS to retail customers.

• Gas revenues decreased$94 million due primarily to lower BGSS sales volumes.

• Electric revenues decreased$84 million due primarily to a $42 million or 5% decrease in BGS revenues due to lower sales volumes, $26 million of lower revenues from collections of NGC and a decrease of $16 million due to lower volumes of NUG energy sold at lower prices.

Clause Revenuesdecreased$282 million due primarily to lower STC of $251 million and lower SBC of $38 million, partially offset by higher Margin Adjustment Clause (MAC) revenue of $14 million. The STC reduction is a result of rate reductions due to the completion of securitization collections in 2015. The changes in the STC, SBC and MAC amounts are entirely offset by decreases in the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SBC or MAC collections.

Operating Expenses

Energy Costsdecreased$178 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenancedecreased$46 million, of which the most significant components were

• a $72 million net reduction in costs related to various clause mechanisms and GPRC,

• partially offset by an $11 millionincrease in distribution maintenance, due to increases of $6 million for corrective maintenance and $5 million for vegetation management and

• $10 million of storm insurance recovery proceeds received in 2015.

Depreciation and Amortizationdecreased$206 million due to a decrease of $239 million in amortization of Regulatory Assets primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by a $32 millionincrease in depreciation due to additional plant in service.

Interest Expenseincreased$6 million due primarily to an increase of $13 million due net debt issuances in 2015 and 2016, partially offset by an $8 million decrease due to the redemption of securitization debt in 2015.

Income Tax Expensedecreased$12 million due primarily to plant and other flow through items and uncertain tax positions offset by higher pre-tax income.

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Power

	Three Months Ended					Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,										June 30,
	2016			2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions					Millions			%		Millions				Millions			%
Operating Revenues	$	714		$	1,025	$	(311	)	(30	)	$	2,027	$	2,750	$	(723	)	(26	)
Energy Costs	381			409		(28		)	(7	)	1,019		1,302		(283		)	(22	)
Operation and Maintenance	265			313		(48		)	(15	)	518		485		33			7
Depreciation and Amortization	80			75		5			7		159		151		8			5
Income from Equity Method Investments	4			5		(1		)	(20	)	6		8		(2		)	(25	)
Other Income (Deductions)	16			48		(32		)	(67	)	24		66		(42		)	(64	)
Other-Than-Temporary Impairments	10			10		—			—		20		15		5			33
Interest Expense	20			33		(13		)	(39	)	42		64		(22		)	(34	)
Income Tax Expense	(11		)	72		(83		)	N/A		118		306		(188		)	(61	)

Three Months EndedJune 30, 2016 as Compared to 2015

Operating Revenuesdecreased$311 million due to changes in generation, gas supply and other revenues.

Generation Revenuesdecreased$300 million due primarily to

• a decrease of $212 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $187 million was due to changes in forward power prices, which increased in the current period and decreased during the comparable period in 2015. Also contributing to the decrease was $25 million from higher gains on positions reclassified to realized upon settlement this year compared to last year, 

• a decrease of $66 million in energy sales primarily in the PJM region due to lower volumes and lower average realized prices,

• a decrease of $14 million in capacity revenue primarily in the PJM region due to the retirement of older peaking units in June 2015, and

• a net decrease of $8 million in electricity sold under our BGS contracts due primarily to lower volumes.

Gas Supply Revenuesdecreased$11 million due primarily to

• a net decrease of $15 million in sales under the BGSS contract primarily due to lower average sales prices and MTM losses, and

• a net increase of $4 million on sales to third party customers, of which $8 million was due to higher volumes sold partially offset by $4 million of lower average sales prices.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased$28 million due to

• Generation costsdecreased$37 million due primarily to lower natural gas and coal fuel costs of $30 million reflecting lower average realized prices and the utilization of lower volumes.

• Gas costsincreased$9 million mainly related to higher volumes sold to third parties.

Operation and Maintenancedecreased$48 million due primarily to

• a net decrease of $35 millionrelated to our fossil plants, primarily due to higher costs incurred in 2015 for the installation of upgraded technology at our combined cycle Bergen generating plant, and

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• a net decrease of $33 million related to our nuclear facilities, largely due to a planned outage at our 100%-owned Hope Creek plant in 2015, partly offset in 2016 by an extended refueling outage at our 57%-owned Salem Unit 1 plant,

• partially offset by $17 million of insurance recoveries received in 2015 related to Superstorm Sandy,

Depreciation and Amortization increased$5 million due primarily to a higher depreciable nuclear asset base.

Other Income (Deductions) decreased$32 million due primarily to $28 million of insurance recoveries received in 2015 related to Superstorm Sandy and higher net realized gains from the NDT Fund in 2015.

Interest Expensedecreased$13 million due primarily to the maturity of $300 million of 5.50% Senior Notes in December 2015 and higher capitalized interest in 2016.

Income Tax Expensedecreased$83 million in 2016 due primarily to lower pre-tax income, partially offset by a benefit related to a Nuclear Decommissioning Tax Carryback transaction that was recorded in 2015.

Six Months EndedJune 30, 2016 as Compared to 2015

Operating Revenuesdecreased$723 million due to changes in generation and gas supply revenues.

Generation Revenuesdecreased$474 million due primarily to

• a decrease of $173 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $103 million was due to higher gains on positions reclassified to realized upon settlement this year compared to last year. Also contributing to the decrease was $70 million from a decrease in forward power prices in 2015,

• a decrease of $140 million in energy sales volumes in the PJM and New England (NE) regions due primarily to milder weather and lower average realized prices in the PJM and New York regions,

• a net decrease of $87 million primarily in the PJM region due to lower operating reserve revenues coupled with lower capacity revenues resulting from the retirement of older peaking units in June 2015, and

• a decrease of $40 million in electricity sold under wholesale load contracts in the PJM and NE regions due primarily to lower volumes and lower average prices.

Gas Supply Revenuesdecreased$249 million due primarily to

• a net decrease of $234 million in sales under the BGSS contract, substantially comprised of lower sales volumes due to warmer average temperatures in the 2016 winter heating season, coupled with lower average sales prices, and

• a net decrease of $15 million on sales to third party customers, of which $47 million was due to lower average sales prices, partially offset by $32 million of higher volumes sold.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased$283 million due to

Generation costsdecreased$160 million due primarily to

• lower fuel costs of $267 million reflecting lower average realized prices for natural gas and the utilization of lower volumes of fuel, and

• a decrease of $18 million due to MTM gains in 2016 as compared to MTM losses in 2015. The 2016 MTM gains were primarily due to favorable forward price movements on natural gas, while the 2015 MTM losses were primarily due to higher gains on positions reclassified to realized upon settlement on transmission products, 

• partially offset by higher congestion costs in PJM of $142 million, mainly as a result of credits received in the prior year due to extremely cold weather.

Gas costsdecreased$123 million mainly related to

• a decrease of $136 million related to sales under the BGSS contract due primarily to lower volumes sold due to warmer average temperatures during the 2016 winter heating season and lower average gas costs,

• partially offset by a net increase of $13 million related to sales to third parties due primarily to an increase in volumes sold.

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Operation and Maintenanceincreased$33 million due primarily to

• $145 million of insurance recoveries received in 2015 related to Superstorm Sandy,

• partially offset by a net decrease of $85 million related to our fossil plants, largely due to higher costs incurred in 2015 for our planned major outages at the Bethlehem Energy Center and Bergen generating plants, and

• a net decrease of $38 million related to our nuclear plants due primarily to the aforementioned reasons provided for the second quarter variance.

Depreciation and Amortization increased$8 milliondue primarily to a higher depreciable nuclear asset base.

Other Income (Deductions) decreased$42 million due primarily to $28 million of insurance recoveries received in 2015 related to Superstorm Sandy and higher net realized gains from the NDT Fund in 2015.

Other-Than-Temporary Impairmentsincreased$5 million due to an increase in impairments of equity securities in the NDT Fund in 2016.

Interest Expensedecreased$22 million due primarily to the maturity of $300 million of 5.50% Senior Notes in December 2015 and higher capitalized interest in 2016.

Income Tax Expensedecreased$188 million in 2016 due primarily to lower pre-tax income.

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

For the six months ended June 30, 2016, our operating cash flow decreased$512 million as compared to the same period in 2015. The net change was due primarily to the net changes from PSE&G and Power as discussed below.

PSE&G

PSE&G’s operating cash flow decreased$101 million from $909 million to $808 million for the six months ended June 30, 2016, as compared to the same period in 2015, due primarily to a decrease of $87 million due to a change in regulatory deferrals primarily driven by lower volumes due to warmer weather impacting our Gas Weather Normalization, SBC, GPRC and BGSS clauses and a $77 milliondecrease due to higher vendor payments. These amounts were partially offset by higher earnings and higher tax refunds in 2016.

Power

Power’s operating cash flow decreased$375 million from $1,292 million to $917 million for the six months ended June 30, 2016, as compared to the same period in 2015, primarily due to lower earnings, a $123 milliondecrease from fuels, materials and supplies, and a $115 millionincrease in margin deposit requirements, partially offset by a reduction in tax payments.

Short-Term Liquidity

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

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We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of June 30, 2016 were as follows:

Company/Facility	As of June 30, 2016
	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,000	$	10	$	990
PSE&G	600		14		586
Power	2,553		202		2,351
Total	$	4,153	$	226	$	3,927

As of June 30, 2016, 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, which would represent a three level downgrade from its current S&P and 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 $748 million and $864 million as of June 30, 2016 and December 31, 2015, respectively.

As of June 30, PSEG’s credit facilities are available to back-stop its Commercial Paper Program and issue letters of credit. As of June 30, 2016, no Commercial Paper was outstanding. PSE&G's credit facility primary use is to support its Commercial Paper Program under which as of June 30, 2016, no amounts were outstanding. Most of our credit facilities expire in 2019 and 2020.

For additional information, see Item 1.Note 9. Debt and Credit Facilities.

Long-Term Debt Financing

Power has $303 million of 5.32% Senior Notes and $250 million of 2.75% Senior Notes maturing in September 2016.

For a discussion of our long-term debt transactions during 2016, see Item 1. Note 9. Debt and Credit Facilities.

Common Stock Dividends

On April 19, 2016, our Board of Directors approved a $0.41 per share of common stock dividend for the second quarter of 2016. On July 19, 2016, our Board of Directors declared a quarterly dividend of $0.41 per share of common stock for the third quarter of 2016. This reflects an indicative annual dividend rate of $1.64 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. Note 15. Earnings Per Share (EPS) and Dividends.

Credit Ratings

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

In January 2016, S&P published updated research reports on PSEG and PSE&G and the existing ratings and outlooks were unchanged. In June 2016, Moody's published credit opinions on Power and PSE&G and the existing ratings and outlooks were unchanged. In June 2016, S&P published an updated research report on Power and the existing rating and outlook were unchanged.

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	Moody’s (A)	S&P (B)
PSEG
Outlook	Positive	Stable
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. The Corporate Credit Rating outlook does not apply to PSEG's or PSE&G's Commercial Paper Rating or PSE&G's Mortgage Bond rating.

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 Power and Services as compared to amounts disclosed in our 2015 Form 10-K.

PSEG

In July 2016, PSEG partnered with Vectren Corporation on a FERC 1000 proposal to construct, own and operate a twenty mile, 345 kilovolt transmission line in the midwest region served by the Midcontinent Independent System Operator (MISO). MISO estimated the project would cost approximately $60 million and would go in service in 2021. MISO is expected to select a proposal in December 2016. This project is not included in PSEG's projected capital expenditures.    

PSE&G

PSE&G increased its estimate of its capital expenditure program as reported in our 2015 Form 10-K by approximately $300 million from $8.3 billion to $8.6 billion primarily to address new business requests and to replace aging equipment and infrastructure.   

In May 2016, PSE&G filed a petition with the BPU requesting an extension of its existing landfill/brownfield solar program to construct 100 MW of grid-connected solar facilities with projected capital expenditures of up to $240 million through approximately 2021. This is not included in PSE&G's projected capital expenditures.

During the six months ended June 30, 2016, PSE&G made capital expenditures of $1,355 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of $74 million, which are included in operating cash flows.

Power

During the six months ended June 30, 2016, Power made capital expenditures of $505 million, excluding $93 million for nuclear fuel, primarily related to our Keys, Sewaren 7, BH5 and other generation projects.

ACCOUNTING MATTERS

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Contracts

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

Value-at-Risk (VaR) Models

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

MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. 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 2016,MTM VaR remained relatively stable between low of $10 million to high of $18 million at 95% confidence level. The range of VaR was narrower for the three months ended June 30, 2016 as compared with the year ended December 31, 2015.

	MTM VaR
	Three Months Ended June 30, 2016		Year Ended December 31, 2015
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	16	$	24
Average for the Period	$	15	$	17
High	$	18	$	40
Low	$	10	$	8
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	25	$	38
Average for the Period	$	23	$	26
High	$	27	$	63
Low	$	16	$	12

See Item 1. Note 10. Financial Risk Management Activities for a discussion of credit risk.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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 Public Service Enterprise Group Incorporated, Public Service Electric and Gas Company and PSEG Power LLC. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of Public Service Enterprise Group Incorporated, Public Service Electric and Gas Company and PSEG Power LLC 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

There have been no changes in internal control over financial reporting that occurred during the second quarter of 2016 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 2015 Annual Report on Form 10-K, see Part I, Item 1. Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.

ITEM 1A. RISK FACTORS

There are no additional Risk Factors to be added to those disclosed in Part I, Item 1A of our 2015 Annual Report on Form 10-K.

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 2016.

Three Months Ended June 30, 2016	Total Number of Shares Purchased	Average Price Paid per Share
April 1 - April 30	—	$	—
May 1 - May 31	228,639	$	46.23
June 1- June 30	50,000	$	44.50

ITEM 5. OTHER INFORMATION

Certain information reported in the 2015 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 2015 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.

Employee Relations

December 31, 2015 Form 10-K page 16 and March 31, 2016 Form 10-Q page 70. Since the beginning of 2016, six of our eight labor unions ratified extensions of their collective bargaining agreements with us, with expiration dates from 2019 to

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2021. The collective bargaining agreements for the remaining two unions expire in 2017 and 2018. We believe we maintain satisfactory relationships with our employees.

Federal Regulation

FERC

Capacity Market Issues—PJM

December 31, 2015 Form 10-K page 17 and March 31, 2016 Form 10-Q page 70. An emerging issue in PJM involves the impact of subsidized generation on RPM market outcomes. In particular, FirstEnergy Corp. (FE) and American Electric Power (AEP) have proposed to enter into power purchase agreements (PPAs) with their non-utility generation affiliates providing for above-market purchases from certain coal plants and a nuclear plant (in FE's case). The Ohio Public Utility Commission (PUCO) approved the PPAs on terms similar to the terms sought by those companies. The Dayton Power and Light Company has recently also filed for comparable arrangements covering generating plants that it owns. On April 27, 2016, FERC issued orders finding that the PPAs should be reviewed to determine whether they comport with the Commission’s standards for contracts. FE subsequently submitted a modified arrangement to PUCO arguing that it is within PUCO’s exclusive jurisdiction. This modified proposal is currently the subject of contested proceedings at both the PUCO and at FERC. In another proceeding at FERC, certain parties are claiming that PJM should be directed to expand the MOPR to apply to existing contracts, including the FE and AEP PPAs.

We are unable to predict the results of these pending proceedings or any future related proceedings or to calculate the potential impacts on our business.

Capacity Market Issues—ISO-New England

December 31, 2015 Form 10-K page 18 and March 31, 2016 Form 10-Q page 71. In March 2015, in conjunction with other companies, we filed a petition for review with the D.C. Circuit Court of Appeals (D.C. Court) of FERC's ruling accepting the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources. On December 1, 2015, following a request by FERC for a voluntary remand of the order, the D.C. Court remanded the case to FERC for additional consideration. However, on April 8, 2016, FERC issued an order upholding the exemption. We and other companies continue to contest the reasonableness of the exemption.

Reactive Power Rates

December 31, 2015 Form 10-K page 19 and March 31, 2016 Form 10-Q page 71. In June 2015, Power submitted a tariff filing with FERC to increase Power’s rates for reactive supply and voltage control service from approximately $27 million per year to about $39 million per year. Following settlement discussions with FERC Trial Staff, Power agreed to accept an overall rate of $34 million per year on the condition that we will refile in six years, which FERC approved in February 2016. FERC had earlier referred the filing to the FERC Office of Enforcement for its evaluation, which remains pending. More broadly, FERC has begun to review regulations relating to reactive power compensation. We cannot predict the impact of potential changes to reactive power compensation regulations on our business and results of operations.

Transmission Regulation

December 31, 2015 Form 10-K page 19. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. In June 2016, PSE&G filed its 2015 true-up adjustment pertaining to its transmission formula rates in effect for 2015, which resulted in an adjustment of $34 million less than the 2015 originally filed revenues. For additional information about our transmission formula rate, see Part I, Item 1. Financial Information—Note 4. Rate Filings.

Transmission Regulation—Transmission Policy Developments

December 31, 2015 Form 10-K page 19 and March 31, 2016 Form 10-Q page 71. FERC concluded in Order 1000 that the incumbent transmission owner should not always have a Right of First Refusal (ROFR) to construct and own transmission projects in its service territory. We and other companies appealed Order 1000 but this appeal was denied in 2014 by the D.C. Court. The current PJM rules retain carve-outs for projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing rights-of-way and whose construction would interfere with incumbents’ use of their rights-of-way. While these carve-outs ameliorate the impacts of the Order 1000 ruling on incumbents, we and several other companies appealed various aspects of the FERC order approving PJM’s implementation of Order 1000, including the elimination of the ROFR from the PJM Tariff. On July 1, 2016, the D.C. Court dismissed the case, thus upholding FERC’s determination. We are currently analyzing the impact of the D.C. Court’s decision on our operations and whether further action is appropriate.

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There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G contending that insufficient levels of costs are being allocated to PSE&G. Projects involved include the Artificial Island project, the Bergen-Linden project in New Jersey and a smaller project in Sewaren, New Jersey. On April 22, 2016, FERC issued orders denying the complaints and leaving the current cost allocation in effect as to the Artificial Island and Bergen-Linden projects. Due to an intervening FERC order concerning the allocation of costs for projects constructed to meet local reliability requirements, FERC directed that all of the Sewaren costs be allocated to PSE&G. It is anticipated that additional proceedings are likely to occur. It is anticipated that these various proceedings will not be resolved for several years.

Another proceeding is a matter remanded from a federal appellate court concerning the appropriate cost allocation for certain 500 kV projects in PJM that either have been built or are in the process of being built, including the Susquehanna-Roseland project. A proposed settlement was filed with FERC on June 15, 2016. The settlement, if adopted by FERC, will result in increased annual cost allocations to customers in the PSE&G Transmission Zone. Under this settlement, Power, as a BGS supplier could become obligated to pay amounts previously paid by other PJM transmission customers. However, we do not believe that the anticipated level of any such potential payments would have a material effect on Power’s financial statements.

Con Edison Wheeling Agreement

In April 2016, Con Edison informed PJM that it would allow its Wheeling Agreement to expire effective as of May 1, 2017. The Wheeling Agreement enables Con Edison to move 1,000 MW of energy from southeast New York across the PSE&G system for delivery into New York City. Discussions are currently ongoing among PJM and NYISO stakeholders regarding future operational procedures and transmission planning assumptions associated with the affected transmission lines. Depending on the outcome of these discussions, which may require FERC to approve tariff revisions, there could be impacts on capacity and energy prices in the region as well as impacts on transmission planning. In addition, Regional Transmission Expansion Plan costs that would have been allocated to Con Edison under the Wheeling Agreement will be reallocated elsewhere, which will include some reallocations to the customers within the PSE&G Transmission Zone.   

Nuclear Regulatory Commission (NRC)

December 31, 2015 Form 10-K page 21. As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in 2011, the NRC began performing additional operational and safety reviews of nuclear facilities in the United States. We believe that our nuclear plants currently meet the stringent applicable design and safety specifications of the NRC.

Among other things, the NRC advised the staff to give the highest priority to those activities that can achieve the greatest safety benefit and/or have the broadest applicability (Tier 1).

The NRC issued letters and orders to licensees implementing the Tier 1 recommendations in March 2012. In June 2013, the NRC issued an order requiring Mark I and Mark II licensees to upgrade or replace their reliable hardened vents with containment venting systems designed and installed to remain functional during severe accident conditions. We are implementing the diverse and flexible strategies and spent fuel pool level indication modifications in accordance with the regulatory requirements at the Salem, Hope Creek and Peach Bottom nuclear units. For our Hope Creek and Peach Bottom units, final installation of the required modifications is expected to be completed by 2018.

In March 2013, the NRC initiated a rulemaking process for filtering strategies with drywell filtration and severe accident management for U.S. Boiling Water Reactors with Mark I and Mark II containments. The NRC subsequently disapproved the staff plan to pursue rulemaking, based in part on the upgrades required by the June 2013 order. The NRC continues to evaluate potential revisions to its requirements in connection with its operational and safety reviews of nuclear facilities in the United States as a result of the Fukushima Daiichi incident.

We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to our Salem, Hope Creek and Peach Bottom facilities, but such cost could be material.

State Regulation

Connecticut Rate Filing

December 31, 2015 Form 10-K page 23. On June 30, 2016, 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 2017 revenues of $20 million. This matter is pending.

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Solar 4 All Program Extension II

In May 2016, PSE&G filed a petition with the BPU requesting an extension of its existing landfill/brownfield solar program to construct 100 MW of grid-connected solar facilities with projected capital expenses of up to $240 million, through approximately 2021. This matter is pending.  

Environmental Matters

Air Pollution Control

Hazardous Air Pollutants Regulation

December 31, 2015 Form 10-K page 24 and March 31, 2016 Form 10-Q page 72. In February 2012, the(EPA) published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources under the National Emission Standard for Hazardous Air Pollutants (NESHAP) provisions of the CAA. The MATS established allowable levels for mercury as well as other hazardous air pollutants and went into effect in April 2015. In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plants. On April 15, 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to the U.S. Supreme Court's ruling. Industry participants and various state authorities have filed petitions with the D.C. Court challenging the EPA’s Supplemental Finding. We do not expect this Supplemental Finding to impact operation of our facilities.

Demand Response (DR) Reciprocating Internal Combustion Engines (RICE) Litigation

December 31, 2015 Form 10-K page 24. In March 2013, Power filed a petition at the EPA challenging the National Emission Standards for Hazardous Air Pollutants (NESHAP) for RICE issued in January 2013. Among other things, the NESHAP include two exemptions that allow owners and operators of stationery emergency RICE to operate their engines without the installation and operation of emission controls (1) as part of an emergency DR program for 100 hours per year (100 hour exemption) or (2) as part of a financial arrangement with another entity per specified restrictions in non-emergency situations for 50 hours per year (50 hour exemption). We believe this waiver of NESHAP standards results in disparate treatment of different generation technology types. In its appeal, Power sought more stringent emission control standards for RICE to support more competitive markets, particularly the PJM capacity market. In August 2014, the EPA denied the March 2013 petition and in October 2014, Power appealed the EPA's denial to the D.C. Court. On September 23, 2015, the D.C. Court granted the EPA's motion for voluntary remand of the 50 hour exemption provision to the EPA. On May 4, 2016, the D.C. Court vacated the 100 hour exemption which removes that provision from the rule. We believe that the impact of the D.C. Court's rulings would likely benefit Power's and its competitors' operations of their power generation peaking units.

Cooling Water Intake Structure Regulation    

December 31, 2015 Form10-K page 26. On June 10, 2016, the New Jersey Department of Environmental Protection (NJDEP) issued the final New Jersey Pollutant Discharge Elimination System (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 Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. On July 8, 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP's issuance of a final NJPDES renewal permit for Salem. The Riverkeeper's filing does not change the effective date of the permit. For additional information, see Part I, Item 1. Note 8. Commitments and Contingent Liabilities.

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ITEM 6. EXHIBITS

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

a. PSEG:
Exhibit 10a(10):	Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016
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 10a(9):	Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016 (1)
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 10a(8):	Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016 (1)
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

(1) Filed as Exhibit 10a(10) by PSEG with this Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, File No. 001-09120 on July 29, 2026 and incorporated herein by this reference.

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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 29, 2016

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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 29, 2016

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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 29, 2016

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EX-10

EXHIBIT 10a(10)

KEY EXECUTIVE SEVERANCE PLAN OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

Amended effective July 19, 2016

ARTICLE I

PURPOSE OF THE PLAN

1.1    Purpose The Key Executive Severance Plan of Public Service Enterprise Group Incorporated (“Plan”) is maintained by the Company to provide severance benefits to certain key executive-level employees of the Company and its affiliates whose employment is terminated under the circumstances described herein. The Plan was amended and restated effective December 17, 2012.

The Plan was amended effective January 1, 2014 to provide that (i) for Eligible Employees who become Schedule B Participants after December 31, 2013, their Change in Control benefit under Section 5.2(b) of the Plan shall be equal to two times Annual Base Salary and Target Bonus, and (ii) for Eligible Employees who become Schedule A Participants after December 31, 2013, their Change in Control benefit under Section 5.2(b) of the Plan shall be equal to 1.5 times Annual Base Salary and Target Bonus. The Plan was further amended to provide that the for purposes of determining the nonqualified plan change in control benefit under Section 5.5(a) of the Plan, with respect to Eligible Employees who become Schedule A or Schedule B Participants after December 31, 2013, their employment shall be assumed to have continued for 1.5 or two additional years (for Schedule A Participants and Schedule B Participants, respectively). Finally, the Plan was amended to update the Schedule A Participant list.

The Plan was amended effective June 16, 2014 to (i) add a new class of eligible Participants, Schedule C Participants, (ii) to provide that there will be no additions to Schedule B Participants, (iii) to provide that other than a current Schedule B Participant, an Eligible Employee newly hired or promoted into a position reflected on Schedule B as of June 16, 2014, shall become a Schedule A Participant, and (iv) to update the Schedule A Participant list, the Schedule B Participant list and the Schedule C Participant list.

The Plan was amended effective July 14, 2014 to update the Schedule A Participant list and the Schedule C Participant list.

The Plan was amended effective February 17, 2015 to update the Schedule A Participant list, the Schedule B Participant list and the Schedule C Participant list.

The Plan was amended effective November 18, 2015 to update the Schedule A Participant list, the Schedule B Participant list and the Schedule C Participant list, and to include the language to comply with the Securities and Exchange Commission’s whistleblower protections.

The Plan was amended effective December 15, 2015 to update the Schedule A Participant list and the Schedule C Participant list.

The Plan is being amended effective July 19, 2016 to update the Schedule A Participant list and the Schedule C Participant list. The Plan is also being amended to comply with the Defense of Trade Secrets Act regarding the confidentiality provision. Finally, the Plan is being

1

amended to clarify that if an Eligible Employee is newly hired or promoted into a position reflected on Schedule B as of June 6, 2014, such Eligible Employee shall become a Schedule A Participant.

The Plan is intended to comply in operation and form with Section 409A to the Internal Revenue Code of 1986, as amended (“Code”). The timing and form of payment of benefits provided under the Plan will be deemed to be automatically modified, and a Participant’s rights under the Plan will be limited so as to conform to any requirements under Section 409A of the Code.

ARTICLE II

DEFINITIONS

2.1    “Accrued Obligation” shall have the meaning set forth in Section 4.1 or 5.1 of the Plan.

2.2    “Affiliate” means any corporation, trade or business if it or the Company are members of a controlled group of corporations, are under common control or are members of an affiliated service group, within the meanings of Sections 414(b), 414(c) and 414(m), respectively, of the Code. The term “Affiliate” shall also include any other entity required to be aggregated with the Company pursuant to regulations under Section 414(o) of the Code.

2.3    “Annual Base Salary” means the annual rate of base salary payable to a Participant for services performed for an Employer, as in effect immediately prior to the Participant’s Date of Termination.

2.4    “Board” means the board of directors of the Company.

2.5    “Cause” means:

(a)For purposes of Article IV:

(i) Misconduct, gross negligence, theft, or fraud against the Company;

(ii) For “Performance Reasons,” as defined in Section 2.21 of the Plan;

(iii) Violation of the Standards of Integrity or other Company policy;

(iv) Insubordination;

(v) One or more significant acts of dishonesty;

(vi) Any act that is likely to have the effect of injuring the reputation, business, or business relationship of, the Company, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries;

(vii) Violation of any fiduciary duty;

(viii) Breach of any duty of loyalty;

(ix) Any breach of the restrictive covenants contained in Exhibit I below;

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(x) One or more acts of moral turpitude that constitute a violation of applicable law (included but not limited to a felony); or

(xi) Conviction of a felony or plea of nolo contendere to a felony charge.

(b)For purposes of Article V:

(i) The willful and continued failure to substantially perform his employment duties;

(ii) The willful engaging in gross misconduct that is materially and demonstrably injurious to the Employer;

(iii) The willful violation of the Company’s Standards of Integrity or other applicable corporate code of conduct, or

(iv) The conviction of a felony or a plea of nolo contetendere to a felony charge.

No act or failure to act on the part of the Participant shall be considered “willful” unless it is done, or omitted to be done, by the Participant in bad faith or without reasonable belief that the Participant’s action or omission was in the best interests of the Employer. Any act or failure to act that is based upon authority given pursuant to a resolution duly adopted by the Board, or the advice of counsel for the Employer, shall be conclusively presumed to be done, or omitted to be done, by the Participant in good faith and in the best interests of the Employer.

Notwithstanding the forgoing, for purposes of the Plan, the termination of a Participant’s employment with an Employer shall not be deemed to be for Cause unless such termination is effected in accordance with the following procedures. The Employer shall give the Participant written notice (“Notice of Termination for Cause”) of its intention to terminate the Participant’s employment for Cause, setting forth in reasonable detail the specific conduct of the Participant that it considers to constitute Cause. Such notice shall be given no later than 60 days after the act or failure (or the last in a series of acts or failures) that the Employer alleges to constitute Cause. The Participant shall have 30 days after receiving the Notice of Termination for Cause in which to cure such act or failure, to the extent such cure is possible. In the case of a termination under clause (a), (b) or (c) above, if the Participant fails to cure such act or failure to the reasonable satisfaction of the Employer, the Employer shall give the Participant a second written notice stating that in the good faith opinion of the Employer, the Participant is guilty of the conduct described in the Notice of Termination for Cause and that such conduct constitutes Cause under the Plan.

2.6    “Change in Control” means 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 (the “Exchange Act”) is or becomes the beneficial owner within the meaning of Rule 13d-3 under the Exchange Act (a “Beneficial Owner”), directly or indirectly, of securities of the Company (not including in the securities beneficially owned by such person any securities acquired directly from the Company or its Affiliates) representing 25% or more of the combined voting power of the Company’s then outstanding securities, excluding any person who

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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 constitute a majority of the number of directors of the Company then serving: individuals who, on the Effective Date, constitute the Board and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation, relating to the election of directors of the Company) whose appointment or election by the Board or nomination for election by the Company’s stockholders was approved or recommended by a vote of at least two-thirds of the directors then still in office who either were directors on the Effective Date or whose appointment, election or nomination for election was previously so approved or recommended; or

(c) There is consummated a merger or consolidation of the Company or any direct or indirect wholly-owned subsidiary of the Company with any other corporation, other than (i) a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation 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 the Company or of its Affiliates, at least 75% of the combined voting power of the securities of the Company 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 the Company (or similar transaction) in which no person is or becomes the Beneficial Owner, directly or indirectly, of securities of the Company representing 25% or more of the combined voting power of the Company’s then outstanding securities; or

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

Notwithstanding the foregoing, 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 the Company 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 the Company immediately following such transaction or series of transactions.

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2.7    “Code” means the Internal Revenue Code of 1986, as amended, and the regulations promulgated thereunder.

2.8    “Committee” means the Organization and Compensation Committee of the Board or any successor of such Committee.

2.9    “Company” means Public Service Enterprise Group Incorporated and any successors thereto.

2.10    “Confidential Information” means all trade secrets, proprietary and confidential business information belonging to, used by, or in the possession of the Company or any of its Affiliates, including but not limited to information, knowledge or data related to business strategies, plans and financial information, mergers, acquisitions or consolidations, purchase or sale of property, leasing, pricing, sales programs or tactics, actual or past sellers, purchasers, lessees, lessors or customers, those with whom the Company or its Affiliates has begun negotiations for new business, costs, employee compensation, marketing and development plans, inventions and technology, whether such confidential information, knowledge or data is oral, written or electronically recorded or stored, except information in the public domain, information known by the Participant prior to employment with an Employer, and information received by the Participant from sources other than the Company or its Affiliates, without obligation of confidentiality.

2.11    “Date of Termination” means the date of a Participant’s death, Disability Effective Date, or the date on which the termination of the Participant’s employment by an Employer for Cause or without Cause or by the Participant for Good Reason or without Good Reason, including Retirement, is effective, as the case may be, provided that the termination constitutes a Separation from Service.

2.12    “Disability” means that the Participant (a) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (b) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than three months under an accident or health plan covering employees of an Employer.

2.13    “Disability Effective Date” means the 30th day after the Participant’s receipt of written notice of the Employer’s intention to terminate the Participant’s employment on account of Disability, provided that, within the 30 days after the Participant’s receipt of such notice, the Participant shall not have returned to full-time performance of his employment duties.

2.14    “Eligible Employee” means an individual who is designated as such in accordance with Section 3.1.

2.15    “Effective Date” of the amendment and restatement is July 19, 2016.

2.16    “Employer” means the Company and each Affiliate, and any successors thereto.

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2.17    “Good Reason” means:

(a) Any material reduction in the Participant’s Annual Base Salary, Target Bonus or Target Long-Term Incentive, other than reductions pursuant to a broad-based compensation reduction program or policy affecting the Participant and all similarly situated employees of the Employer;

(b) Any material adverse change in the Participant’s title, authority, duties, or responsibilities or the assignment to the Participant of any duties or responsibilities inconsistent in any respect with those customarily associated with the position of the Participant immediately prior to the Change in Control;

(c) The failure of any successor to the Company to assume this Plan in accordance with Section 11.5(b);

(d) Where the only comparable position offered to the Participant within the Employer following a Change in Control would otherwise meet the requirements of subsections (a) and (b) of this Section 2.17 of the Plan, but would require the Participant to increase his or her one-way commuting distance from his or her principal residence by more than 50 miles; or

(e) Any other material breach of the terms of the Plan by the Company that either is not taken in good faith or, even if taken in good faith, is not remedied by the Company promptly after receipt of notice thereof from the Participant.

Notwithstanding the forgoing, for purposes of the Plan, the termination of a Participant’s employment with an Employer shall not be deemed to be for Good Reason unless such termination is effected in accordance with the following procedures. The Participant shall give his Employer a written notice (“Notice of Termination for Good Reason”) of the termination, setting forth in reasonable detail the specific acts or omissions of the Employer that constitute Good Reason and the specific provision(s) of the Plan on which the Participant relies. Unless the Committee determines otherwise, a Notice of Termination for Good Reason by the Participant must be made within 60 days after the Participant first has actual knowledge of the act or omission (or the last in a series of acts or omissions) that the Participant alleges to constitute Good Reason, and the Employer shall have 30 days from the receipt of such Notice of Termination for Good Reason to cure the conduct cited therein. A termination of employment by the Participant for Good Reason shall be effective on the final day of such 30-day cure period unless prior to such time the Employer has cured the specific conduct asserted by the Participant to constitute Good Reason to the reasonable satisfaction of the Participant.

For purposes of the Plan, a Participant’s determination that an act or failure to act constitutes Good Reason shall be presumed to be valid unless such determination is decided to be unreasonable by the Committee or its delegate pursuant to Article IX.

2.18    “Nonqualified Plan” the Retirement Income Reinstatement Plan for Non‑Represented Employees of Public Service Enterprise Group Incorporated.

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2.19    “Other Benefits” shall have the meaning set forth in Articles IV and V, as applicable.

2.20    “Participant” means an Eligible Employee who has satisfied the conditions for participation in the Plan, as set out in Section 3.2, and is listed on either Schedule A, Schedule B or Schedule C hereto, as the same may be amended from time to time.

2.21    “Performance Reasons” means the Participant’s failure meet the expectations established for his function in the Company as: (a) communicated to him by his manager during any performance review, or (b) may be communicated to him otherwise by his manager from time to time either orally or in writing.

2.22    “Plan” means this Key Executive Severance Plan of Public Service Enterprise Group Incorporated, as set forth herein and as may be amended, modified or supplemented from time to time.

2.23    “Prior Equity Awards” shall mean outstanding stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares and performance shares units.

2.24    “Retirement” means a Separation from Service after the Participant has satisfied the eligibility requirements for early or normal retirement under the terms of the Retirement Plan in which the Participant participates. Notwithstanding the foregoing, for the purposes of determining benefit entitlements under Article V of the Plan, Retirement shall not include forced retirements or any termination by an Employer without Cause or voluntary termination by the Participant for Good Reason that occurs on a date on which the Participant is Retirement eligible.

2.25    “Retirement Plan” the retirement plan in which the Participant participates either the Pension Plan of Public Service Enterprise Group Incorporated or the Cash Balance Pension Plan of Public Service Enterprise Group Incorporated.

2.26    “Schedule A Participant” shall mean a Participant listed on Schedule A hereto.

2.27    “Schedule B Participant” shall mean a Participant listed on Schedule B hereto.

2.28    “Schedule C Participant” shall mean a Participant listed on Schedule C hereto.

2.29    “Separation from Service” shall be deemed to have occurred if a Participant and the Company or any Affiliate reasonably anticipates, based on the facts and circumstances, that either:

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

(b) 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.

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(c) If a Participant is absent from employment due to military leave, sick leave or any other bona fide leave of absence authorized by the Company or an Affiliate and there is a reasonable expectation that the Participant will return to perform services for the Company 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 the Company 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, unless a greater period is provided for under applicable law.

2.30    “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 the Company 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 the Company or an Affiliate is publicly traded on an established securities market or otherwise.

2.31    “Target Bonus” means the Participant’s target annual bonus, if any, under the applicable annual incentive compensation plan of the Company for the fiscal year in which the Date of Termination occurs.

2.32    “Target Long-Term Incentive” means the Participant’s target long-term incentive award, if any, under the applicable long-term incentive compensation plan of the Company.

ARTICLE III

ELIGIBILITY AND PARTICIPATION

3.1    Eligible Employees. Eligibility to participate in the Plan shall be limited to certain key executives of an Employer who (a) are not parties to individual employment or change in control agreements that provide for severance benefits, and (b) are designated, by duly adopted resolution of the Committee, as Eligible Employees.

3.2    Participation. As a condition to becoming a Participant and being entitled to the benefits and protections provided under the Plan, each Eligible Employee must execute and deliver to the Company, within 30 days after the later of the Effective Date and the date such individual is designated by the Committee as an Eligible Employee, a written agreement in the form attached hereto as Exhibit I (or in such other form as may be satisfactory to the Company) to be bound by the restrictive covenants set forth in Article VII. Schedules A, B and C hereto list the Eligible Employees who have satisfied the conditions for Plan participation and the date as of which each such Eligible Employee became a Participant. The Committee shall cause Schedules A, B and C to be updated from time to time to reflect the Participants who are currently

8

participating in the Plan. An employee who becomes an Eligible Employee on or after January 1, 2014 shall become a Schedule C Participant. However, if an Eligible Employee is newly hired or promoted into a position reflected on Schedule B as of June 6, 2014, the Eligible Employee shall become a Schedule A Participant.

3.3    Release of Claims. Notwithstanding anything in the Plan to the contrary, payment of any benefits under the Plan is expressly contingent upon the Participant’s execution and delivery to the Company, within 30 days after the Participant’s Date of Termination, of a written agreement provided by the Company, wherein the Participant releases and discharges the Company and each of its Affiliates of any and all claims against the Company and its Affiliates related in any way to the Participant’s employment with an Employer and the termination of such employment.

3.4Committee Discretion. The Committee shall have the sole discretion to determine eligibility for benefits under the Plan.

ARTICLE IV

SEVERANCE BENEFITS IN GENERAL

4.1    Termination by Employer Other than for Cause or by the Participant for Good Reason. Subject to Section 3.3 and Article VI of the Plan, if a Participant’s employment is involuntarily terminated by an Employer for reasons other than Cause or a Participant terminates employment for Good Reason, the Participant shall be entitled to the benefits described in Sections 4.2 through 4.9 of the Plan. For purposes of clarity, subject to Section 3.3 and Article VI of the Plan, Participant shall be entitled to the benefits described in Sections 4.2 through 4.9 of the Plan if a Participant’s employment is involuntarily terminated by an Employer due to a reduction in force or a reorganization of the Employer (as determined by the Committee), or a Participant experiences a cessation of employment in connection with a reduction in force or Employer reorganization (as determined by the Committee) where the only position offered to the Participant within the Company and Affiliates would require the Participant to accept a reduction in his or her annual rate of base salary of more than 20% below the annual rate of base salary of the Participant’s position immediately prior to such action. For the avoidance of any doubt, a Participant shall not be entitled to benefits under the Plan if (i) his employment terminates as a result of death, Disability, the Participant voluntarily terminates employment, except for Good Reason, or (ii) the Participant’s cessation of employment is in connection with the sale of the Participant’s Employer, line or unit of business of the Employer within which the Participant’s position is located, business function of the Employer within which the Participant’s position is located, or the assets related to the Employer, line or unit or business, or business function within which the Participant’s position is located, and the Participant accepts employment with the purchaser within 90 days of the closing of the transaction in a position that has an annual rate of base salary that is at least 80 percent of the Participant’s annual rate of base salary immediately prior to the closing of the sale).

4.2Cash payment. The Company shall pay to the Participant a lump sum, in cash, the sum of (a) and (b):

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(a) The Participant’s base salary and accrued vacation pay through the Date of Termination to the extent not theretofore paid (hereinafter referred to as the “Accrued Obligations”); and

(b) An amount equal to the product of 1.0 times (0.5 times if the Participant were employed less than one year) the sum of the Participant’s Annual Base Salary and Target Bonus.

4.3Long-Term Incentive Awards. The treatment of Prior Equity Awards shall be governed by the terms of the Long-Term Incentive Plan and the related award agreements.

4.4Annual Incentive Awards. The Participant shall receive a prorated annual incentive award pursuant to the performance incentive program, if applicable, for the calendar year in which the Participant’s Termination of Employment occurs. The award shall be calculated based solely on 100 percent of the target incentive award and prorated based on the number of calendar days of employment in the calendar year in which the Participant’s termination occurs through the Participant’s Date of Termination. For purposes of this Section 4.4, calendar year shall mean 365 days.

Annual incentive awards with respect to the calendar year in which a Participant’s Date of Termination occurs will be paid at the same time as awards for such calendar year are paid to active employees of the Employer.

4.5Outplacement Services. Outplacement services approved by the Committee, which may include individual or group counseling and administrative assistance or workshops, shall be available beginning on the Participant’s Date of Termination or such earlier date designated by the Participant’s business unit leadership. Outplacement services shall continue to be available for the period up to 12 months.

4.6Educational Assistance. Educational assistance shall be provided in accordance with the Employer’s tuition program.

4.7Health Care Benefits.

(a) Retiree Health Care Coverage. A Participant who has not otherwise satisfied the eligibility criteria for participation prior to his Date of Termination, shall be entitled to elect retiree coverage under the Employer’s applicable retiree group health care plans as though he or she otherwise satisfied such plans’ eligibility requirements if:

(i) The Participant has attained age 50 and completed ten or more Years of Service as of his Date of Termination but the sum of the Participant’s age and Years of Service is less than 80; or

(ii) The Participant has attained age 49 and completed 20 or more Years of Service as of his Date of Termination but the sum of the Participant’s age and Years of Service is less than 80.

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Such coverage shall commence no earlier than the Participant’s Termination Date. The Participant shall be charged the full cost of retiree coverage under these plans.

(b) COBRA Continuation Coverage. Each Participant who is not eligible for, or does not elect, the retiree health care coverage described in this Section 4.7 of the Plan shall be entitled, pursuant to any continuation coverage rights under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended ("COBRA"), to continue individual and dependent coverage under the Company's group health care plans following the Participant’s Date of Termination. If continuation coverage is elected, the Employer shall pay the same portion of the cost of medical coverage that it paid immediately prior to the Participant’s Date of Termination for active employees during the one-year period following the Participant’s Date of Termination, and the Participant shall pay the balance. The Participant shall be charged the full expense of medical coverage (102 percent of the cost of coverage) during the remainder of the COBRA coverage period, if any, and the full expense of dental and (if applicable) vision and hearing coverage (102 percent of the cost of coverage) during the entire COBRA coverage period.

4.8Life Insurance. A Participant who is not eligible for coverage under the Employer’s retiree life insurance plan shall be entitled, for the one-year period following the Participant’s Date of Termination to life insurance coverage at the Employer’s expense in an amount equal to the group term life insurance coverage in effect for such Participant under the Employer’s group term life insurance plan for active employees as of his Date of Termination.

4.9Other Benefits. A Participant shall not be entitled to any severance, separation or early retirement incentive pay or benefits other than as provided hereunder or under any qualified or nonqualified retirement plan or deferred compensation arrangement maintained by the Employer. Except as provided in the foregoing sentence, a Participant’s rights under any other employee benefit plans maintained by the Company or an Affiliate shall be determined in accordance with the provisions of such plans, including the Company’s right to amend or terminate such plans at any time. (The amounts and benefits payable to the Participant pursuant to Sections 4.3 through 4.9 of the Plan shall be hereinafter referred to as the “Other Benefits”).

4.10Termination where a Participant experiences a cessation of employment in connection with a reduction in force or Employer reorganization where the only position offered to the Participant within the Company and Affiliates would require the Participant to increase his or her one-way commuting distance by more than 50 miles. Subject to Section 3.3 and Article V, if a Participant experiences a cessation of employment in connection with a reduction in force or an Employer reorganization (as determined by the Committee) where the only position offered to the Participant within the Company and Affiliates would require the Participant to increase his or her one-way commuting distance by more than 50 miles:

(a) Severance Pay. The Participant shall receive a lump sum cash payment in accordance with Section 6.1 of the Plan, based upon the amount of the Participant’s base salary, the number of Years of Service completed as of the Participant’s Termination Date, as follows:

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(i) Less than Thirteen Years of Service: If, as of the Participant’s Date of Termination, he has completed fewer than thirteen Years of Service, the amount of severance pay shall equal 26 weeks of base salary.

(ii) Thirteen or More Years of Service: If, as of the Participant’s Date of Termination, he has completed thirteen or more Years of Service, the amount of severance pay shall equal two weeks of base salary for each Year of Service, up to a maximum of 52 weeks of base salary.

(b) Annual Incentive Awards. A Participant shall receive a prorated annual incentive award pursuant to the performance incentive program, if applicable, for the calendar year in which the Participant’s Termination of Employment occurs. The award shall be calculated based solely on 100 percent of the target incentive award and prorated based on the number of days of employment in the calendar year in which the participant’s Termination of Employment occurs through the employee’s Termination Date. Annual incentive awards with respect to the calendar year in which a Participant’s Termination Date occurs will be paid at the same time as awards for such calendar year are paid to active employees of the Employer.

(c) Outplacement Services. Outplacement services approved by the Committee, which may include individual or group counseling and administrative assistance or workshops, shall be available beginning on the participant’s Termination Date or such earlier date designated by the participant’s business unit leadership. Outplacement services shall continue to be available for the period up to 12 months.

(d) Educational Assistance. Education assistance shall be provided in accordance with the Employer’s tuition program.

(e) Health Care Benefits.

(i) Retiree Health Care Coverage. An Eligible Employee who has not otherwise satisfied the eligibility criteria for participation prior to his Date of Termination, shall be entitled to elect retiree coverage under the Employer’s applicable retiree group health care plans as though he or she otherwise satisfied such plans’ eligibility requirements if:

(A) The Participant has attained age 50 and completed ten or more Years of Service as of his Date of Termination but the sum of the Participant’s age and Years of Service is less than 80; or

(B) The Participant has attained age 49 and completed 20 or more Years of Service as of his Date of Termination but the sum of the Participant’s age and Years of Service is less than 80.

Such coverage shall commence no earlier than the Participant’s Date of Date. The Participant shall be charged the full cost of retiree coverage under these plans.

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(ii) COBRA Continuation Coverage. Each Participant who is not eligible for, or does not elect, the retiree health care coverage described in this subsection (i) shall be entitled, pursuant to any continuation coverage rights under COBRA to continue individual and dependent coverage under the Company's group health care plans following the Participant’s Termination Date. If continuation coverage is elected, the Employer shall pay the same portion of the cost of medical coverage that it paid immediately prior to the Participant’s Date of Termination for active employees during the period that the Participant would have received severance pay if severance pay had been paid in bi-weekly installments, and the Participant shall pay the balance. The Participant shall be charged the full expense of medical coverage (102 percent of the cost of coverage) during the remainder of the COBRA coverage period, if any, and the full expense of dental and (if applicable) vision and hearing coverage (102 percent of the cost of coverage) during the entire COBRA coverage period.

(f) Life Insurance. A Participant who is not eligible for coverage under the Employer’s retiree life insurance plan shall be entitled during the period that the Participant would have received severance pay if severance pay had been paid in bi-weekly installments, to life insurance coverage at the Employer’s expense in an amount equal to the group term life insurance coverage in effect for such Participant under the Employer’s group term life insurance plan for active employees as of his Date of Termination Date.

(g) Other Benefits. A Participant shall not be entitled to any severance, separation or early retirement incentive pay or benefits other than as provided under the Plan or under any qualified or nonqualified retirement plan or deferred compensation arrangement maintained by the Employer. Except as provided in the foregoing sentence, a Participant’s rights under any other employee benefit plans maintained by the Company or an Affiliate shall be determined in accordance with the provisions of such plans, including the Company’s right to amend or terminate such plans at any time.

ARTICLE V

SEVERANCE BENEFITS AFTER A CHANGE IN CONTROL

5.1    Termination By Employer Other Than For Cause or By Participant For Good Reason (other than Good Reason as described in Subsection 2.17(d)) Within Two Years After a Change in Control. Subject to Section 3.3 and Article VI of the Plan, if, within two years following the occurrence of a Change in Control, either (a) an Employer shall terminate a Participant’s employment other than for Cause or Disability, or (b) a Participant shall voluntarily terminate his employment for Good Reason pursuant to Subsections 2.17 (a), (b), (c) or (e), the Participant shall be entitled to benefits in Sections 5.2 through 5.8 of the Plan. For the avoidance of any doubt, a Participant shall not be entitled to benefits under the Plan if his

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employment terminates as a result of death, Disability or the Participant voluntarily terminates employment, except for Good Reason, except as otherwise provided under the Plan.

5.2 Cash Payment. The Company shall pay to the Participant, in a lump sum in cash, the aggregate of the amounts in (a) and (b) below:

(a) the sum of:

(i) The Participant’s base salary and accrued through the Date of Termination; and

(ii) The product of (x) the Participant’s Target Bonus and (y) a fraction, the numerator of which is the number of days in the current calendar year through the Date of Termination, and the denominator of which is 365;

in each case to the extent not theretofore paid (the sum of the amounts described in clauses (i) and (ii) shall be hereinafter referred to as the “Accrued Obligations”); and

(b) Either (i), (ii) or (iii):

(i) In the case of a Schedule A Participant, the amount equal to the product of two times the sum of the Schedule A Participant’s Annual Base Salary and Target Bonus;

(ii) In the case of a Schedule B Participant, the amount equal to the product of three times the sum of the Schedule B Participant’s Annual Base Salary and Target Bonus; or

(iii) In the case of a Schedule C Participant, the amount equal to the product of one and half times the sum of the Schedule C Participant’s Annual Base Salary and Target Bonus.

5.3 Long Term Incentive Awards. The treatment of Prior Equity Awards shall be governed by the terms of the Long-Term Incentive Plan and the related award agreements.

5.4Health Care and Other Welfare Benefits. The Company shall pay the cost of the continued coverage of the Participant and/or the Participant’s family under the Company’s medical and dental employee benefit plans for 18 months after the Date of Termination provided that the Participant makes an election to continue such coverage in the Company’s medical and dental employee benefit plans under COBRA, subject to the requirements and limitations thereof. Unless otherwise limited by applicable law, thereafter, the Company shall pay the cost of the continued coverage of the Participant and/or the Participant’s family under the Company’s medical and dental employee benefit plans for an additional period of six months, in the case of a Schedule A Participant, or 18 months, in the case of a Schedule B Participant (for a Schedule C Participant, no additional period beyond the initial 18 months); provided however, that if the Participant becomes re-employed with another employer and is eligible to receive medical or dental benefits under another employer provided plan, the medical and dental benefits provided

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by the Company under this Plan shall be secondary to those provided under such other plan during the applicable period of eligibility.

Unless otherwise limited by applicable law, for two years after the Date of Termination in the case of a Schedule A Participant, three years after the Date of Termination in the case of a Schedule B Participant, or in the case of a Schedule C Participant, eighteen months after the Date of Termination (or for any Participant such longer period as may be provided by the terms of the appropriate plan, program, practice or policy), the Company shall continue benefits (other than medical and dental benefits) to the Participant and/or the Participant’s family at least equal to those which would have been provided to them in accordance with the welfare plans, programs, practices and policies maintained by the Company if the Participant’s employment had not been terminated or, if more favorable to the Participant, as in effect generally at any time thereafter with respect to other peer executives of the Employer and their families.

Unless otherwise limited by applicable law, the Participant’s eligibility (but not the time of commencement of such benefits) for retiree benefits pursuant to the welfare plans, programs, practices and policies maintained by the Company shall be determined as if the Participant had (A) remained employed until two years (in the case of a Schedule A Participant), three years (in the case of a Schedule B Participant), or eighteen months (in the case of a Schedule C Participant) after the Date of Termination and (B) retired on the last day of such period.

5.5 Nonqualified Pension Benefit. The Participant shall be paid, in a lump sum payment in cash, an amount equal to the excess of:

(a) The actuarial equivalent of the benefit under the Company’s applicable Retirement Plan (utilizing the rate used to determine lump sums and, to the extent applicable, other actuarial assumptions no less favorable to the Participant than those in effect under the Retirement Plan immediately prior to the Effective Date), any benefit under the Nonqualified Plan and, to the extent applicable, any other defined benefit retirement arrangement between the Participant and the Company (“Other Pension Benefits”) which the Participant would receive if the Participant’s employment continued for two, three or one and half additional years (for Schedule A Participants, Schedule B and Schedule C Participants, respectively) beyond the Date of Termination and, assuming that the Participant’s compensation for such deemed additional period was the Participant’s Annual Base Salary as in effect immediately prior to the Date of Termination and assuming a bonus in each year during such deemed additional period equal to the Target Bonus, over

(b) The actuarial equivalent of the Participant’s actual benefit (paid or payable), if any, under the Retirement Plan, the Nonqualified Plan and Other Pension Benefits as of the Date of Termination (utilizing the rate used to determine lump sums and, to the extent applicable, other actuarial assumptions no less favorable to the Participant than those in effect under the Retirement Plan immediately prior to the effective date of the Change in Control).

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5.6Deferred Compensation. Any compensation previously deferred (other than pursuant to a tax-qualified plan) by or on behalf of the Participant (together with any accrued interest or earnings thereon), whether or not then vested, shall become vested on the Date of Termination and shall be paid in accordance with the terms of the applicable deferred compensation plan, policy or practice under which it was deferred to the extent permitted by Section 409A of the Code.

5.7Outplacement Services. The Company shall, at its sole expense as incurred, provide the Participant with outplacement services suitable to the Participant’s position for a period not to exceed one year following the Date of Termination with a nationally recognized outplacement firm.

5.8Other Benefits. To the extent not theretofore paid or provided, the Company shall pay or provide to the Participant any other amounts or benefits required to be paid or provided or which the Participant is entitled to receive under any plan, program, policy, practice, contract or agreement of the Company (or other Employer), including earned but unpaid stock and similar compensation, but excluding medical or dental benefits if the Participant is eligible for such benefits to be provided by a subsequent employer, and benefits payable under any severance plan or policy (such other amounts and benefits that are payable to the Participant shall be hereinafter referred to as the “Other Benefits”).

5.9Termination By Participant For Good Reason as described in Subsection 2.17(d) Within Two Years After a Change in Control.

Subject to Section 3.3 and Article V of the Plan, if, within two years following the occurrence of a Change in Control, a Participant shall voluntarily terminate his or her employment for Good Reason as described in Subsection 2.17(d):

(a) Severance Pay. The Participant shall receive a lump sum payment in accordance with Section 6.1 of the Plan based upon the amount of the Participant’s base salary, the number of Years of Service completed as of the Participant’s Termination Date, as indicated below:

(i) Less than Thirteen Years of Service: If, as of the Participant’s Termination Date he or she has completed fewer than thirteen Years of Service, the amount of severance pay shall equal 26 weeks of base salary.

(ii) Thirteen or More Years of Service: If, as of the Participant’s Termination Date, he or she has completed thirteen or more Years of Service, the amount of severance pay shall equal two weeks of base salary for each Year of Service, up to a maximum of 52 weeks of base salary.

(b) Annual Incentive Awards. A Participant shall receive a prorated annual incentive award pursuant to the performance incentive program, if applicable, for the calendar year in which the Participant’s Termination of Employment occurs. The award shall be calculated based solely on 100 percent of the target incentive award and prorated based on the number of days of employment in the calendar year in which the participant’s Termination of Employment occurs through the

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employee’s Termination Date. Annual incentive awards with respect to the calendar year in which a Participant’s Termination Date occurs will be paid at the same time as awards for such calendar year are paid to active employees of the Employer.

(c) Outplacement Services. Outplacement services approved by the Committee, which may include individual or group counseling and administrative assistance or workshops, shall be available beginning on the Participant’s Date of Termination or such earlier date designated by the participant’s business unit leadership. Outplacement services shall continue to be available for the period up to 12 months.

(d) Educational Assistance. Education assistance shall be provided in accordance with the Employer’s tuition program.

(e) Health Care Benefits.

(i) Retiree Health Care Coverage. An Eligible Employee who has not otherwise satisfied the eligibility criteria for participation prior to his Date of Termination Date, shall be entitled to elect retiree coverage under the Employer’s applicable retiree group health care plans as though he or she otherwise satisfied such plans’ eligibility requirements if:

(A) The Participant has attained age 50 and completed ten or more Years of Service as of his or her Termination Date but the sum of the Participant’s age and Years of Service is less than 80; or

(B) The Participant has attained age 49 and completed 20 or more Years of Service as of his or her Termination Date but the sum of the Participant’s age and Years of Service is less than 80.

Such coverage shall commence no earlier than the Participant’s Termination Date. The Participant shall be charged the full cost of retiree coverage under these plans.

(ii) COBRA Continuation Coverage. Each Participant who is not eligible for, or does not elect, the retiree health care coverage described in this subsection (e) shall be entitled, pursuant to any continuation coverage rights under COBRA to continue individual and dependent coverage under the Company's group health care plans following the Participant’s Termination Date. If continuation coverage is elected, the Employer shall pay the same portion of the cost of medical coverage that it paid immediately prior to the Participant’s Date of Termination for active employees during the period that the Participant would have received severance pay if severance pay had been paid in bi-weekly installments, and the Participant shall pay the balance. The Participant shall be charged the full expense of medical coverage (102 percent of the cost of coverage)

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during the remainder of the COBRA coverage period, if any, and the full expense of dental and (if applicable) vision and hearing coverage (102 percent of the cost of coverage) during the entire COBRA coverage period.

(f) Life Insurance. A Participant who is not eligible for coverage under the Employer’s retiree life insurance plan shall be entitled, during the period that the Participant would have received severance pay if severance pay had been paid in bi-weekly installments, to life insurance coverage at the Employer’s expense in an amount equal to the group term life insurance coverage in effect for such Participant under the Employer’s group term life insurance plan for active employees as of his Date of Termination.

(g) Other Benefits. A Participant shall not be entitled to any severance, separation or early retirement incentive pay or benefits other than as provided under the Plan or under any qualified or nonqualified retirement plan or deferred compensation arrangement maintained by the Employer. Except as provided in the foregoing sentence, a Participant’s rights under any other employee benefit plans maintained by the Company or an Affiliate shall be determined in accordance with the provisions of such plans, including the Company’s right to amend or terminate such plans at any time.

5.10 Termination By Employer For Cause or By Participant Other Than For Good Reason. If, at any time after a Change in Control, either (a) an Employer shall terminate a Participant’s employment for Cause or (b) the Participant shall voluntarily terminate his employment other than for Good Reason, the Employer shall have no further payment obligations to the Participant other than for the Participant’s base salary through the Date of Termination and any accrued but unpaid vacation pay. In such case, all such amounts shall be paid to the Participant in a lump sum in accordance with Section 6.1 of the Plan.

5.11    Death. If a Participant’s employment terminates by reason of the Participant’s death after a Change in Control, all Accrued Obligations as of the time of death shall be paid to the Participant’s estate or beneficiary, as applicable, in a lump sum in cash in accordance with Section 6.1 of the Plan. The Participant’s estate or beneficiary shall be entitled to any Other Benefits in accordance with their terms. The treatment of Prior Equity Awards shall be governed by the terms of the Long-Term Incentive Plan and the related award agreements.

5.12    Disability. If a Participant’s employment is terminated by reason of Disability after a Change in Control, all Accrued Obligations shall be paid to the Participant in a lump sum in cash in accordance with Section 6.1 of the Plan. The treatment of Prior Equity Awards shall be governed by the terms of the Long-Term Incentive Plan and the related award agreements.

5.13    Retirement. If a Participant’s employment terminates as a result of Retirement after a Change in Control, the Participant shall be paid the Accrued Obligations in a lump sum in cash in accordance with Section 6.1 of the Plan and the Participant shall be entitled to any Other Benefits in accordance with their terms. The treatment of Prior Equity Awards shall be governed by the terms of the Long-Term Incentive Plan and the related award agreements.

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ARTICLEVI

TIMING OF, LIMITATIONS ON AND ADJUSTMENTS TO PLAN PAYMENTS

6.1    Time of Payments. Payments under the Plan shall be made to the Participant as follows:

(a) With respect to benefits under Sections 4.2, 4.10(a), 5.2, 5.5, 5.9(a), 5.12 and 5.13 of the Plan, payment to a Participant who is not a Specified Employee shall be made within the 60-day period following the Participant’s Date of Termination. With respect to benefits under Section 5.11 of the Plan, payment shall be made within the 60-day period following the Participant’s date of the Participant’s death. However, if the period to consider and revoke the written agreement required to receive the benefits described in Articles IV and V of the Plan (i.e., the waiver and release) spans two taxable years, in all events the payments will be made in second taxable year within 30 days following the later of the end of the first taxable year or the date the executed release is received by the Company.

(b) With respect to benefits under Sections 4.4, 4.10(b) and 5.9(b) of the Plan, payments shall be made to the Participants at the same time the payments are made to active employees.

(c) Notwithstanding anything to the contrary in the Plan, to the extent necessary to comply with Section 409A of the Code, payments to a Participant who is a Specified Employee shall be made within the 60-day period following the six-month anniversary of the Participant’s Date of Termination (other than by reason of death).

(d) All payments under the Plan that are reimbursements of covered expenses incurred by the Participant shall be made within the taxable year in which the expense is incurred.

6.2    Payment Offsets. Notwithstanding anything in the Plan to the contrary, in the event a Participant is entitled to receive severance payments both under this Plan and under the terms of either (a) an individual change of control or employment agreement, (b) another severance pay plan or policy of an Employer or (c) any existing or future law or regulation, the benefits payable under this Plan shall be reduced by the amount of any severance benefits such Participant is entitled to receive under such individual agreement, plan, policy, law or regulation.

6.3    Cap on Excess Parachute Payments; Gross-Up Payments. Notwithstanding anything in the Plan to the contrary, if (a) a Participant is a “disqualified individual” (as defined in Section 280G(c) of the Code) and (b) the severance benefits provided under Articles IV or V, as applicable, together with any other payments the Participant has the right to receive from an Employer, would constitute a “parachute payment” (as defined in Section 280G(b) of the Code) (“Parachute Payments”), the following provisions shall apply:

(a) The severance benefits under Articles IV or V shall not exceed an amount which, together with any other Parachute Payments the Participant has a right to receive

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from the Employer, would be 2.99 times the Participant’s “base amount” (as defined in Section 280G of the Code) so that no portion of the amounts received by the Participant shall be subject to the excise tax imposed under Section 4999 of the Code.

(b) The determination of whether any limitation on the severance benefits payable under Articles IV or V is necessary shall be made by the Company’s independent auditor or such other certified public accounting firm as may be jointly designated by the Participant and the Company (the “Accounting Firm”), which shall provide detailed supporting calculations to the Participant and the Company. The determinations of the Accounting Firm shall be conclusive and binding on the Company and the Participant. All fees and expenses of the Accounting Firm shall be borne solely by the Company.

(c) If through error or otherwise, a Participant shall receive payments under the Plan, together with other Parachute Payments the Participant has the right to receive from an Employer, in excess of 2.99 times his base amount, the Participant shall immediately repay the excess to the Employer upon notification from the Employer that an overpayment has been made. If the Participant fails to repay the excess to the Employer within 10 business days of the date of the Employer’s notification, the Participant will become liable to the Employer for an amount equal to two (2) times the excess amount.

6.4    Compliance with Section 409A of the Code. Notwithstanding anything in the Plan to the contrary, all Plan benefit obligations and payments are subject to Section 409A of the Code. To the extent required, the Company may modify the severance benefits payable hereunder to comply with Section 409A of the Code; provided, however, that the present value of the aggregate Plan benefits payable to a Participant after such modification shall not be less than the present value of the Plan benefits payable to the Participant prior to the modification.

6.5    Tax Withholding. Notwithstanding any other provision of this Plan, the Company may withhold from any amounts payable under this Plan such Federal, state, local, employment or foreign taxes as shall be required to be withheld pursuant to any applicable law or regulation.

ARTICLE VII

RESTRICTIVE COVENANTS

7.1    Confidentiality. As a condition to participation in the Plan, each Participant agrees to hold in a fiduciary capacity for the benefit of the Company and its Affiliates all Confidential Information which shall have been obtained by the Participant during the Participant’s employment by the Employer; except, however, that this Section 7.1 shall not apply to Confidential Information that is or becomes public knowledge, unless such Confidential Information became or becomes public knowledge due to acts of the Participant or representatives of the Participant in violation of this Section 7.1. Upon termination of the Participant’s employment, he shall return to the Company all Confidential Information in his possession. After termination of the Participant’s employment with the Employer, the

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Participant shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any such Confidential Information to anyone other than the Company and those designated by it, except (a) otherwise publicly available information, (b) as may be necessary to enforce his rights under the Plan or as necessary to defend himself against a claim asserted directly or indirectly by the Company or its Affiliates or (c) as may be compelled by service of a valid subpoena or other legal process (if the Participant is served with a valid subpoena or other legal process, he must so notify the Company within three business days). Furthermore, nothing contained in this Plan prevents a Participant from disclosing without notice to the Company any perceived violation of law to any federal, state, or local governmental agency or entity including, but not limited to, the Securities and Exchange Commission, or making other disclosures that are protected under the whistleblower provisions of any law. Finally, nothing in this Plan prevents a Participant - nor should a Participant be held civilly or criminally liable under any law - if the Participant discloses a trade secret: (a) in confidence to a Federal, State or local government official, either directly or indirectly, or to an attorney solely for the purpose of reporting or investigating a suspected violation of law; (b) in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal; (c) to the Participant’s attorney in connection with a lawsuit alleging retaliation by an employer for reporting a suspected violation of law; or (d) in connection with a lawsuit described in the immediately preceding subparagraph (c), provided the Participant: (i) files any document containing the trade secret under seal; and (ii) does not disclose the trade secret, except pursuant to a court order. Unless and until a determination has been made in accordance with Section 7.4 that the Participant has violated this Section 7.1, an asserted violation of the provisions of this Section 7.1 shall not constitute a basis for deferring or withholding any amounts otherwise payable to the Participant under the Plan.

7.2    Non-Compete. As a condition to participation in the Plan, each Participant agrees, that, in the event the Participant voluntarily terminates his employment other than for Good Reason, for the period of one year from Date of Termination he will not, without the written consent of the Company, directly or indirectly own, manage, operate, join, control, become employed by, consult to or participate in the ownership, management, or control of any business which is in direct competition with the Company or its Affiliates.

7.3    Non-Solicitation. As a condition to participation in the Plan, each Participant agrees that, in the event the Participant voluntarily terminates his employment other than for Good Reason, for the period of one year following the Date of Termination, he will not, directly or indirectly, solicit or hire, or encourage the solicitation or hiring by any employer other than the Company or its Affiliates, for any position as an employee, independent contractor, consultant or otherwise, any person who was a managerial or higher level employee of an Employer at any time during the term of the Participant’s employment by the Employer; provided, however, that this provision shall not apply with respect to the solicitation of any person after six months from the date on which such person’s employment by an Employer has terminated.

7.4    Enforcement. In the event of a breach by the Participant of any of the covenants set forth in this Article VII, it is agreed that the Company shall suffer irreparable harm for which money damages are not an adequate remedy, and that, in the event of such breach, the Company shall be entitled to obtain an order of a court of competent jurisdiction for equitable relief from

21

such breach, including, but not limited to, temporary restraining orders and preliminary and/or permanent injunctions against the breach of such covenants by the Participant. In the event that the Company should initiate any legal action for the breach or enforcement of any of the provisions contained in this Article VII and the Company does not prevail in such action, the Company shall promptly reimburse the Participant the full amount of any court costs, filing fees, attorney’s fees which the Participant incurs in defending such action, and any loss of income during the period of such litigation.

Nothing in this Plan prohibits the Participant from reporting possible violations of Federal law or regulation to any governmental agency or entity, including but not limited to the Department of Justice, the Securities and Exchange Commission, the Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of federal law or regulation.  The Participant does not need the prior authorization of the Law Department to make any such reports or disclosures, and is not required to notify the Company that such reports or disclosures have been made.

ARTICLE VIII

AMENDMENT AND TERMINATION

8.1    Amendment. The Company may amend this Plan at any time, and from time to time, by action of the Committee; provided, however, that no amendment adopted after the effective date of a Change in Control shall have the effect of either (a) removing an individual from the list of Participants, (b) adding conditions for participation or the entitlement to receive benefits hereunder, (c) reducing the amount of benefits payable to a Participant or (d) otherwise restricting a Participant’s right to receive benefits under the Plan, except as may otherwise be required to conform such payments to the requirements of Section 409A of the Code, as provided in Section 1.1.

8.2    Termination. The Committee may terminate the Plan at any time prior to a Change in Control. The Plan may not be terminated after the effective date of a Change in Control.

ARTICLE IX

ADMINISTRATION

9.1    Plan Administrator. The Plan shall be administered by the Committee, which shall have the duties and responsibilities for administering the Plan as are specifically set forth in this Article IX.

9.2    Responsibilities of Committee.

(a) The Committee shall have responsibility for the day to day administration of the Plan. In addition, the Committee shall have the specific powers, duties, responsibilities and obligations specifically provided for herein.

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(b) Subject to the express provisions of the Plan, the Committee shall have full and exclusive authority to interpret the Plan and to make all other factual determinations deemed necessary or advisable in the implementation and administration of the Plan, including but not limited to determinations with respect to the eligibility of Participants to receive benefits under the Plan and the status and rights of such Participants and all other persons affected hereunder. The Committee’s interpretation and construction of the Plan shall be conclusive and binding on all persons.

(c) The Committee shall have sole authority to adopt rules and regulations, which shall be administered by the Committee. In addition, the Committee shall have the discretionary authority to issue rulings and interpretations concerning the Plan and all matters arising thereunder, on a uniform and nondiscriminatory basis, provided the same shall not be contrary to or inconsistent with any provision of the Plan.

(d) As a condition of distributing any benefit under the Plan, the Committee may prescribe the use of such forms and require the furnishing of such information as the Committee may deem appropriate for administering the Plan.

9.3    Allocation or Delegation of Duties and Responsibilities. In furtherance of its duties and responsibilities under the Plan, the Committee may:

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

(b)     Employ agents to carry out fiduciary responsibilities;

(c)     Consult with counsel, who may be counsel to the Company; and

(d) Delegate any of its duties and responsibilities hereunder to such officer or officers of the Company as the Committee shall designate; except, however, that the Committee may not delegate to any other person the designation of Eligible Employees under Section 3.1 or the authority to consider and determine appeals of alleged adverse benefit determinations.

9.4    Expenses. Unless otherwise agreed to by the Company, no person acting as a fiduciary hereunder (who is an employee of an Employer) shall receive any compensation for services as such. Expenses incurred by fiduciaries in connection with the administration of the Plan shall be paid by the Company.

9.5    Indemnification of Plan Administrator. The Company shall indemnify, to the fullest extent permitted by law, each person made or threatened to be made a party to any civil or criminal action or proceeding by reason of the fact that he, or his testator or intestate, was a member of the Committee, or a delegate of the Committee, acting in the capacity of Plan administrator.

9.6    Reliance Upon Others. The Committee, any person to whom it may delegate such of its duties and powers as provided herein, and the officers and directors of the Company shall be entitled to rely conclusively upon and shall be fully protected in any action taken by them in

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good faith in reliance upon any tables, valuations, certificates, opinions, reports or other advice furnished to them by any duly appointed actuary, accountant, legal counsel (who may be counsel for the Company) or other specialist.

9.7    Notification. All notices, reports and statements in connection with the Plan that are given, made, delivered or transmitted to a Participant shall be deemed duly given, made, delivered, or transmitted when mailed, by such class as the sender may deem appropriate, with postage prepaid and addressed to the Participant at the address last appearing on the records of the Employer with respect to this Plan. All notices, direct actions or other communications given, made, delivered or transmitted by a Participant to an Employer or Committee shall not be deemed to have been duly given, made, delivered, transmitted or received unless and until actually received by the Employer or Committee.

9.8    Multiple Capacities. A person may serve in more than one fiduciary capacity with respect to the Plan.

ARTICLE X

CLAIMS PROCEDURE

10.1    Submission of Claims. The initial claim by any Participant for benefits under this Plan shall be submitted in writing to the Committee (or its delegate) within 60 days after the occurrence of the termination of employment that the Participant claims to have triggered entitlement to Plan benefits.

10.2    Computation and Review of Claims. All benefits shall be computed by the Committee or its delegate. All claims shall be approved or denied by the Committee (or its delegate) as soon as practicable, but in no event later than 90 days after application by the Participant. The Committee may take an additional 90 days to review the claim, provided that the Participant is notified in writing within the initial 90-day period.

(a) Initial Denial of Claim - Any denial of a claim shall include:

(i) Reason or reasons for the denial;

(ii) Reference to pertinent Plan provisions on which the denial is based;

(iii) Description of any additional material or information necessary for the Participant to perfect the claim together with an explanation of why the material or information is necessary; and

(iv) Explanation of the Plan’s claim review procedure, described below.

(b) Review of a Denied Claim - A Participant shall have a reasonable opportunity to appeal a denied claim to the Committee (or its delegate) for a full and fair review. The Participant or a duly authorized representative:

(i) Shall have 60 days, after receipt of written notification of the denial of claim in which to request a review.

(ii) May request a review upon written application to the Committee.

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(iii) Shall submit written comments, documents, records and other information relating to the claim.

(iv) May review, free of charge, pertinent Plan documents, records and other information relevant to the claim.

(c) Committee Review - The Committee’s (or its delegate’s) review shall take into account all comments, documents, records and other information submitted by the Participant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.

(d) Written Decision - The Committee (or its delegate) shall issue a decision on the reviewed claim promptly but no later than 60 days after receipt of the review. The Committee may take an additional 60 days to review the claim, provided that the Participant is notified in writing within the initial 60-day period. The Committee’s decision shall be in writing and shall include:

(i) Reasons for the decision;

(ii) References to the Plan provisions on which the decision is based;

(iii) Statement that the Participant is entitled to receive, upon request, reasonable access to, and copies of, all documents, records and other information relevant to the claim; and

(iv) Statement that the Participant is entitled to bring a civil suit under Section 502(a) of ERISA.

(e) Binding Effect - The Committee’s (or its delegate’s) decision shall be final and binding on the Participant and the Employer.

ARTICLE XI

GENERAL PROVISIONS

11.1    Construction. This Plan shall be construed and enforced in accordance with and governed by the internal substantive laws (and not the laws relating to conflict of laws or choice of laws) of the State of New Jersey, except to the extent that such laws are preempted by Federal law.

11.2    Unfunded Plan. The obligations of the Company under this Plan are not required to be funded in advance. Nothing contained in this Plan shall give an Eligible Employee or Participant any right, title or interest in any property of the Company or any of its Affiliates.

11.3    No Right to Continued Employment. Nothing contained herein shall be deemed to give any Eligible Employee or Participant the right to be retained in the employment of an Employer or to limit the rights of any Employer to discharge any Eligible Employee or Participant at any time, with or without notice and with or without Cause.

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11.4    Partial Invalidity. The invalidity or unenforceability of any term or provision, or any clause, or portion thereof, of this Plan shall in no way impair or affect the validity or enforceability of any other provision of this Plan, which shall remain in full force and effect.

11.5    Successors and Assigns.

(a) This Plan shall inure to the benefit of and be binding upon the Company and its successors and assigns.

(b) The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to assume expressly and agree to perform the Company’s obligations under the Plan in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place.

(c) In no event shall a Participant assign his interests under the Plan to any other person without the prior written consent of the Committee.

11.6    Waivers. Failure to strictly comply with any term, condition or requirement set forth in the Plan shall not be deemed a waiver of such term, condition or requirement, nor shall any waiver of any such term, condition or requirement at any one time or times be deemed to result in a waiver of such term, condition or requirement at any other time or times.

11.7    Gender and Number. Masculine pronouns include the feminine as well as the neuter genders, and the singular shall include the plural, unless indicated otherwise by the context.

11.8    Headings. The headings of the Plan are for purposes of reference only and shall not limit or otherwise affect the meaning hereof.

* * *
/s/ Margaret M. Pego	7/21/2016
Signature	Date

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SCHEDULE A

As Amended as of July 19, 2016

PARTICIPANTS

NAME	TITLE	PARTICIPATION DATE
Stuart J. Black	VP and Controller	03/01/10
Jorge L. Cardenas	VP - Asset Management and Centralized Services, PSE&G	1/23/07
Rose M. Chernick	VP - Finance Holdings & Corporate Strategy & Planning	8/09/10
John Paul Cowan	SVP - Operations, PSEG Fossil	09/15/09
Lathrop B. Craig	VP - ISO Operations (ER&T)	09/05/11
Daniel J. Cregg	EVP & CFO, PSEG	12/09/06
David M. Daly	President and COO - PSEG Long Island	1/28/08
Paul J. Davison	VP - Hope Creek, PSEG Nuclear	12/14/09
Derek DiRisio	President - PSEG Services Corporation	12/20/04
Diana L. Drysdale	VP - Renewables	02/15/10
Kathleen Fitzgerald	VP - Corporate Communications	01/03/12
Joseph A. Forline	VP - Gas Operations	12/19/06
Carl J. Fricker	VP - Trading Support & Operations (ER&T)	12/14/09
Kim C. Hanemann	SVP - Delivery Projects and Construction	12/21/10
Bradford D. Huntington	VP & Treasurer	04/16/11
Scott Jennings	VP - Finance PSE&G	10/18/05
Robert C. Krueger, Jr	VP & Assistant Controller - Tax	12/19/06
Kathleen A. Lally	VP - Investor Relations	01/16/07
John R. Latka	SVP - Electric & Gas Operations, PSE&G	10/23/06
Shawn P. Leyden	VP and Deputy General Counsel	12/20/04
Tamara L. Linde	EVP and General Counsel	12/19/06
Kristen M. Ludecke	VP - Federal Affairs	02/22/10
Shahid Malik	President - Energy Resources & Trade (ER&T)	12/5/11
Christine T. Neely	VP - Internal Auditing Services	9/30/13
Margaret M. Pego	SVP - Human Resources & CHRO	12/20/04
John F. Perry	VP - Salem, PSEG Nuclear	09/15/09
Kevin J. Quinn	VP - Finance Power	03/01/10
Sheila J. Rostiac	VP - Total Rewards & Talent Management	08/20/12
Joseph Santamaria	VP - Information Technology & CIO	10/29/12
John P. Scarlata	VP - Gas Supply, PSEG ER&T	4/20/10
Richard T. Thigpen	VP - State Governmental Affairs	3/26/07

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SCHEDULE B

As Amended as of July 19, 2016

PARTICIPANTS

NAME	TITLE	PARTICIPATION DATE
Ralph Izzo	Chairman of the Board, President and CEO	12/15/08
Ralph A. LaRossa	President & COO - Public Service Electric and Gas Company, and COB, PSEG Long Island	10/17/06
William Levis	President & COO, PSEG Power LLC	01/01/07

28

SCHEDULE C

As Amended as of July 19, 2016

PARTICIPANTS

NAME	TITLE	PARTICIPATION DATE
John A. Bridges	VP Electric Operations	12/21/15
Kevin B. Cellars	VP Construction	2/17/15
Gregory Dunlap	VP Customer Operations - PSE&G	7/14/14
Aaron Ford	VP Business Assurance and Resilience	11/18/15
M. Courtney McCormick	VP Renewables and Energy Solutions	3/31/14
Laurent Pommier	VP Risk Management and Chief Risk Officer	7/14/14
Peter P. Sena III	President & CNO, PSEG Nuclear	3/21/16

29

EXHIBIT I

Form of Restrictive Covenant Agreement

AGREEMENT, by and between Public Service Enterprise Group Incorporated, a New Jersey Corporation (the “Company”) and [_________________] (“Executive”), dated as of [______________].

WHEREAS, the Company maintains the Key Executive Severance Plan of Public Service Enterprise Group Incorporated (the “Plan”), effective July 19, 2016, and as thereafter amended, modified or supplemented;

WHEREAS, Executive was designated as an Eligible Employee under the Plan by the Organization and Compensation Committee of the Company’s Board of Directors;

WHEREAS, pursuant to Section 3.2 of the Plan, in order to be a Participant in and be entitled to benefits and protections under the Plan, Executive must execute and delivery to the Company within 30 days after Executive was designated as an Eligible Employee a written agreement to be bound by the terms and conditions of certain covenants set out in Article VII of the Plan, which is hereby incorporated herein;

NOW THEREFORE, the parties agree as follows:

1.Executive has received a copy of the Plan and has read and understands the terms of conditions of Section 7.1, Confidentiality, Section 7.2, Non-Compete, and Section 7.3, Non-Solicitation, therein, as applied to Executive (the “Covenants”).

2.Executive agrees to be bound by and comply with the terms of the Covenants in consideration for becoming a Participant in the Plan.

3.Executive acknowledges that the Covenants are reasonable in the scope of the activities restricted, the geographic area covered by the restrictions, the duration of the restrictions, and that such Covenants are reasonably necessary to protect the Company’s legitimate interests in its Confidential Information and its relationships with its employees, customers and suppliers.

4.Executive acknowledges that the Covenants will not deprive Executive of the ability to earn a livelihood or to support Executive’s dependents.

5.Executive shall be a Participant in the Plan and be entitled to all of the rights and benefits provided thereunder as of the date of this Agreement.

6.This Agreement shall be construed and enforced in accordance with and governed by the internal substantive laws (and not the laws relating to conflict of laws or choice of laws) of the State of New Jersey, except to the extent that such laws are preempted by Federal law.

30

IN WITNESS WHEREOF, the parties have executed this Agreement as of the date and year first above written.

[This Agreement may be executed in counterparts.]

EXECUTIVE

PUBLIC SERVICE ENTERPRISE

GROUP INCORPORATED

By: _______________________

Title:_______________________

31

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,
	2016			2015			2015			2014			2013			2012			2011
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	1,032		$	1,515		$	2,680		$	2,456		$	2,055		$	2,011		$	2,384
(Income) Loss from Equity Investees, net of Distributions	3			2			3			4			(7		)	9			(4		)
Fixed Charges	232			223			457			450			458			479			522
Capitalized Interest	(19		)	(5		)	(18		)	(16		)	(16		)	(19		)	(14		)
Total Earnings	$	1,248		$	1,735		$	3,122		$	2,894		$	2,490		$	2,480		$	2,888
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	221		$	213		$	437		$	430		$	442		$	465		$	509
Interest Factor in Rentals	11			10			20			20			16			14			13
Total Fixed Charges	$	232		$	223		$	457		$	450		$	458		$	479		$	522
Ratio of Earnings to Fixed Charges	5.38			7.78			6.83			6.43			5.44			5.18			5.53

(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,
	2016			2015			2015			2014			2013			2012			2011
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	690		$	670		$	1,257		$	1,174		$	993		$	835		$	861
Fixed Charges	154			148			306			303			316			314			319
Capitalized Interest	(7		)	(8		)	(17		)	(16		)	(16		)	(13		)	(4		)
Total Earnings	$	837		$	810		$	1,546		$	1,461		$	1,293		$	1,136		$	1,176
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	149		$	144		$	297		$	293		$	309		$	308		$	314
Interest Factor in Rentals	5			4			9			10			7			6			5
Total Fixed Charges	$	154		$	148		$	306		$	303		$	316		$	314		$	319
Ratio of Earnings to Fixed Charges	5.44			5.47			5.05			4.82			4.09			3.62			3.69

(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 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, (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,
	2016			2015		2015			2014		2013			2012			2011
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	299		$	807	$	1,367		$	1,251	$	1,063		$	1,099		$	1,703
(Income) Loss from Equity Investees, net of Distributions	3			1		1			3		(10		)	(6		)	(12		)
Fixed Charges	69			78		152			150		143			164			208
Capitalized Interest	(12		)	2		(1		)	1		1			(6		)	(10		)
Total Earnings	$	359		$	888	$	1,519		$	1,405	$	1,197		$	1,251		$	1,889
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	67		$	75	$	148		$	146	$	139		$	161		$	205
Interest Factor in Rentals	2			3		4			4		4			3			3
Total Fixed Charges	$	69		$	78	$	152		$	150	$	143		$	164		$	208
Ratio of Earnings to Fixed Charges	5.20			11.38		9.99			9.37		8.37			7.63			9.08

(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.

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 29, 2016	/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 29, 2016	/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 29, 2016	/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 29, 2016	/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 29, 2016	/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 29, 2016	/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, 2016 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 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 29, 2016

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, 2016 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 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 29, 2016

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, 2016 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 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 29, 2016

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, 2016 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 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 29, 2016

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, 2016 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 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 29, 2016

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, 2016 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 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 29, 2016

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 19, 2016
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
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		505,916,520
PSE And G [Member]
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
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, 2016
Document Fiscal Year Focus	2016
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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating Revenues	$ 1,905	$ 2,314	$ 4,521	$ 5,449
Operating Expenses [Abstract]
Energy Costs	624	668	1,460	1,762
Operation and Maintenance	710	761	1,439	1,424
Depreciation and Amortization	224	317	448	647
Total Operating Expenses	1,558	1,746	3,347	3,833
OPERATING INCOME	347	568	1,174	1,616
Income from Equity Method Investments	4	4	6	7
Other Income	44	76	92	124
Other Deductions	(10)	(10)	(31)	(22)
Other-Than-Temporary Impairments	(10)	(10)	(20)	(15)
Interest Expense	(97)	(97)	(189)	(195)
INCOME BEFORE INCOME TAXES	278	531	1,032	1,515
Income Tax Expense	(91)	(186)	(374)	(584)
Net Income	$ 187	$ 345	$ 658	$ 931
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC (in shares)	505	506	505	506
DILUTED (in shares)	508	508	508	508
EARNINGS PER SHARE:
BASIC (in dollars per share)	$ 0.37	$ 0.68	$ 1.30	$ 1.84
DILUTED (in dollars per share)	0.37	0.68	1.30	1.83
DIVIDENDS PAID PER SHARE OF COMMON STOCK (in dollars per share)	$ 0.41	$ 0.39	$ 0.82	$ 0.78
PSE And G [Member]
Operating Revenues	$ 1,350	$ 1,466	$ 3,062	$ 3,468
Operating Expenses [Abstract]
Energy Costs	529	544	1,258	1,436
Operation and Maintenance	352	368	734	780
Depreciation and Amortization	136	234	275	481
Total Operating Expenses	1,017	1,146	2,267	2,697
OPERATING INCOME	333	320	795	771
Other Income	19	19	39	37
Other Deductions	(1)	(1)	(2)	(2)
Interest Expense	(74)	(67)	(142)	(136)
INCOME BEFORE INCOME TAXES	277	271	690	670
Income Tax Expense	(98)	(104)	(249)	(261)
Net Income	179	167	441	409
Power [Member]
Operating Revenues	714	1,025	2,027	2,750
Operating Expenses [Abstract]
Energy Costs	381	409	1,019	1,302
Operation and Maintenance	265	313	518	485
Depreciation and Amortization	80	75	159	151
Total Operating Expenses	726	797	1,696	1,938
OPERATING INCOME	(12)	228	331	812
Income from Equity Method Investments	4	5	6	8
Other Income	25	55	51	84
Other Deductions	(9)	(7)	(27)	(18)
Other-Than-Temporary Impairments	(10)	(10)	(20)	(15)
Interest Expense	(20)	(33)	(42)	(64)
INCOME BEFORE INCOME TAXES	(22)	238	299	807
Income Tax Expense	11	(72)	(118)	(306)
Net Income	$ (11)	$ 166	$ 181	$ 501

XML

Condensed Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Net Income	$ 187	$ 345	$ 658	$ 931
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit	10	(15)	26	(1)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit	(1)	0	1	(9)
Pension/Other Postretirement Benefit (OPEB) adjustment, net of tax (expense) benefit	8	8	16	16
Other Comprehensive Income (Loss), net of tax	17	(7)	43	6
COMPREHENSIVE INCOME	204	338	701	937
PSE And G [Member]
Net Income	179	167	441	409
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit	1	(1)	1	(1)
COMPREHENSIVE INCOME	180	166	442	408
Power [Member]
Net Income	(11)	166	181	501
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit	9	(14)	25	0
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit	0	0	0	(9)
Pension/Other Postretirement Benefit (OPEB) adjustment, net of tax (expense) benefit	7	7	14	14
Other Comprehensive Income (Loss), net of tax	16	(7)	39	5
COMPREHENSIVE INCOME	$ 5	$ 159	$ 220	$ 506

XML

Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Unrealized Gains (Losses) on Available-for-Sale Securities, tax	$ (10)	$ 15	$ (26)	$ 2
Unrealized Gains (Losses) on Cash Flow Hedges, tax	0	0	(1)	7
Pension/OPEB adjustment, tax	(6)	(6)	(12)	(12)
PSE And G [Member]
Unrealized Gains (Losses) on Available-for-Sale Securities, tax	0	0	0	0
Power [Member]
Unrealized Gains (Losses) on Available-for-Sale Securities, tax	(9)	14	(25)	1
Unrealized Gains (Losses) on Cash Flow Hedges, tax	0	0	0	7
Pension/OPEB adjustment, tax	$ (5)	$ (5)	$ (10)	$ (10)

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and Cash Equivalents		$ 648	$ 394
Accounts Receivable, net of allowances		988	1,068
Tax Receivable		4	305
Unbilled Revenues		202	197
Fuel		351	463
Materials and Supplies		554	513
Prepayments		271	135
Derivative Contracts		152	242
Regulatory Assets		310	164
Other		9	13
Total Current Assets		3,489	3,494
PROPERTY, PLANT AND EQUIPMENT		37,285	35,494
Less: Accumulated Depreciation and Amortization		(9,271)	(8,955)
Net Property, Plant and Equipment		28,014	26,539
NONCURRENT ASSETS
Regulatory Assets		3,120	3,196
Long-Term Investments		1,218	1,233
Nuclear Decommissioning Trust (NDT) Fund		1,797	1,754
Long-Term Tax Receivable		183	171
Long-Term Receivable of Variable Interest Entities (VIEs)		513	495
Other Special Funds		246	227
Goodwill		16	16
Other Intangibles		131	102
Derivative Contracts		76	77
Other		242	231
Total Noncurrent Assets		7,542	7,502
Total Assets		39,045	37,535
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		662	734
Commercial Paper and Loans		0	364
Accounts Payable		1,308	1,369
Derivative Contracts		20	76
Accrued Interest		103	96
Accrued Taxes		107	42
Clean Energy Program		200	142
Obligation to Return Cash Collateral		128	128
Regulatory Liabilities		74	123
Regulatory Liabilities of VIEs		22	42
Other		496	459
Total Current Liabilities		3,120	3,575
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		8,545	8,166
Regulatory Liabilities		165	175
Asset Retirement Obligations		693	679
OPEB Costs		1,199	1,228
OPEB Costs of Servco		389	375
Accrued Pension Costs		429	487
Accrued Pension Costs of Servco		118	114
Clean Energy Program Noncurrent		27	0
Environmental Costs		402	415
Derivative Contracts		14	27
Long-Term Accrued Taxes		171	212
Other		181	181
Total Noncurrent Liabilities		12,333	12,059
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		10,273	8,834
STOCKHOLDER'S EQUITY
Common Stock		4,919	4,915
Treasury Stock, at cost		(709)	(671)
Retained Earnings		9,360	9,117
Accumulated Other Comprehensive Income (Loss)		(252)	(295)
Total Common Stockholders' Equity		13,318	13,066
Noncontrolling Interest		1	1
Total Stockholder's Equity		13,319	13,067
Total Capitalization		23,592	21,901
TOTAL LIABILITIES AND CAPITALIZATION		39,045	37,535
PSE And G [Member]
CURRENT ASSETS
Cash and Cash Equivalents		168	198
Accounts Receivable, net of allowances		736	787
Accounts Receivable-Affiliated Companies		0	222
Unbilled Revenues		202	197
Materials and Supplies		162	148
Prepayments		196	31
Derivative Contracts		0	13
Regulatory Assets		310	164
Other		8	9
Total Current Assets		1,782	1,769
PROPERTY, PLANT AND EQUIPMENT		24,976	23,732
Less: Accumulated Depreciation and Amortization		(5,627)	(5,504)
Net Property, Plant and Equipment		19,349	18,228
NONCURRENT ASSETS
Regulatory Assets		3,120	3,196
Long-Term Investments		316	330
Other Special Funds		57	49
Other		113	105
Total Noncurrent Assets		3,606	3,680
Total Assets		24,737	23,677
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		100	171
Commercial Paper and Loans		0	153
Accounts Payable		680	724
Accounts Payable-Affiliated Companies		179	292
Derivative Contracts		2	0
Accrued Interest		73	70
Clean Energy Program		200	142
Obligation to Return Cash Collateral		127	128
Regulatory Liabilities		74	123
Regulatory Liabilities of VIEs		22	42
Other		339	297
Total Current Liabilities		1,796	2,142
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		5,503	5,181
Regulatory Liabilities		165	175
Asset Retirement Obligations		220	218
OPEB Costs		904	937
Accrued Pension Costs		165	202
Clean Energy Program Noncurrent		27	0
Environmental Costs		336	365
Derivative Contracts		0	11
Long-Term Accrued Taxes		99	109
Other		113	114
Total Noncurrent Liabilities		7,532	7,312
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		7,394	6,650
STOCKHOLDER'S EQUITY
Common Stock		892	892
Contributed Capital		695	695
Basis Adjustment		986	986
Retained Earnings		5,440	4,999
Accumulated Other Comprehensive Income (Loss)		2	1
Total Stockholder's Equity		8,015	7,573
Total Capitalization		15,409	14,223
TOTAL LIABILITIES AND CAPITALIZATION		24,737	23,677
Power [Member]
CURRENT ASSETS
Cash and Cash Equivalents		16	12
Accounts Receivable, net of allowances		202	217
Accounts Receivable-Affiliated Companies		94	276
Short-Term Loan to Affiliate		1,335	363
Fuel		351	463
Materials and Supplies		389	363
Prepayments		7	25
Derivative Contracts	[1]	150	223
Other		4	7
Total Current Assets		2,548	1,949
PROPERTY, PLANT AND EQUIPMENT		11,969	11,354
Less: Accumulated Depreciation and Amortization		(3,491)	(3,227)
Net Property, Plant and Equipment		8,478	8,127
NONCURRENT ASSETS
Long-Term Investments		112	119
Nuclear Decommissioning Trust (NDT) Fund		1,797	1,754
Other Special Funds		60	55
Goodwill		16	16
Other Intangibles		131	102
Derivative Contracts	[1]	76	77
Other		60	51
Total Noncurrent Assets		2,252	2,174
Total Assets		13,278	12,250
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		553	553
Accounts Payable		466	432
Accounts Payable-Affiliated Companies		102	33
Derivative Contracts	[1]	17	76
Accrued Interest		29	25
Other		96	107
Total Current Liabilities		1,263	1,226
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		2,418	2,347
Asset Retirement Obligations		470	457
OPEB Costs		234	230
Accrued Pension Costs		151	166
Derivative Contracts	[1]	14	16
Long-Term Accrued Taxes		22	35
Other		104	87
Total Noncurrent Liabilities		3,413	3,338
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		2,380	1,684
STOCKHOLDER'S EQUITY
Contributed Capital		2,214	2,214
Basis Adjustment		(986)	(986)
Retained Earnings		5,195	5,014
Accumulated Other Comprehensive Income (Loss)		(201)	(240)
Total Stockholder's Equity		6,222	6,002
TOTAL LIABILITIES AND CAPITALIZATION		$ 13,278	$ 12,250

[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, 2016 and December 31, 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

XML

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Accounts Receivable, allowances	$ 65	$ 67
Common Stock, issued	534	534
Common Stock, authorized	1,000	1,000
Treasury Stock, Shares	29	28
PSE And G [Member]
Accounts Receivable, allowances	$ 65	$ 67
Common Stock, issued	132	132
Common Stock, outstanding	132	132
Common Stock, authorized	150	150

XML

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$ 658	$ 931
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	448	647
Amortization of Nuclear Fuel	105	106
Provision for Deferred Income Taxes and ITC	334	170
Non-Cash Employee Benefit Plan Costs	63	81
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(30)	(22)
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	153	(9)
Change in Accrued Storm Costs	(1)	15
Net Change in Other Regulatory Assets and Liabilities	(124)	(53)
Cost of Removal	(74)	(58)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(2)	(21)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	301	188
Accrued Taxes	94	71
Margin Deposit	(46)	69
Other Current Assets and Liabilities	(120)	98
Employee Benefit Plan Funding and Related Payments	(78)	(67)
Other	41	88
Net Cash Provided By (Used In) Operating Activities	1,722	2,234
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,971)	(1,743)
Proceeds from Sale of Available-for-Sale Securities	392	885
Investments in Available-for-Sale Securities	(407)	(918)
Other	(18)	3
Net Cash Provided By (Used In) Investing Activities	(2,004)	(1,773)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(364)	0
Issuance of Long-Term Debt	1,550	600
Redemption of Long-Term Debt	(171)	(300)
Redemption of Securitization Debt	0	(125)
Cash Dividends Paid on Common Stock	(415)	(394)
Other	(64)	(47)
Net Cash Provided By (Used In) Financing Activities	536	(266)
Net Increase (Decrease) In Cash and Cash Equivalents	254	195
Cash and Cash Equivalents at Beginning of Period	394	402
Cash and Cash Equivalents at End of Period	648	597
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	(276)	184
Interest Paid, Net of Amounts Capitalized	176	195
Accrued Property, Plant and Equipment Expenditures	513	324
PSE And G [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	441	409
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	275	481
Provision for Deferred Income Taxes and ITC	290	79
Non-Cash Employee Benefit Plan Costs	36	48
Change in Accrued Storm Costs	(1)	15
Net Change in Other Regulatory Assets and Liabilities	(124)	(53)
Cost of Removal	(74)	(58)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	50	53
Fuel, Materials and Supplies	(14)	(10)
Prepayments	(165)	(162)
Accounts Payable	(29)	48
Accounts Receivable/Payable-Affiliated Companies, net	181	154
Other Current Assets and Liabilities	17	(27)
Employee Benefit Plan Funding and Related Payments	(62)	(55)
Other	(13)	(13)
Net Cash Provided By (Used In) Operating Activities	808	909
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,355)	(1,230)
Proceeds from Sale of Available-for-Sale Securities	12	12
Investments in Available-for-Sale Securities	(13)	(14)
Other	2	12
Net Cash Provided By (Used In) Investing Activities	(1,354)	(1,220)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	(153)	0
Issuance of Long-Term Debt	850	600
Redemption of Long-Term Debt	(171)	(300)
Redemption of Securitization Debt	0	(125)
Other	(10)	(8)
Net Cash Provided By (Used In) Financing Activities	516	167
Net Increase (Decrease) In Cash and Cash Equivalents	(30)	(144)
Cash and Cash Equivalents at Beginning of Period	198	310
Cash and Cash Equivalents at End of Period	168	166
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	(255)	(74)
Interest Paid, Net of Amounts Capitalized	134	131
Accrued Property, Plant and Equipment Expenditures	381	282
Power [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	181	501
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	159	151
Amortization of Nuclear Fuel	105	106
Provision for Deferred Income Taxes and ITC	37	64
Non-Cash Employee Benefit Plan Costs	19	24
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	153	(9)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(2)	(21)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	86	209
Margin Deposit	(46)	69
Accounts Receivable	(12)	76
Accounts Payable	(10)	(62)
Accounts Receivable/Payable-Affiliated Companies, net	179	123
Other Current Assets and Liabilities	11	(21)
Employee Benefit Plan Funding and Related Payments	(10)	(7)
Other	67	89
Net Cash Provided By (Used In) Operating Activities	917	1,292
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(598)	(487)
Proceeds from Sale of Available-for-Sale Securities	346	837
Investments in Available-for-Sale Securities	(359)	(854)
Short-Term Loan-Affiliated Company, net	(972)	(366)
Other	(24)	(17)
Net Cash Provided By (Used In) Investing Activities	(1,607)	(887)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	700	0
Cash Dividends Paid on Common Stock	0	(400)
Other	(6)	(2)
Net Cash Provided By (Used In) Financing Activities	694	(402)
Net Increase (Decrease) In Cash and Cash Equivalents	4	3
Cash and Cash Equivalents at Beginning of Period	12	9
Cash and Cash Equivalents at End of Period	16	12
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	(53)	218
Interest Paid, Net of Amounts Capitalized	38	62
Accrued Property, Plant and Equipment Expenditures	$ 132	$ 42

XML

Organization and Basis of Presentation

6 Months Ended

Jun. 30, 2016

Organization and Basis of Presentation

Organization and Basis of Presentation

Organization

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:

• 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.

• Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. 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) 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, 2015.

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, 2015.

PSE And G [Member]

Organization and Basis of Presentation

Organization and Basis of Presentation

Organization

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:

• 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.

• Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. 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) 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, 2015.

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, 2015.

Power [Member]

Organization and Basis of Presentation

Organization and Basis of Presentation

Organization

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:

• 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.

• Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. 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) 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, 2015.

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, 2015.

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Recent Accounting Standards

6 Months Ended

Jun. 30, 2016

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 was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements.

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 is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (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.

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.

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.

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. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. 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.

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 was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements.

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 is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (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.

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.

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.

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. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. 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.

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 was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements.

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 is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (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.

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.

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.

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. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. 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.

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Variable Interest Entities (VIEs)

6 Months Ended

Jun. 30, 2016

Variable Interest Entity [Line Items]

Variable Interest Entities (VIEs)

Variable Interest Entities (VIEs)

VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which was pledged as collateral to a trustee. PSE&G acted as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds were remitted to Transition Funding and Transition Funding II and were used for interest and principal payments on the transition bonds and related costs. During 2015, Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained with these VIEs. Effective January 1, 2016, PSE&G commenced refunding the overcollections from customers associated with these VIEs and expects to fully refund these liabilities in 2016.

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 Operation and Maintenance (O&M) Expense, respectively. Servco recorded $101 million and $84 million for the three months and $199 million and $166 million for the six months ended June 30, 2016 and 2015, 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.

PSE And G [Member]

Variable Interest Entity [Line Items]

Variable Interest Entities (VIEs)

Variable Interest Entities (VIEs)

VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which was pledged as collateral to a trustee. PSE&G acted as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds were remitted to Transition Funding and Transition Funding II and were used for interest and principal payments on the transition bonds and related costs. During 2015, Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained with these VIEs. Effective January 1, 2016, PSE&G commenced refunding the overcollections from customers associated with these VIEs and expects to fully refund these liabilities in 2016.

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 Operation and Maintenance (O&M) Expense, respectively. Servco recorded $101 million and $84 million for the three months and $199 million and $166 million for the six months ended June 30, 2016 and 2015, 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, 2016

Regulatory Assets [Line Items]

Rate Filings

Rate Filings

This Note should be read in conjunction with Note 5. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

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:

Remediation Adjustment Charge (RAC)—In April 2016, the BPU approved PSE&G's filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015.

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 2016, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million, respectively. The petition requests rates to be effective September 1, 2016, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.

Basic Gas Supply Service (BGSS)—In June 2016, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $87 million in annual BGSS revenues. If approved, the BGSS rate would be reduced from approximately 40 cents to 34 cents per therm effective October 1, 2016. This matter is pending.

Transmission Formula Rate Filings—In June 2016, PSE&G filed its 2015 true-up adjustment pertaining to its transmission formula rates in effect for 2015. This resulted in an adjustment of $34 million less than the 2015 originally filed revenues primarily due to the impact of bonus depreciation legislation enacted after PSE&G filed its 2015 formula rate requirement in October 2014. PSE&G had recognized the majority of this adjustment in its Consolidated Statement of Operations for the year ended December 31, 2015.

Weather Normalization Clause—On July 1, 2016, PSE&G filed a petition requesting approval to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period. The deficiency gas revenues would be collected from customers over the 2016-2017 and 2017-2018 Winter Periods (October 1 through May 31). This matter is pending.

Solar and Energy Efficiency - 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. On July 1, 2016, PSE&G filed its 2016 GPRC cost recovery petition requesting recovery for the nine combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2016 through September 30, 2017 designed to recover approximately $44 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.

Gas System Modernization Program (GSMP)—On July 29, 2016, PSE&G filed its initial annual GSMP cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $13 million effective January 1, 2017. This increase represents the return of and on investment for GSMP investments expected to be in service through September 30, 2016. This request will be updated in October 2016 for actual costs.

PSE And G [Member]

Regulatory Assets [Line Items]

Rate Filings

Rate Filings

This Note should be read in conjunction with Note 5. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

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:

Remediation Adjustment Charge (RAC)—In April 2016, the BPU approved PSE&G's filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015.

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 2016, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million, respectively. The petition requests rates to be effective September 1, 2016, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.

Basic Gas Supply Service (BGSS)—In June 2016, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $87 million in annual BGSS revenues. If approved, the BGSS rate would be reduced from approximately 40 cents to 34 cents per therm effective October 1, 2016. This matter is pending.

Transmission Formula Rate Filings—In June 2016, PSE&G filed its 2015 true-up adjustment pertaining to its transmission formula rates in effect for 2015. This resulted in an adjustment of $34 million less than the 2015 originally filed revenues primarily due to the impact of bonus depreciation legislation enacted after PSE&G filed its 2015 formula rate requirement in October 2014. PSE&G had recognized the majority of this adjustment in its Consolidated Statement of Operations for the year ended December 31, 2015.

Weather Normalization Clause—On July 1, 2016, PSE&G filed a petition requesting approval to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period. The deficiency gas revenues would be collected from customers over the 2016-2017 and 2017-2018 Winter Periods (October 1 through May 31). This matter is pending.

Solar and Energy Efficiency - 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. On July 1, 2016, PSE&G filed its 2016 GPRC cost recovery petition requesting recovery for the nine combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2016 through September 30, 2017 designed to recover approximately $44 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.

Gas System Modernization Program (GSMP)—On July 29, 2016, PSE&G filed its initial annual GSMP cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $13 million effective January 1, 2017. This increase represents the return of and on investment for GSMP investments expected to be in service through September 30, 2016. This request will be updated in October 2016 for actual costs.

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Financing Receivables

6 Months Ended

Jun. 30, 2016

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, 2016		December 31, 2015
	Millions
Commercial/Industrial	$	174	$	177
Residential	12		12
Total	$	186	$	189

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’ investments in the leases are comprised of the total expected lease receivables on its investments 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. 

The following table shows Energy Holdings’ gross and net lease investment as of June 30, 2016 and December 31, 2015, respectively.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	630		$	631
Estimated Residual Value of Leased Assets	519			519
Total Investment in Rental Receivables	1,149			1,150
Unearned and Deferred Income	(359		)	(366		)
Gross Investment in Leases	790			784
Deferred Tax Liabilities	(694		)	(724		)
Net Investment in Leases	$	96		$	60

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, 2016
	As of June 30, 2016
	Millions
AA	$	16
BBB+ — BBB-	316
BB-	134
CCC	164
Total	$	630

The “BB-” and the "CCC" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of June 30, 2016, the gross investment in the leases of such assets, net of non-recourse debt, was $573 million ($(5) million, net of deferred taxes). A more detailed description of such assets under lease, as of June 30, 2016, 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	$	84	64	%	1,044	Coal (A)	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC (C)	NRG REMA, LLC
Conemaugh Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC (C)	NRG REMA, LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	113	100	%	603	Coal (B)	CCC (C)	NRG REMA, LLC

(A) The Joliet facility is currently in the process of converting to natural gas.

(B) NRG REMA, LLC (NRG REMA) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the fall of 2016 with the ability to use natural gas.

(C) On May 24, 2016, S&P lowered its corporate credit rating on GenOn Energy Inc. and affiliates (including NRG REMA) to "CCC" from "CCC+" due to a weaker forward power curve, milder weather patterns and weakening financial measures. PSEG continues to monitor any changes to GenOn's status and potential impacts on Energy Holdings' lease investments.

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. 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 attempt to 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 investments and trigger certain material tax obligations which could be mitigated by tax indemnification claims with 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. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities to the Internal Revenue Service.

Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which 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 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, 2016		December 31, 2015
	Millions
Commercial/Industrial	$	174	$	177
Residential	12		12
Total	$	186	$	189

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’ investments in the leases are comprised of the total expected lease receivables on its investments 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. 

The following table shows Energy Holdings’ gross and net lease investment as of June 30, 2016 and December 31, 2015, respectively.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	630		$	631
Estimated Residual Value of Leased Assets	519			519
Total Investment in Rental Receivables	1,149			1,150
Unearned and Deferred Income	(359		)	(366		)
Gross Investment in Leases	790			784
Deferred Tax Liabilities	(694		)	(724		)
Net Investment in Leases	$	96		$	60

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, 2016
	As of June 30, 2016
	Millions
AA	$	16
BBB+ — BBB-	316
BB-	134
CCC	164
Total	$	630

The “BB-” and the "CCC" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of June 30, 2016, the gross investment in the leases of such assets, net of non-recourse debt, was $573 million ($(5) million, net of deferred taxes). A more detailed description of such assets under lease, as of June 30, 2016, 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	$	84	64	%	1,044	Coal (A)	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC (C)	NRG REMA, LLC
Conemaugh Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC (C)	NRG REMA, LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	113	100	%	603	Coal (B)	CCC (C)	NRG REMA, LLC

(A) The Joliet facility is currently in the process of converting to natural gas.

(B) NRG REMA, LLC (NRG REMA) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the fall of 2016 with the ability to use natural gas.

(C) On May 24, 2016, S&P lowered its corporate credit rating on GenOn Energy Inc. and affiliates (including NRG REMA) to "CCC" from "CCC+" due to a weaker forward power curve, milder weather patterns and weakening financial measures. PSEG continues to monitor any changes to GenOn's status and potential impacts on Energy Holdings' lease investments.

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. 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 attempt to 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 investments and trigger certain material tax obligations which could be mitigated by tax indemnification claims with 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. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities to the Internal Revenue Service.

Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which 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 the quality and condition of assets under lease.

XML

Available-for-Sale Securities

6 Months Ended

Jun. 30, 2016

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 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 trust funds are managed by third party investment advisers 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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	679	$	198	$	(12	)	$	865
Debt Securities
Government Obligations	503		23		—			526
Other	348		12		(3		)	357
Total Debt Securities	851		35		(3		)	883
Other Securities	49		—		—			49
Total NDT Available-for-Sale Securities	$	1,579	$	233	$	(15	)	$	1,797

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	693	$	185	$	(13	)	$	865
Debt Securities
Government Obligations	483		8		(3		)	488
Other	366		3		(10		)	359
Total Debt Securities	849		11		(13		)	847
Other Securities	42		—		—			42
Total NDT Available-for-Sale Securities	$	1,584	$	196	$	(26	)	$	1,754

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	18	$	17
Accounts Payable	$	10	$	10

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, 2016										As of December 31, 2015
	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)	$	108	$	(12	)	$	5	$	—		$	151	$	(13	)	$	1	$	—
Debt Securities
Government Obligations (B)	12		—			6		—			245		(2		)	19		(1		)
Other (C)	12		—			43		(3		)	222		(7		)	36		(3		)
Total Debt Securities	24		—			49		(3		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	132	$	(12	)	$	54	$	(3	)	$	618	$	(22	)	$	56	$	(4	)

(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, 2016.

(B) Debt Securities (Government Obligations)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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,
	2016			2015			2016			2015
	Millions
Proceeds from NDT Fund Sales (A)	$	154		$	232		$	331		$	822
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	10			14			25			33
Gross Realized Losses	(6		)	(4		)	(22		)	(13		)
Net Realized Gains (Losses) on NDT Fund	$	4		$	10		$	3		$	20

(A) 2015 proceeds include 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 $110 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of June 30, 2016.

The NDT available-for-sale debt securities held as of June 30, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	19
1 - 5 years	216
6 - 10 years	220
11 - 15 years	54
16 - 20 years	61
Over 20 years	313
Total NDT Available-for-Sale Debt Securities	$	883

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, 2016, other-than-temporary impairments of $20 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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	10	$	—		$	21
Debt Securities
Government Obligations	104		2		—			106
Other	90		1		(1		)	90
Total Debt Securities	194		3		(1		)	196
Other Securities	5		—		—			5
Total Rabbi Trust Available-for-Sale Securities	$	210	$	13	$	(1	)	$	222

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	10	$	—		$	22
Debt Securities
Government Obligations	108		1		(1		)	108
Other	82		—		(1		)	81
Total Debt Securities	190		1		(2		)	189
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	204	$	11	$	(2	)	$	213

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	2	$	1
Accounts Payable	$	4	$	—

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

	As of June 30, 2016									As of December 31, 2015
	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 Obligations (B)	14		—		3		—			53		(1		)	2		—
Other (C)	14		—		11		(1		)	46		(1		)	9		—
Total Debt Securities	28		—		14		(1		)	99		(2		)	11		—
Rabbi Trust Available-for-Sale Securities	$	28	$	—	$	14	$	(1	)	$	99	$	(2	)	$	11	$	—

(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 Obligations)—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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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,
	2016			2015		2016			2015
	Millions
Proceeds from Rabbi Trust Sales (A)	$	36		$	44	$	61		$	63
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2	$	3		$	2
Gross Realized Losses	(1		)	—		(2		)	—
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	2	$	1		$	2

(A) 2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers.

Gross realized gains disclosed in the preceding table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of $7 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of June 30, 2016.

The Rabbi Trust available-for-sale debt securities held as of June 30, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	8
1 - 5 years	45
6 - 10 years	48
11 - 15 years	6
16 - 20 years	7
Over 20 years	82
Total Rabbi Trust Available-for-Sale Debt Securities	$	196

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 a commingled 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). 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 assets in the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:

	As of		As of
	June 30, 2016		December 31, 2015
	Millions
PSE&G	$	44	$	42
Power	54		52
Other	124		119
Total Rabbi Trust Available-for-Sale Securities	$	222	$	213

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 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 trust funds are managed by third party investment advisers 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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	679	$	198	$	(12	)	$	865
Debt Securities
Government Obligations	503		23		—			526
Other	348		12		(3		)	357
Total Debt Securities	851		35		(3		)	883
Other Securities	49		—		—			49
Total NDT Available-for-Sale Securities	$	1,579	$	233	$	(15	)	$	1,797

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	693	$	185	$	(13	)	$	865
Debt Securities
Government Obligations	483		8		(3		)	488
Other	366		3		(10		)	359
Total Debt Securities	849		11		(13		)	847
Other Securities	42		—		—			42
Total NDT Available-for-Sale Securities	$	1,584	$	196	$	(26	)	$	1,754

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	18	$	17
Accounts Payable	$	10	$	10

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, 2016										As of December 31, 2015
	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)	$	108	$	(12	)	$	5	$	—		$	151	$	(13	)	$	1	$	—
Debt Securities
Government Obligations (B)	12		—			6		—			245		(2		)	19		(1		)
Other (C)	12		—			43		(3		)	222		(7		)	36		(3		)
Total Debt Securities	24		—			49		(3		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	132	$	(12	)	$	54	$	(3	)	$	618	$	(22	)	$	56	$	(4	)

(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, 2016.

(B) Debt Securities (Government Obligations)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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,
	2016			2015			2016			2015
	Millions
Proceeds from NDT Fund Sales (A)	$	154		$	232		$	331		$	822
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	10			14			25			33
Gross Realized Losses	(6		)	(4		)	(22		)	(13		)
Net Realized Gains (Losses) on NDT Fund	$	4		$	10		$	3		$	20

(A) 2015 proceeds include 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 $110 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of June 30, 2016.

The NDT available-for-sale debt securities held as of June 30, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	19
1 - 5 years	216
6 - 10 years	220
11 - 15 years	54
16 - 20 years	61
Over 20 years	313
Total NDT Available-for-Sale Debt Securities	$	883

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, 2016, other-than-temporary impairments of $20 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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	10	$	—		$	21
Debt Securities
Government Obligations	104		2		—			106
Other	90		1		(1		)	90
Total Debt Securities	194		3		(1		)	196
Other Securities	5		—		—			5
Total Rabbi Trust Available-for-Sale Securities	$	210	$	13	$	(1	)	$	222

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	10	$	—		$	22
Debt Securities
Government Obligations	108		1		(1		)	108
Other	82		—		(1		)	81
Total Debt Securities	190		1		(2		)	189
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	204	$	11	$	(2	)	$	213

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	2	$	1
Accounts Payable	$	4	$	—

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

	As of June 30, 2016									As of December 31, 2015
	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 Obligations (B)	14		—		3		—			53		(1		)	2		—
Other (C)	14		—		11		(1		)	46		(1		)	9		—
Total Debt Securities	28		—		14		(1		)	99		(2		)	11		—
Rabbi Trust Available-for-Sale Securities	$	28	$	—	$	14	$	(1	)	$	99	$	(2	)	$	11	$	—

(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 Obligations)—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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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,
	2016			2015		2016			2015
	Millions
Proceeds from Rabbi Trust Sales (A)	$	36		$	44	$	61		$	63
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2	$	3		$	2
Gross Realized Losses	(1		)	—		(2		)	—
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	2	$	1		$	2

(A) 2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers.

Gross realized gains disclosed in the preceding table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of $7 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of June 30, 2016.

The Rabbi Trust available-for-sale debt securities held as of June 30, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	8
1 - 5 years	45
6 - 10 years	48
11 - 15 years	6
16 - 20 years	7
Over 20 years	82
Total Rabbi Trust Available-for-Sale Debt Securities	$	196

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 a commingled 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). 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 assets in the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:

	As of		As of
	June 30, 2016		December 31, 2015
	Millions
PSE&G	$	44	$	42
Power	54		52
Other	124		119
Total Rabbi Trust Available-for-Sale Securities	$	222	$	213

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 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 trust funds are managed by third party investment advisers 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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	679	$	198	$	(12	)	$	865
Debt Securities
Government Obligations	503		23		—			526
Other	348		12		(3		)	357
Total Debt Securities	851		35		(3		)	883
Other Securities	49		—		—			49
Total NDT Available-for-Sale Securities	$	1,579	$	233	$	(15	)	$	1,797

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	693	$	185	$	(13	)	$	865
Debt Securities
Government Obligations	483		8		(3		)	488
Other	366		3		(10		)	359
Total Debt Securities	849		11		(13		)	847
Other Securities	42		—		—			42
Total NDT Available-for-Sale Securities	$	1,584	$	196	$	(26	)	$	1,754

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	18	$	17
Accounts Payable	$	10	$	10

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, 2016										As of December 31, 2015
	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)	$	108	$	(12	)	$	5	$	—		$	151	$	(13	)	$	1	$	—
Debt Securities
Government Obligations (B)	12		—			6		—			245		(2		)	19		(1		)
Other (C)	12		—			43		(3		)	222		(7		)	36		(3		)
Total Debt Securities	24		—			49		(3		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	132	$	(12	)	$	54	$	(3	)	$	618	$	(22	)	$	56	$	(4	)

(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, 2016.

(B) Debt Securities (Government Obligations)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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,
	2016			2015			2016			2015
	Millions
Proceeds from NDT Fund Sales (A)	$	154		$	232		$	331		$	822
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	10			14			25			33
Gross Realized Losses	(6		)	(4		)	(22		)	(13		)
Net Realized Gains (Losses) on NDT Fund	$	4		$	10		$	3		$	20

(A) 2015 proceeds include 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 $110 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of June 30, 2016.

The NDT available-for-sale debt securities held as of June 30, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	19
1 - 5 years	216
6 - 10 years	220
11 - 15 years	54
16 - 20 years	61
Over 20 years	313
Total NDT Available-for-Sale Debt Securities	$	883

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, 2016, other-than-temporary impairments of $20 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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	10	$	—		$	21
Debt Securities
Government Obligations	104		2		—			106
Other	90		1		(1		)	90
Total Debt Securities	194		3		(1		)	196
Other Securities	5		—		—			5
Total Rabbi Trust Available-for-Sale Securities	$	210	$	13	$	(1	)	$	222

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	10	$	—		$	22
Debt Securities
Government Obligations	108		1		(1		)	108
Other	82		—		(1		)	81
Total Debt Securities	190		1		(2		)	189
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	204	$	11	$	(2	)	$	213

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	2	$	1
Accounts Payable	$	4	$	—

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

	As of June 30, 2016									As of December 31, 2015
	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 Obligations (B)	14		—		3		—			53		(1		)	2		—
Other (C)	14		—		11		(1		)	46		(1		)	9		—
Total Debt Securities	28		—		14		(1		)	99		(2		)	11		—
Rabbi Trust Available-for-Sale Securities	$	28	$	—	$	14	$	(1	)	$	99	$	(2	)	$	11	$	—

(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 Obligations)—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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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,
	2016			2015		2016			2015
	Millions
Proceeds from Rabbi Trust Sales (A)	$	36		$	44	$	61		$	63
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2	$	3		$	2
Gross Realized Losses	(1		)	—		(2		)	—
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	2	$	1		$	2

(A) 2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers.

Gross realized gains disclosed in the preceding table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of $7 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of June 30, 2016.

The Rabbi Trust available-for-sale debt securities held as of June 30, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	8
1 - 5 years	45
6 - 10 years	48
11 - 15 years	6
16 - 20 years	7
Over 20 years	82
Total Rabbi Trust Available-for-Sale Debt Securities	$	196

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 a commingled 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). 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 assets in the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:

	As of		As of
	June 30, 2016		December 31, 2015
	Millions
PSE&G	$	44	$	42
Power	54		52
Other	124		119
Total Rabbi Trust Available-for-Sale Securities	$	222	$	213

XML

Pension and OPEB

6 Months Ended

Jun. 30, 2016

Defined Benefit Plan Disclosure [Line Items]

Pension and Other Postretirement Benefits (OPEB)

Pension and Other Postretirement Benefits (OPEB)

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

Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change is being reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $8 million and $3 million, for the three months ended June 30, 2016 respectively, and $17 million and $6 million for the six months ended June 30, 2016, respectively, as compared to the 2016 amounts that would have been derived from applying PSEG's 2015 and prior years' methodology.

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.

Pension and OPEB costs for PSEG, except for 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,
	2016			2015			2016			2015			2016			2015			2016			2015
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	27		$	31		$	4		$	6		$	54		$	62		$	8		$	11
Interest Cost	51			58			14			17			101			117			29			34
Expected Return on Plan Assets	(99		)	(104		)	(7		)	(8		)	(197		)	(207		)	(15		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(4		)	(4		)	(4		)	(9		)	(9		)	(7		)	(7		)
Actuarial Loss	40			37			10			11			79			74			20			21
Total Benefit Costs	$	14		$	18		$	17		$	22		$	28		$	37		$	35		$	44

Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, except for 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,
	2016		2015		2016		2015		2016		2015		2016		2015
	Millions
PSE&G	$	7	$	10	$	11	$	14	$	14	$	20	$	22	$	28
Power	4		5		5		6		8		11		11		13
Other	3		3		1		2		6		6		2		3
Total Benefit Costs	$	14	$	18	$	17	$	22	$	28	$	37	$	35	$	44

During the three months ended March 31, 2016, PSEG contributed its entire planned contributions for the year 2016 of $21 million into its pension plans and $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 3. Variable Interest Entities. 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 $28 million into its pension plan during 2016. Servco's pension-related revenues and costs were $6 million and $7 million for the three months ended June 30, 2016 and 2015, respectively, and $12 million and $13 million for the six months ended June 30, 2016 and 2015, respectively. The OPEB-related revenues earned and costs incurred for each of the three months and six months ended June 30, 2016 and 2015 were immaterial.

PSE And G [Member]

Defined Benefit Plan Disclosure [Line Items]

Pension and Other Postretirement Benefits (OPEB)

Pension and Other Postretirement Benefits (OPEB)

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

Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change is being reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $8 million and $3 million, for the three months ended June 30, 2016 respectively, and $17 million and $6 million for the six months ended June 30, 2016, respectively, as compared to the 2016 amounts that would have been derived from applying PSEG's 2015 and prior years' methodology.

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.

Pension and OPEB costs for PSEG, except for 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,
	2016			2015			2016			2015			2016			2015			2016			2015
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	27		$	31		$	4		$	6		$	54		$	62		$	8		$	11
Interest Cost	51			58			14			17			101			117			29			34
Expected Return on Plan Assets	(99		)	(104		)	(7		)	(8		)	(197		)	(207		)	(15		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(4		)	(4		)	(4		)	(9		)	(9		)	(7		)	(7		)
Actuarial Loss	40			37			10			11			79			74			20			21
Total Benefit Costs	$	14		$	18		$	17		$	22		$	28		$	37		$	35		$	44

Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, except for 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,
	2016		2015		2016		2015		2016		2015		2016		2015
	Millions
PSE&G	$	7	$	10	$	11	$	14	$	14	$	20	$	22	$	28
Power	4		5		5		6		8		11		11		13
Other	3		3		1		2		6		6		2		3
Total Benefit Costs	$	14	$	18	$	17	$	22	$	28	$	37	$	35	$	44

During the three months ended March 31, 2016, PSEG contributed its entire planned contributions for the year 2016 of $21 million into its pension plans and $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 3. Variable Interest Entities. 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 $28 million into its pension plan during 2016. Servco's pension-related revenues and costs were $6 million and $7 million for the three months ended June 30, 2016 and 2015, respectively, and $12 million and $13 million for the six months ended June 30, 2016 and 2015, respectively. The OPEB-related revenues earned and costs incurred for each of the three months and six months ended June 30, 2016 and 2015 were immaterial.

Power [Member]

Defined Benefit Plan Disclosure [Line Items]

Pension and Other Postretirement Benefits (OPEB)

Pension and Other Postretirement Benefits (OPEB)

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

Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change is being reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $8 million and $3 million, for the three months ended June 30, 2016 respectively, and $17 million and $6 million for the six months ended June 30, 2016, respectively, as compared to the 2016 amounts that would have been derived from applying PSEG's 2015 and prior years' methodology.

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.

Pension and OPEB costs for PSEG, except for 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,
	2016			2015			2016			2015			2016			2015			2016			2015
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	27		$	31		$	4		$	6		$	54		$	62		$	8		$	11
Interest Cost	51			58			14			17			101			117			29			34
Expected Return on Plan Assets	(99		)	(104		)	(7		)	(8		)	(197		)	(207		)	(15		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(4		)	(4		)	(4		)	(9		)	(9		)	(7		)	(7		)
Actuarial Loss	40			37			10			11			79			74			20			21
Total Benefit Costs	$	14		$	18		$	17		$	22		$	28		$	37		$	35		$	44

Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, except for 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,
	2016		2015		2016		2015		2016		2015		2016		2015
	Millions
PSE&G	$	7	$	10	$	11	$	14	$	14	$	20	$	22	$	28
Power	4		5		5		6		8		11		11		13
Other	3		3		1		2		6		6		2		3
Total Benefit Costs	$	14	$	18	$	17	$	22	$	28	$	37	$	35	$	44

During the three months ended March 31, 2016, PSEG contributed its entire planned contributions for the year 2016 of $21 million into its pension plans and $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 3. Variable Interest Entities. 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 $28 million into its pension plan during 2016. Servco's pension-related revenues and costs were $6 million and $7 million for the three months ended June 30, 2016 and 2015, respectively, and $12 million and $13 million for the six months ended June 30, 2016 and 2015, respectively. The OPEB-related revenues earned and costs incurred for each of the three months and six months ended June 30, 2016 and 2015 were immaterial.

XML

Commitments and Contingent Liabilities

6 Months Ended

Jun. 30, 2016

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.

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.

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

• all 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. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Power is subject to

• counterparty collateral calls related to commodity contracts, and

• certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

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, 2016 and December 31, 2015.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Face Value of Outstanding Guarantees	$	1,809		$	1,734
Exposure under Current Guarantees	$	136		$	172
Letters of Credit Margin Posted	$	160		$	122
Letters of Credit Margin Received	$	130		$	192
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(4	)	$	(15	)
Net Broker Balance Deposited (Received)	$	30		$	(5	)
Additional Amounts Posted:
Other Letters of Credit	$	51		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. 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 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 had posted letters of credit to support Power's various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power's payment obligations related to its equity interest in the PennEast natural gas pipeline and 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.

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 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 contemplated 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 set forth various alternatives for remediating this portion of the Passaic River.

The CPG, which consisted of 53 members as of June 30, 2016, 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 for the preparation of the RI/FS is approximately $163 million, which the CPG continues to incur. Of the estimated $163 million, as of June 30, 2016, the CPG had spent approximately $150 million, of which PSE&G's and Power's combined share was approximately $11 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, 2016, 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 Chemicals 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, will voluntarily perform the remedial design for the ROD Remedy. If the EPA secures a commitment to perform the Remedial Design from OCC, the EPA plans to 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. "Major PRP" is undefined in the letter.

On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG's share of the costs.

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 $426 million and $491 million through2021, including its $46 million share for the Passaic River accrued as of June 30, 2016, as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $426 million as ofJune 30, 2016. Of this amount, $99 million was recorded in Other Current Liabilities and $327 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $426 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 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.

On May 19, 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. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule.

On June 10, 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 Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. On July 8, 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.

State permitting decisions could have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants, including Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1.0 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power's future capital requirements, financial condition or results of operations.

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act 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 current 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 late 2016.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. 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 will seek to operate BH3 through the current estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. 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.

Steam Electric Effluent Guidelines

On September 30, 2015, the EPA issued a new Effluent Guidelines Limitation 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. 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 Mercer and Bridgeport Harbor stations and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this 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.

Coal Combustion Residuals (CCRs)

On December 19, 2014, the EPA issued a final rule which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power's Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.

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 $335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78 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
	2013	2014	2015	2016
36-Month Terms Ending	May 2016	May 2017	May 2018	May 2019	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$92.18	$97.39	$99.54	$96.38

(A) Prices set in the 2016 BGS auction year became effective on June 1, 2016 when the 2013 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 17. 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 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom.

Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G's customers, Power can use the gas to supply its fossil generating stations.

Power also has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations.

As of June 30, 2016, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Power's Share of Commitments through 2020
	Millions
Nuclear Fuel
Uranium	$	454
Enrichment	$	358
Fabrication	$	180
Natural Gas	$	972
Coal	$	265

Regulatory Proceedings

FERC Compliance

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 continues to implement procedures to help mitigate the risk of similar issues occurring in the future.

During the three month period ended March 31, 2014, based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has responded to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.

PSEG is unable to reasonably estimate the range of possible loss for this matter; however, the amounts of potential disgorgement and other potential penalties that Power may incur span a wide range depending on the success of PSEG's legal arguments. These arguments include that Power’s energy market bids in a substantial majority of the hours were below the allowed rate under the Tariff and therefore any errors in those hours were immaterial and that it is unclear whether the quantity of the bids violated any legal requirement. If PSEG's legal arguments do not prevail in whole or in part with FERC or in ajudicial challenge that PSEG may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to PSEG’s and Power’s Consolidated Statements of Operations in the quarterly and annual periods in which they are recorded.

Nuclear Insurance Coverages

The following should be read in conjunction with Note 12. Commitments and Contingent Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

Based upon a review of its nuclear insurance, Power made changes to its Nuclear Electric Insurance Limited (NEIL) insurance coverage of the excess layer for property damage which became effective on April 1, 2016. The excess layer provides coverage above the primary layer of NEIL insurance coverage for property damage of $1.5 billion. For the excess layer at the Salem/Hope Creek site, Power purchased coverage for property damage of $300 million due to a nuclear event and $300 million due to a non-nuclear event. For the excess layer at the Peach Bottom site, Power purchased coverage for its ownership interest for property damage of $300 million due to a nuclear event. For the excess layer at the Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ownership interest of Power.

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.

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.

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

• all 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. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Power is subject to

• counterparty collateral calls related to commodity contracts, and

• certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

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, 2016 and December 31, 2015.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Face Value of Outstanding Guarantees	$	1,809		$	1,734
Exposure under Current Guarantees	$	136		$	172
Letters of Credit Margin Posted	$	160		$	122
Letters of Credit Margin Received	$	130		$	192
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(4	)	$	(15	)
Net Broker Balance Deposited (Received)	$	30		$	(5	)
Additional Amounts Posted:
Other Letters of Credit	$	51		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. 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 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 had posted letters of credit to support Power's various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power's payment obligations related to its equity interest in the PennEast natural gas pipeline and 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.

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 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 contemplated 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 set forth various alternatives for remediating this portion of the Passaic River.

The CPG, which consisted of 53 members as of June 30, 2016, 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 for the preparation of the RI/FS is approximately $163 million, which the CPG continues to incur. Of the estimated $163 million, as of June 30, 2016, the CPG had spent approximately $150 million, of which PSE&G's and Power's combined share was approximately $11 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, 2016, 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 Chemicals 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, will voluntarily perform the remedial design for the ROD Remedy. If the EPA secures a commitment to perform the Remedial Design from OCC, the EPA plans to 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. "Major PRP" is undefined in the letter.

On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG's share of the costs.

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 $426 million and $491 million through2021, including its $46 million share for the Passaic River accrued as of June 30, 2016, as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $426 million as ofJune 30, 2016. Of this amount, $99 million was recorded in Other Current Liabilities and $327 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $426 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 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.

On May 19, 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. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule.

On June 10, 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 Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. On July 8, 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.

State permitting decisions could have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants, including Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1.0 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power's future capital requirements, financial condition or results of operations.

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act 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 current 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 late 2016.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. 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 will seek to operate BH3 through the current estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. 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.

Steam Electric Effluent Guidelines

On September 30, 2015, the EPA issued a new Effluent Guidelines Limitation 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. 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 Mercer and Bridgeport Harbor stations and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this 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.

Coal Combustion Residuals (CCRs)

On December 19, 2014, the EPA issued a final rule which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power's Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.

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 $335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78 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
	2013	2014	2015	2016
36-Month Terms Ending	May 2016	May 2017	May 2018	May 2019	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$92.18	$97.39	$99.54	$96.38

(A) Prices set in the 2016 BGS auction year became effective on June 1, 2016 when the 2013 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 17. 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 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom.

Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G's customers, Power can use the gas to supply its fossil generating stations.

Power also has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations.

As of June 30, 2016, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Power's Share of Commitments through 2020
	Millions
Nuclear Fuel
Uranium	$	454
Enrichment	$	358
Fabrication	$	180
Natural Gas	$	972
Coal	$	265

Regulatory Proceedings

FERC Compliance

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 continues to implement procedures to help mitigate the risk of similar issues occurring in the future.

During the three month period ended March 31, 2014, based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has responded to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.

PSEG is unable to reasonably estimate the range of possible loss for this matter; however, the amounts of potential disgorgement and other potential penalties that Power may incur span a wide range depending on the success of PSEG's legal arguments. These arguments include that Power’s energy market bids in a substantial majority of the hours were below the allowed rate under the Tariff and therefore any errors in those hours were immaterial and that it is unclear whether the quantity of the bids violated any legal requirement. If PSEG's legal arguments do not prevail in whole or in part with FERC or in ajudicial challenge that PSEG may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to PSEG’s and Power’s Consolidated Statements of Operations in the quarterly and annual periods in which they are recorded.

Nuclear Insurance Coverages

The following should be read in conjunction with Note 12. Commitments and Contingent Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

Based upon a review of its nuclear insurance, Power made changes to its Nuclear Electric Insurance Limited (NEIL) insurance coverage of the excess layer for property damage which became effective on April 1, 2016. The excess layer provides coverage above the primary layer of NEIL insurance coverage for property damage of $1.5 billion. For the excess layer at the Salem/Hope Creek site, Power purchased coverage for property damage of $300 million due to a nuclear event and $300 million due to a non-nuclear event. For the excess layer at the Peach Bottom site, Power purchased coverage for its ownership interest for property damage of $300 million due to a nuclear event. For the excess layer at the Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ownership interest of Power.

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.

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.

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

• all 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. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Power is subject to

• counterparty collateral calls related to commodity contracts, and

• certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

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, 2016 and December 31, 2015.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Face Value of Outstanding Guarantees	$	1,809		$	1,734
Exposure under Current Guarantees	$	136		$	172
Letters of Credit Margin Posted	$	160		$	122
Letters of Credit Margin Received	$	130		$	192
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(4	)	$	(15	)
Net Broker Balance Deposited (Received)	$	30		$	(5	)
Additional Amounts Posted:
Other Letters of Credit	$	51		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. 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 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 had posted letters of credit to support Power's various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power's payment obligations related to its equity interest in the PennEast natural gas pipeline and 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.

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 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 contemplated 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 set forth various alternatives for remediating this portion of the Passaic River.

The CPG, which consisted of 53 members as of June 30, 2016, 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 for the preparation of the RI/FS is approximately $163 million, which the CPG continues to incur. Of the estimated $163 million, as of June 30, 2016, the CPG had spent approximately $150 million, of which PSE&G's and Power's combined share was approximately $11 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, 2016, 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 Chemicals 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, will voluntarily perform the remedial design for the ROD Remedy. If the EPA secures a commitment to perform the Remedial Design from OCC, the EPA plans to 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. "Major PRP" is undefined in the letter.

On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG's share of the costs.

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 $426 million and $491 million through2021, including its $46 million share for the Passaic River accrued as of June 30, 2016, as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $426 million as ofJune 30, 2016. Of this amount, $99 million was recorded in Other Current Liabilities and $327 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $426 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 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.

On May 19, 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. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule.

On June 10, 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 Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. On July 8, 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.

State permitting decisions could have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants, including Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1.0 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power's future capital requirements, financial condition or results of operations.

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act 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 current 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 late 2016.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. 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 will seek to operate BH3 through the current estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. 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.

Steam Electric Effluent Guidelines

On September 30, 2015, the EPA issued a new Effluent Guidelines Limitation 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. 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 Mercer and Bridgeport Harbor stations and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this 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.

Coal Combustion Residuals (CCRs)

On December 19, 2014, the EPA issued a final rule which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power's Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.

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 $335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78 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
	2013	2014	2015	2016
36-Month Terms Ending	May 2016	May 2017	May 2018	May 2019	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$92.18	$97.39	$99.54	$96.38

(A) Prices set in the 2016 BGS auction year became effective on June 1, 2016 when the 2013 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 17. 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 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom.

Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G's customers, Power can use the gas to supply its fossil generating stations.

Power also has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations.

As of June 30, 2016, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Power's Share of Commitments through 2020
	Millions
Nuclear Fuel
Uranium	$	454
Enrichment	$	358
Fabrication	$	180
Natural Gas	$	972
Coal	$	265

Regulatory Proceedings

FERC Compliance

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 continues to implement procedures to help mitigate the risk of similar issues occurring in the future.

During the three month period ended March 31, 2014, based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has responded to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.

PSEG is unable to reasonably estimate the range of possible loss for this matter; however, the amounts of potential disgorgement and other potential penalties that Power may incur span a wide range depending on the success of PSEG's legal arguments. These arguments include that Power’s energy market bids in a substantial majority of the hours were below the allowed rate under the Tariff and therefore any errors in those hours were immaterial and that it is unclear whether the quantity of the bids violated any legal requirement. If PSEG's legal arguments do not prevail in whole or in part with FERC or in ajudicial challenge that PSEG may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to PSEG’s and Power’s Consolidated Statements of Operations in the quarterly and annual periods in which they are recorded.

Nuclear Insurance Coverages

The following should be read in conjunction with Note 12. Commitments and Contingent Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

Based upon a review of its nuclear insurance, Power made changes to its Nuclear Electric Insurance Limited (NEIL) insurance coverage of the excess layer for property damage which became effective on April 1, 2016. The excess layer provides coverage above the primary layer of NEIL insurance coverage for property damage of $1.5 billion. For the excess layer at the Salem/Hope Creek site, Power purchased coverage for property damage of $300 million due to a nuclear event and $300 million due to a non-nuclear event. For the excess layer at the Peach Bottom site, Power purchased coverage for its ownership interest for property damage of $300 million due to a nuclear event. For the excess layer at the Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ownership interest of Power.

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Debt and Credit Facilities

6 Months Ended

Jun. 30, 2016

Debt Instrument [Line Items]

Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transactions occurred in the six months ended June 30, 2016:

PSE&G

• issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021,

• issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046, and

• retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds, Series VV at maturity.

Power

• issued $700 million of 3.00% Senior Notes due June 2021.

PSE&G

On July 1, 2016, PSE&G repurchased at par $100 million aggregate principal amount of Pollution Control Financing Authority of Salem County Bonds (Salem Bonds) and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds.

Short-Term Liquidity

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

The commitments under PSEG's $4.2 billion credit facilities are provided by a diverse bank group with no single institution representing more than 7% of the total commitments in PSEG's credit facilities. As of June 30, 2016, PSEG's total available credit capacity of $3.9 billion was in excess of its anticipated maximum liquidity requirements.

Each of PSEG's 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. PSEG's total credit facilities and available liquidity as of June 30, 2016 were as follows:

	As of June 30, 2016
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	10	$	490	Apr 2019	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—		500		Apr 2020	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	10	$	990
PSE&G
5-year Credit Facility (B)	$	600	$	14	$	586	Apr 2020	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
5-year Credit Facility	$	1,600	$	189	$	1,411	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	953		13		940		Apr 2020	Funding/Letters of Credit
Total Power	$	2,553	$	202	$	2,351
Total	$	4,153	$	226	$	3,927

(A) PSEG facility will be reduced by $12 million in March 2018.

(B) PSE&G facility will be reduced by $14 million in March 2018.

(C)Power facility will be reduced by $24 million in March 2018.

(D) The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs. PSEG and PSE&G had no amounts outstanding under their respective CP Programs as of June 30, 2016.

PSE And G [Member]

Debt Instrument [Line Items]

Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transactions occurred in the six months ended June 30, 2016:

PSE&G

• issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021,

• issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046, and

• retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds, Series VV at maturity.

Power

• issued $700 million of 3.00% Senior Notes due June 2021.

PSE&G

On July 1, 2016, PSE&G repurchased at par $100 million aggregate principal amount of Pollution Control Financing Authority of Salem County Bonds (Salem Bonds) and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds.

Short-Term Liquidity

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

The commitments under PSEG's $4.2 billion credit facilities are provided by a diverse bank group with no single institution representing more than 7% of the total commitments in PSEG's credit facilities. As of June 30, 2016, PSEG's total available credit capacity of $3.9 billion was in excess of its anticipated maximum liquidity requirements.

Each of PSEG's 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. PSEG's total credit facilities and available liquidity as of June 30, 2016 were as follows:

	As of June 30, 2016
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	10	$	490	Apr 2019	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—		500		Apr 2020	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	10	$	990
PSE&G
5-year Credit Facility (B)	$	600	$	14	$	586	Apr 2020	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
5-year Credit Facility	$	1,600	$	189	$	1,411	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	953		13		940		Apr 2020	Funding/Letters of Credit
Total Power	$	2,553	$	202	$	2,351
Total	$	4,153	$	226	$	3,927

(A) PSEG facility will be reduced by $12 million in March 2018.

(B) PSE&G facility will be reduced by $14 million in March 2018.

(C)Power facility will be reduced by $24 million in March 2018.

(D) The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs. PSEG and PSE&G had no amounts outstanding under their respective CP Programs as of June 30, 2016.

Power [Member]

Debt Instrument [Line Items]

Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transactions occurred in the six months ended June 30, 2016:

PSE&G

• issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021,

• issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046, and

• retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds, Series VV at maturity.

Power

• issued $700 million of 3.00% Senior Notes due June 2021.

PSE&G

On July 1, 2016, PSE&G repurchased at par $100 million aggregate principal amount of Pollution Control Financing Authority of Salem County Bonds (Salem Bonds) and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds.

Short-Term Liquidity

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

The commitments under PSEG's $4.2 billion credit facilities are provided by a diverse bank group with no single institution representing more than 7% of the total commitments in PSEG's credit facilities. As of June 30, 2016, PSEG's total available credit capacity of $3.9 billion was in excess of its anticipated maximum liquidity requirements.

Each of PSEG's 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. PSEG's total credit facilities and available liquidity as of June 30, 2016 were as follows:

	As of June 30, 2016
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	10	$	490	Apr 2019	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—		500		Apr 2020	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	10	$	990
PSE&G
5-year Credit Facility (B)	$	600	$	14	$	586	Apr 2020	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
5-year Credit Facility	$	1,600	$	189	$	1,411	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	953		13		940		Apr 2020	Funding/Letters of Credit
Total Power	$	2,553	$	202	$	2,351
Total	$	4,153	$	226	$	3,927

(A) PSEG facility will be reduced by $12 million in March 2018.

(B) PSE&G facility will be reduced by $14 million in March 2018.

(C)Power facility will be reduced by $24 million in March 2018.

(D) The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs. PSEG and PSE&G had no amounts outstanding under their respective CP Programs as of June 30, 2016.

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Financial Risk Management Activities

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Financial Risk Management Activities

Financial Risk Management Activities

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

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 purchase normal sale (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. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. 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 price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. PSEG had no commodity derivative transactions designated as cash flow or fair value hedges as of June 30, 2016 and December 31, 2015.

Economic Hedges

Power enters into derivative contracts that are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of Power's expected generation. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract tooptimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities.

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. As of June 30, 2016, PSEG had interest rate swaps outstanding totaling $550 million. These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of June 30, 2016 and December 31, 2015, the fair value of all the underlying hedges was $2 million and $6 million, respectively. The effect of these hedges reduced interest expense by $2 million and $5 million for the three months ended June 30, 2016 and 2015, respectively, and $4 million and $10 million for the six months ended June 30, 2016 and 2015, respectively.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of June 30, 2016, PSEG had interest rate hedges outstanding totaling $500 million. The hedge ineffectiveness associated with these hedges was immaterial. The total fair value of these interest rate hedges was $(1) million as of June 30, 2016. PSEG interest rate hedges totaling $400 million were terminated during the second quarter and a gain of $2 million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power's $700 million of 3% Senior Notes due June 2021. For additional information see Note 9. Debt and Credit Facilities. There were no outstanding interest rate cash flow hedges as of December 31, 2015. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $1 million as of June 30, 2016 and was immaterial as of December 31, 2015. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months are immaterial. The expiration date of the longest-dated interest rate hedge is in May 2021.

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 have been offset on the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables.

	As of June 30, 2016 (A)
	Power									PSE&G			PSEG			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	$	460		$	(310	)	$	150		$	—		$	2		$	152
Noncurrent Assets	264			(188		)	76			—			—			76
Total Mark-to-Market Derivative Assets	$	724		$	(498	)	$	226		$	—		$	2		$	228
Derivative Contracts
Current Liabilities	$	(334	)	$	317		$	(17	)	$	(2	)	$	(1	)	$	(20	)
Noncurrent Liabilities	(203		)	189			(14		)	—			—			(14		)
Total Mark-to-Market Derivative (Liabilities)	$	(537	)	$	506		$	(31	)	$	(2	)	$	(1	)	$	(34	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	187		$	8		$	195		$	(2	)	$	1		$	194

	As of December 31, 2015 (A)
	Power									PSE&G			PSEG		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	$	700		$	(477	)	$	223		$	13		$	6	$	242
Noncurrent Assets	208			(131		)	77			—			—		77
Total Mark-to-Market Derivative Assets	$	908		$	(608	)	$	300		$	13		$	6	$	319
Derivative Contracts
Current Liabilities	$	(513	)	$	437		$	(76	)	$	—		$	—	$	(76	)
Noncurrent Liabilities	(132		)	116			(16		)	(11		)	—		(27		)
Total Mark-to-Market Derivative (Liabilities)	$	(645	)	$	553		$	(92	)	$	(11	)	$	—	$	(103	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	263		$	(55	)	$	208		$	2		$	6	$	216

(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, 2016 and December 31, 2015. 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, 2016 and December 31, 2015, net cash collateral (received) paid of $8 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against current assets, and $10 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

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, 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 and 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, and contracts designated as NPNS) was $26 million and $78 million as of June 30, 2016 and December 31, 2015, respectively. As of June 30, 2016 and December 31, 2015, Power had the contractual right of offset of $18 million and $12 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 $8 million and $66 million as of June 30, 2016 and December 31, 2015, 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 ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Three Months Ended						Three Months Ended					Three Months Ended
	June 30,						June 30,					June 30,
	2016			2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Interest Rate Swaps	(1		)	—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	(1	)	$	—		$	—	$	—		$	—	$	—
Power
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total Power	$	—		$	—		$	—	$	—		$	—	$	—

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 six months ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Six Months Ended					Six Months Ended					Six Months Ended
	June 30,					June 30,					June 30,
	2016		2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Interest Rate Swaps	2		—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	2	$	1		$	—	$	17		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	17		$	—	$	—

The following reconciles the Accumulated Other Comprehensive Income 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, 2014	$	17			$	10
Gain Recognized in AOCI	3				2
Less: Gain Reclassified into Income	(20		)		(12		)
Balance as of December 31, 2015	$	—			$	—
Gain Recognized in AOCI	3			—	2
Less: Gain Reclassified into Income	—				—
Balance as of March 31, 2016	$	3			$	2
Loss Recognized in AOCI	(1		)		(1		)
Less: Gain Reclassified into Income	—				—
Balance as of June 30, 2016	$	2			$	1

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS, such as its BGS contracts and certain other energy supply contracts, for the three months and six months ended June 30, 2016 and 2015. Power's derivative contracts reflected in these tables include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel.

Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2016			2015			2016		2015
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	(86	)	$	124		$	130	$	48
Energy-Related Contracts	Energy Costs	6			(10		)	8		—
Total PSEG and Power		$	(80	)	$	114		$	138	$	48

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2016 and December 31, 2015.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2016
Natural Gas	Dekatherm (Dth)	347	—	327	20
Electricity	MWh	326	—	326	—
Financial Transmission Rights (FTRs)	MWh	21	—	21	—
Interest Rate Swaps	U.S. Dollars	1,050	1,050	—	—
As of December 31, 2015
Natural Gas	Dth	201	—	168	33
Electricity	MWh	299	—	299	—
FTRs	MWh	23	—	23	—
Interest Rate Swaps	U.S. Dollars	550	550	—	—

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe 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, 2016, 90% of the 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 and non-derivatives and normal purchases/normal sales).

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2016. It further delineates that exposure by the credit rating of the counterparties and 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		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade—External Rating	$	334	$	129	$	205	2	$	125	(A)
Non-Investment Grade—External Rating	20		—		20		—	—
Investment Grade—No External Rating	8		1		7		—	—
Non-Investment Grade—No External Rating	3		—		3		—	—
Total	$	365	$	130	$	235	2	$	125

(A) Represents net exposure of $94 million with PSE&G. The remaining net exposure of $31 million is with a non-affiliated power purchaser which is an investment grade counterparty.

As of June 30, 2016, collateral held from counterparties where Power had credit exposure included $3 million in cash collateral and $127 million in letters of credit.

As of June 30, 2016, Power had 140 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, 2016, 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 suppliers’ credit exposure is calculated each business day. As of June 30, 2016, 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

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

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 purchase normal sale (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. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. 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 price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. PSEG had no commodity derivative transactions designated as cash flow or fair value hedges as of June 30, 2016 and December 31, 2015.

Economic Hedges

Power enters into derivative contracts that are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of Power's expected generation. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract tooptimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities.

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. As of June 30, 2016, PSEG had interest rate swaps outstanding totaling $550 million. These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of June 30, 2016 and December 31, 2015, the fair value of all the underlying hedges was $2 million and $6 million, respectively. The effect of these hedges reduced interest expense by $2 million and $5 million for the three months ended June 30, 2016 and 2015, respectively, and $4 million and $10 million for the six months ended June 30, 2016 and 2015, respectively.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of June 30, 2016, PSEG had interest rate hedges outstanding totaling $500 million. The hedge ineffectiveness associated with these hedges was immaterial. The total fair value of these interest rate hedges was $(1) million as of June 30, 2016. PSEG interest rate hedges totaling $400 million were terminated during the second quarter and a gain of $2 million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power's $700 million of 3% Senior Notes due June 2021. For additional information see Note 9. Debt and Credit Facilities. There were no outstanding interest rate cash flow hedges as of December 31, 2015. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $1 million as of June 30, 2016 and was immaterial as of December 31, 2015. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months are immaterial. The expiration date of the longest-dated interest rate hedge is in May 2021.

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 have been offset on the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables.

	As of June 30, 2016 (A)
	Power									PSE&G			PSEG			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	$	460		$	(310	)	$	150		$	—		$	2		$	152
Noncurrent Assets	264			(188		)	76			—			—			76
Total Mark-to-Market Derivative Assets	$	724		$	(498	)	$	226		$	—		$	2		$	228
Derivative Contracts
Current Liabilities	$	(334	)	$	317		$	(17	)	$	(2	)	$	(1	)	$	(20	)
Noncurrent Liabilities	(203		)	189			(14		)	—			—			(14		)
Total Mark-to-Market Derivative (Liabilities)	$	(537	)	$	506		$	(31	)	$	(2	)	$	(1	)	$	(34	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	187		$	8		$	195		$	(2	)	$	1		$	194

	As of December 31, 2015 (A)
	Power									PSE&G			PSEG		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	$	700		$	(477	)	$	223		$	13		$	6	$	242
Noncurrent Assets	208			(131		)	77			—			—		77
Total Mark-to-Market Derivative Assets	$	908		$	(608	)	$	300		$	13		$	6	$	319
Derivative Contracts
Current Liabilities	$	(513	)	$	437		$	(76	)	$	—		$	—	$	(76	)
Noncurrent Liabilities	(132		)	116			(16		)	(11		)	—		(27		)
Total Mark-to-Market Derivative (Liabilities)	$	(645	)	$	553		$	(92	)	$	(11	)	$	—	$	(103	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	263		$	(55	)	$	208		$	2		$	6	$	216

(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, 2016 and December 31, 2015. 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, 2016 and December 31, 2015, net cash collateral (received) paid of $8 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against current assets, and $10 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

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, 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 and 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, and contracts designated as NPNS) was $26 million and $78 million as of June 30, 2016 and December 31, 2015, respectively. As of June 30, 2016 and December 31, 2015, Power had the contractual right of offset of $18 million and $12 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 $8 million and $66 million as of June 30, 2016 and December 31, 2015, 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 ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Three Months Ended						Three Months Ended					Three Months Ended
	June 30,						June 30,					June 30,
	2016			2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Interest Rate Swaps	(1		)	—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	(1	)	$	—		$	—	$	—		$	—	$	—
Power
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total Power	$	—		$	—		$	—	$	—		$	—	$	—

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 six months ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Six Months Ended					Six Months Ended					Six Months Ended
	June 30,					June 30,					June 30,
	2016		2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Interest Rate Swaps	2		—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	2	$	1		$	—	$	17		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	17		$	—	$	—

The following reconciles the Accumulated Other Comprehensive Income 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, 2014	$	17			$	10
Gain Recognized in AOCI	3				2
Less: Gain Reclassified into Income	(20		)		(12		)
Balance as of December 31, 2015	$	—			$	—
Gain Recognized in AOCI	3			—	2
Less: Gain Reclassified into Income	—				—
Balance as of March 31, 2016	$	3			$	2
Loss Recognized in AOCI	(1		)		(1		)
Less: Gain Reclassified into Income	—				—
Balance as of June 30, 2016	$	2			$	1

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS, such as its BGS contracts and certain other energy supply contracts, for the three months and six months ended June 30, 2016 and 2015. Power's derivative contracts reflected in these tables include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel.

Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2016			2015			2016		2015
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	(86	)	$	124		$	130	$	48
Energy-Related Contracts	Energy Costs	6			(10		)	8		—
Total PSEG and Power		$	(80	)	$	114		$	138	$	48

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2016 and December 31, 2015.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2016
Natural Gas	Dekatherm (Dth)	347	—	327	20
Electricity	MWh	326	—	326	—
Financial Transmission Rights (FTRs)	MWh	21	—	21	—
Interest Rate Swaps	U.S. Dollars	1,050	1,050	—	—
As of December 31, 2015
Natural Gas	Dth	201	—	168	33
Electricity	MWh	299	—	299	—
FTRs	MWh	23	—	23	—
Interest Rate Swaps	U.S. Dollars	550	550	—	—

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe 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, 2016, 90% of the 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 and non-derivatives and normal purchases/normal sales).

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2016. It further delineates that exposure by the credit rating of the counterparties and 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		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade—External Rating	$	334	$	129	$	205	2	$	125	(A)
Non-Investment Grade—External Rating	20		—		20		—	—
Investment Grade—No External Rating	8		1		7		—	—
Non-Investment Grade—No External Rating	3		—		3		—	—
Total	$	365	$	130	$	235	2	$	125

(A) Represents net exposure of $94 million with PSE&G. The remaining net exposure of $31 million is with a non-affiliated power purchaser which is an investment grade counterparty.

As of June 30, 2016, collateral held from counterparties where Power had credit exposure included $3 million in cash collateral and $127 million in letters of credit.

As of June 30, 2016, Power had 140 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, 2016, 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 suppliers’ credit exposure is calculated each business day. As of June 30, 2016, 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

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

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 purchase normal sale (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. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. 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 price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. PSEG had no commodity derivative transactions designated as cash flow or fair value hedges as of June 30, 2016 and December 31, 2015.

Economic Hedges

Power enters into derivative contracts that are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of Power's expected generation. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract tooptimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities.

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. As of June 30, 2016, PSEG had interest rate swaps outstanding totaling $550 million. These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of June 30, 2016 and December 31, 2015, the fair value of all the underlying hedges was $2 million and $6 million, respectively. The effect of these hedges reduced interest expense by $2 million and $5 million for the three months ended June 30, 2016 and 2015, respectively, and $4 million and $10 million for the six months ended June 30, 2016 and 2015, respectively.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of June 30, 2016, PSEG had interest rate hedges outstanding totaling $500 million. The hedge ineffectiveness associated with these hedges was immaterial. The total fair value of these interest rate hedges was $(1) million as of June 30, 2016. PSEG interest rate hedges totaling $400 million were terminated during the second quarter and a gain of $2 million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power's $700 million of 3% Senior Notes due June 2021. For additional information see Note 9. Debt and Credit Facilities. There were no outstanding interest rate cash flow hedges as of December 31, 2015. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $1 million as of June 30, 2016 and was immaterial as of December 31, 2015. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months are immaterial. The expiration date of the longest-dated interest rate hedge is in May 2021.

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 have been offset on the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables.

	As of June 30, 2016 (A)
	Power									PSE&G			PSEG			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	$	460		$	(310	)	$	150		$	—		$	2		$	152
Noncurrent Assets	264			(188		)	76			—			—			76
Total Mark-to-Market Derivative Assets	$	724		$	(498	)	$	226		$	—		$	2		$	228
Derivative Contracts
Current Liabilities	$	(334	)	$	317		$	(17	)	$	(2	)	$	(1	)	$	(20	)
Noncurrent Liabilities	(203		)	189			(14		)	—			—			(14		)
Total Mark-to-Market Derivative (Liabilities)	$	(537	)	$	506		$	(31	)	$	(2	)	$	(1	)	$	(34	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	187		$	8		$	195		$	(2	)	$	1		$	194

	As of December 31, 2015 (A)
	Power									PSE&G			PSEG		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	$	700		$	(477	)	$	223		$	13		$	6	$	242
Noncurrent Assets	208			(131		)	77			—			—		77
Total Mark-to-Market Derivative Assets	$	908		$	(608	)	$	300		$	13		$	6	$	319
Derivative Contracts
Current Liabilities	$	(513	)	$	437		$	(76	)	$	—		$	—	$	(76	)
Noncurrent Liabilities	(132		)	116			(16		)	(11		)	—		(27		)
Total Mark-to-Market Derivative (Liabilities)	$	(645	)	$	553		$	(92	)	$	(11	)	$	—	$	(103	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	263		$	(55	)	$	208		$	2		$	6	$	216

(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, 2016 and December 31, 2015. 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, 2016 and December 31, 2015, net cash collateral (received) paid of $8 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against current assets, and $10 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

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, 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 and 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, and contracts designated as NPNS) was $26 million and $78 million as of June 30, 2016 and December 31, 2015, respectively. As of June 30, 2016 and December 31, 2015, Power had the contractual right of offset of $18 million and $12 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 $8 million and $66 million as of June 30, 2016 and December 31, 2015, 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 ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Three Months Ended						Three Months Ended					Three Months Ended
	June 30,						June 30,					June 30,
	2016			2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Interest Rate Swaps	(1		)	—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	(1	)	$	—		$	—	$	—		$	—	$	—
Power
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total Power	$	—		$	—		$	—	$	—		$	—	$	—

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 six months ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Six Months Ended					Six Months Ended					Six Months Ended
	June 30,					June 30,					June 30,
	2016		2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Interest Rate Swaps	2		—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	2	$	1		$	—	$	17		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	17		$	—	$	—

The following reconciles the Accumulated Other Comprehensive Income 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, 2014	$	17			$	10
Gain Recognized in AOCI	3				2
Less: Gain Reclassified into Income	(20		)		(12		)
Balance as of December 31, 2015	$	—			$	—
Gain Recognized in AOCI	3			—	2
Less: Gain Reclassified into Income	—				—
Balance as of March 31, 2016	$	3			$	2
Loss Recognized in AOCI	(1		)		(1		)
Less: Gain Reclassified into Income	—				—
Balance as of June 30, 2016	$	2			$	1

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS, such as its BGS contracts and certain other energy supply contracts, for the three months and six months ended June 30, 2016 and 2015. Power's derivative contracts reflected in these tables include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel.

Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2016			2015			2016		2015
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	(86	)	$	124		$	130	$	48
Energy-Related Contracts	Energy Costs	6			(10		)	8		—
Total PSEG and Power		$	(80	)	$	114		$	138	$	48

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2016 and December 31, 2015.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2016
Natural Gas	Dekatherm (Dth)	347	—	327	20
Electricity	MWh	326	—	326	—
Financial Transmission Rights (FTRs)	MWh	21	—	21	—
Interest Rate Swaps	U.S. Dollars	1,050	1,050	—	—
As of December 31, 2015
Natural Gas	Dth	201	—	168	33
Electricity	MWh	299	—	299	—
FTRs	MWh	23	—	23	—
Interest Rate Swaps	U.S. Dollars	550	550	—	—

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe 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, 2016, 90% of the 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 and non-derivatives and normal purchases/normal sales).

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2016. It further delineates that exposure by the credit rating of the counterparties and 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		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade—External Rating	$	334	$	129	$	205	2	$	125	(A)
Non-Investment Grade—External Rating	20		—		20		—	—
Investment Grade—No External Rating	8		1		7		—	—
Non-Investment Grade—No External Rating	3		—		3		—	—
Total	$	365	$	130	$	235	2	$	125

(A) Represents net exposure of $94 million with PSE&G. The remaining net exposure of $31 million is with a non-affiliated power purchaser which is an investment grade counterparty.

As of June 30, 2016, collateral held from counterparties where Power had credit exposure included $3 million in cash collateral and $127 million in letters of credit.

As of June 30, 2016, Power had 140 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, 2016, 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 suppliers’ credit exposure is calculated each business day. As of June 30, 2016, 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.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2016

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.

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, 2016, these consisted primarily of long-term gas supply contracts and certain electric load contracts.

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, 2016 and December 31, 2015, 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, 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)	$	570		$	—		$	570	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
Interest Rate Swaps (C)	$	2		$	—		$	—	$	2		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	21		$	—		$	21	$	—		$	—
Debt Securities—Govt Obligations	$	106		$	—		$	—	$	106		$	—
Debt Securities—Other	$	90		$	—		$	—	$	90		$	—
Other Securities	$	5		$	—		$	5	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(33	)	$	506		$	—	$	(537	)	$	(2	)
Interest Rate Swaps (C)	$	(1	)	$	—		$	—	$	(1	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	125		$	—		$	125	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	4		$	—		$	4	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(2	)	$	—		$	—	$	—		$	(2	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	22		$	—		$	—	$	22		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(31	)	$	506		$	—	$	(537	)	$	—

	Recurring Fair Value Measurements as of December 31, 2015
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)	$	326		$	—		$	326	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	313		$	(608	)	$	—	$	896		$	25
Interest Rate Swaps (C)	$	6		$	—		$	—	$	6		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22	$	—		$	—
Debt Securities—Govt Obligations	$	108		$	—		$	—	$	108		$	—
Debt Securities—Other	$	81		$	—		$	—	$	81		$	—
Other Securities	$	2		$	—		$	2	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(103	)	$	553		$	—	$	(644	)	$	(12	)
PSE&G
Assets:
Cash Equivalents (A)	$	160		$	—		$	160	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	13		$	—		$	—	$	—		$	13
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	—		$	—	$	—		$	(11	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	300		$	(608	)	$	—	$	896		$	12
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	20		$	—		$	—	$	20		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(92	)	$	553		$	—	$	(644	)	$	(1	)

(A) Represents money market mutual funds.

(B) 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.

(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 NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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, 2016, net cash collateral (received) paid of $8 million was netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against assets, and $10 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets, and $14 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 Audit Committee 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, natural gas supply contracts are 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, 2016 and December 31, 2015.

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	—	$	(2	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(2	)
Power
Electricity	Electric Load Contracts	$	7	$	—		Discounted Cash flow	Historic Load Variability	0% to +10%
Total Power		$	7	$	—
Total PSEG		$	7	$	(2	)

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2015					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	13	$	(11	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	13	$	(11	)
Power
Electricity	Electric Load Contracts	$	11	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Electricity	Other	1		—
Total Power		$	12	$	(1	)
Total PSEG		$	25	$	(12	)

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 gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. 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 and six months ended June 30, 2016 and June 30, 2015, respectively, follows:

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

for the Three Months andSix 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 (A)		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 (A)		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)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

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

for the Three Months and Six Months EndedJune 30, 2015

	Three Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	9	$	5	$	(2	)	$	—	$	(4	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	7	$	—	$	(2	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	2	$	5	$	—		$	—	$	(4	)	$	—	$	3
	Six Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	8	$	(21	)	$	—	$	(16	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(21	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	11	$	8	$	—		$	—	$	(16	)	$	—	$	3

(A) 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.

(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 $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively. Represents $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015, respectively.

(D) There were no transfers among levels during the three months and six months ended June 30, 2016 and 2015.

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $5 million and $8 million in Operating Income for the three months and six months ended June 30, 2015, respectively. The $5 million in Operating Income is realized. Of the $8 million in Operating Income, $(9) million is unrealized.

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.

As of June 30, 2015, PSEG carried $2.7 billion of net assets that are measured at fair value on a recurring basis, of which $8 million of net liabilities 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, 2016 and December 31, 2015.

	As of				As of
	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	501	$	502	$	503	$	506
PSE&G (B)	7,494		8,624		6,821		7,235
Power - Recourse Debt (B)	2,933		3,274		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	7		7		7		7
Total Long-Term Debt	$	10,935	$	12,407	$	9,568	$	10,256

(A) Fair value includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(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.

(C) Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

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.

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, 2016, these consisted primarily of long-term gas supply contracts and certain electric load contracts.

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, 2016 and December 31, 2015, 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, 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)	$	570		$	—		$	570	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
Interest Rate Swaps (C)	$	2		$	—		$	—	$	2		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	21		$	—		$	21	$	—		$	—
Debt Securities—Govt Obligations	$	106		$	—		$	—	$	106		$	—
Debt Securities—Other	$	90		$	—		$	—	$	90		$	—
Other Securities	$	5		$	—		$	5	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(33	)	$	506		$	—	$	(537	)	$	(2	)
Interest Rate Swaps (C)	$	(1	)	$	—		$	—	$	(1	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	125		$	—		$	125	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	4		$	—		$	4	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(2	)	$	—		$	—	$	—		$	(2	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	22		$	—		$	—	$	22		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(31	)	$	506		$	—	$	(537	)	$	—

	Recurring Fair Value Measurements as of December 31, 2015
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)	$	326		$	—		$	326	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	313		$	(608	)	$	—	$	896		$	25
Interest Rate Swaps (C)	$	6		$	—		$	—	$	6		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22	$	—		$	—
Debt Securities—Govt Obligations	$	108		$	—		$	—	$	108		$	—
Debt Securities—Other	$	81		$	—		$	—	$	81		$	—
Other Securities	$	2		$	—		$	2	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(103	)	$	553		$	—	$	(644	)	$	(12	)
PSE&G
Assets:
Cash Equivalents (A)	$	160		$	—		$	160	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	13		$	—		$	—	$	—		$	13
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	—		$	—	$	—		$	(11	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	300		$	(608	)	$	—	$	896		$	12
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	20		$	—		$	—	$	20		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(92	)	$	553		$	—	$	(644	)	$	(1	)

(A) Represents money market mutual funds.

(B) 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.

(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 NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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, 2016, net cash collateral (received) paid of $8 million was netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against assets, and $10 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets, and $14 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 Audit Committee 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, natural gas supply contracts are 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, 2016 and December 31, 2015.

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	—	$	(2	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(2	)
Power
Electricity	Electric Load Contracts	$	7	$	—		Discounted Cash flow	Historic Load Variability	0% to +10%
Total Power		$	7	$	—
Total PSEG		$	7	$	(2	)

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2015					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	13	$	(11	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	13	$	(11	)
Power
Electricity	Electric Load Contracts	$	11	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Electricity	Other	1		—
Total Power		$	12	$	(1	)
Total PSEG		$	25	$	(12	)

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 gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. 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 and six months ended June 30, 2016 and June 30, 2015, respectively, follows:

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

for the Three Months andSix 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 (A)		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 (A)		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)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

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

for the Three Months and Six Months EndedJune 30, 2015

	Three Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	9	$	5	$	(2	)	$	—	$	(4	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	7	$	—	$	(2	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	2	$	5	$	—		$	—	$	(4	)	$	—	$	3
	Six Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	8	$	(21	)	$	—	$	(16	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(21	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	11	$	8	$	—		$	—	$	(16	)	$	—	$	3

(A) 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.

(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 $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively. Represents $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015, respectively.

(D) There were no transfers among levels during the three months and six months ended June 30, 2016 and 2015.

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $5 million and $8 million in Operating Income for the three months and six months ended June 30, 2015, respectively. The $5 million in Operating Income is realized. Of the $8 million in Operating Income, $(9) million is unrealized.

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.

As of June 30, 2015, PSEG carried $2.7 billion of net assets that are measured at fair value on a recurring basis, of which $8 million of net liabilities 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, 2016 and December 31, 2015.

	As of				As of
	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	501	$	502	$	503	$	506
PSE&G (B)	7,494		8,624		6,821		7,235
Power - Recourse Debt (B)	2,933		3,274		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	7		7		7		7
Total Long-Term Debt	$	10,935	$	12,407	$	9,568	$	10,256

(A) Fair value includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(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.

(C) Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

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.

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, 2016, these consisted primarily of long-term gas supply contracts and certain electric load contracts.

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, 2016 and December 31, 2015, 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, 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)	$	570		$	—		$	570	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
Interest Rate Swaps (C)	$	2		$	—		$	—	$	2		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	21		$	—		$	21	$	—		$	—
Debt Securities—Govt Obligations	$	106		$	—		$	—	$	106		$	—
Debt Securities—Other	$	90		$	—		$	—	$	90		$	—
Other Securities	$	5		$	—		$	5	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(33	)	$	506		$	—	$	(537	)	$	(2	)
Interest Rate Swaps (C)	$	(1	)	$	—		$	—	$	(1	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	125		$	—		$	125	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	4		$	—		$	4	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(2	)	$	—		$	—	$	—		$	(2	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	22		$	—		$	—	$	22		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(31	)	$	506		$	—	$	(537	)	$	—

	Recurring Fair Value Measurements as of December 31, 2015
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)	$	326		$	—		$	326	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	313		$	(608	)	$	—	$	896		$	25
Interest Rate Swaps (C)	$	6		$	—		$	—	$	6		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22	$	—		$	—
Debt Securities—Govt Obligations	$	108		$	—		$	—	$	108		$	—
Debt Securities—Other	$	81		$	—		$	—	$	81		$	—
Other Securities	$	2		$	—		$	2	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(103	)	$	553		$	—	$	(644	)	$	(12	)
PSE&G
Assets:
Cash Equivalents (A)	$	160		$	—		$	160	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	13		$	—		$	—	$	—		$	13
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	—		$	—	$	—		$	(11	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	300		$	(608	)	$	—	$	896		$	12
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	20		$	—		$	—	$	20		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(92	)	$	553		$	—	$	(644	)	$	(1	)

(A) Represents money market mutual funds.

(B) 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.

(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 NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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, 2016, net cash collateral (received) paid of $8 million was netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against assets, and $10 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets, and $14 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 Audit Committee 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, natural gas supply contracts are 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, 2016 and December 31, 2015.

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	—	$	(2	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(2	)
Power
Electricity	Electric Load Contracts	$	7	$	—		Discounted Cash flow	Historic Load Variability	0% to +10%
Total Power		$	7	$	—
Total PSEG		$	7	$	(2	)

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2015					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	13	$	(11	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	13	$	(11	)
Power
Electricity	Electric Load Contracts	$	11	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Electricity	Other	1		—
Total Power		$	12	$	(1	)
Total PSEG		$	25	$	(12	)

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 gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. 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 and six months ended June 30, 2016 and June 30, 2015, respectively, follows:

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

for the Three Months andSix 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 (A)		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 (A)		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)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

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

for the Three Months and Six Months EndedJune 30, 2015

	Three Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	9	$	5	$	(2	)	$	—	$	(4	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	7	$	—	$	(2	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	2	$	5	$	—		$	—	$	(4	)	$	—	$	3
	Six Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	8	$	(21	)	$	—	$	(16	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(21	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	11	$	8	$	—		$	—	$	(16	)	$	—	$	3

(A) 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.

(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 $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively. Represents $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015, respectively.

(D) There were no transfers among levels during the three months and six months ended June 30, 2016 and 2015.

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $5 million and $8 million in Operating Income for the three months and six months ended June 30, 2015, respectively. The $5 million in Operating Income is realized. Of the $8 million in Operating Income, $(9) million is unrealized.

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.

As of June 30, 2015, PSEG carried $2.7 billion of net assets that are measured at fair value on a recurring basis, of which $8 million of net liabilities 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, 2016 and December 31, 2015.

	As of				As of
	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	501	$	502	$	503	$	506
PSE&G (B)	7,494		8,624		6,821		7,235
Power - Recourse Debt (B)	2,933		3,274		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	7		7		7		7
Total Long-Term Debt	$	10,935	$	12,407	$	9,568	$	10,256

(A) Fair value includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(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.

(C) Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

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Other Income and Deductions

6 Months Ended

Jun. 30, 2016

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, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—	$	23
Allowance for Funds Used During Construction	10		—		—		10
Solar Loan Interest	5		—		—		5
Other	4		2		—		6
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
Solar Loan Interest	11		—		—		11
Other	7		3		2		12
Total Other Income	$	39	$	51	$	2	$	92
Three Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	12		—		—		12
Solar Loan Interest	6		—		—		6
Gain on Insurance Recovery	—		28		—		28
Other	1		2		2		5
Total Other Income	$	19	$	55	$	2	$	76
Six Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	54	$	—	$	54
Allowance for Funds Used During Construction	22		—		—		22
Solar Loan Interest	12		—		—		12
Gain on Insurance Recovery	—		28		—		28
Other	3		2		3		8
Total Other Income	$	37	$	84	$	3	$	124

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
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
Three Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		2		4
Total Other Deductions	$	1	$	7	$	2	$	10
Six Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	17	$	—	$	17
Other	2		1		2		5
Total Other Deductions	$	2	$	18	$	2	$	22

(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, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—	$	23
Allowance for Funds Used During Construction	10		—		—		10
Solar Loan Interest	5		—		—		5
Other	4		2		—		6
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
Solar Loan Interest	11		—		—		11
Other	7		3		2		12
Total Other Income	$	39	$	51	$	2	$	92
Three Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	12		—		—		12
Solar Loan Interest	6		—		—		6
Gain on Insurance Recovery	—		28		—		28
Other	1		2		2		5
Total Other Income	$	19	$	55	$	2	$	76
Six Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	54	$	—	$	54
Allowance for Funds Used During Construction	22		—		—		22
Solar Loan Interest	12		—		—		12
Gain on Insurance Recovery	—		28		—		28
Other	3		2		3		8
Total Other Income	$	37	$	84	$	3	$	124

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
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
Three Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		2		4
Total Other Deductions	$	1	$	7	$	2	$	10
Six Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	17	$	—	$	17
Other	2		1		2		5
Total Other Deductions	$	2	$	18	$	2	$	22

(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, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—	$	23
Allowance for Funds Used During Construction	10		—		—		10
Solar Loan Interest	5		—		—		5
Other	4		2		—		6
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
Solar Loan Interest	11		—		—		11
Other	7		3		2		12
Total Other Income	$	39	$	51	$	2	$	92
Three Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	12		—		—		12
Solar Loan Interest	6		—		—		6
Gain on Insurance Recovery	—		28		—		28
Other	1		2		2		5
Total Other Income	$	19	$	55	$	2	$	76
Six Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	54	$	—	$	54
Allowance for Funds Used During Construction	22		—		—		22
Solar Loan Interest	12		—		—		12
Gain on Insurance Recovery	—		28		—		28
Other	3		2		3		8
Total Other Income	$	37	$	84	$	3	$	124

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
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
Three Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		2		4
Total Other Deductions	$	1	$	7	$	2	$	10
Six Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	17	$	—	$	17
Other	2		1		2		5
Total Other Deductions	$	2	$	18	$	2	$	22

(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, 2016

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, 2016 and 2015 were as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
PSEG	32.7%	35.0%	36.2%	38.5%
PSE&G	35.4%	38.4%	36.1%	39.0%
Power	50.0%	30.3%	39.5%	37.9%

For the three months and six months ended June 30, 2016, the overall decreases 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, offset by the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

For the three months and six months ended June 30, 2016, the overall decreases 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 and plant and other flow through items.

For the three months ended June 30, 2016, the increase 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%, was due primarily to the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

The Tax Increase Prevention Act of 2014 extended the 50% bonus depreciation rules for qualified property placed in service before January 1, 2015 and for long production property placed in service in 2015.

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. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. 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.

These provisions have 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, 2016 and 2015 were as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
PSEG	32.7%	35.0%	36.2%	38.5%
PSE&G	35.4%	38.4%	36.1%	39.0%
Power	50.0%	30.3%	39.5%	37.9%

For the three months and six months ended June 30, 2016, the overall decreases 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, offset by the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

For the three months and six months ended June 30, 2016, the overall decreases 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 and plant and other flow through items.

For the three months ended June 30, 2016, the increase 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%, was due primarily to the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

The Tax Increase Prevention Act of 2014 extended the 50% bonus depreciation rules for qualified property placed in service before January 1, 2015 and for long production property placed in service in 2015.

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. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. 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.

These provisions have 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, 2016 and 2015 were as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
PSEG	32.7%	35.0%	36.2%	38.5%
PSE&G	35.4%	38.4%	36.1%	39.0%
Power	50.0%	30.3%	39.5%	37.9%

For the three months and six months ended June 30, 2016, the overall decreases 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, offset by the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

For the three months and six months ended June 30, 2016, the overall decreases 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 and plant and other flow through items.

For the three months ended June 30, 2016, the increase 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%, was due primarily to the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

The Tax Increase Prevention Act of 2014 extended the 50% bonus depreciation rules for qualified property placed in service before January 1, 2015 and for long production property placed in service in 2015.

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. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. 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.

These provisions have 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, 2016

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, 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)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	1		$	(403	)	$	132		$	(270	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			(1		)	7
Net Current Period Other Comprehensive Income (Loss)	—			8			(15		)	(7		)
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)
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	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	10		$	(411	)	$	118		$	(283	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	16			(3		)	3
Net Current Period Other Comprehensive Income (Loss)	(9		)	16			(1		)	6
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)

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)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	2		$	(344	)	$	126		$	(216	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			7			—			7
Net Current Period Other Comprehensive Income (Loss)	—			7			(14		)	(7		)
Balance as of June 30, 2015	$	2		$	(337	)	$	112		$	(223	)
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	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	11		$	(351	)	$	112		$	(228	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	14			(2		)	2
Net Current Period Other Comprehensive Income (Loss)	(9		)	14			—			5
Balance as of June 30, 2015	$	2		$	(337	)	$	112		$	(223	)

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		)
Other-Than-Temporary Impairments (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	)

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, 2015									June 30, 2015
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
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	16			(8		)	8			35			(18		)	17
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		2			(1		)	1			7			(4		)	3
Total		$	(12	)	$	5		$	(7	)	$	(4	)	$	1		$	(3	)

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		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, 2015									June 30, 2015
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
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	(15		)	6			(9		)	(30		)	12			(18		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	14			(7		)	7			33			(17		)	16
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		—			—			—			5			(3		)	2
Total		$	(12	)	$	5		$	(7	)	$	(2	)	$	—		$	(2	)

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, 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)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	1		$	(403	)	$	132		$	(270	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			(1		)	7
Net Current Period Other Comprehensive Income (Loss)	—			8			(15		)	(7		)
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)
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	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	10		$	(411	)	$	118		$	(283	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	16			(3		)	3
Net Current Period Other Comprehensive Income (Loss)	(9		)	16			(1		)	6
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)

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)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	2		$	(344	)	$	126		$	(216	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			7			—			7
Net Current Period Other Comprehensive Income (Loss)	—			7			(14		)	(7		)
Balance as of June 30, 2015	$	2		$	(337	)	$	112		$	(223	)
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	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	11		$	(351	)	$	112		$	(228	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	14			(2		)	2
Net Current Period Other Comprehensive Income (Loss)	(9		)	14			—			5
Balance as of June 30, 2015	$	2		$	(337	)	$	112		$	(223	)

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		)
Other-Than-Temporary Impairments (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	)

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, 2015									June 30, 2015
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
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	16			(8		)	8			35			(18		)	17
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		2			(1		)	1			7			(4		)	3
Total		$	(12	)	$	5		$	(7	)	$	(4	)	$	1		$	(3	)

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		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, 2015									June 30, 2015
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
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	(15		)	6			(9		)	(30		)	12			(18		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	14			(7		)	7			33			(17		)	16
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		—			—			—			5			(3		)	2
Total		$	(12	)	$	5		$	(7	)	$	(2	)	$	—		$	(2	)

XML

Earnings Per Share (EPS) and Dividends

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Share (EPS) and Dividends

Earnings Per Share (EPS) and Dividends

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,
	2016				2015				2016				2015
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	187	$	187	$	345	$	345	$	658	$	658	$	931	$	931
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		506		506		505		505		506		506
Effect of Stock Based Compensation Awards	—		3		—		2		—		3		—		2
Total Shares	505		508		506		508		505		508		506		508
EPS
Net Income	$	0.37	$	0.37	$	0.68	$	0.68	$	1.30	$	1.30	$	1.84	$	1.83

There were approximately 0.3 million and 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months and six months ended June 30, 2016 and 2015, respectively.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2016		2015		2016		2015
Per Share	$	0.41	$	0.39	$	0.82	$	0.78
In Millions	$	208	$	197	$	415	$	394

On July 19, 2016, PSEG's Board of Directors approved a $0.41 per share common stock dividend for the third quarter of 2016.

XML

Financial Information By Business Segments

6 Months Ended

Jun. 30, 2016

Segment Reporting Information [Line Items]

Financial Information By Business Segments

Financial Information by Business Segment

	PSE&G		Power			Other (A)		Eliminations (B)			Consolidated
	Millions
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
Three Months Ended June 30, 2015
Total Operating Revenues	$	1,466	$	1,025		$	108	$	(285	)	$	2,314
Net Income (Loss)	167		166			12		—			345
Gross Additions to Long-Lived Assets	631		348			17		—			996
Six Months Ended June 30, 2015
Operating Revenues	$	3,468	$	2,750		$	206	$	(975	)	$	5,449
Net Income (Loss)	409		501			21		—			931
Gross Additions to Long-Lived Assets	1,230		487			26		—			1,743
As of June 30, 2016
Total Assets	$	24,737	$	13,278		$	2,873	$	(1,843	)	$	39,045
Investments in Equity Method Subsidiaries	$	—	$	112		$	—	$	—		$	112
As of December 31, 2015
Total Assets	$	23,677	$	12,250		$	2,810	$	(1,202	)	$	37,535
Investments in Equity Method Subsidiaries	$	—	$	119		$	—	$	—		$	119

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

(B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. 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 17. 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
	Millions
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
Three Months Ended June 30, 2015
Total Operating Revenues	$	1,466	$	1,025		$	108	$	(285	)	$	2,314
Net Income (Loss)	167		166			12		—			345
Gross Additions to Long-Lived Assets	631		348			17		—			996
Six Months Ended June 30, 2015
Operating Revenues	$	3,468	$	2,750		$	206	$	(975	)	$	5,449
Net Income (Loss)	409		501			21		—			931
Gross Additions to Long-Lived Assets	1,230		487			26		—			1,743
As of June 30, 2016
Total Assets	$	24,737	$	13,278		$	2,873	$	(1,843	)	$	39,045
Investments in Equity Method Subsidiaries	$	—	$	112		$	—	$	—		$	112
As of December 31, 2015
Total Assets	$	23,677	$	12,250		$	2,810	$	(1,202	)	$	37,535
Investments in Equity Method Subsidiaries	$	—	$	119		$	—	$	—		$	119

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

(B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. 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 17. 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
	Millions
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
Three Months Ended June 30, 2015
Total Operating Revenues	$	1,466	$	1,025		$	108	$	(285	)	$	2,314
Net Income (Loss)	167		166			12		—			345
Gross Additions to Long-Lived Assets	631		348			17		—			996
Six Months Ended June 30, 2015
Operating Revenues	$	3,468	$	2,750		$	206	$	(975	)	$	5,449
Net Income (Loss)	409		501			21		—			931
Gross Additions to Long-Lived Assets	1,230		487			26		—			1,743
As of June 30, 2016
Total Assets	$	24,737	$	13,278		$	2,873	$	(1,843	)	$	39,045
Investments in Equity Method Subsidiaries	$	—	$	112		$	—	$	—		$	112
As of December 31, 2015
Total Assets	$	23,677	$	12,250		$	2,810	$	(1,202	)	$	37,535
Investments in Equity Method Subsidiaries	$	—	$	119		$	—	$	—		$	119

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

(B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. 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 17. Related-Party Transactions.

XML

Related-Party Transactions

6 Months Ended

Jun. 30, 2016

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	2016		2015		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Administrative Billings from Services (B)	82		65		151		131
Total Billings from Affiliates	$	379	$	362	$	993	$	1,124

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSEG (C)	$	—	$	222
Payable to Power (A)	$	94	$	212
Payable to Services (B)	79		80
Payable to PSEG (C)	6		—
Accounts Payable—Affiliated Companies	$	179	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	99	$	109

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	2016		2015		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Billings from Affiliates:
Administrative Billings from Services (B)	$	45	$	46	$	90	$	91

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSE&G (A)	$	94	$	212
Receivables from PSEG (C)	—		64
Accounts Receivable—Affiliated Companies	$	94	$	276
Payable to Services (B)	$	28	$	33
Payable to PSEG (C)	74		—
Accounts Payable—Affiliated Companies	$	102	$	33
Short-Term Loan Due (to) from Affiliate (E)	$	1,335	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	22	$	35

(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 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	2016		2015		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Administrative Billings from Services (B)	82		65		151		131
Total Billings from Affiliates	$	379	$	362	$	993	$	1,124

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSEG (C)	$	—	$	222
Payable to Power (A)	$	94	$	212
Payable to Services (B)	79		80
Payable to PSEG (C)	6		—
Accounts Payable—Affiliated Companies	$	179	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	99	$	109

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	2016		2015		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Billings from Affiliates:
Administrative Billings from Services (B)	$	45	$	46	$	90	$	91

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSE&G (A)	$	94	$	212
Receivables from PSEG (C)	—		64
Accounts Receivable—Affiliated Companies	$	94	$	276
Payable to Services (B)	$	28	$	33
Payable to PSEG (C)	74		—
Accounts Payable—Affiliated Companies	$	102	$	33
Short-Term Loan Due (to) from Affiliate (E)	$	1,335	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	22	$	35

(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 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	2016		2015		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Administrative Billings from Services (B)	82		65		151		131
Total Billings from Affiliates	$	379	$	362	$	993	$	1,124

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSEG (C)	$	—	$	222
Payable to Power (A)	$	94	$	212
Payable to Services (B)	79		80
Payable to PSEG (C)	6		—
Accounts Payable—Affiliated Companies	$	179	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	99	$	109

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	2016		2015		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Billings from Affiliates:
Administrative Billings from Services (B)	$	45	$	46	$	90	$	91

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSE&G (A)	$	94	$	212
Receivables from PSEG (C)	—		64
Accounts Receivable—Affiliated Companies	$	94	$	276
Payable to Services (B)	$	28	$	33
Payable to PSEG (C)	74		—
Accounts Payable—Affiliated Companies	$	102	$	33
Short-Term Loan Due (to) from Affiliate (E)	$	1,335	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	22	$	35

(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 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.

XML

Guarantees of Debt

6 Months Ended

Jun. 30, 2016

Debt Instrument [Line Items]

Guarantees of Debt

Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities 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, 2016 and December 31, 2015 and for the three months and six months ended June 30, 2016 and 2015.

	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
Three Months Ended June 30, 2015
Operating Revenues	$	—		$	1,012		$	39		$	(26	)	$	1,025
Operating Expenses	(1		)	787			37			(26		)	797
Operating Income (Loss)	1			225			2			—			228
Equity Earnings (Losses) of Subsidiaries	186			(1		)	5			(185		)	5
Other Income	12			55			—			(12		)	55
Other Deductions	(1		)	(6		)	—			—			(7		)
Other-Than-Temporary    Impairments	—			(10		)	—			—			(10		)
Interest Expense	(33		)	(7		)	(5		)	12			(33		)
Income Tax Benefit (Expense)	1			(73		)	—			—			(72		)
Net Income (Loss)	$	166		$	183		$	2		$	(185	)	$	166
Comprehensive Income (Loss)	$	159		$	169		$	2		$	(171	)	$	159
Six Months Ended June 30, 2015
Operating Revenues	$	—		$	2,727		$	107		$	(84	)	$	2,750
Operating Expenses	4			1,918			100			(84		)	1,938
Operating Income (Loss)	(4		)	809			7			—			812
Equity Earnings (Losses) of Subsidiaries	535			(2		)	8			(533		)	8
Other Income	23			85			—			(24		)	84
Other Deductions	(1		)	(17		)	—			—			(18		)
Other-Than-Temporary Impairments	—			(15		)	—			—			(15		)
Interest Expense	(62		)	(16		)	(10		)	24			(64		)
Income Tax Benefit (Expense)	10			(315		)	(1		)	—			(306		)
Net Income (Loss)	$	501		$	529		$	4		$	(533	)	$	501
Comprehensive Income (Loss)	$	506		$	520		$	4		$	(524	)	$	506
Six Months Ended June 30, 2015
Net Cash Provided By (Used In)    Operating Activities	$	410		$	1,508		$	61		$	(687	)	$	1,292
Net Cash Provided By (Used In)    Investing Activities	$	(480	)	$	(963	)	$	(210	)	$	766		$	(887	)
Net Cash Provided By (Used In)    Financing Activities	$	70		$	(543	)	$	150		$	(79	)	$	(402	)

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2016
Current Assets	$	5,490	$	1,655	$	231	$	(4,828	)	$	2,548
Property, Plant and Equipment, net	58		6,476		1,944		—			8,478
Investment in Subsidiaries	4,419		345		—		(4,764		)	—
Noncurrent Assets	134		2,041		128		(51		)	2,252
Total Assets	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
Current Liabilities	$	1,079	$	3,719	$	1,293	$	(4,828	)	$	1,263
Noncurrent Liabilities	420		2,652		392		(51		)	3,413
Long-Term Debt	2,380		—		—		—			2,380
Member's Equity	6,222		4,146		618		(4,764		)	6,222
Total Liabilities and Member's Equity	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
As of December 31, 2015
Current Assets	$	4,501	$	1,912	$	364	$	(4,828	)	$	1,949
Property, Plant and Equipment, net	83		6,502		1,542		—			8,127
Investment in Subsidiaries	4,501		346		—		(4,847		)	—
Noncurrent Assets	155		1,959		136		(76		)	2,174
Total Assets	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250
Current Liabilities	$	1,112	$	3,866	$	1,076	$	(4,828	)	$	1,226
Noncurrent Liabilities	442		2,597		375		(76		)	3,338
Long-Term Debt	1,684		—		—		—			1,684
Member's Equity	6,002		4,256		591		(4,847		)	6,002
Total Liabilities and Member's Equity	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250

Power [Member]

Debt Instrument [Line Items]

Guarantees of Debt

Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities 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, 2016 and December 31, 2015 and for the three months and six months ended June 30, 2016 and 2015.

	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
Three Months Ended June 30, 2015
Operating Revenues	$	—		$	1,012		$	39		$	(26	)	$	1,025
Operating Expenses	(1		)	787			37			(26		)	797
Operating Income (Loss)	1			225			2			—			228
Equity Earnings (Losses) of Subsidiaries	186			(1		)	5			(185		)	5
Other Income	12			55			—			(12		)	55
Other Deductions	(1		)	(6		)	—			—			(7		)
Other-Than-Temporary    Impairments	—			(10		)	—			—			(10		)
Interest Expense	(33		)	(7		)	(5		)	12			(33		)
Income Tax Benefit (Expense)	1			(73		)	—			—			(72		)
Net Income (Loss)	$	166		$	183		$	2		$	(185	)	$	166
Comprehensive Income (Loss)	$	159		$	169		$	2		$	(171	)	$	159
Six Months Ended June 30, 2015
Operating Revenues	$	—		$	2,727		$	107		$	(84	)	$	2,750
Operating Expenses	4			1,918			100			(84		)	1,938
Operating Income (Loss)	(4		)	809			7			—			812
Equity Earnings (Losses) of Subsidiaries	535			(2		)	8			(533		)	8
Other Income	23			85			—			(24		)	84
Other Deductions	(1		)	(17		)	—			—			(18		)
Other-Than-Temporary Impairments	—			(15		)	—			—			(15		)
Interest Expense	(62		)	(16		)	(10		)	24			(64		)
Income Tax Benefit (Expense)	10			(315		)	(1		)	—			(306		)
Net Income (Loss)	$	501		$	529		$	4		$	(533	)	$	501
Comprehensive Income (Loss)	$	506		$	520		$	4		$	(524	)	$	506
Six Months Ended June 30, 2015
Net Cash Provided By (Used In)    Operating Activities	$	410		$	1,508		$	61		$	(687	)	$	1,292
Net Cash Provided By (Used In)    Investing Activities	$	(480	)	$	(963	)	$	(210	)	$	766		$	(887	)
Net Cash Provided By (Used In)    Financing Activities	$	70		$	(543	)	$	150		$	(79	)	$	(402	)

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2016
Current Assets	$	5,490	$	1,655	$	231	$	(4,828	)	$	2,548
Property, Plant and Equipment, net	58		6,476		1,944		—			8,478
Investment in Subsidiaries	4,419		345		—		(4,764		)	—
Noncurrent Assets	134		2,041		128		(51		)	2,252
Total Assets	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
Current Liabilities	$	1,079	$	3,719	$	1,293	$	(4,828	)	$	1,263
Noncurrent Liabilities	420		2,652		392		(51		)	3,413
Long-Term Debt	2,380		—		—		—			2,380
Member's Equity	6,222		4,146		618		(4,764		)	6,222
Total Liabilities and Member's Equity	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
As of December 31, 2015
Current Assets	$	4,501	$	1,912	$	364	$	(4,828	)	$	1,949
Property, Plant and Equipment, net	83		6,502		1,542		—			8,127
Investment in Subsidiaries	4,501		346		—		(4,847		)	—
Noncurrent Assets	155		1,959		136		(76		)	2,174
Total Assets	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250
Current Liabilities	$	1,112	$	3,866	$	1,076	$	(4,828	)	$	1,226
Noncurrent Liabilities	442		2,597		375		(76		)	3,338
Long-Term Debt	1,684		—		—		—			1,684
Member's Equity	6,002		4,256		591		(4,847		)	6,002
Total Liabilities and Member's Equity	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250

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Organization and Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2016

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, 2015.

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, 2015.

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, 2015.

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, 2015.

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, 2015.

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, 2015.

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Recent Accounting Standards (Policies)

6 Months Ended

Jun. 30, 2016

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 was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements.

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 is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (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.

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.

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.

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. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. 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.

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 was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements.

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 is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (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.

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.

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.

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. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. 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.

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 was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements.

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 is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (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.

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.

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.

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. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. 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.

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Financing Receivables (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016		December 31, 2015
	Millions
Commercial/Industrial	$	174	$	177
Residential	12		12
Total	$	186	$	189

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, 2016 and December 31, 2015, respectively.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	630		$	631
Estimated Residual Value of Leased Assets	519			519
Total Investment in Rental Receivables	1,149			1,150
Unearned and Deferred Income	(359		)	(366		)
Gross Investment in Leases	790			784
Deferred Tax Liabilities	(694		)	(724		)
Net Investment in Leases	$	96		$	60

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, 2016
	As of June 30, 2016
	Millions
AA	$	16
BBB+ — BBB-	316
BB-	134
CCC	164
Total	$	630

Schedule Of Assets Under Lease Receivables

A more detailed description of such assets under lease, as of June 30, 2016, 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	$	84	64	%	1,044	Coal (A)	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC (C)	NRG REMA, LLC
Conemaugh Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC (C)	NRG REMA, LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	113	100	%	603	Coal (B)	CCC (C)	NRG REMA, LLC

(A) The Joliet facility is currently in the process of converting to natural gas.

(B) NRG REMA, LLC (NRG REMA) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the fall of 2016 with the ability to use natural gas.

(C) On May 24, 2016, S&P lowered its corporate credit rating on GenOn Energy Inc. and affiliates (including NRG REMA) to "CCC" from "CCC+" due to a weaker forward power curve, milder weather patterns and weakening financial measures. PSEG continues to monitor any changes to GenOn's status and potential impacts on Energy Holdings' lease investments.

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Available-for-Sale Securities (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	679	$	198	$	(12	)	$	865
Debt Securities
Government Obligations	503		23		—			526
Other	348		12		(3		)	357
Total Debt Securities	851		35		(3		)	883
Other Securities	49		—		—			49
Total NDT Available-for-Sale Securities	$	1,579	$	233	$	(15	)	$	1,797

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	693	$	185	$	(13	)	$	865
Debt Securities
Government Obligations	483		8		(3		)	488
Other	366		3		(10		)	359
Total Debt Securities	849		11		(13		)	847
Other Securities	42		—		—			42
Total NDT Available-for-Sale Securities	$	1,584	$	196	$	(26	)	$	1,754

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	18	$	17
Accounts Payable	$	10	$	10

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, 2016										As of December 31, 2015
	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)	$	108	$	(12	)	$	5	$	—		$	151	$	(13	)	$	1	$	—
Debt Securities
Government Obligations (B)	12		—			6		—			245		(2		)	19		(1		)
Other (C)	12		—			43		(3		)	222		(7		)	36		(3		)
Total Debt Securities	24		—			49		(3		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	132	$	(12	)	$	54	$	(3	)	$	618	$	(22	)	$	56	$	(4	)

(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, 2016.

(B) Debt Securities (Government Obligations)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

Proceeds From The Sales Of And The Net Realized Gains On Securities In The NDT Funds And Rabbi Trusts

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	Millions
Proceeds from NDT Fund Sales (A)	$	154		$	232		$	331		$	822
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	10			14			25			33
Gross Realized Losses	(6		)	(4		)	(22		)	(13		)
Net Realized Gains (Losses) on NDT Fund	$	4		$	10		$	3		$	20

(A) 2015 proceeds include 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, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	19
1 - 5 years	216
6 - 10 years	220
11 - 15 years	54
16 - 20 years	61
Over 20 years	313
Total NDT Available-for-Sale Debt Securities	$	883

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 and greater than 12 months.

	As of June 30, 2016									As of December 31, 2015
	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 Obligations (B)	14		—		3		—			53		(1		)	2		—
Other (C)	14		—		11		(1		)	46		(1		)	9		—
Total Debt Securities	28		—		14		(1		)	99		(2		)	11		—
Rabbi Trust Available-for-Sale Securities	$	28	$	—	$	14	$	(1	)	$	99	$	(2	)	$	11	$	—

(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 Obligations)—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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C) Debt Securities (Other)—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, 2016.

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, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	10	$	—		$	21
Debt Securities
Government Obligations	104		2		—			106
Other	90		1		(1		)	90
Total Debt Securities	194		3		(1		)	196
Other Securities	5		—		—			5
Total Rabbi Trust Available-for-Sale Securities	$	210	$	13	$	(1	)	$	222

	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	10	$	—		$	22
Debt Securities
Government Obligations	108		1		(1		)	108
Other	82		—		(1		)	81
Total Debt Securities	190		1		(2		)	189
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	204	$	11	$	(2	)	$	213

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, 2016		December 31, 2015
	Millions
Accounts Receivable	$	2	$	1
Accounts Payable	$	4	$	—

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,
	2016			2015		2016			2015
	Millions
Proceeds from Rabbi Trust Sales (A)	$	36		$	44	$	61		$	63
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2	$	3		$	2
Gross Realized Losses	(1		)	—		(2		)	—
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	2	$	1		$	2

(A) 2015 proceeds include 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, 2016 had the following maturities:

Time Frame	Fair Value
	Millions
Less than one year	$	8
1 - 5 years	45
6 - 10 years	48
11 - 15 years	6
16 - 20 years	7
Over 20 years	82
Total Rabbi Trust Available-for-Sale Debt Securities	$	196

Fair Value Of The Rabbi Trusts

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

	As of		As of
	June 30, 2016		December 31, 2015
	Millions
PSE&G	$	44	$	42
Power	54		52
Other	124		119
Total Rabbi Trust Available-for-Sale Securities	$	222	$	213

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Pension and OPEB (Tables)

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Components Of Net Periodic Benefit Cost

Pension and OPEB costs for PSEG, except for 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,
	2016			2015			2016			2015			2016			2015			2016			2015
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	27		$	31		$	4		$	6		$	54		$	62		$	8		$	11
Interest Cost	51			58			14			17			101			117			29			34
Expected Return on Plan Assets	(99		)	(104		)	(7		)	(8		)	(197		)	(207		)	(15		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(4		)	(4		)	(4		)	(9		)	(9		)	(7		)	(7		)
Actuarial Loss	40			37			10			11			79			74			20			21
Total Benefit Costs	$	14		$	18		$	17		$	22		$	28		$	37		$	35		$	44

Schedule Of Pension And OPEB Costs

Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, except for 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,
	2016		2015		2016		2015		2016		2015		2016		2015
	Millions
PSE&G	$	7	$	10	$	11	$	14	$	14	$	20	$	22	$	28
Power	4		5		5		6		8		11		11		13
Other	3		3		1		2		6		6		2		3
Total Benefit Costs	$	14	$	18	$	17	$	22	$	28	$	37	$	35	$	44

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Commitments and Contingent Liabilities (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016 and December 31, 2015.

	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Face Value of Outstanding Guarantees	$	1,809		$	1,734
Exposure under Current Guarantees	$	136		$	172
Letters of Credit Margin Posted	$	160		$	122
Letters of Credit Margin Received	$	130		$	192
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(4	)	$	(15	)
Net Broker Balance Deposited (Received)	$	30		$	(5	)
Additional Amounts Posted:
Other Letters of Credit	$	51		$	51

Total Minimum Purchase Commitments

As of June 30, 2016, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Power's Share of Commitments through 2020
	Millions
Nuclear Fuel
Uranium	$	454
Enrichment	$	358
Fabrication	$	180
Natural Gas	$	972
Coal	$	265

PSE And G [Member]

Loss Contingencies [Line Items]

Contract For Anticipated BGS-Fixed Price Eligible Load

	Auction Year
	2013	2014	2015	2016
36-Month Terms Ending	May 2016	May 2017	May 2018	May 2019	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$92.18	$97.39	$99.54	$96.38

(A) Prices set in the 2016 BGS auction year became effective on June 1, 2016 when the 2013 BGS auction agreements expired.

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Debt and Credit Facilities Debt and Credit Facilities (Tables)

6 Months Ended

Jun. 30, 2016

Debt and Credit Facilities [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

Each of PSEG's 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. PSEG's total credit facilities and available liquidity as of June 30, 2016 were as follows:

	As of June 30, 2016
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	10	$	490	Apr 2019	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—		500		Apr 2020	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	10	$	990
PSE&G
5-year Credit Facility (B)	$	600	$	14	$	586	Apr 2020	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
5-year Credit Facility	$	1,600	$	189	$	1,411	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	953		13		940		Apr 2020	Funding/Letters of Credit
Total Power	$	2,553	$	202	$	2,351
Total	$	4,153	$	226	$	3,927

(A) PSEG facility will be reduced by $12 million in March 2018.

(B) PSE&G facility will be reduced by $14 million in March 2018.

(C)Power facility will be reduced by $24 million in March 2018.

(D) The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs. PSEG and PSE&G had no amounts outstanding under their respective CP Programs as of June 30, 2016.

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Financial Risk Management Activities (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule Of Derivative Instruments Fair Value In Balance Sheets

	As of June 30, 2016 (A)
	Power									PSE&G			PSEG			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	$	460		$	(310	)	$	150		$	—		$	2		$	152
Noncurrent Assets	264			(188		)	76			—			—			76
Total Mark-to-Market Derivative Assets	$	724		$	(498	)	$	226		$	—		$	2		$	228
Derivative Contracts
Current Liabilities	$	(334	)	$	317		$	(17	)	$	(2	)	$	(1	)	$	(20	)
Noncurrent Liabilities	(203		)	189			(14		)	—			—			(14		)
Total Mark-to-Market Derivative (Liabilities)	$	(537	)	$	506		$	(31	)	$	(2	)	$	(1	)	$	(34	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	187		$	8		$	195		$	(2	)	$	1		$	194

	As of December 31, 2015 (A)
	Power									PSE&G			PSEG		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	$	700		$	(477	)	$	223		$	13		$	6	$	242
Noncurrent Assets	208			(131		)	77			—			—		77
Total Mark-to-Market Derivative Assets	$	908		$	(608	)	$	300		$	13		$	6	$	319
Derivative Contracts
Current Liabilities	$	(513	)	$	437		$	(76	)	$	—		$	—	$	(76	)
Noncurrent Liabilities	(132		)	116			(16		)	(11		)	—		(27		)
Total Mark-to-Market Derivative (Liabilities)	$	(645	)	$	553		$	(92	)	$	(11	)	$	—	$	(103	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	263		$	(55	)	$	208		$	2		$	6	$	216

(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, 2016 and December 31, 2015. 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, 2016 and December 31, 2015, net cash collateral (received) paid of $8 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against current assets, and $10 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

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 ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Three Months Ended						Three Months Ended					Three Months Ended
	June 30,						June 30,					June 30,
	2016			2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Interest Rate Swaps	(1		)	—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	(1	)	$	—		$	—	$	—		$	—	$	—
Power
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total Power	$	—		$	—		$	—	$	—		$	—	$	—

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 six months ended June 30, 2016 and 2015.

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)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Six Months Ended					Six Months Ended					Six Months Ended
	June 30,					June 30,					June 30,
	2016		2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Interest Rate Swaps	2		—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	2	$	1		$	—	$	17		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	17		$	—	$	—

Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block]

The following reconciles the Accumulated Other Comprehensive Income 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, 2014	$	17			$	10
Gain Recognized in AOCI	3				2
Less: Gain Reclassified into Income	(20		)		(12		)
Balance as of December 31, 2015	$	—			$	—
Gain Recognized in AOCI	3			—	2
Less: Gain Reclassified into Income	—				—
Balance as of March 31, 2016	$	3			$	2
Loss Recognized in AOCI	(1		)		(1		)
Less: Gain Reclassified into Income	—				—
Balance as of June 30, 2016	$	2			$	1

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, such as its BGS contracts and certain other energy supply contracts, for the three months and six months ended June 30, 2016 and 2015. Power's derivative contracts reflected in these tables include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel.

Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2016			2015			2016		2015
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	(86	)	$	124		$	130	$	48
Energy-Related Contracts	Energy Costs	6			(10		)	8		—
Total PSEG and Power		$	(80	)	$	114		$	138	$	48

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, 2016 and December 31, 2015.

Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2016
Natural Gas	Dekatherm (Dth)	347	—	327	20
Electricity	MWh	326	—	326	—
Financial Transmission Rights (FTRs)	MWh	21	—	21	—
Interest Rate Swaps	U.S. Dollars	1,050	1,050	—	—
As of December 31, 2015
Natural Gas	Dth	201	—	168	33
Electricity	MWh	299	—	299	—
FTRs	MWh	23	—	23	—
Interest Rate Swaps	U.S. Dollars	550	550	—	—

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, 2016. It further delineates that exposure by the credit rating of the counterparties and 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		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade—External Rating	$	334	$	129	$	205	2	$	125	(A)
Non-Investment Grade—External Rating	20		—		20		—	—
Investment Grade—No External Rating	8		1		7		—	—
Non-Investment Grade—No External Rating	3		—		3		—	—
Total	$	365	$	130	$	235	2	$	125

(A) Represents net exposure of $94 million with PSE&G. The remaining net exposure of $31 million is with a non-affiliated power purchaser which is an investment grade counterparty.

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016 and December 31, 2015, 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, 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)	$	570		$	—		$	570	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
Interest Rate Swaps (C)	$	2		$	—		$	—	$	2		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	21		$	—		$	21	$	—		$	—
Debt Securities—Govt Obligations	$	106		$	—		$	—	$	106		$	—
Debt Securities—Other	$	90		$	—		$	—	$	90		$	—
Other Securities	$	5		$	—		$	5	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(33	)	$	506		$	—	$	(537	)	$	(2	)
Interest Rate Swaps (C)	$	(1	)	$	—		$	—	$	(1	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	125		$	—		$	125	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	4		$	—		$	4	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(2	)	$	—		$	—	$	—		$	(2	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	22		$	—		$	—	$	22		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(31	)	$	506		$	—	$	(537	)	$	—

	Recurring Fair Value Measurements as of December 31, 2015
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)	$	326		$	—		$	326	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	313		$	(608	)	$	—	$	896		$	25
Interest Rate Swaps (C)	$	6		$	—		$	—	$	6		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22	$	—		$	—
Debt Securities—Govt Obligations	$	108		$	—		$	—	$	108		$	—
Debt Securities—Other	$	81		$	—		$	—	$	81		$	—
Other Securities	$	2		$	—		$	2	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(103	)	$	553		$	—	$	(644	)	$	(12	)
PSE&G
Assets:
Cash Equivalents (A)	$	160		$	—		$	160	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	13		$	—		$	—	$	—		$	13
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	—		$	—	$	—		$	(11	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	300		$	(608	)	$	—	$	896		$	12
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	20		$	—		$	—	$	20		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(92	)	$	553		$	—	$	(644	)	$	(1	)

(A) Represents money market mutual funds.

(B) 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.

(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 NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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, 2016, net cash collateral (received) paid of $8 million was netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against assets, and $10 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets, and $14 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, 2016 and December 31, 2015.

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	—	$	(2	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(2	)
Power
Electricity	Electric Load Contracts	$	7	$	—		Discounted Cash flow	Historic Load Variability	0% to +10%
Total Power		$	7	$	—
Total PSEG		$	7	$	(2	)

	Quantitative Information About Level 3 Fair Value Measurements
								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2015					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	13	$	(11	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	13	$	(11	)
Power
Electricity	Electric Load Contracts	$	11	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Electricity	Other	1		—
Total Power		$	12	$	(1	)
Total PSEG		$	25	$	(12	)

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 gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. 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 and six months ended June 30, 2016 and June 30, 2015, respectively, follows:

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

for the Three Months andSix 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 (A)		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 (A)		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)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

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

for the Three Months and Six Months EndedJune 30, 2015

	Three Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	9	$	5	$	(2	)	$	—	$	(4	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	7	$	—	$	(2	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	2	$	5	$	—		$	—	$	(4	)	$	—	$	3
	Six Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	8	$	(21	)	$	—	$	(16	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(21	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	11	$	8	$	—		$	—	$	(16	)	$	—	$	3

(A) 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.

(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 $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively. Represents $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015, respectively.

(D) There were no transfers among levels during the three months and six months ended June 30, 2016 and 2015.

(E) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $5 million and $8 million in Operating Income for the three months and six months ended June 30, 2015, respectively. The $5 million in Operating Income is realized. Of the $8 million in Operating Income, $(9) 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, 2016 and December 31, 2015.

	As of				As of
	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	501	$	502	$	503	$	506
PSE&G (B)	7,494		8,624		6,821		7,235
Power - Recourse Debt (B)	2,933		3,274		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	7		7		7		7
Total Long-Term Debt	$	10,935	$	12,407	$	9,568	$	10,256

(A) Fair value includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(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.

(C) Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

XML

Other Income and Deductions (Tables)

6 Months Ended

Jun. 30, 2016

Other Income and Expenses [Abstract]

Schedule Of Other Income

Other Income	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—	$	23
Allowance for Funds Used During Construction	10		—		—		10
Solar Loan Interest	5		—		—		5
Other	4		2		—		6
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
Solar Loan Interest	11		—		—		11
Other	7		3		2		12
Total Other Income	$	39	$	51	$	2	$	92
Three Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	12		—		—		12
Solar Loan Interest	6		—		—		6
Gain on Insurance Recovery	—		28		—		28
Other	1		2		2		5
Total Other Income	$	19	$	55	$	2	$	76
Six Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	54	$	—	$	54
Allowance for Funds Used During Construction	22		—		—		22
Solar Loan Interest	12		—		—		12
Gain on Insurance Recovery	—		28		—		28
Other	3		2		3		8
Total Other Income	$	37	$	84	$	3	$	124

Schedule Of Other Deductions

Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
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
Three Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		2		4
Total Other Deductions	$	1	$	7	$	2	$	10
Six Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	17	$	—	$	17
Other	2		1		2		5
Total Other Deductions	$	2	$	18	$	2	$	22

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

XML

Income Taxes (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016 and 2015 were as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
PSEG	32.7%	35.0%	36.2%	38.5%
PSE&G	35.4%	38.4%	36.1%	39.0%
Power	50.0%	30.3%	39.5%	37.9%

XML

Accumulated Other Comprehensive Income (Loss), Net of Tax (Tables)

6 Months Ended

Jun. 30, 2016

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, 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)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	1		$	(403	)	$	132		$	(270	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			(1		)	7
Net Current Period Other Comprehensive Income (Loss)	—			8			(15		)	(7		)
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)
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	)
PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	10		$	(411	)	$	118		$	(283	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	16			(3		)	3
Net Current Period Other Comprehensive Income (Loss)	(9		)	16			(1		)	6
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)

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)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	2		$	(344	)	$	126		$	(216	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			7			—			7
Net Current Period Other Comprehensive Income (Loss)	—			7			(14		)	(7		)
Balance as of June 30, 2015	$	2		$	(337	)	$	112		$	(223	)
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	)
Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	11		$	(351	)	$	112		$	(228	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	14			(2		)	2
Net Current Period Other Comprehensive Income (Loss)	(9		)	14			—			5
Balance as of June 30, 2015	$	2		$	(337	)	$	112		$	(223	)

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, 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		)
Other-Than-Temporary Impairments (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	)

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, 2015									June 30, 2015
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
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	16			(8		)	8			35			(18		)	17
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		2			(1		)	1			7			(4		)	3
Total		$	(12	)	$	5		$	(7	)	$	(4	)	$	1		$	(3	)

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		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, 2015									June 30, 2015
		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
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	(15		)	6			(9		)	(30		)	12			(18		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	14			(7		)	7			33			(17		)	16
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		—			—			—			5			(3		)	2
Total		$	(12	)	$	5		$	(7	)	$	(2	)	$	—		$	(2	)

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Earnings Per Share (EPS) and Dividends (Tables)

6 Months Ended

Jun. 30, 2016

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,
	2016				2015				2016				2015
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	187	$	187	$	345	$	345	$	658	$	658	$	931	$	931
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		506		506		505		505		506		506
Effect of Stock Based Compensation Awards	—		3		—		2		—		3		—		2
Total Shares	505		508		506		508		505		508		506		508
EPS
Net Income	$	0.37	$	0.37	$	0.68	$	0.68	$	1.30	$	1.30	$	1.84	$	1.83

There were approximately 0.3 million and 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months

Dividend Payments On Common Stock

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2016		2015		2016		2015
Per Share	$	0.41	$	0.39	$	0.82	$	0.78
In Millions	$	208	$	197	$	415	$	394

On July 19, 2016, PSEG's Board of Directors approved a $0.41 per share common stock dividend for the third quarter of 2016.

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Financial Information By Business Segments (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Financial Information By Business Segments

	PSE&G		Power			Other (A)		Eliminations (B)			Consolidated
	Millions
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
Three Months Ended June 30, 2015
Total Operating Revenues	$	1,466	$	1,025		$	108	$	(285	)	$	2,314
Net Income (Loss)	167		166			12		—			345
Gross Additions to Long-Lived Assets	631		348			17		—			996
Six Months Ended June 30, 2015
Operating Revenues	$	3,468	$	2,750		$	206	$	(975	)	$	5,449
Net Income (Loss)	409		501			21		—			931
Gross Additions to Long-Lived Assets	1,230		487			26		—			1,743
As of June 30, 2016
Total Assets	$	24,737	$	13,278		$	2,873	$	(1,843	)	$	39,045
Investments in Equity Method Subsidiaries	$	—	$	112		$	—	$	—		$	112
As of December 31, 2015
Total Assets	$	23,677	$	12,250		$	2,810	$	(1,202	)	$	37,535
Investments in Equity Method Subsidiaries	$	—	$	119		$	—	$	—		$	119

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

(B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. 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 17. Related-Party Transactions.

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Related-Party Transactions (Tables)

6 Months Ended

Jun. 30, 2016

PSE And G [Member]

Related Party Transaction [Line Items]

Schedule Of Related Party Transactions, Revenue

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	2016		2015		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Administrative Billings from Services (B)	82		65		151		131
Total Billings from Affiliates	$	379	$	362	$	993	$	1,124

Schedule Of Related Party Transactions, Payables

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSEG (C)	$	—	$	222
Payable to Power (A)	$	94	$	212
Payable to Services (B)	79		80
Payable to PSEG (C)	6		—
Accounts Payable—Affiliated Companies	$	179	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	99	$	109

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	2016		2015		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Billings from Affiliates:
Administrative Billings from Services (B)	$	45	$	46	$	90	$	91

Schedule Of Related Party Transactions, Receivables

	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSE&G (A)	$	94	$	212
Receivables from PSEG (C)	—		64
Accounts Receivable—Affiliated Companies	$	94	$	276
Payable to Services (B)	$	28	$	33
Payable to PSEG (C)	74		—
Accounts Payable—Affiliated Companies	$	102	$	33
Short-Term Loan Due (to) from Affiliate (E)	$	1,335	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	22	$	35

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Guarantees of Debt (Tables)

6 Months Ended

Jun. 30, 2016

Power [Member]

Debt Instrument [Line Items]

Schedule Of Financial Statements Of Guarantors

	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
Three Months Ended June 30, 2015
Operating Revenues	$	—		$	1,012		$	39		$	(26	)	$	1,025
Operating Expenses	(1		)	787			37			(26		)	797
Operating Income (Loss)	1			225			2			—			228
Equity Earnings (Losses) of Subsidiaries	186			(1		)	5			(185		)	5
Other Income	12			55			—			(12		)	55
Other Deductions	(1		)	(6		)	—			—			(7		)
Other-Than-Temporary    Impairments	—			(10		)	—			—			(10		)
Interest Expense	(33		)	(7		)	(5		)	12			(33		)
Income Tax Benefit (Expense)	1			(73		)	—			—			(72		)
Net Income (Loss)	$	166		$	183		$	2		$	(185	)	$	166
Comprehensive Income (Loss)	$	159		$	169		$	2		$	(171	)	$	159
Six Months Ended June 30, 2015
Operating Revenues	$	—		$	2,727		$	107		$	(84	)	$	2,750
Operating Expenses	4			1,918			100			(84		)	1,938
Operating Income (Loss)	(4		)	809			7			—			812
Equity Earnings (Losses) of Subsidiaries	535			(2		)	8			(533		)	8
Other Income	23			85			—			(24		)	84
Other Deductions	(1		)	(17		)	—			—			(18		)
Other-Than-Temporary Impairments	—			(15		)	—			—			(15		)
Interest Expense	(62		)	(16		)	(10		)	24			(64		)
Income Tax Benefit (Expense)	10			(315		)	(1		)	—			(306		)
Net Income (Loss)	$	501		$	529		$	4		$	(533	)	$	501
Comprehensive Income (Loss)	$	506		$	520		$	4		$	(524	)	$	506
Six Months Ended June 30, 2015
Net Cash Provided By (Used In)    Operating Activities	$	410		$	1,508		$	61		$	(687	)	$	1,292
Net Cash Provided By (Used In)    Investing Activities	$	(480	)	$	(963	)	$	(210	)	$	766		$	(887	)
Net Cash Provided By (Used In)    Financing Activities	$	70		$	(543	)	$	150		$	(79	)	$	(402	)

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2016
Current Assets	$	5,490	$	1,655	$	231	$	(4,828	)	$	2,548
Property, Plant and Equipment, net	58		6,476		1,944		—			8,478
Investment in Subsidiaries	4,419		345		—		(4,764		)	—
Noncurrent Assets	134		2,041		128		(51		)	2,252
Total Assets	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
Current Liabilities	$	1,079	$	3,719	$	1,293	$	(4,828	)	$	1,263
Noncurrent Liabilities	420		2,652		392		(51		)	3,413
Long-Term Debt	2,380		—		—		—			2,380
Member's Equity	6,222		4,146		618		(4,764		)	6,222
Total Liabilities and Member's Equity	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
As of December 31, 2015
Current Assets	$	4,501	$	1,912	$	364	$	(4,828	)	$	1,949
Property, Plant and Equipment, net	83		6,502		1,542		—			8,127
Investment in Subsidiaries	4,501		346		—		(4,847		)	—
Noncurrent Assets	155		1,959		136		(76		)	2,174
Total Assets	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250
Current Liabilities	$	1,112	$	3,866	$	1,076	$	(4,828	)	$	1,226
Noncurrent Liabilities	442		2,597		375		(76		)	3,338
Long-Term Debt	1,684		—		—		—			1,684
Member's Equity	6,002		4,256		591		(4,847		)	6,002
Total Liabilities and Member's Equity	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250

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Variable Interest Entities (VIEs) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Variable Interest Entity [Line Items]
Operating Revenues	$ 1,905	$ 2,314	$ 4,521	$ 5,449
Operation and Maintenance	710	761	1,439	1,424
PSE And G [Member]
Variable Interest Entity [Line Items]
Operating Revenues	1,350	1,466	3,062	3,468
Operation and Maintenance	352	368	734	780
Long Island ServCo [Member]
Variable Interest Entity [Line Items]
Operating Revenues	101	84	199	166
Operation and Maintenance	$ 101	$ 84	$ 199	$ 166

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Rate Filings (Details) - PSE And G [Member] $ in Millions	1 Months Ended
	Jul. 31, 2016 USD ($)	Jun. 30, 2016 USD ($)	Oct. 01, 2016
Regulatory Assets And Liabilities [Line Items]
Request for RAC Recovery		$ 54
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 16
Current BGSS rate per therm		0.40
Proposed Recovery of costs for Electric Green Energy Program		$ 44
True-up adjustment for Transmission Formula Rate Revenues		34
Proposed Recovery of costs for Gas Green Energy Programs		13
Gas Distribution [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		23
Overrecovered Gas Costs Basic Gas Supply Service [Member]
Regulatory Assets And Liabilities [Line Items]
BGSS Revenue Reduction		$ 87
Subsequent Event [Member]
Regulatory Assets And Liabilities [Line Items]
Proposed BGSS rate per therm			0.34
Subsequent Event [Member] | Gas Weather Normalization Deferral [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 54
Subsequent Event [Member] | Gas System Modernization Program [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 13

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Financing Receivables (Outstanding Loans by Class of Customer) (Detail) - PSE And G [Member] - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Outstanding Loans by Class of Customer	$ 186	$ 189
Commercial/Industrial [Member]
Concentration Risk [Line Items]
Outstanding Loans by Class of Customer	174	177
Residential [Member]
Concentration Risk [Line Items]
Outstanding Loans by Class of Customer	$ 12	$ 12

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Financing Receivables (Gross And Net Lease Investment) (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Schedule of Financial Receivables [Line Items]
Total Investment in Rental Receivables	$ 1,149	$ 1,150
Energy Holdings [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	630	631
Estimated Residual Value of Leased Assets	519	519
Unearned and Deferred Income	(359)	(366)
Gross Investment in Leases	790	784
Deferred Tax Liabilities	(694)	(724)
Net Investment in Leases	$ 96	$ 60

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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, 2016	Dec. 31, 2015
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	$ 630	$ 631
Standard & Poor's, AA Rating [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	16
Standard & Poor's, BBB plus - BBB - Rating [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	316
Standard & Poor's, BB- Rating [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	134
Standard & Poor's, CCC plus Rating [Member]
Schedule of Financial Receivables [Line Items]
Lease Receivables (net of Non-Recourse Debt)	$ 164

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Financing Receivables (Narrative) (Detail) $ in Millions	Jun. 30, 2016 USD ($)
Schedule of Financial Receivables [Line Items]
Lease investment with non-investment grade counterparties, gross	$ 573
Lease investment with non-investment grade counterparties, net of deferred taxes	$ (5)

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Financing Receivables (Schedule Of Assets Under Lease Receivables) (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2016 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 | $	$ 84
% Owned	64.00%
Total MW | MW	1,044
Fuel Type	Coal (A)	[1]
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 | $	$ 121
% Owned	17.00%
Total MW | MW	1,711
Fuel Type	Coal
Counterparties’ S&P Credit Ratings	CCC (C)	[2]
Counterparty	NRG REMA, LLC
Conemaugh Station Units 1 And 2 [Member]
Schedule of Financial Receivables [Line Items]
Location	PA
Gross Investment | $	$ 121
% Owned	17.00%
Total MW | MW	1,711
Fuel Type	Coal
Counterparties’ S&P Credit Ratings	CCC (C)	[2]
Counterparty	NRG REMA, LLC
Shawville Station Units 1, 2, 3 And 4 [Member]
Schedule of Financial Receivables [Line Items]
Location	PA
Gross Investment | $	$ 113
% Owned	100.00%
Total MW | MW	603
Fuel Type	Coal (B)	[3]
Counterparties’ S&P Credit Ratings	CCC (C)	[2]
Counterparty	NRG REMA, LLC

[1] The Joliet facility is currently in the process of converting to natural gas.

[2] On May 24, 2016, S&P lowered its corporate credit rating on GenOn Energy Inc. and affiliates (including NRG REMA) to "CCC" from "CCC+" due to a weaker forward power curve, milder weather patterns and weakening financial measures. PSEG continues to monitor any changes to GenOn's status and potential impacts on Energy Holdings' lease investments.

[3] NRG REMA, LLC (NRG REMA) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the fall of 2016 with the ability to use natural gas.

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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, 2016	Dec. 31, 2015
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 1,579	$ 1,584
Gross Unrealized Gains	233	196
Gross Unrealized Losses	(15)	(26)
Fair Value	1,797	1,754
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	679	693
Gross Unrealized Gains	198	185
Gross Unrealized Losses	(12)	(13)
Fair Value	865	865
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Government Obligations [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	503	483
Gross Unrealized Gains	23	8
Gross Unrealized Losses	0	(3)
Fair Value	526	488
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Other Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	348	366
Gross Unrealized Gains	12	3
Gross Unrealized Losses	(3)	(10)
Fair Value	357	359
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Total Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	851	849
Gross Unrealized Gains	35	11
Gross Unrealized Losses	(3)	(13)
Fair Value	883	847
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Other Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	49	42
Gross Unrealized Gains	0	0
Gross Unrealized Losses	0	0
Fair Value	49	42
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	210	204
Gross Unrealized Gains	13	11
Gross Unrealized Losses	(1)	(2)
Fair Value	222	213
Rabbi Trust [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	11	12
Gross Unrealized Gains	10	10
Gross Unrealized Losses	0	0
Fair Value	21	22
Rabbi Trust [Member] | Government Obligations [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	104	108
Gross Unrealized Gains	2	1
Gross Unrealized Losses	0	(1)
Fair Value	106	108
Rabbi Trust [Member] | Other Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	90	82
Gross Unrealized Gains	1	0
Gross Unrealized Losses	(1)	(1)
Fair Value	90	81
Rabbi Trust [Member] | Total Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	194	190
Gross Unrealized Gains	3	1
Gross Unrealized Losses	(1)	(2)
Fair Value	196	189
Rabbi Trust [Member] | Other Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	5	2
Gross Unrealized Gains	0	0
Gross Unrealized Losses	0	0
Fair Value	5	2
Rabbi Trust [Member] | Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Fair Value	$ 54	$ 52

XML

Available-For-Sale Securities (Schedule Of Accounts Receivable And Accounts Payable) (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Accounts Receivable	$ 18	$ 17
Accounts Payable	10	10
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Accounts Receivable	2	1
Accounts Payable	$ 4	$ 0

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, 2016	Dec. 31, 2015
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		$ 132	$ 618
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		(12)	(22)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value		54	56
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses		(3)	(4)
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]	108	151
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[1]	(12)	(13)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[1]	5	1
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[1]	0	0
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Government Obligations [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[2]	12	245
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[2]	0	(2)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[2]	6	19
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[2]	0	(1)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Other Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[3]	12	222
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[3]	0	(7)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[3]	43	36
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[3]	(3)	(3)
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		24	467
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		0	(9)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value		49	55
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses		(3)	(4)
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value		28	99
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		0	(2)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value		14	11
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses		(1)	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 Obligations [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[5]	14	53
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[5]	0	(1)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[5]	3	2
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[5]	0	0
Rabbi Trust [Member] | Other Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Continuous Unrealized Loss Position, Less Than 12 Months, Fair Value	[6]	14	46
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses	[6]	0	(1)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value	[6]	11	9
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses	[6]	(1)	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		28	99
Continuous Unrealized Loss Position, Less Than 12 Months, Gross Unrealized Losses		0	(2)
Continuous Unrealized Loss Position, Greater Than 12 Months, Fair Value		14	11
Continuous Unrealized Loss Position, Greater Than 12 Months, Gross Unrealized Losses		$ (1)	$ 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, 2016.

[2] Debt Securities (Government Obligations)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

[3] Debt Securities (Other)—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, 2016.

[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 Obligations)—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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

[6] Debt Securities (Other)—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, 2016.

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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, 2016		Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Proceeds from Sales	$ 36	[1]	$ 44	[1]	$ 61	$ 63	[1]
Gross Realized Gains	2		2		3	2
Gross Realized Losses	(1)		0		(2)	0
Net Realized Gains (Losses)	1		2		1	2
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Proceeds from Sales	154	[2]	232	[2]	331	822	[2]
Gross Realized Gains	10		14		25	33
Gross Realized Losses	(6)		(4)		(22)	(13)
Net Realized Gains (Losses)	$ 4		$ 10		$ 3	$ 20

[1] 2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers

[2] 2015 proceeds include 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, 2016 USD ($)
Rabbi Trust [Member]
Schedule of Available-for-sale Securities [Line Items]
Less than one year	$ 8
1 - 5 years	45
6 - 10 years	48
11 - 15 years	6
16 - 20 years	7
Over 20 years	82
Total Available-for-Sale Debt Securities	196
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Less than one year	19
1 - 5 years	216
6 - 10 years	220
11 - 15 years	54
16 - 20 years	61
Over 20 years	313
Total Available-for-Sale Debt Securities	$ 883

XML

Available-For-Sale Securities (Fair Value Of Rabbi Trust) (Detail) - Rabbi Trust [Member] - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Schedule of Available-for-sale Securities [Line Items]
Total Rabbi Trust Available-for-Sale Securities	$ 222	$ 213
Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Total Rabbi Trust Available-for-Sale Securities	54	52
PSE And G [Member]
Schedule of Available-for-sale Securities [Line Items]
Total Rabbi Trust Available-for-Sale Securities	44	42
Other Entity [Member]
Schedule of Available-for-sale Securities [Line Items]
Total Rabbi Trust Available-for-Sale Securities	$ 124	$ 119

XML

Available-For-Sale Securities (Narrative) (Detail) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) Facility	Jun. 30, 2015 USD ($)
Schedule of Available-for-sale Securities [Line Items]
Other-Than-Temporary Impairments	$ 10	$ 10	$ 20	$ 15
Power [Member]
Schedule of Available-for-sale Securities [Line Items]
Number of Nuclear Facilities | Facility			5
Other-Than-Temporary Impairments	$ 10	$ 10	$ 20	$ 15
Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Available-for-sale Securities [Line Items]
Other-Than-Temporary Impairments			20
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			110
Rabbi Trust [Member] | Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
After tax amount of net unrealized gains recognized in AOCI			$ 7

XML

Pension And OPEB (Components Of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 27	$ 31	$ 54	$ 62
Interest Cost	51	58	101	117
Expected Return on Plan Assets	(99)	(104)	(197)	(207)
Amortization of Prior Service Cost	(5)	(4)	(9)	(9)
Amortization of Actuarial Loss	40	37	79	74
Total Benefit Costs	14	18	28	37
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	4	6	8	11
Interest Cost	14	17	29	34
Expected Return on Plan Assets	(7)	(8)	(15)	(15)
Amortization of Prior Service Cost	(4)	(4)	(7)	(7)
Amortization of Actuarial Loss	10	11	20	21
Total Benefit Costs	$ 17	$ 22	$ 35	$ 44

XML

Pension And OPEB (Schedule Of Pension And OPEB Costs) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 14	$ 18	$ 28	$ 37
Pension Benefits [Member] | PSE And G [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	7	10	14	20
Pension Benefits [Member] | Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	4	5	8	11
Pension Benefits [Member] | Other Entity [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	3	3	6	6
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	17	22	35	44
OPEB [Member] | PSE And G [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	11	14	22	28
OPEB [Member] | Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	5	6	11	13
OPEB [Member] | Other Entity [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 1	$ 2	$ 2	$ 3

XML

Pension And OPEB (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions				$ 21
Total Benefit Costs	$ 14		$ 18	28	$ 37
Postretirement Healthcare Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions		$ 14
Total Benefit Costs	17		22	35	44
Long Island Electric Utility Servco LLC Pension and OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year				28
Total Benefit Costs	6		$ 7	12	$ 13
Cost Reduction related to change in estimate [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	8			17
Cost Reduction related to change in estimate [Member] | Postretirement Healthcare Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 3			$ 6

XML

Commitments And Contingent Liabilities (Guaranteed Obligations) (Detail) - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding		$ 226
Line of Credit Facility, Remaining Borrowing Capacity		3,927
Power [Member]
Loss Contingencies [Line Items]
Face Value of Outstanding Guarantees		1,809	$ 1,734
Exposure under Current Guarantees		136	172
Letters of Credit Margin Posted		160	122
Letters of Credit Margin Received		130	192
Counterparty Cash Margin Deposited		0	0
Counterparty Cash Margin Received		(4)	(15)
Net Broker Balance Deposited (Received)		30	(5)
Other Letters of Credit		51	$ 51
Line of Credit Facility, Fair Value of Amount Outstanding		202
Line of Credit Facility, Remaining Borrowing Capacity		2,351
Pse And G [Member]
Loss Contingencies [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding	[1]	14
Line of Credit Facility, Remaining Borrowing Capacity		586
PennEast Natural Gas Pipeline [Member] | Power [Member]
Loss Contingencies [Line Items]
Face Value of Outstanding Guarantees		106
755 MW Gas-Fired Combined Cycle Generating Station [Member] | Power [Member]
Loss Contingencies [Line Items]
Face Value of Outstanding Guarantees		$ 21

[1] The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs. PSEG and PSE&G had no amounts outstanding under their respective CP Programs as of June 30, 2016.

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Commitments And Contingent Liabilities (Environmental Matters) (Detail)	1 Months Ended	6 Months Ended
	Jun. 30, 2008 USD ($)	Jun. 30, 2016 USD ($) Potentially_Responsible_Party entity site Station Plant mi	Dec. 31, 2015 USD ($)	Mar. 31, 2007 Potentially_Responsible_Party	Dec. 31, 2006	Dec. 31, 2003 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
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
Accrued environmental costs		$ 402,000,000	$ 415,000,000
New Salem facility cooling towers estimated cost total		1,000,000,000
PSE And G [Member]
Site Contingency [Line Items]
Percentage of cost attributable to potentially responsible party					7.00%
Accrued environmental costs		$ 336,000,000	$ 365,000,000
Power [Member]
Site Contingency [Line Items]
Ownership percentage of Keystone Coal fired plant in Pennsylvania		23.00%
New Salem facility cooling towers estimated cost total		$ 575,000,000
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		53		73
Estimated, total cost of the study		$ 163,000,000
Total Spend of Study to date		150,000,000
Company Share of Total Spend of Study to date		11,000,000
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
CPG Estimated Cleanup Costs Low Estimate		518,000,000
CPG Estimated Cleanup Costs High Estimate		3,200,000,000
CPG Targeted Method Cleanup Costs Low Estimate		518,000,000
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
CPG Targeted Remedy Cleanup Costs High Estimate		772,000,000
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]
Accrued environmental costs		426,000,000
Estimated Expenditures Low End Of Range		426,000,000
Estimated Expenditures High End Of Range		491,000,000
Remediation Liability Recorded As Other Current Liabilities		99,000,000
Remediation Liability Recorded As Other Noncurrent Liabilities		327,000,000
Regulatory Assets		426,000,000
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%

XML

Commitments And Contingent Liabilities (Basic Generation Service (BGS) And Basic Gas Supply Service (BGSS)) (Detail) cf in Billions	6 Months Ended
	Jun. 30, 2016 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 2013 [Member]
Long-term Purchase Commitment [Line Items]
36-Month Terms Ending	May 31, 2016	[1]
Load (MW) | MW	2,800
Dollars Per Megawatt Hour | $ / mwh	92.18
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 2014 [Member]
Long-term Purchase Commitment [Line Items]
Dollars Per Megawatt-Day | $ / mwd	272.78
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	[1]
Load (MW) | MW	2,800
Dollars Per Megawatt Hour | $ / mwh	96.38

[1] Prices set in the 2016 BGS auction year became effective on June 1, 2016 when the 2013 BGS auction agreements expired.

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Commitments And Contingent Liabilities (Minimum Fuel Purchase Requirements) (Detail) - Power [Member] $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Long-term Purchase Commitment [Line Items]
Coverage percentage of nuclear fuel commitments of uranium, enrichment, and fabrication requirements	100.00%
Commitments Through 2019 [Member] | Nuclear Fuel Uranium [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	$ 454
Commitments Through 2019 [Member] | Nuclear Fuel Enrichment [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	358
Commitments Through 2019 [Member] | Nuclear Fuel Fabrication [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	180
Commitments Through 2019 [Member] | Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	972
Commitments Through 2019 [Member] | Coal [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	$ 265

XML

Commitments And Contingent Liabilities (Regulatory Proceedings and Superstorm Sandy) (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
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
Nuclear Electric Insurance Limited Ii Salem Hope Creek Peach Bottom [Member] | Total Site Coverage [Member]
Loss Contingencies [Line Items]
Property Damage Primary Layer	1,500
Property Damage Excess Layers	300
Nuclear Electric Insurance Limited Ii Salem Hope Creek Peach Bottom [Member] | Total Site Coverage for Non Nuclear Event [Member]
Loss Contingencies [Line Items]
Property Damage Excess Layers	300
Nuclear Electric Insurance Limited I Peach Bottom [Member] | Total Site Coverage [Member]
Loss Contingencies [Line Items]
Property Damage Excess Layers	300
Nuclear Electric Insurance Limited I Peach Bottom [Member] | Total Site Coverage for Non Nuclear Event [Member]
Loss Contingencies [Line Items]
Property Damage Excess Layers	$ 600

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Debt and Credit Facilities (Changes in Long-Term Debt) (Detail) - USD ($) $ in Millions	1 Months Ended	6 Months Ended
	Jul. 31, 2016	Jun. 30, 2016
Medium Term Notes One Point Nine Zero Percent Due in Two Thousand Twenty One [Member] | PSE And G [Member]
Debt Instrument [Line Items]
Issued long-term debt		$ 300
Stated interest rate of debt instrument		1.90%
Medium Term Notes Three Point Eight Zero Percent due Two Thousand Forty Six [Member] | PSE And G [Member]
Debt Instrument [Line Items]
Issued long-term debt		$ 550
Stated interest rate of debt instrument		3.80%
First And Refunding Mortgage Bonds Six Point Seven Five Percentage Due On Two Thousand Sixteen [Member] | PSE And G [Member]
Debt Instrument [Line Items]
Stated interest rate of debt instrument		6.75%
Repayments of long-term debt		$ 171
Senior Notes Three Point Zero Percent Due In Two Thousand Twenty One [Member] | Power [Member]
Debt Instrument [Line Items]
Issued long-term debt		$ 700
Stated interest rate of debt instrument		3.00%
Subsequent Event [Member] | First And Refunding Mortgage Bonds Six Point Seven Five Percentage Due On Two Thousand Sixteen [Member] | PSE And G [Member]
Debt Instrument [Line Items]
Repayments of long-term debt	$ 100

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Debt and Credit Facilities Debt and Credit Facilities (Short-Term Liquidity) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Commitments of Single Institution as Percentage of Total Commitments	7.00%
Line of Credit Facility, Remaining Borrowing Capacity	$ 3,927
Line of Credit Facility, Maximum Borrowing Capacity	4,153
Line of Credit Facility, Fair Value of Amount Outstanding	226
PSEG [Member]
Line of Credit Facility, Remaining Borrowing Capacity	990
Line of Credit Facility, Maximum Borrowing Capacity	1,000
Line of Credit Facility, Fair Value of Amount Outstanding	10	[1]
PSE And G [Member]
Line of Credit Facility, Remaining Borrowing Capacity	586
Line of Credit Facility, Maximum Borrowing Capacity	600
Line of Credit Facility, Fair Value of Amount Outstanding	14	[1]
Power [Member]
Line of Credit Facility, Remaining Borrowing Capacity	2,351
Line of Credit Facility, Maximum Borrowing Capacity	2,553
Line of Credit Facility, Fair Value of Amount Outstanding	202
Five Year Credit Facility Maturing on April 2019 [Member] | PSEG [Member]
Line of Credit Facility, Remaining Borrowing Capacity	$ 490
Debt Instrument, Maturity Date, Description	Apr 2019
Line of Credit Facility, Maximum Borrowing Capacity	$ 500
Line of Credit Facility, Fair Value of Amount Outstanding	10	[1]
Five Year Credit Facility Maturing on April 2019 [Member] | Power [Member]
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,411
Debt Instrument, Maturity Date, Description	Apr 2019
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,600
Line of Credit Facility, Fair Value of Amount Outstanding	189
Five Year Credit Facility Maturing on April 2020 [Member] | PSEG [Member]
Credit Facility Reduction in March 2018	12
Line of Credit Facility, Remaining Borrowing Capacity	$ 500
Debt Instrument, Maturity Date, Description	Apr 2020
Line of Credit Facility, Maximum Borrowing Capacity	$ 500	[2]
Line of Credit Facility, Fair Value of Amount Outstanding	0	[1]
Five Year Credit Facility Maturing on April 2020 [Member] | PSE And G [Member]
Credit Facility Reduction in March 2018	14
Line of Credit Facility, Remaining Borrowing Capacity	$ 586
Debt Instrument, Maturity Date, Description	Apr 2020
Line of Credit Facility, Maximum Borrowing Capacity	$ 600	[3]
Line of Credit Facility, Fair Value of Amount Outstanding	14	[1]
Five Year Credit Facility Maturing on April 2020 [Member] | Power [Member]
Credit Facility Reduction in March 2018	24
Line of Credit Facility, Remaining Borrowing Capacity	$ 940
Debt Instrument, Maturity Date, Description	Apr 2020
Line of Credit Facility, Maximum Borrowing Capacity	$ 953	[4]
Line of Credit Facility, Fair Value of Amount Outstanding	$ 13

[1] The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs. PSEG and PSE&G had no amounts outstanding under their respective CP Programs as of June 30, 2016.

[2] PSEG facility will be reduced by $12 million in March 2018.

[3] PSE&G facility will be reduced by $14 million in March 2018.

[4] Power facility will be reduced by $24 million in March 2018.

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Financial Risk Management Activities (Narrative) (Detail) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016 USD ($) Counterparty	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) Counterparty	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts		$ 8		$ 8		$ (55)
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral		26		26		78
Cash Flow Hedge Derivative Instrument Assets at Fair Value		(1)		(1)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax		1		1
Power [Member]
Derivatives, Fair Value [Line Items]
Net exposure		235		235
Net cash collateral received in connection with net derivative contracts	[1],[2]	$ 8		$ 8		(55)
Number of active counterparties on credit risk derivatives | Counterparty		140		140
Power [Member] | Senior Notes 5.32% Due September 2016 [Member]
Derivatives, Fair Value [Line Items]
Senior Notes converted into variable rate debt		$ 303		$ 303
Power [Member] | Senior Notes 3.00% Due June 2021 [Member]
Derivatives, Fair Value [Line Items]
Stated interest rate of debt instrument		3.00%		3.00%
Debt Instrument, Face Amount		$ 700		$ 700
PSEG [Member]
Derivatives, Fair Value [Line Items]
Fair value of interest rate swaps designated as underlying hedges		2		2		6
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral		18		18		12
Additional collateral aggregate fair value		8		8		66
Amount of reduction in interest expense attributed to interest rate swaps designated as fair value hedges		(2)	$ (5)	(4)	$ (10)
Gain (Loss) on Hedging Activity		2
PSEG [Member] | Senior Notes 5.32% Due September 2016 [Member]
Derivatives, Fair Value [Line Items]
Senior Notes converted into variable rate debt		$ 300		$ 300
Stated interest rate of debt instrument		5.32%		5.32%
PSEG [Member] | Senior Notes 2.75% Due September 2016 [Member]
Derivatives, Fair Value [Line Items]
Senior Notes converted into variable rate debt		$ 250		$ 250
Stated interest rate of debt instrument		2.75%		2.75%
Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts						$ (16)
Investment Grade - External Rating [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Net exposure		$ 205		$ 205
Credit exposure, percentage				90.00%
Fair Value Hedging [Member] | PSEG [Member]
Derivatives, Fair Value [Line Items]
Aggregate amount of series of interest rate swaps converting to variable-rate debt		550		$ 550
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		500
Cash Flow Hedging [Member] | PSEG [Member] | Senior Notes 3.00% Due June 2021 [Member]
Derivatives, Fair Value [Line Items]
Aggregate amount of series of interest rate swaps converting to variable-rate debt		$ 400		$ 400

[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, 2016 and December 31, 2015, net cash collateral (received) paid of $8 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against current assets, and $10 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

[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, 2016 and December 31, 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

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Financial Risk Management Activities (Schedule Of Derivative Instruments Fair Value In Balance Sheets) (Detail) - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets		$ 152	$ 242
Derivative Contracts, Noncurrent Assets		76	77
Total Mark-to-Market Derivative Assets		228	319
Derivative Contracts, Current Liabilities		(20)	(76)
Derivative Contracts, Noncurrent Liabilities		(14)	(27)
Total Mark-to-Market Derivative (Liabilities)		(34)	(103)
Net Mark-to-Market Derivative Assets (Liabilities)		194	216
Net cash collateral received in connection with net derivative contracts		8	(55)
Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	[1]	150	223
Derivative Contracts, Noncurrent Assets	[1]	76	77
Total Mark-to-Market Derivative Assets	[1]	226	300
Derivative Contracts, Current Liabilities	[1]	(17)	(76)
Derivative Contracts, Noncurrent Liabilities	[1]	(14)	(16)
Total Mark-to-Market Derivative (Liabilities)	[1]	(31)	(92)
Net Mark-to-Market Derivative Assets (Liabilities)	[1]	195	208
Net cash collateral received in connection with net derivative contracts	[1],[2]	8	(55)
PSE And G [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets		0	13
Derivative Contracts, Current Liabilities		(2)	0
Derivative Contracts, Noncurrent Liabilities		0	(11)
PSEG [Member] | Interest Rate Swap [Member] | Fair Value Hedging [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	[1]	2	6
Derivative Contracts, Noncurrent Assets	[1]	0	0
Total Mark-to-Market Derivative Assets	[1]	2	6
Derivative Contracts, Current Liabilities	[1]	(1)	0
Derivative Contracts, Noncurrent Liabilities	[1]	0	0
Total Mark-to-Market Derivative (Liabilities)	[1]	(1)	0
Net Mark-to-Market Derivative Assets (Liabilities)	[1]	1	6
Not Designated as Hedging Instrument [Member] | Power [Member] | Energy-Related Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	[1]	460	700
Derivative Contracts, Noncurrent Assets	[1]	264	208
Total Mark-to-Market Derivative Assets	[1]	724	908
Derivative Contracts, Current Liabilities	[1]	(334)	(513)
Derivative Contracts, Noncurrent Liabilities	[1]	(203)	(132)
Total Mark-to-Market Derivative (Liabilities)	[1]	(537)	(645)
Net Mark-to-Market Derivative Assets (Liabilities)	[1]	187	263
Not Designated as Hedging Instrument [Member] | PSE And G [Member] | Energy-Related Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	[1]	0	13
Derivative Contracts, Noncurrent Assets	[1]	0	0
Total Mark-to-Market Derivative Assets	[1]	0	13
Derivative Contracts, Current Liabilities	[1]	(2)	0
Derivative Contracts, Noncurrent Liabilities	[1]	0	(11)
Total Mark-to-Market Derivative (Liabilities)	[1]	(2)	(11)
Net Mark-to-Market Derivative Assets (Liabilities)	[1]	(2)	2
Assets [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts		(2)	(69)
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts		(2)	(53)
Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts			(16)
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts		10	12
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts			2
Other Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts		10	14
Energy-Related Contracts [Member] | Assets [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[3],[4]	(498)	(608)
Energy-Related Contracts [Member] | Assets [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[1],[2],[3],[4]	(498)	(608)
Energy-Related Contracts [Member] | Assets [Member] | PSE And G [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[3],[4]	0	0
Energy-Related Contracts [Member] | Current Assets [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[1],[2]	(310)	(477)
Energy-Related Contracts [Member] | Non Current Assets [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[1],[2]	(188)	(131)
Energy-Related Contracts [Member] | Current Liabilities [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[1],[2]	317	437
Energy-Related Contracts [Member] | Noncurrent Liabilities [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[1],[2]	189	116
Energy-Related Contracts [Member] | Other Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[3],[4]	506	553
Energy-Related Contracts [Member] | Other Liabilities [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[1],[2],[3],[4]	506	553
Energy-Related Contracts [Member] | Other Liabilities [Member] | PSE And G [Member]
Derivatives, Fair Value [Line Items]
Net cash collateral received in connection with net derivative contracts	[3],[4]	$ 0	$ 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, 2016 and December 31, 2015. 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, 2016 and December 31, 2015, net cash collateral (received) paid of $8 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against current assets, and $10 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

[3] 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.

[4] 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, 2016, net cash collateral (received) paid of $8 million was netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against assets, and $10 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets, and $14 million was netted against liabilities.

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Recognized in AOCI on Derivatives (Effective Portion)	$ (1)	$ 0	$ 2	$ 1
Interest Expense	(97)	(97)	(189)	(195)
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	0	0	0	0
Operating Revenues	1,905	2,314	4,521	5,449
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Reclassified from AOCI into Energy Costs (Effective Portion)	0	0	0	17
Power [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		0	1
Interest Expense	(20)	(33)	(42)	(64)
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	0	0	0	0
Operating Revenues	714	1,025	2,027	2,750
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Reclassified from AOCI into Energy Costs (Effective Portion)	0	0	0	17
Operating Revenues [Member] | Energy-Related Contracts [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	0	0	1
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	0	0	0	17
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	0	0	0	0
Operating Revenues [Member] | Power [Member] | Energy-Related Contracts [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	0	0	1
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	0	0	0	17
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective 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)	(1)	0	2	0
Interest Expense	0	0	0	0
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective 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, 2016	Mar. 31, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) in AOCI	$ 7		$ (14)	$ 19	$ 3
(Gain) Loss into Income	10		7	24	3
Cash Flow Hedges [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Pre-Tax Balance at Beginning of Period	3	$ 0		0	17	$ 17
Gain (Loss) in AOCI	(1)	3				3
(Gain) Loss into Income	0	0	0		(17)	(20)
Pre-Tax Balance at End of Period	2	3		2		0
After-Tax Balance at Beginning of Period	2	0		0	10	10
Gain (Loss) in AOCI	(1)	2	0	1	1	2
(Gain) Loss into Income	0	0	$ 0	0	$ (10)	(12)
After-Tax Balance at End of Period	$ 1	$ 2		$ 1		$ 0

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Financial Risk Management Activities (Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Impact On Results Of Operations) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	$ (80)	$ 114	$ 138	$ 48
Operating Revenues [Member] | Energy-Related Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	(86)	124	130	48
Energy Costs [Member] | Energy-Related Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	$ 6	$ (10)	$ 8	$ 0

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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	12 Months Ended
	Jun. 30, 2016 $ / mwh $ / Derivative $ / DTH	Dec. 31, 2015 $ / mwh $ / Derivative $ / DTH
Natural Gas Dth [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / DTH	347	201
Electricity MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	326	299
FTRs MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	21	23
Interest Rate Swaps [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / Derivative	1,050	550
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	1,050	550
Power [Member] | Natural Gas Dth [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis | $ / DTH	327	168
Power [Member] | Electricity MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	326	299
Power [Member] | FTRs MWh [Member]
Derivative [Line Items]
Gross Volume of Derivative on Absolute Value Basis	21	23
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	20	33
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, 2016 USD ($)
Derivative [Line Items]
Current Exposure	$ 365
Securities held as Collateral	130
Net exposure	235
Number of Counterparties greater than 10%	2
Amount Of Net Credit Exposure Greater Than Ten Percent	125
Investment Grade - External Rating [Member]
Derivative [Line Items]
Current Exposure	334
Securities held as Collateral	129
Net exposure	205
Number of Counterparties greater than 10%	2
Amount Of Net Credit Exposure Greater Than Ten Percent	125	[1]
Non-Investment Grade - External Rating [Member]
Derivative [Line Items]
Current Exposure	20
Securities held as Collateral	0
Net exposure	20
Number of Counterparties greater than 10%	0
Amount Of Net Credit Exposure Greater Than Ten Percent	0
Investment Grade - No External Rating [Member]
Derivative [Line Items]
Current Exposure	8
Securities held as Collateral	1
Net exposure	7
Number of Counterparties greater than 10%	0
Amount Of Net Credit Exposure Greater Than Ten Percent	0
Non-Investment Grade - No External Rating [Member]
Derivative [Line Items]
Current Exposure	3
Securities held as Collateral	0
Net exposure	3
Number of Counterparties greater than 10%	0
Amount Of Net Credit Exposure Greater Than Ten Percent	0
Cash [Member]
Derivative [Line Items]
Securities held as Collateral	3
Letter of Credit [Member]
Derivative [Line Items]
Securities held as Collateral	$ 127

[1] Represents net exposure of $94 million with PSE&G. The remaining net exposure of $31 million is with a non-affiliated power purchaser which is an investment grade counterparty.

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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, 2016		Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets		$ 228		$ 319
Total Mark-to-Market Derivative (Liabilities)		(34)		(103)
Collateral netted against assets and liabilities		8		(55)
Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]	0
Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]	0
Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]	0
Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]	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],[2]	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],[2]	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],[2]	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],[2]	0
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[3]	226		300
Total Mark-to-Market Derivative (Liabilities)	[3]	(31)		(92)
Collateral netted against assets and liabilities	[3],[4]	8		(55)
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],[2]	0		0
Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]	0		0
Power [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]	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],[2]	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],[2]	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],[2]	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],[2]	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],[2]	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],[2]	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],[2]	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],[2]	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],[2]	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	[5]	570		326
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	[2]	865		865
Quoted Market Prices of Identical Assets (Level 1) [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	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	[2]	49		42
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	[2]	21		22
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	[2]	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	[2]	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	[2]	5		2
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	[2]	865		865
Quoted Market Prices of Identical Assets (Level 1) [Member] | Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	0		0
Quoted Market Prices of Identical Assets (Level 1) [Member] | Power [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	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	[2]	49		42
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	[2]	5		5
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	[2]	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	[2]	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	[2]	1		1
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	[5]	125		160
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	[2]	4		5
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	[2]	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	[2]	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	[2]	1		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	[5]	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	[2]	0		0
Significant Other Observable Inputs (Level 2) [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	526		488
Significant Other Observable Inputs (Level 2) [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	357		359
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	[2]	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	[2]	0		0
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	106		108
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	[2]	90		81
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	[2]	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	[2]	0		0
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	526		488
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	357		359
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	[2]	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	[2]	0		0
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	26		26
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	[2]	22		20
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	[2]	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	[5]	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	[2]	0		0
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	[2]	21		21
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	[2]	18		16
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	[2]	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	[5]	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	[2]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	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	[2]	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	[2]	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	[2]	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	[2]	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	[2]	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	[2]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	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	[2]	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	[2]	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	[2]	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	[2]	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	[2]	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	[5]	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	[2]	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	[2]	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	[2]	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	[2]	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	[5]	570		326
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	[2]	865		865
Total Estimate Of Fair Value [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	526		488
Total Estimate Of Fair Value [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	357		359
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	[2]	49		42
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	[2]	21		22
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	[2]	106		108
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	[2]	90		81
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	[2]	5		2
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	[2]	865		865
Total Estimate Of Fair Value [Member] | Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	526		488
Total Estimate Of Fair Value [Member] | Power [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[2]	357		359
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	[2]	49		42
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	[2]	5		5
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	[2]	26		26
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	[2]	22		20
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	[2]	1		1
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	[5]	125		160
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	[2]	4		5
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	[2]	21		21
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	[2]	18		16
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	[2]	1		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]	0		0
Total Mark-to-Market Derivative (Liabilities)	[6]	0		0
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]	0		0
Total Mark-to-Market Derivative (Liabilities)	[6]	0		0
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		0
Total Mark-to-Market Derivative (Liabilities)	[6]	0		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]	717		896
Total Mark-to-Market Derivative (Liabilities)	[6]	(537)		(644)
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]	717		896
Total Mark-to-Market Derivative (Liabilities)	[6]	(537)		(644)
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		0
Total Mark-to-Market Derivative (Liabilities)	[6]	0		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]	7		25
Total Mark-to-Market Derivative (Liabilities)	[6]	(2)		(12)
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]	7		12
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		13
Total Mark-to-Market Derivative (Liabilities)	[6]	(2)		(11)
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]	226		313
Total Mark-to-Market Derivative (Liabilities)		(33)	[6]	(103)
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]	226		300
Total Mark-to-Market Derivative (Liabilities)	[6]	(31)		(92)
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		13
Total Mark-to-Market Derivative (Liabilities)	[6]	(2)		(11)
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]	2		6
Total Mark-to-Market Derivative (Liabilities)	[7]	(1)
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]	2		6
Total Mark-to-Market Derivative (Liabilities)	[7]	(1)
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],[5]	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],[5]	0		0
Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities		(2)		(69)
Assets [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]			0
Assets [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]			0
Assets [Member] | Other Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]			0
Assets [Member] | Other Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities	[1],[2]			0
Assets [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],[2]			0
Assets [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],[2]			0
Assets [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],[2]			0
Assets [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],[2]			0
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],[6]	(498)		(608)
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],[3],[4],[6]	(498)		(608)
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],[6]	0		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],[7]	0		0
Other Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral netted against assets and liabilities		10		14
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],[6]	506		553
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],[3],[4],[6]	506		553
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],[6]	0		$ 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],[7]	$ 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, 2016, net cash collateral (received) paid of $8 million was netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against assets, and $10 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets, and $14 million was netted against liabilities.

[2] The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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.

[3] 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, 2016 and December 31, 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

[4] 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, 2016 and December 31, 2015, net cash collateral (received) paid of $8 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2016, $(2) million of cash collateral was netted against current assets, and $10 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

[5] Represents money market mutual funds

[6] 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.

[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, 2016	Jun. 30, 2015	Dec. 31, 2015
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	$ 7		$ 12
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		13
Liabilities, Fair Value	(2)		(11)
PSEG [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	7		25
Liabilities, Fair Value	(2)		(12)
Various [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value			1
Liabilities, Fair Value			0
Electric Load Contracts [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	7		11
Liabilities, Fair Value	$ 0		(1)
Valuation Technique (s)	Discounted Cash flow	Discounted Cash Flow
Significant Unobservable Inputs	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		13
Liabilities, Fair Value	$ (2)		$ (11)
Valuation Technique (s)	Discounted Cash Flow	Discounted Cash Flow
Significant Unobservable Inputs	Transportation Costs	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	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	0.80

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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, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Settlements		$ (5)		$ (4)		$ (20)		$ (16)
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		1		5		16		8
Gains and losses attributable to changes in net derivative assets and liabilities, unrealized		(4)				(4)		(9)
Net Derivative Assets (Liabilities) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Opening Balance		21		9		13		37
Included in Income		1	[1]	5	[2]	16	[1]	8	[2]
Included in Regulatory Assets/Liabilities	[3]	(12)		(2)		(4)		(21)
Purchases, (Sales)		0		0		0		0
Issuances (Settlements)	[4]	(5)		(4)		(20)		(16)
Transfers In (Out)	[5]	0		0		0		0
Closing Balance		5		8		5		8
Net Derivative Assets (Liabilities) [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Opening Balance		11		2		11		11
Included in Income		1	[1]	5	[2]	16	[1]	8	[2]
Included in Regulatory Assets/Liabilities	[3]	0		0		0		0
Purchases, (Sales)		0		0		0		0
Issuances (Settlements)	[4]	(5)		(4)		(20)		(16)
Transfers In (Out)	[5]	0		0		0		0
Closing Balance		7		3		7		3
Net Derivative Assets (Liabilities) [Member] | PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Opening Balance		10		7		2		26
Included in Income		0	[1]	0	[2]	0	[1]	0	[2]
Included in Regulatory Assets/Liabilities	[3]	(12)		(2)		(4)		(21)
Purchases, (Sales)		0		0		0		0
Issuances (Settlements)	[4]	0		0		0		0
Transfers In (Out)	[5]	0		0		0		0
Closing Balance		$ (2)		$ 5		$ (2)		$ 5

[1] 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.

[2] PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $5 million and $8 million in Operating Income for the three months and six months ended June 30, 2015, respectively. The $5 million in Operating Income is realized. Of the $8 million in Operating Income, $(9) million is unrealized.

[3] 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.

[4] Represents $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively. Represents $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015, respectively.

[5] There were no transfers among levels during the three months and six months ended June 30, 2016 and 2015.

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Fair Value Measurements (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	$ 5	$ 4	$ 20	$ 16
Net assets measured at fair value on a recurring basis	2,800		2,800		$ 2,700
Net assets measured at fair value on a recurring basis measured using unobservable input and as Level 3	5		5		$ 8
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	(4)		(4)	(9)
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Trading Revenue	$ 1	$ 5	$ 16	$ 8

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Fair Value Measurements (Fair Value Of Debt) (Detail) - USD ($) $ in Millions		Jun. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount		$ 10,935	$ 9,568
Long-Term Debt, Fair Value		12,407	10,256
Power - Recourse Debt [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount	[1]	2,933	2,237
Long-Term Debt, Fair Value	[1]	3,274	2,508
PSE And G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount	[1]	7,494	6,821
Long-Term Debt, Fair Value	[1]	8,624	7,235
Energy Holdings Project Level, Non-Recourse Debt [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount	[2]	7	7
Long-Term Debt, Fair Value	[2]	7	7
PSEG [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-Term Debt, Carrying Amount	[3]	501	503
Long-Term Debt, Fair Value	[3]	$ 502	$ 506

[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] Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

[3] Fair value includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

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Other Income And Deductions (Schedule Of Other Income) (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Component of Other Income [Line Items]
NDT Fund Gains, Interest, Dividend and Other Income		$ 23	$ 25	$ 48	$ 54
Allowance for Funds Used During Construction		10	12	21	22
Solar Loan Interest		5	6	11	12
Gain on Insurance Recovery			28		28
Other		6	5	12	8
Total Other Income		44	76	92	124
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		10	12	21	22
Solar Loan Interest		5	6	11	12
Gain on Insurance Recovery			0		0
Other		4	1	7	3
Total Other Income		19	19	39	37
Power [Member]
Component of Other Income [Line Items]
NDT Fund Gains, Interest, Dividend and Other Income		23	25	48	54
Allowance for Funds Used During Construction		0	0	0	0
Solar Loan Interest		0	0	0	0
Gain on Insurance Recovery			28		28
Other		2	2	3	2
Total Other Income		25	55	51	84
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
Solar Loan Interest	[1]	0	0	0	0
Gain on Insurance Recovery	[1]		0		0
Other	[1]	0	2	2	3
Total Other Income	[1]	$ 0	$ 2	$ 2	$ 3

[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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Component of Other Deductions [Line Items]
NDT Fund Realized Losses and Expenses		$ 8	$ 6	$ 26	$ 17
Other		2	4	5	5
Total Other Deductions		10	10	31	22
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		8	6	26	17
Other		1	1	1	1
Total Other Deductions		9	7	27	18
Other Entities [Member]
Component of Other Deductions [Line Items]
NDT Fund Realized Losses and Expenses	[1]	0	0	0	0
Other	[1]	0	2	2	2
Total Other Deductions	[1]	$ 0	$ 2	$ 2	$ 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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Taxes [Line Items]
Effective tax rate	32.70%	35.00%	36.20%	38.50%
PSE And G [Member]
Income Taxes [Line Items]
Effective tax rate	35.40%	38.40%	36.10%	39.00%
Power [Member]
Income Taxes [Line Items]
Effective tax rate	50.00%	30.30%	39.50%	37.90%

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Income Taxes (Narrative) (Detail)	6 Months Ended
	Jun. 30, 2016
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%

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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, 2016	Mar. 31, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	$ (269)	$ (295)	$ (270)	$ (295)	$ (283)	$ (283)
Other Comprehensive Income before Reclassifications	7		(14)	19	3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	10		7	24	3
Other Comprehensive Income (Loss), net of tax	17		(7)	43	6
Accumulated Other Comprehensive Income (Loss), Ending Balance	(252)	(269)	(277)	(252)	(277)	(295)
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	2	0	1	0	10	10
Other Comprehensive Income before Reclassifications	(1)	2	0	1	1	2
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	0	0	0	0	(10)	(12)
Other Comprehensive Income (Loss), net of tax	(1)		0	1	(9)
Accumulated Other Comprehensive Income (Loss), Ending Balance	1	2	1	1	1	0
Pension and OPEB Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	(378)	(386)	(403)	(386)	(411)	(411)
Other Comprehensive Income before Reclassifications	0		0	0	0
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	8		8	16	16
Other Comprehensive Income (Loss), net of tax	8		8	16	16
Accumulated Other Comprehensive Income (Loss), Ending Balance	(370)	(378)	(395)	(370)	(395)	(386)
Available-for-Sale Securities [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	107	91	132	91	118	118
Other Comprehensive Income before Reclassifications	8		(14)	18	2
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	2		(1)	8	(3)
Other Comprehensive Income (Loss), net of tax	10		(15)	26	(1)
Accumulated Other Comprehensive Income (Loss), Ending Balance	117	107	117	117	117	91
Power [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	(217)	(240)	(216)	(240)	(228)	(228)
Other Comprehensive Income before Reclassifications	6		(14)	16	3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	10		7	23	2
Other Comprehensive Income (Loss), net of tax	16		(7)	39	5
Accumulated Other Comprehensive Income (Loss), Ending Balance	(201)	(217)	(223)	(201)	(223)	(240)
Power [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	0	0	2	0	11	11
Other Comprehensive Income before Reclassifications	0		0	0	1
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	0		0	0	(10)
Other Comprehensive Income (Loss), net of tax	0		0	0	(9)
Accumulated Other Comprehensive Income (Loss), Ending Balance	0	0	2	0	2	0
Power [Member] | Pension and OPEB Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	(320)	(327)	(344)	(327)	(351)	(351)
Other Comprehensive Income before Reclassifications	0		0	0	0
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	7		7	14	14
Other Comprehensive Income (Loss), net of tax	7		7	14	14
Accumulated Other Comprehensive Income (Loss), Ending Balance	(313)	(320)	(337)	(313)	(337)	(327)
Power [Member] | Available-for-Sale Securities [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	103	87	126	87	112	112
Other Comprehensive Income before Reclassifications	6		(14)	16	2
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	3		0	9	(2)
Other Comprehensive Income (Loss), net of tax	9		(14)	25	0
Accumulated Other Comprehensive Income (Loss), Ending Balance	$ 112	$ 103	$ 112	$ 112	$ 112	$ 87

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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, 2016	Mar. 31, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	$ (19)		$ (12)	$ (44)	$ (4)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Tax	9		5	20	1
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(10)		(7)	(24)	(3)
Cash Flow Hedges [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Energy-Related Contracts, Pre-Tax	0	$ 0	0		17	$ 20
Energy-Related Contracts, Tax			0		(7)
Energy-Related Contracts, After-Tax			0		10
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	$ 0	0	0	10	$ 12
Pension and OPEB Plans [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification Adjustment from AOCI, Pension and OPEB, Pre-Tax	(14)		(14)	(28)	(28)
Reclassification Adjustment from AOCI, Pension and OPEB, Tax	6		6	12	12
Reclassification Adjustment from AOCI, Pension and OPEB, After-Tax	(8)		(8)	(16)	(16)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(8)		(8)	(16)	(16)
Available-for-Sale Securities [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification for Available for Sale Securities, Pre-Tax	(5)		2	(16)	7
Reclassification for Available for Sale Securities, Tax	3		(1)	8	(4)
Reclassification for Available for Sale Securities, After-Tax	(2)		1	(8)	3
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(2)		1	(8)	3
Power [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	(18)		(12)	(41)	(2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Tax	8		5	18	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(10)		(7)	(23)	(2)
Power [Member] | Cash Flow Hedges [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Energy-Related Contracts, Pre-Tax			0		17
Energy-Related Contracts, Tax			0		(7)
Energy-Related Contracts, After-Tax			0		10
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0		0	0	10
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	(12)		(12)	(24)	(24)
Reclassification Adjustment from AOCI, Pension and OPEB, Tax	5		5	10	10
Reclassification Adjustment from AOCI, Pension and OPEB, After-Tax	(7)		(7)	(14)	(14)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(7)		(7)	(14)	(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	(6)		0	(17)	5
Reclassification for Available for Sale Securities, Tax	3		0	8	(3)
Reclassification for Available for Sale Securities, After-Tax	(3)		0	(9)	2
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(3)		0	(9)	2
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	3		3	6	6
Amortization of Prior Service (Cost) Credit, Tax	(1)		(1)	(2)	(2)
Amortization of Prior Service (Cost) Credit, After-Tax	2		2	4	4
Amortization of Actuarial Loss, Pre-Tax	(17)		(17)	(34)	(34)
Amortization of Actuarial Loss, Tax	7		7	14	14
Amortization of Actuarial Loss, After-Tax	(10)		(10)	(20)	(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		3	5	6
Amortization of Prior Service (Cost) Credit, Tax	(1)		(1)	(2)	(2)
Amortization of Prior Service (Cost) Credit, After-Tax	1		2	3	4
Amortization of Actuarial Loss, Pre-Tax	(14)		(15)	(29)	(30)
Amortization of Actuarial Loss, Tax	6		6	12	12
Amortization of Actuarial Loss, After-Tax	(8)		(9)	(17)	(18)
Operating Revenues [Member] | Cash Flow Hedges [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Energy-Related Contracts, Pre-Tax			0		17
Energy-Related Contracts, Tax			0		(7)
Energy-Related Contracts, After-Tax			0		10
Operating Revenues [Member] | Power [Member] | Cash Flow Hedges [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Energy-Related Contracts, Pre-Tax			0		17
Energy-Related Contracts, Tax			0		(7)
Energy-Related Contracts, After-Tax			0		10
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	12		16	28	35
Reclassification for Available for Sale Securities, Tax	(6)		(8)	(14)	(18)
Reclassification for Available for Sale Securities, After-Tax	6		8	14	17
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	10		14	25	33
Reclassification for Available for Sale Securities, Tax	(5)		(7)	(13)	(17)
Reclassification for Available for Sale Securities, After-Tax	5		7	12	16
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	(7)		(4)	(24)	(13)
Reclassification for Available for Sale Securities, Tax	4		2	12	7
Reclassification for Available for Sale Securities, After-Tax	(3)		(2)	(12)	(6)
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	(6)		(4)	(22)	(13)
Reclassification for Available for Sale Securities, Tax	3		2	11	7
Reclassification for Available for Sale Securities, After-Tax	(3)		(2)	(11)	(6)
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	(10)		(10)	(20)	(15)
Reclassification for Available for Sale Securities, Tax	5		5	10	7
Reclassification for Available for Sale Securities, After-Tax	(5)		(5)	(10)	(8)
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	(10)		(10)	(20)	(15)
Reclassification for Available for Sale Securities, Tax	5		5	10	7
Reclassification for Available for Sale Securities, After-Tax	$ (5)		$ (5)	$ (10)	$ (8)

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Net Income	$ 187	$ 345	$ 658	$ 931
Weighted Average Common Shares Outstanding, Basic (shares)	505	506	505	506
Effect of Stock Based Compensation Awards, Basic (shares)	0	0	0	0
Total Shares, Basic (shares)	505	506	505	506
Net Income, Basic (in dollars per share)	$ 0.37	$ 0.68	$ 1.30	$ 1.84
Weighted Average Common Shares Outstanding, Diluted (shares)	505	506	505	506
Effect of Stock Based Compensation Awards, Diluted (shares)	3	2	3	2
Total Shares, Diluted (shares)	508	508	508	508
Net Income, Diluted (in dollars per share)	$ 0.37	$ 0.68	$ 1.30	$ 1.83

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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
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share [Abstract]
DIVIDENDS PAID PER SHARE OF COMMON STOCK (in dollars per share)	$ 0.41	$ 0.39	$ 0.82	$ 0.78
Dividend Payments on Common Stock	$ 208	$ 197	$ 415	$ 394

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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, 2016		Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating Revenues		$ 1,905		$ 2,314		$ 4,521	$ 5,449
Net Income (Loss)		187		345		658	931
Property, Plant and Equipment, Additions		906		996		1,971	1,743
Total Assets		39,045				39,045		$ 37,535
Investments in Equity Method Subsidiaries		112				112		119
Operating Segments [Member] | PSE And G [Member]
Segment Reporting Information [Line Items]
Operating Revenues		1,350		1,466		3,062	3,468
Net Income (Loss)		179		167		441	409
Property, Plant and Equipment, Additions		631		631		1,355	1,230
Total Assets		24,737				24,737		23,677
Investments in Equity Method Subsidiaries		0				0		0
Operating Segments [Member] | Power [Member]
Segment Reporting Information [Line Items]
Operating Revenues		714		1,025		2,027	2,750
Net Income (Loss)		(11)		166		181	501
Property, Plant and Equipment, Additions		265		348		598	487
Total Assets		13,278				13,278		12,250
Investments in Equity Method Subsidiaries		112				112		119
Operating Segments [Member] | Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]	127		108		249	206
Net Income (Loss)	[1]	19		12		36	21
Property, Plant and Equipment, Additions	[1]	10		17		18	26
Total Assets	[1]	2,873				2,873		2,810
Investments in Equity Method Subsidiaries	[1]	0				0		0
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[2]	(286)		(285)		(817)	(975)
Net Income (Loss)		0	[2]	0	[2]	0	0
Property, Plant and Equipment, Additions		0	[2]	$ 0	[2]	0	$ 0
Total Assets	[2]	(1,843)				(1,843)		(1,202)
Investments in Equity Method Subsidiaries		$ 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 primarily relate 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 17. 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, 2016	Jun. 30, 2015	Jun. 30, 2016		Jun. 30, 2015
PSE And G [Member]
Related Party Transaction [Line Items]
Billings from Power through BGS and BGSS	[1]	$ 297	$ 297	$ 842		$ 993
Administrative Billings from Services	[2]	82	65	151		131
Total Billings from Affiliates		379	362	993		1,124
Power [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties		297	297	842	[1]	993	[1]
Administrative Billings from Services		$ 45	$ 46	$ 90	[2]	$ 91	[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 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, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Receivable From PSEG	[1]	$ 0	$ 222
Payable To Power	[2]	94	212
Payable To Services	[3]	79	80
Payable to PSEG	[1]	6	0
Accounts Payable - Affiliated Companies		179	292
Working Capital Advances to Services	[4]	33	33
Long-Term Accrued Taxes Payable		$ 99	$ 109

[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 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, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Receivable from PSE&G	[1]	$ 94	$ 212
Receivable From PSEG	[2]	0	64
Due from Affiliate, Current		94	276
Payable To Services	[3]	28	33
Payable to PSEG	[2]	74	0
Accounts Payable - Affiliated Companies		102	33
Short Term Loan To Affiliate	[4]	1,335	363
Working Capital Advances to Services	[5]	17	17
Long-Term Accrued Taxes Payable		$ 22	$ 35

[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 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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Operating Revenues	$ 1,905	$ 2,314	$ 4,521	$ 5,449
Operating Expenses	1,558	1,746	3,347	3,833
Operating Income (Loss)	347	568	1,174	1,616
Equity Earnings (Losses) of Subsidiaries	4	4	6	7
Other Income	44	76	92	124
Other Deductions	(10)	(10)	(31)	(22)
Other-Than-Temporary Impairments	(10)	(10)	(20)	(15)
Interest Expense	(97)	(97)	(189)	(195)
Income Tax Expense	(91)	(186)	(374)	(584)
Net Income	187	345	658	931
Net Cash Provided By (Used In) Operating Activities			1,722	2,234
Net Cash Provided By (Used In) Investing Activities			(2,004)	(1,773)
Net Cash Provided By (Used In) Financing Activities			536	(266)
Current Assets	3,489		3,489		$ 3,494
Property, Plant and Equipment, net	28,014		28,014		26,539
Noncurrent Assets	7,542		7,542		7,502
Total Assets	39,045		39,045		37,535
Current Liabilities	3,120		3,120		3,575
Noncurrent Liabilities	12,333		12,333		12,059
Long-Term Debt	10,273		10,273		8,834
Member's Equity	13,319		13,319		13,067
TOTAL LIABILITIES AND CAPITALIZATION	39,045		39,045		37,535
Power Senior Notes [Member]
Debt Instrument [Line Items]
Operating Revenues	714	1,025	2,027	2,750
Operating Expenses	726	797	1,696	1,938
Operating Income (Loss)	(12)	228	331	812
Equity Earnings (Losses) of Subsidiaries	4	5	6	8
Other Income	25	55	51	84
Other Deductions	(9)	(7)	(27)	(18)
Other-Than-Temporary Impairments	(10)	(10)	(20)	(15)
Interest Expense	(20)	(33)	(42)	(64)
Income Tax Expense	11	(72)	(118)	(306)
Net Income	(11)	166	181	501
Comprehensive Income (Loss)	5	159	220	506
Net Cash Provided By (Used In) Operating Activities			917	1,292
Net Cash Provided By (Used In) Investing Activities			(1,607)	(887)
Net Cash Provided By (Used In) Financing Activities			694	(402)
Current Assets	2,548		2,548		1,949
Property, Plant and Equipment, net	8,478		8,478		8,127
Investment in Subsidiaries	0		0		0
Noncurrent Assets	2,252		2,252		2,174
Total Assets	13,278		13,278		12,250
Current Liabilities	1,263		1,263		1,226
Noncurrent Liabilities	3,413		3,413		3,338
Long-Term Debt	2,380		2,380		1,684
Member's Equity	6,222		6,222		6,002
TOTAL LIABILITIES AND CAPITALIZATION	13,278		13,278		12,250
Power Senior Notes [Member] | Consolidating Adjustments [Member]
Debt Instrument [Line Items]
Operating Revenues	(32)	(26)	(63)	(84)
Operating Expenses	(32)	(26)	(63)	(84)
Operating Income (Loss)	0	0	0	0
Equity Earnings (Losses) of Subsidiaries	0	(185)	(204)	(533)
Other Income	(22)	(12)	(45)	(24)
Other Deductions	0	0	0	0
Other-Than-Temporary Impairments	0	0	0	0
Interest Expense	22	12	45	24
Income Tax Expense	0	0	0	0
Net Income	0	(185)	(204)	(533)
Comprehensive Income (Loss)	(9)	(171)	(229)	(524)
Net Cash Provided By (Used In) Operating Activities			(356)	(687)
Net Cash Provided By (Used In) Investing Activities			579	766
Net Cash Provided By (Used In) Financing Activities			(223)	(79)
Current Assets	(4,828)		(4,828)		(4,828)
Property, Plant and Equipment, net	0		0		0
Investment in Subsidiaries	(4,764)		(4,764)		(4,847)
Noncurrent Assets	(51)		(51)		(76)
Total Assets	(9,643)		(9,643)		(9,751)
Current Liabilities	(4,828)		(4,828)		(4,828)
Noncurrent Liabilities	(51)		(51)		(76)
Long-Term Debt	0		0		0
Member's Equity	(4,764)		(4,764)		(4,847)
TOTAL LIABILITIES AND CAPITALIZATION	(9,643)		(9,643)		(9,751)
Power Senior Notes [Member] | Power Parent [Member]
Debt Instrument [Line Items]
Operating Revenues	0	0	0	0
Operating Expenses	2	(1)	12	4
Operating Income (Loss)	(2)	1	(12)	(4)
Equity Earnings (Losses) of Subsidiaries	(1)	186	204	535
Other Income	17	12	34	23
Other Deductions	0	(1)	0	(1)
Other-Than-Temporary Impairments	0	0	0	0
Interest Expense	(31)	(33)	(61)	(62)
Income Tax Expense	6	1	16	10
Net Income	(11)	166	181	501
Comprehensive Income (Loss)	5	159	220	506
Net Cash Provided By (Used In) Operating Activities			337	410
Net Cash Provided By (Used In) Investing Activities			(1,287)	(480)
Net Cash Provided By (Used In) Financing Activities			951	70
Current Assets	5,490		5,490		4,501
Property, Plant and Equipment, net	58		58		83
Investment in Subsidiaries	4,419		4,419		4,501
Noncurrent Assets	134		134		155
Total Assets	10,101		10,101		9,240
Current Liabilities	1,079		1,079		1,112
Noncurrent Liabilities	420		420		442
Long-Term Debt	2,380		2,380		1,684
Member's Equity	6,222		6,222		6,002
TOTAL LIABILITIES AND CAPITALIZATION	10,101		10,101		9,240
Power Senior Notes [Member] | Guarantor Subsidiaries [Member]
Debt Instrument [Line Items]
Operating Revenues	700	1,012	2,002	2,727
Operating Expenses	716	787	1,668	1,918
Operating Income (Loss)	(16)	225	334	809
Equity Earnings (Losses) of Subsidiaries	1	(1)	0	(2)
Other Income	30	55	62	85
Other Deductions	(9)	(6)	(27)	(17)
Other-Than-Temporary Impairments	(10)	(10)	(20)	(15)
Interest Expense	(7)	(7)	(17)	(16)
Income Tax Expense	3	(73)	(137)	(315)
Net Income	(8)	183	195	529
Comprehensive Income (Loss)	1	169	220	520
Net Cash Provided By (Used In) Operating Activities			777	1,508
Net Cash Provided By (Used In) Investing Activities			(504)	(963)
Net Cash Provided By (Used In) Financing Activities			(273)	(543)
Current Assets	1,655		1,655		1,912
Property, Plant and Equipment, net	6,476		6,476		6,502
Investment in Subsidiaries	345		345		346
Noncurrent Assets	2,041		2,041		1,959
Total Assets	10,517		10,517		10,719
Current Liabilities	3,719		3,719		3,866
Noncurrent Liabilities	2,652		2,652		2,597
Long-Term Debt	0		0		0
Member's Equity	4,146		4,146		4,256
TOTAL LIABILITIES AND CAPITALIZATION	10,517		10,517		10,719
Power Senior Notes [Member] | Non-Guarantor Subsidiaries [Member]
Debt Instrument [Line Items]
Operating Revenues	46	39	88	107
Operating Expenses	40	37	79	100
Operating Income (Loss)	6	2	9	7
Equity Earnings (Losses) of Subsidiaries	4	5	6	8
Other Income	0	0	0	0
Other Deductions	0	0	0	0
Other-Than-Temporary Impairments	0	0	0	0
Interest Expense	(4)	(5)	(9)	(10)
Income Tax Expense	2	0	3	(1)
Net Income	8	2	9	4
Comprehensive Income (Loss)	8	$ 2	9	4
Net Cash Provided By (Used In) Operating Activities			159	61
Net Cash Provided By (Used In) Investing Activities			(395)	(210)
Net Cash Provided By (Used In) Financing Activities			239	$ 150
Current Assets	231		231		364
Property, Plant and Equipment, net	1,944		1,944		1,542
Investment in Subsidiaries	0		0		0
Noncurrent Assets	128		128		136
Total Assets	2,303		2,303		2,042
Current Liabilities	1,293		1,293		1,076
Noncurrent Liabilities	392		392		375
Long-Term Debt	0		0		0
Member's Equity	618		618		591
TOTAL LIABILITIES AND CAPITALIZATION	$ 2,303		$ 2,303		$ 2,042