PEG 10-Q Quarterly Report June 30, 2015

PUBLIC SERVICE ENTERPRISE GROUP INC

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10-Q 1 pseg-6302015xq2.htm 10-Q PSEG-6/30/2015-Q2

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED June 30, 2015

¨ 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, P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com	22-2625848
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza, P.O. Box 570 Newark, New Jersey 07101-0570 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 07102-4194 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 21, 2015 , Public Service Enterprise Group Incorporated had outstanding 505,874,772 shares of its sole class of Common Stock, without par value.

As of July 21, 2015 , 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.

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		Page
FORWARD-LOOKING STATEMENTS		ii

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)	17
	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)	27
	Note 8. Commitments and Contingent Liabilities	28
	Note 9. Changes in Capitalization	35
	Note 10. Financial Risk Management Activities	35
	Note 11. Fair Value Measurements	42
	Note 12. Other Income and Deductions	50
	Note 13. Income Taxes	51
	Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax	52
	Note 15. Earnings Per Share (EPS) and Dividends	56
	Note 16. Financial Information by Business Segments	57
	Note 17. Related-Party Transactions	58
	Note 18. Guarantees of Debt	60
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	63
	Executive Overview of 2015 and Future Outlook	63
	Results of Operations	68
	Liquidity and Capital Resources	73
	Capital Requirements	75
	Accounting Matters	75
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	76
Item 4.	Controls and Procedures	77

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	77
Item 1A.	Risk Factors	77
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	77
Item 5.	Other Information	77
Item 6.	Exhibits	81
	Signatures	82

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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 the price 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,


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


•	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 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,


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


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


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


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


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


•	delays or unforeseen cost escalations in our construction and development activities,


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


•	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,


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


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


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


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


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


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

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition 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.

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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,
	2015			2014			2015			2014
OPERATING REVENUES	$	2,314		$	2,249		$	5,449		$	5,472
OPERATING EXPENSES
Energy Costs	668			789			1,762			2,145
Operation and Maintenance	761			800			1,424			1,656
Depreciation and Amortization	317			295			647			601
Total Operating Expenses	1,746			1,884			3,833			4,402
OPERATING INCOME	568			365			1,616			1,070
Income from Equity Method Investments	4			3			7			7
Other Income	76			62			124			110
Other Deductions	(10		)	(10		)	(22		)	(22		)
Other-Than-Temporary Impairments	(10		)	(2		)	(15		)	(4		)
Interest Expense	(97		)	(94		)	(195		)	(191		)
INCOME BEFORE INCOME TAXES	531			324			1,515			970
Income Tax Expense	(186		)	(112		)	(584		)	(372		)
NET INCOME	$	345		$	212		$	931		$	598
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	506			506			506			506
DILUTED	508			508			508			508
NET INCOME PER SHARE:
BASIC	$	0.68		$	0.42		$	1.84		$	1.18
DILUTED	$	0.68		$	0.42		$	1.83		$	1.18
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.39		$	0.37		$	0.78		$	0.74

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
NET INCOME	$	345		$	212	$	931		$	598
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $15, $(9), $2 and $(12) for the three and six months ended 2015 and 2014, respectively	(15		)	11		(1		)	13
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $7, and $(2) for the three and six months ended 2015 and 2014, respectively	—			1		(9		)	3
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(6), $(1), $(12) and $(3) for three and six months ended 2015 and 2014, respectively	8			2		16			6
Other Comprehensive Income (Loss), net of tax	(7		)	14		6			22
COMPREHENSIVE INCOME	$	338		$	226	$	937		$	620

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	597		$	402
Accounts Receivable, net of allowances of $60 and $52 in 2015 and 2014, respectively	1,126			1,254
Tax Receivable	23			211
Unbilled Revenues	247			284
Fuel	358			538
Materials and Supplies, net	466			484
Prepayments	272			108
Derivative Contracts	155			240
Deferred Income Taxes	—			11
Regulatory Assets	235			323
Regulatory Assets of Variable Interest Entities (VIEs)	123			249
Other	25			15
Total Current Assets	3,627			4,119
PROPERTY, PLANT AND EQUIPMENT	33,603			32,196
Less: Accumulated Depreciation and Amortization	(8,796		)	(8,607		)
Net Property, Plant and Equipment	24,807			23,589
NONCURRENT ASSETS
Regulatory Assets	3,170			3,192
Long-Term Investments	1,273			1,307
Nuclear Decommissioning Trust (NDT) Fund	1,792			1,780
Long-Term Tax Receivable	165			64
Long-Term Receivable of VIE	602			580
Other Special Funds	234			212
Goodwill	16			16
Other Intangibles	101			84
Derivative Contracts	107			77
Restricted Cash of VIEs	25			24
Other	293			289
Total Noncurrent Assets	7,778			7,625
TOTAL ASSETS	$	36,212		$	35,333

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	June 30, 2015			December 31, 2014
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	491		$	624
Securitization Debt of VIEs Due Within One Year	134			259
Accounts Payable	1,156			1,178
Derivative Contracts	72			132
Accrued Interest	96			95
Accrued Taxes	148			21
Deferred Income Taxes	14			173
Clean Energy Program	200			142
Obligation to Return Cash Collateral	128			121
Regulatory Liabilities	143			186
Other	525			547
Total Current Liabilities	3,107			3,478
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	7,578			7,303
Regulatory Liabilities	176			258
Regulatory Liabilities of VIEs	47			39
Asset Retirement Obligations	765			743
Other Postretirement Benefit (OPEB) Costs	1,254			1,277
OPEB Costs of Servco	471			452
Accrued Pension Costs	392			440
Accrued Pension Costs of Servco	128			126
Clean Energy Program	27			—
Environmental Costs	421			417
Derivative Contracts	24			33
Long-Term Accrued Taxes	282			208
Other	143			112
Total Noncurrent Liabilities	11,708			11,408
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Total Long-Term Debt	8,689			8,261
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2015 and 2014—533,556,660 shares	4,883			4,876
Treasury Stock, at cost, 2015— 27,743,506 shares; 2014— 27,720,068 shares	(663		)	(635		)
Retained Earnings	8,764			8,227
Accumulated Other Comprehensive Loss	(277		)	(283		)
Total Common Stockholders’ Equity	12,707			12,185
Noncontrolling Interest	1			1
Total Stockholders’ Equity	12,708			12,186
Total Capitalization	21,397			20,447
TOTAL LIABILITIES AND CAPITALIZATION	$	36,212		$	35,333

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Six Months Ended
	June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	931		$	598
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	647			601
Amortization of Nuclear Fuel	106			98
Provision for Deferred Income Taxes (Other than Leases) and ITC	170			70
Non-Cash Employee Benefit Plan Costs	81			24
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(22		)	(44		)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(9		)	297
Change in Accrued Storm Costs	15			(3		)
Net Change in Other Regulatory Assets and Liabilities	(53		)	192
Cost of Removal	(58		)	(50		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(21		)	(59		)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	188			9
Accrued Taxes	71			54
Margin Deposit	69			(234		)
Other Current Assets and Liabilities	98			(116		)
Employee Benefit Plan Funding and Related Payments	(67		)	(50		)
Other	88			61
Net Cash Provided By (Used In) Operating Activities	2,234			1,448
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,743		)	(1,229		)
Proceeds from Sales of Capital Leases and Investments	5			11
Proceeds from Sales of Available-for-Sale Securities	885			584
Investments in Available-for-Sale Securities	(918		)	(599		)
Other	(2		)	(49		)
Net Cash Provided By (Used In) Investing Activities	(1,773		)	(1,282		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	—			(60		)
Issuance of Long-Term Debt	600			500
Redemption of Long-Term Debt	(300		)	—
Redemption of Securitization Debt	(125		)	(111		)
Cash Dividends Paid on Common Stock	(394		)	(374		)
Other	(47		)	(44		)
Net Cash Provided By (Used In) Financing Activities	(266		)	(89		)
Net Increase (Decrease) in Cash and Cash Equivalents	195			77
Cash and Cash Equivalents at Beginning of Period	402			493
Cash and Cash Equivalents at End of Period	$	597		$	570
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	184		$	296
Interest Paid, Net of Amounts Capitalized	$	195		$	192
Accrued Property, Plant and Equipment Expenditures	$	324		$	240

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
OPERATING REVENUES	$	1,466		$	1,435		$	3,468		$	3,580
OPERATING EXPENSES
Energy Costs	544			565			1,436			1,610
Operation and Maintenance	368			362			780			824
Depreciation and Amortization	234			217			481			444
Total Operating Expenses	1,146			1,144			2,697			2,878
OPERATING INCOME	320			291			771			702
Other Income	19			14			37			28
Other Deductions	(1		)	(1		)	(2		)	(1		)
Interest Expense	(67		)	(67		)	(136		)	(135		)
INCOME BEFORE INCOME TAXES	271			237			670			594
Income Tax Expense	(104		)	(86		)	(261		)	(229		)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	167		$	151		$	409		$	365

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
NET INCOME	$	167		$	151	$	409		$	365
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 for the three and six months ended 2015 and 2014, respectively	(1		)	—		(1		)	—
COMPREHENSIVE INCOME	$	166		$	151	$	408		$	365

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	166		$	310
Accounts Receivable, net of allowances of $60 and $52 in 2015 and 2014, respectively	848			864
Accounts Receivable-Affiliated Companies	52			274
Unbilled Revenues	247			284
Materials and Supplies	143			133
Prepayments	204			42
Regulatory Assets	235			323
Regulatory Assets of VIEs	123			249
Derivative Contracts	5			18
Deferred Income Taxes	—			24
Other	7			7
Total Current Assets	2,030			2,528
PROPERTY, PLANT AND EQUIPMENT	22,274			21,103
Less: Accumulated Depreciation and Amortization	(5,336		)	(5,183		)
Net Property, Plant and Equipment	16,938			15,920
NONCURRENT ASSETS
Regulatory Assets	3,170			3,192
Long-Term Investments	346			348
Other Special Funds	54			53
Derivative Contracts	—			8
Restricted Cash of VIEs	25			24
Other	158			150
Total Noncurrent Assets	3,753			3,775
TOTAL ASSETS	$	22,721		$	22,223

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	June 30, 2015		December 31, 2014
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	171	$	300
Securitization Debt of VIEs Due Within One Year	134		259
Accounts Payable	612		574
Accounts Payable—Affiliated Companies	215		379
Accrued Interest	68		68
Clean Energy Program	200		142
Deferred Income Taxes	13		165
Obligation to Return Cash Collateral	128		121
Regulatory Liabilities	143		186
Other	358		381
Total Current Liabilities	2,042		2,575
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	4,810		4,575
Other Postretirement Benefit (OPEB) Costs	936		967
Accrued Pension Costs	144		173
Regulatory Liabilities	176		258
Regulatory Liabilities of VIEs	47		39
Clean Energy Program	27		—
Environmental Costs	370		364
Asset Retirement Obligations	299		290
Long-Term Accrued Taxes	161		116
Other	74		67
Total Noncurrent Liabilities	7,044		6,849
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Total Long-Term Debt	6,440		6,012
STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2015 and 2014—132,450,344 shares	892		892
Contributed Capital	695		695
Basis Adjustment	986		986
Retained Earnings	4,621		4,212
Accumulated Other Comprehensive Income	1		2
Total Stockholder’s Equity	7,195		6,787
Total Capitalization	13,635		12,799
TOTAL LIABILITIES AND CAPITALIZATION	$	22,721	$	22,223

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Six Months Ended
	June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	409		$	365
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	481			444
Provision for Deferred Income Taxes and ITC	79			73
Non-Cash Employee Benefit Plan Costs	48			13
Cost of Removal	(58		)	(50		)
Change in Accrued Storm Costs	15			(3		)
Net Change in Other Regulatory Assets and Liabilities	(53		)	192
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	53			44
Materials and Supplies	(10		)	(11		)
Prepayments	(162		)	(162		)
Accounts Payable	48			16
Accounts Receivable/Payable—Affiliated Companies, net	154			(98		)
Other Current Assets and Liabilities	(27		)	(31		)
Employee Benefit Plan Funding and Related Payments	(55		)	(44		)
Other	(13		)	(11		)
Net Cash Provided By (Used In) Operating Activities	909			737
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,230		)	(996		)
Proceeds from Sales of Available-for-Sale Securities	12			8
Investments in Available-for-Sale Securities	(14		)	(6		)
Other	12			(1		)
Net Cash Provided By (Used In) Investing Activities	(1,220		)	(995		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	—			(60		)
Issuance of Long-Term Debt	600			500
Redemption of Long-Term Debt	(300		)	—
Redemption of Securitization Debt	(125		)	(111		)
Contributed Capital	—			175
Other	(8		)	(7		)
Net Cash Provided By (Used In) Financing Activities	167			497
Net Increase (Decrease) In Cash and Cash Equivalents	(144		)	239
Cash and Cash Equivalents at Beginning of Period	310			18
Cash and Cash Equivalents at End of Period	$	166		$	257
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(74	)	$	102
Interest Paid, Net of Amounts Capitalized	$	131		$	127
Accrued Property, Plant and Equipment Expenditures	$	282		$	192

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

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PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
OPERATING REVENUES	$	1,025		$	986		$	2,750		$	2,686
OPERATING EXPENSES
Energy Costs	409			520			1,302			1,564
Operation and Maintenance	313			327			485			629
Depreciation and Amortization	75			72			151			144
Total Operating Expenses	797			919			1,938			2,337
OPERATING INCOME	228			67			812			349
Income from Equity Method Investments	5			3			8			7
Other Income	55			46			84			79
Other Deductions	(7		)	(9		)	(18		)	(19		)
Other-Than-Temporary Impairments	(10		)	(2		)	(15		)	(4		)
Interest Expense	(33		)	(29		)	(64		)	(61		)
INCOME BEFORE INCOME TAXES	238			76			807			351
Income Tax Expense	(72		)	(22		)	(306		)	(133		)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	166		$	54		$	501		$	218

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

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PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
NET INCOME	$	166		$	54	$	501		$	218
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $14, $(9), $1 and $(11) for the three and six months ended 2015 and 2014, respectively	(14		)	9		—			11
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $(1), $7 and $(2) for the three and six months ended 2015 and 2014, respectively	—			2		(9		)	3
Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(1), $(10) and $(3) for the three and six months ended 2015 and 2014, respectively	7			2		14			5
Other Comprehensive Income (Loss), net of tax	(7		)	13		5			19
COMPREHENSIVE INCOME	$	159		$	67	$	506		$	237

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

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PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	12		$	9
Accounts Receivable	235			334
Accounts Receivable—Affiliated Companies	158			313
Tax Receivable	3			3
Short-Term Loan to Affiliate	950			584
Fuel	358			538
Materials and Supplies, net	321			350
Derivative Contracts	139			207
Prepayments	22			17
Other	13			4
Total Current Assets	2,211			2,359
PROPERTY, PLANT AND EQUIPMENT	10,942			10,732
Less: Accumulated Depreciation and Amortization	(3,235		)	(3,217		)
Net Property, Plant and Equipment	7,707			7,515
NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund	1,792			1,780
Long-Term Investments	116			121
Goodwill	16			16
Other Intangibles	101			84
Other Special Funds	57			49
Derivative Contracts	103			62
Other	63			60
Total Noncurrent Assets	2,248			2,172
TOTAL ASSETS	$	12,166		$	12,046

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

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PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	June 30, 2015			December 31, 2014
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	300		$	300
Accounts Payable	387			424
Accounts Payable-Affiliated Companies	128			118
Derivative Contracts	72			132
Deferred Income Taxes	22			43
Accrued Interest	27			27
Other	141			140
Total Current Liabilities	1,077			1,184
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	2,152			2,065
Asset Retirement Obligations	462			450
Other Postretirement Benefit (OPEB) Costs	254			248
Derivative Contracts	24			33
Accrued Pension Costs	139			153
Long-Term Accrued Taxes	56			41
Other	94			71
Total Noncurrent Liabilities	3,181			3,061
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT
Total Long-Term Debt	2,244			2,243
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,659			4,558
Accumulated Other Comprehensive Loss	(223		)	(228		)
Total Member’s Equity	5,664			5,558
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	12,166		$	12,046

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

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PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Six Months Ended
	June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	501		$	218
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	151			144
Amortization of Nuclear Fuel	106			98
Provision for Deferred Income Taxes and ITC	64			(22		)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(9		)	297
Non-Cash Employee Benefit Plan Costs	24			7
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(21		)	(59		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	209			132
Margin Deposit	69			(234		)
Accounts Receivable	76			16
Accounts Payable	(62		)	(72		)
Accounts Receivable/Payable—Affiliated Companies, net	123			229
Other Current Assets and Liabilities	(21		)	13
Employee Benefit Plan Funding and Related Payments	(7		)	(3		)
Other	89			50
Net Cash Provided By (Used In) Operating Activities	1,292			814
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(487		)	(226		)
Proceeds from Sales of Available-for-Sale Securities	837			563
Investments in Available-for-Sale Securities	(854		)	(577		)
Short-Term Loan—Affiliated Company, net	(366		)	50
Other	(17		)	(46		)
Net Cash Provided By (Used In) Investing Activities	(887		)	(236		)
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid	(400		)	(575		)
Other	(2		)	(3		)
Net Cash Provided By (Used In) Financing Activities	(402		)	(578		)
Net Increase (Decrease) in Cash and Cash Equivalents	3			—
Cash and Cash Equivalents at Beginning of Period	9			6
Cash and Cash Equivalents at End of Period	$	12		$	6
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	218		$	47
Interest Paid, Net of Amounts Capitalized	$	62		$	62
Accrued Property, Plant and Equipment Expenditures	$	42		$	48

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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This combined 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 each is only responsible for information about itself and its subsidiaries.

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 an operating 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 trading functions through its principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the FERC, the Nuclear Regulatory Commission (NRC) 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 respective 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, 2014 .

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, 2014 .

Note 2. Recent Accounting Standards

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

This accounting standard was issued to clarify the principles for recognizing revenue and to develop a common standard that would remove inconsistencies in revenue requirements; improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provide 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 update was originally effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board has voted to proceed with a one-year deferral with an effective date beginning after December 31, 2017. Early application will be permitted as of the original effective date of December 31, 2016. We are currently analyzing the impact of this standard on our financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Amendments to the Consolidation Analysis

This standard was issued to respond to concerns regarding the current accounting for consolidation of certain legal entities. Under the new standard, all legal entities are subject to reevaluation under a revised consolidation model which will determine whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities; eliminate the presumption that a general partner should consolidate a limited partnership; affect the consolidation analysis of reporting entities that are involved with VIEs and provide a scope exception from consolidation guidance for reporting entities with interests in certain legal entities who must comply with other requirements.

The update is effective for annual and interim reporting periods beginning after December 15, 2015. We are currently analyzing the impact of this standard on our financial statements.

Simplifying the Presentation of Debt Issuance Costs

This standard was issued to simplify presentation of debt issuance costs. The standard will require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard.

The update is effective for annual and interim reporting periods beginning after December 15, 2015. We do not expect the impact of adoption of this standard to be material to our Condensed Consolidated Balance Sheets.

Note 3. Variable Interest Entities (VIEs)

Variable Interest Entities 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 is pledged as collateral to a trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.

The assets and liabilities of Transition Funding and Transition Funding II are presented separately on the face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the assets of these VIEs are restricted and can only be used to settle their respective obligations. No Transition Funding or Transition Funding II creditor has any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding or Transition Funding II.

PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of June 30, 2015 and December 31, 2014 . The risk of actual loss to PSE&G is considered remote. PSE&G did not provide any financial support to Transition Funding or Transition Funding II during the first six months of 2015 or in 2014 . PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.

Variable Interest Entity 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.

PSEG recognized a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and other postretirement benefit (OPEB) liabilities. This receivable is presented separately on the Condensed Consolidated Balance Sheet

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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of PSEG as a noncurrent asset because it is restricted. See

Note 7. Pension and Other Postretirement Benefits for additional information.

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 $84 million and $111 million for the three months and $166 million and $200 million for the six months ended June 30, 2015 and 2014 , 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

The following information discusses significant updates regarding orders and pending 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, 2014 .

In addition to items previously reported in the Annual Report on Form 10-K, significant 2015 regulatory orders received and currently pending rate filings with the FERC and the BPU by PSE&G are as follows:

•

Energy Strong Recovery Filing —In June 2015, PSE&G updated its Energy Strong cost recovery petition seeking BPU approval to recover in base rates estimated annual increases in electric revenues of $6 million and gas revenues of $17 million . These increases represent recovery of Energy Strong investment costs in service as of May 31, 2015. The petition requests rates to be effective September 1, 2015, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.

•

Basic Gas Supply Service (BGSS) —On April 15, 2015, the BPU issued an Order approving PSE&G’s provisional BGSS rate of 45 cents per therm which had been implemented on October 1, 2014. In March 2015, PSE&G filed a letter with the BPU to extend the 28 cents per therm residential rate reduction via a bill credit for one additional month through April 30, 2015, w hich provided an additional approximate $31 million credit to customers.

On June 1, 2015, PSE&G made its Annual BGSS Filing with the BPU requesting a reduction of $70 million in annual BGSS revenues. If approved, the BGSS rate would be reduced from approximately 45 cents to 40 cents per therm effective October 1, 2015.


•	Weather Normalization Clause —On April 15, 2015, the BPU approved PSE&G's final filing with respect to excess revenues collected during the colder than normal 2013-2014 Winter Period (October 1, 2013 through May 31, 2014). Effective October 1, 2014, PSEG commenced returning $45 million in revenues to its customers during the 2014-2015 Winter Period (October 1, 2014 through May 31, 2015).

In June 2015, PSE&G filed a petition requesting approval to refund excess revenues collected during the colder than normal 2014-2015 Winter Period. This refund would be made to customers over the 2015-2016 Winter Period (October 1, 2015 through May 31, 2016). Colder weather in the 2014-2015 Winter Period resulted in an excess collection of $40 million of revenues to be refunded to customers.

•

Solar and Energy Efficiency - Green Program Recovery Charges (GPRC) —In April 2015, the BPU approved PSE&G’s petition for an Energy Efficiency Economic Stimulus Extension II Program (EEE Ext II) to extend three EEE subprograms (multi-family, direct install and hospital efficiency). The Order allows PSE&G to extend the subprogram offerings under the same clause recovery process as its existing EEE Program and allows for $95 million of additional capital expenditures over the next three years and $12 million of additional administrative expenses over the next 15 years. The EEE Ext II program was added as a ninth component of the GPRC rate effective May 1, 2015.

In July of each year, PSE&G files for annual recovery for its Green Program investments which include a return on its investment and recovery of expenses. In May 2015, the BPU approved PSE&G’s July 2014 filing requesting recovery of costs and investments in the first eight combined components of the electric and gas GPRC for the period October 1, 2014 through September 30, 2015. In July 2015, PSE&G filed its annual GPRC cost recovery petition with the BPU once again requesting recovery of costs and investments for the first eight combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2015 through September 30, 2016 designed to recover approximately $64 million and $10 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU approved programs. The matter is pending.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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•

Transmission Formula Rate Filings —In June 2015, PSE&G filed its 2014 true-up adjustment pertaining to its formula rates in effect for 2014, which resulted in an adjustment of $19 million less than the 2014 filed revenues. The adjustment was primarily due to the impact of bonus depreciation and lower interest rates which PSE&G had recognized in its Consolidated Statement of Operations for the year ended December 31, 2014.

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.”




Credit Risk Profile Based on Payment Activity
	As of		As of
Consumer Loans	June 30, 2015		December 31, 2014
	Millions
Commercial/Industrial	$	186	$	188
Residential	13		13
Total	$	199	$	201

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, 2015 and December 31, 2014 , respectively.




	As of			As of
	June 30, 2015			December 31, 2014
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	661		$	691
Estimated Residual Value of Leased Assets	519			525
Unearned and Deferred Income	(372		)	(380		)
Gross Investment in Leases	808			836
Deferred Tax Liabilities	(695		)	(738		)
Net Investment in Leases	$	113		$	98

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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
As of June 30, 2015	June 30, 2015
	Millions
AA	$	17
AA-	29
BBB+ — BBB-	316
BB-	134
B-	165
Total	$	661

The “BB-” and the "B-" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of June 30, 2015 , the gross investment in the leases of such assets, net of non-recourse debt, was $573 million ( $4 million , net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.




Asset	Location	Gross Investment		% Owned		Total	Fuel Type	Counter-parties’ S&P Credit Ratings	Counterparty
		Millions				MW
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	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	B-	NRG REMA LLC
Conemaugh Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	B-	NRG REMA LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	113	100	%	603	Coal	B-	NRG REMA LLC

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. A bankruptcy of a lessee would likely delay 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 (IRS).

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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In early 2014, NRG REMA LLC, an indirect subsidiary of NRG Energy, Inc. (NRG) had disclosed its plan to place the Shawville generating facility in a “long-term protective layup” by April 2015 as it evaluated its alternatives under the lease. However, NRG has since 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 summer of 2016 with the ability to use natural gas.

Note 6. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Fund

Power maintains an external master nuclear decommissioning trust to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains 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, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	697	$	234	$	(10	)	$	921
Debt Securities
Government Obligations	451		7		(3		)	455
Other Debt Securities	388		4		(6		)	386
Total Debt Securities	839		11		(9		)	841
Other Securities	30		—		—			30
Total NDT Available-for-Sale Securities	$	1,566	$	245	$	(19	)	$	1,792




	As of December 31, 2014
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	685	$	220	$	(8	)	$	897
Debt Securities
Government Obligations	430		9		(1		)	438
Other Debt Securities	333		9		(3		)	339
Total Debt Securities	763		18		(4		)	777
Other Securities	106		—		—			106
Total NDT Available-for-Sale Securities	$	1,554	$	238	$	(12	)	$	1,780

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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, 2015		December 31, 2014
	Millions
Accounts Receivable	$	42	$	10
Accounts Payable	$	32	$	2

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, 2015										As of December 31, 2014
	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)	$	114	$	(10	)	$	3	$	—		$	162	$	(8	)	$	1	$	—
Debt Securities
Government Obligations (B)	156		(3		)	22		—			95		—			28		(1		)
Other Debt Securities (C)	199		(4		)	22		(2		)	99		(1		)	30		(2		)
Total Debt Securities	355		(7		)	44		(2		)	194		(1		)	58		(3		)
NDT Available-for-Sale Securities	$	469	$	(17	)	$	47	$	(2	)	$	356	$	(9	)	$	59	$	(3	)


(A)	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. 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, 2015 .

(B)

Debt Securities (Government)—Unrealized losses on Power’s NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States 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, 2015 .

(C)

Debt Securities (Other)—Power’s investments in corporate bonds, collateralized mortgage obligations, asset-backed securities and municipal government obligations are limited to 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, 2015 .

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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,
	2015			2014			2015			2014
	Millions
Proceeds from NDT Fund Sales (A)	$	232		$	313		$	822		$	558
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	14			33			33			56
Gross Realized Losses	(4		)	(5		)	(13		)	(9		)
Net Realized Gains (Losses) on NDT Fund	$	10		$	28		$	20		$	47


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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $111 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, 2015 .

The NDT available-for-sale debt securities held as of June 30, 2015 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	9
1 - 5 years	229
6 - 10 years	197
11 - 15 years	53
16 - 20 years	47
Over 20 years	306
Total NDT Available-for-Sale Debt Securities	$	841

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, 2015 , other-than-temporary impairments of $15 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.”

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	10	$	—		$	22
Debt Securities
Government Obligations	99		1		—			100
Other Debt Securities	90		1		(1		)	90
Total Debt Securities	189		2		(1		)	190
Other Securities	—		—		—			—
Total Rabbi Trust Available-for-Sale Securities	$	201	$	12	$	(1	)	$	212




	As of December 31, 2014
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	12	$	11	$	—	$	23
Debt Securities
Government Obligations	89		2		—		91
Other Debt Securities	74		1		—		75
Total Debt Securities	163		3		—		166
Other Securities	2		—		—		2
Total Rabbi Trust Available-for-Sale Securities	$	177	$	14	$	—	$	191

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, 2015		December 31, 2014
	Millions
Accounts Receivable	$	3	$	1
Accounts Payable	$	2	$	—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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, 2015									As of December 31, 2014
	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)	19		—			1		—		2		—		—		—
Other Debt Securities (C)	39		(1		)	7		—		24		—		—		—
Total Debt Securities	58		(1		)	8		—		26		—		—		—
Rabbi Trust Available-for-Sale Securities	$	58	$	(1	)	$	8	$	—	$	26	$	—	$	—	$	—


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

(B)

Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States 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, 2015 .

(C)

Debt Securities (Other)—PSEG’s investments in corporate bonds, collateralized mortgage obligations, asset-backed securities and municipal government obligations are limited to 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, 2015 .

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,
	2015		2014			2015		2014
	Millions
Proceeds from Rabbi Trust Sales (A)	$	44	$	14		$	63	$	26
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2	$	—		$	2	$	2
Gross Realized Losses	—		(1		)	—		(1		)
Net Realized Gains (Losses) on Rabbi Trust	$	2	$	(1	)	$	2	$	1


(A)	Includes 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 $6 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of June 30, 2015 .

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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The Rabbi Trust available-for-sale debt securities held as of June 30, 2015 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	1
1 - 5 years	56
6 - 10 years	37
11 - 15 years	9
16 - 20 years	8
Over 20 years	79
Total Rabbi Trust Available-for-Sale Debt Securities	$	190

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, 2015		December 31, 2014
	Millions
PSE&G	$	42	$	41
Power	52		45
Other	118		105
Total Rabbi Trust Available-for-Sale Securities	$	212	$	191

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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. 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,
	2015			2014			2015			2014			2015			2014			2015			2014
	Millions
Components of Net Periodic Benefit Costs (Credit)
Service Cost	$	31		$	26		$	6		$	4		$	62		$	52		$	11		$	9
Interest Cost	58			59			17			17			117			118			34			34
Expected Return on Plan Assets	(104		)	(100		)	(8		)	(6		)	(207		)	(200		)	(15		)	(13		)
Amortization of Net
Prior Service Cost (Credit)	(4		)	(4		)	(4		)	(3		)	(9		)	(9		)	(7		)	(7		)
Actuarial Loss	37			14			11			6			74			28			21			12
Total Benefit Costs (Credit)	$	18		$	(5	)	$	22		$	18		$	37		$	(11	)	$	44		$	35

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,
	2015		2014			2015		2014		2015		2014			2015		2014
	Millions
PSE&G	$	10	$	(5	)	$	14	$	12	$	20	$	(10	)	$	28	$	23
Power	5		(1		)	6		5		11		(3		)	13		10
Other	3		1			2		1		6		2			3		2
Total Benefit Costs (Credit)	$	18	$	(5	)	$	22	$	18	$	37	$	(11	)	$	44	$	35

During the three months ended March 31, 2015 , PSEG contributed its entire planned contributions for the year 2015 of $15 million into its pension plans and $14 million into its OPEB plan for 2015 .

Servco Pension and OPEB

At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco's employees had worked under NGES' T&D operations services arrangement with LIPA, Servco's plans provide certain of those employees with pension and OPEB vested credit for prior years' services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See

Note 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco may contribute up to $30 million into its pension plan trusts during 2015 . The pension-related revenues and costs were $7 million and $23 million for the three months ended June 30, 2015 and 2014 , respectively, and were $13 million and $46 million for the six months ended June 30, 2015 and 2014 , respectively. The OPEB-related revenues earned or costs incurred for each of the three months and six months ended June 30, 2015 and 2014 were immaterial.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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The face value of Power's outstanding guarantees, current exposure and margin positions as of June 30, 2015 and December 31, 2014 are shown as follows:




	As of			As of
	June 30, 2015			December 31, 2014
	Millions
Face Value of Outstanding Guarantees	$	1,775		$	1,814
Exposure under Current Guarantees	$	196		$	273

Letters of Credit Margin Posted	$	161		$	159
Letters of Credit Margin Received	$	74		$	40

Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(9	)	$	(13	)
Net Broker Balance Deposited (Received)	$	42		$	115

In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required	$	907		$	945
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,494		$	3,495

Additional Amounts Posted:
Other Letters of Credit	$	45		$	45

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 the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

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 had 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 $23 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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 further 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. This agreement and the work undertaken pursuant to the action agreement will not affect the ultimate remedy that the EPA will select for the remediation of the 17-mile stretch of the lower Passaic River.

In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than in respect of 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 . PSEG’s 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 contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River. The EPA’s estimated costs to remediate the lower eight miles of the Passaic River range from $365 million for a targeted remedy to $3.25 billion for a deep dredge of this portion of the Passaic River. The EPA also identified in the revised draft FFS its preferred alternative, which would involve dredging the river bank to bank and installing an engineered cap. The estimated cost in the revised draft FFS for its preferred alternative is $1.7 billion . No provisional cost allocation has been made by the CPG for the work contemplated by the revised draft FFS, and the work contemplated by the revised draft FFS is not subject to the CPG’s cost sharing allocation agreed to in connection with the removal work for River Mile 10.9 or in connection with the conduct of the RI/FS.

The revised draft FFS was subject to a public comment period, and remains subject to the EPA’s response to comments submitted, a design phase and at least an estimated five years for completion of the work. The public comment period on the revised draft FFS closed on August 21, 2014. Over 300 comments were submitted by a variety of entities potentially impacted by the revised draft FFS, including the CPG, individual companies, municipalities, public officials, citizens groups, Amtrak, NJ Transit and others.

The CPG, which consisted of 61 members as of June 30, 2015 , provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $150 million , which the CPG continues to incur. Of the estimated $150 million , as of June 30, 2015, the CPG had spent approximately $132 million , of which PSEG's total share was approximately $9 million .

The draft FS sets forth various alternatives for remediating that portion of the Passaic River. The draft FS sets 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 . 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 ranges from approximately $518 million to $772 million . No provisional cost allocation has been made by the CPG for the work contemplated by the draft FS. However, based on (i) the low end of the range of the

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current estimates of costs to remediate, (ii) PSE&G's and Power's estimates of their 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.

The EPA will consider the comments received on its revised draft FFS and will consider the CPG’s RI/FS prior to issuing a Record of Decision (ROD) of a selected remedy for the Passaic River. 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 is finalized, (ii) a final remedy is determined by the EPA or through litigation, (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 our 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 United States Department of Commerce and the United States 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 $445 million and $517 million through 2021, including its $10 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $445 million as of June 30, 2015 . Of this amount, $84 million was recorded in Other Current Liabilities and $361 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $445 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly.

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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 New Jersey Department of Environmental Protection (NJDEP) manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. On June 30, 2015, the NJDEP issued a draft Salem permit. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The draft permit is subject to a public notice and comment period after which the NJDEP may make revisions before issuing the final permit expected during the first half of 2016.

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.

State permitting decisions could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, 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. 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 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.

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 Connecticut Department of Energy and Environmental Protection of the

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issues and has taken actions to investigate and resolve the potential non-compliance. At this early stage Power cannot predict the impact of this matter.

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 14, 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, are residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category are larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial 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, 2015 is $272.78 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2015 of $282.04 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
	2012	2013	2014	2015
36-Month Terms Ending	May 2015	May 2016	May 2017	May 2018	(A)
Load (MW)	2,900	2,800	2,800	2,900
$ per MWh	$83.88	$92.18	$97.39	$99.54


(A)	Prices set for the 2015 BGS auction year became effective on June 1, 2015 when the 2012 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,

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enrichment and fabrication requirements through 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom.

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

Power also 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, Power can use the gas to supply its fossil generating stations.

As of June 30, 2015 , the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	Power's Share of Commitments through 2019
	Millions
Nuclear Fuel
Uranium	$	443
Enrichment	$	342
Fabrication	$	185
Natural Gas	$	1,072
Coal	$	360

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. As the 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 the FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors and modified the bid quantities for its peaking units. Power continues to implement procedures to help mitigate the risk of similar issues occurring in the future. On September 2, 2014, the FERC Staff initiated a preliminary, non-public staff investigation into the matter. This investigation, which is ongoing, could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies.

During the three months 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. It is not possible at this time to reasonably estimate the potential range of loss or full impact or predict any resulting penalties or other costs associated with this matter, or the applicability of mitigating factors. As new information becomes available or future developments occur in this investigation, it is possible that Power will record additional estimated losses and such additional losses may be material.

New Jersey Clean Energy Program

In June 2015, the BPU established the funding level for fiscal year 2016 applicable to its Renewable Energy and Energy Efficiency programs. The fiscal year 2016 aggregate funding for all EDCs is $345 million with PSE&G's share of the funding at $200 million . PSE&G has a current liability of $200 million and a noncurrent liability of $27 million as of June 30, 2015 for its outstanding share of the fiscal year 2016 and remaining fiscal year 2015 funding, respectively. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

Superstorm Sandy

In late October 2012, Superstorm Sandy caused severe damage to PSE&G's T&D system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds and the resulting storm surge caused damage to switching stations, substations and generating infrastructure.

PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. In June 2013, PSEG,

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PSE&G and Power filed suit in New Jersey state court (NJ Court) against its insurance carriers seeking an interpretation that the insurance policies cover their losses resulting from damage caused by Superstorm Sandy's storm surge.

As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its infrastructure and return it to pre-storm conditions. Of the costs incurred, approximately $40 million was recognized in O&M Expense, $75 million was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. Of the $295 million , $36 million related to insured property. In 2012, PSE&G recognized $6 million of insurance recoveries, which were deferred. There were no significant additional costs incurred since 2012.

PSE&G made a filing with the BPU to review the prudency of unreimbursed incremental storm restoration costs, including O&M and capital expenditures associated with Superstorm Sandy and certain other extreme weather events, for recovery in its next base rate case or sooner through a BPU-approved cost recovery mechanism. In September 2014, the BPU approved its filing.

Power had incurred a total of $193 million of storm-related costs from 2012 through 2014, primarily for repairs at certain generating stations in Power's fossil fleet. These costs were recognized primarily in O&M Expense, offset by $44 million of insurance recoveries in 2013 and 2012. Power incurred an additional $2 million of storm-related costs in 2015 which were recognized primarily in O&M Expense.

In the first half of 2015, PSEG reached settlements with its insurers with respect to claims for coverage of its Superstorm Sandy-related losses. PSEG received an additional $214 million under these settlements (consisting of $159 million and $55 million recognized in the three months ended March 31, 2015 and June 30, 2015, respectively), bringing cumulative insurance proceeds to $264 million . Of the $214 million recognized in 2015, PSE&G and Power recorded $35 million and $179 million , respectively. In addition to the $35 million recognized in 2015, PSE&G recognized the aforementioned $6 million of previously deferred insurance recoveries, resulting in reductions in Regulatory Assets of $20 million , O&M Expense of $10 million and Property, Plant and Equipment of $11 million . Power recorded reductions in both O&M Expense of $145 million and Property, Plant and Equipment of $6 million and an increase in Other Income of $28 million .

The claim filed by PSEG, PSE&G and Power related to Superstorm Sandy insurance coverage is now fully resolved.

Note 9. Changes in Capitalization

The following capital transactions occurred in the six months ended June 30, 2015 :

PSE&G


•	issued $350 million of 3.00% Secured Medium-Term Notes, Series K due May 2025 ,


•	issued $250 million of 4.05% Secured Medium-Term Notes, Series K due May 2045 ,


•	paid $300 million of 2.70% Secured Medium-Term Notes at maturity,


•	paid $117 million of Transition Funding's securitization debt, and


•	paid the final $8 million of Transition Funding II's securitization debt.

Power


•	paid cash dividends of $400 million to PSEG.

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

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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 do not qualify for or are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and changes in the fair value of these contracts are recorded in earnings each period.

Commodity Prices

Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments 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.

Cash Flow Hedges

PSEG and Power use forward sale and purchase contracts, swaps and futures contracts to hedge certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G. These derivative transactions qualify and are designated as cash flow hedges.

As of June 30, 2015 and December 31, 2014 , the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity were as follows:




	As of		As of
	June 30, 2015		December 31, 2014
	Millions
Fair Value of Cash Flow Hedges	$	1	$	18
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	1	$	10

The expiration date of the longest-dated cash flow hedge at Power is in December 2015 . Power’s remaining $1 million of after-tax unrealized gains on these derivatives is expected to be reclassified to earnings during the next 12 months. There was no ineffectiveness associated with qualifying hedges as of June 30, 2015 .

Economic Hedges

Power enters into derivative contracts that do not qualify or 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 certain long-term natural gas sales derivative contracts to optimize its pipeline capacity utilization. Changes in the fair market value of these contracts 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.

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Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of June 30, 2015 , PSEG had interest rate swaps outstanding totaling $850 million . These swaps convert Power’s $300 million of 5.5% Senior Notes due December 2015, $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, 2015 and December 31, 2014 , the fair value of all the underlying hedges was $15 million and $22 million , 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. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was immaterial as of June 30, 2015 and December 31, 2014 , respectively.

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 our 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, 2015
	Power (A)											PSE&G (A)		PSEG (A)		Consolidated
	Cash Flow Hedges		Not Designated									Not Designated		Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts		Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	1	$	483		$	(345	)	$	139		$	5	$	11	$	155
Noncurrent Assets	—		220			(117		)	103			—		4		107
Total Mark-to-Market Derivative Assets	$	1	$	703		$	(462	)	$	242		$	5	$	15	$	262
Derivative Contracts
Current Liabilities	$	—	$	(421	)	$	349		$	(72	)	$	—	$	—	$	(72	)
Noncurrent Liabilities	—		(145		)	121			(24		)	—		—		(24		)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(566	)	$	470		$	(96	)	$	—	$	—	$	(96	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	1	$	137		$	8		$	146		$	5	$	15	$	166

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	As of December 31, 2014
	Power (A)											PSE&G (A)		PSEG (A)		Consolidated
	Cash Flow Hedges		Not Designated									Not Designated		Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts		Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	18	$	597		$	(408	)	$	207		$	18	$	15	$	240
Noncurrent Assets	—		171			(109		)	62			8		7		77
Total Mark-to-Market Derivative Assets	$	18	$	768		$	(517	)	$	269		$	26	$	22	$	317
Derivative Contracts
Current Liabilities	$	—	$	(568	)	$	436		$	(132	)	$	—	$	—	$	(132	)
Noncurrent Liabilities	—		(138		)	105			(33		)	—		—		(33		)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(706	)	$	541		$	(165	)	$	—	$	—	$	(165	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	18	$	62		$	24		$	104		$	26	$	22	$	152


(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, 2015 and December 31, 2014 . 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, 2015 and December 31, 2014 , net cash collateral (received) paid of $8 million and $24 million , respectively, were netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, 2015 , $(4) million and $(4) million of cash collateral were netted against current assets and noncurrent assets, respectively, and $7 million and $9 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $24 million as of December 31, 2014 , $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and $32 million and $4 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. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $82 million and $127 million as of June 30, 2015 and December 31, 2014 , respectively. As of June 30, 2015 and December 31, 2014 , Power had the contractual right of offset of $18 million 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 $64 million and $109 million as of June 30, 2015 and December 31, 2014 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This

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potential additional collateral is included in the $907 million and $945 million as of June 30, 2015 and December 31, 2014 , respectively, discussed in Note 8. Commitments and Contingent Liabilities .

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, 2015 and 2014 .




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,
	2015		2014			2015		2014			2015		2014
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total PSEG	$	—	$	1		$	—	$	—		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	—		$	—	$	—




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)					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,
	2015		2014				2015		2014				2015		2014
	Millions
PSEG
Energy-Related Contracts	$	1	$	(7	)	Operating Revenues	$	17	$	(12	)	Operating Revenues	$	—	$	—
Total PSEG	$	1	$	(7	)		$	17	$	(12	)		$	—	$	—
Power
Energy-Related Contracts	$	1	$	(7	)	Operating Revenues	$	17	$	(12	)	Operating Revenues	$	—	$	—
Total Power	$	1	$	(7	)		$	17	$	(12	)		$	—	$	—

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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	1			1
Less: Gain Reclassified into Income	(17		)	(10		)
Balance as of March 31, 2015	$	1		$	1
Gain Recognized in AOCI	—			—
Less: Gain Reclassified into Income	—			—
Balance as of June 30, 2015	$	1		$	1

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months and six months ended June 30, 2015 and 2014 .




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,
		2015			2014			2015		2014
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	124		$	(58	)	$	48	$	(852	)
Energy-Related Contracts	Energy Costs	(10		)	(36		)	—		77
Total PSEG and Power		$	114		$	(94	)	$	48	$	(775	)

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of these contracts are marked to market. The tables above do not include contracts for which Power has elected the NPNS exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $5 million for each of the three months and $10 million for each of the six months ended June 30, 2015 and 2014 , respectively.

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2015 and December 31, 2014 .




Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2015
Natural Gas	Dth	259	—	214	45
Electricity	MWh	299	—	299	—
Financial Transmission Rights (FTRs)	MWh	30	—	30	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—
As of December 31, 2014
Natural Gas	Dth	274	—	216	58
Electricity	MWh	310	—	310	—
FTRs	MWh	15	—	15	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—

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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, 2015 , 99.3% of the credit 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 cash collateral, as of June 30, 2015 . 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	$	310	$	82	$	302	2	$	119	(A)
Non-Investment Grade—External Rating	2		—		2		—	—
Investment Grade—No External Rating	10		—		10		—	—
Non-Investment Grade—No External Rating	—		—		—		—	—
Total	$	322	$	82	$	314	2	$	119


(A)	Represents net exposure of $82 million with PSE&G. The remaining net exposure of $37 million is with a non- affiliated power purchaser which is an investment grade counterparty.

The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would be no exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of June 30, 2015 , Power had 138 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, 2015 , 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, 2015 , 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.

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, 2015 , 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, 2015 and December 31, 2014 , 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, 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)	$	547		$	—		$	547	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	247		$	(462	)	$	—	$	701		$	8
Interest Rate Swaps (C)	$	15		$	—		$	—	$	15		$	—
NDT Fund (D)
Equity Securities	$	921		$	—		$	920	$	1		$	—
Debt Securities—Govt Obligations	$	455		$	—		$	—	$	455		$	—
Debt Securities—Other	$	386		$	—		$	—	$	386		$	—
Other Securities	$	30		$	—		$	30	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22	$	—		$	—
Debt Securities—Govt Obligations	$	100		$	—		$	—	$	100		$	—
Debt Securities—Other	$	90		$	—		$	—	$	90		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(96	)	$	470		$	—	$	(566	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	151		$	—		$	151	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	5		$	—		$	—	$	—		$	5
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	4		$	—		$	4	$	—		$	—
Debt Securities—Govt Obligations	$	20		$	—		$	—	$	20		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	242		$	(462	)	$	—	$	701		$	3
NDT Fund (D)
Equity Securities	$	921		$	—		$	920	$	1		$	—
Debt Securities—Govt Obligations	$	455		$	—		$	—	$	455		$	—
Debt Securities—Other	$	386		$	—		$	—	$	386		$	—
Other Securities	$	30		$	—		$	30	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	25		$	—		$	—	$	25		$	—
Debt Securities—Other	$	22		$	—		$	—	$	22		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(96	)	$	470		$	—	$	(566	)	$	—

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	Recurring Fair Value Measurements as of December 31, 2014
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	295		$	(517	)	$	—	$	774		$	38
Interest Rate Swaps (C)	$	22		$	—		$	—	$	22		$	—
NDT Fund (D)
Equity Securities	$	897		$	—		$	896	$	1		$	—
Debt Securities—Govt Obligations	$	438		$	—		$	—	$	438		$	—
Debt Securities—Other	$	339		$	—		$	—	$	339		$	—
Other Securities	$	106		$	—		$	106	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	23		$	—		$	23	$	—		$	—
Debt Securities—Govt Obligations	$	91		$	—		$	—	$	91		$	—
Debt Securities—Other	$	75		$	—		$	—	$	75		$	—
Other Securities	$	2		$	—		$	—	$	2		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(165	)	$	541		$	—	$	(705	)	$	(1	)
PSE&G
Assets:
Cash Equivalents (A)	$	294		$	—		$	294	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	26		$	—		$	—	$	—		$	26
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	20		$	—		$	—	$	20		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	269		$	(517	)	$	—	$	774		$	12
NDT Fund (D)
Equity Securities	$	897		$	—		$	896	$	1		$	—
Debt Securities—Govt Obligations	$	438		$	—		$	—	$	438		$	—
Debt Securities—Other	$	339		$	—		$	—	$	339		$	—
Other Securities	$	106		$	—		$	106	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(165	)	$	541		$	—	$	(705	)	$	(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

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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, 2015 , 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, 2015 , $(8) million of cash collateral was netted against assets, and $16 million was netted against liabilities. As of December 31, 2014 , net cash collateral (received) paid of $24 million , was netted against the corresponding net derivative contract positions. Of the $24 million as of December 31, 2014 , $(12) million of cash collateral was netted against assets, and $36 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 and Power, 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

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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. For Power, long-term electric capacity contracts are measured using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of June 30, 2015 and December 31, 2014 .




	Quantitative Information About Level 3 Fair Value Measurements

							Significant
		Fair Value as of				Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2015				Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	5	$	—	Discounted Cash Flow	Transportation Costs	$0.70 to $1/dekatherm
Total PSE&G		$	5	$	—
Power
Electricity	Electric Load Contracts	$	3	$	—	Discounted Cash flow	Historic Load Variability	0% to +10%
Other	Various (A)	—		—
Total Power		$	3	$	—
Total PSEG		$	8	$	—




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2014					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	26	$	—		Discounted Cash Flow	Transportation Costs	$0.70 to $1/dekatherm
Total PSE&G		$	26	$	—
Power
Electricity	Electric Load Contracts	$	12	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Other	Various (B)	—		—
Total Power		$	12	$	(1	)
Total PSEG		$	38	$	(1	)

(A) Includes long-term electric positions which were immaterial as of June 30, 2015 .


(B)	Includes gas supply positions and long-term electric capacity positions which were immaterial as of December 31, 2014 .

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 either the power basis or the load variability or the longer-term gas basis amounts 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, 2015 and June 30, 2014 , respectively, follows:

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

for the Three Months and Six Months Ended June 30, 2015




	Three Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2015		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out		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 (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out		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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

for the Three Months and Six Months Ended June 30, 2014




	Three Months Ended June 30, 2014
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2014			Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2014
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	6		$	10		$	—	$	(1	)	$	(3	)	$	13
PSE&G
Net Derivative Assets (Liabilities)	$	12		$	—		$	10		$	—	$	—		$	—		$	22
Power
Net Derivative Assets (Liabilities)	$	(11	)	$	6		$	—		$	—	$	(1	)	$	(3	)	$	(9	)

	Six Months Ended June 30, 2014
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2014			Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2014
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	88		$	(58	)	$	(72	)	$	—	$	58		$	(3	)	$	13
PSE&G
Net Derivative Assets (Liabilities)	$	94		$	—		$	(72	)	$	—	$	—		$	—		$	22
Power
Net Derivative Assets (Liabilities)	$	(6	)	$	(58	)	$	—		$	—	$	58		$	(3	)	$	(9	)


(A)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities includes $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.


(B)	Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or 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 $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015 . Includes $(1) million and $58 million in settlements for the three months and six months ended June 30, 2014 .

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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(D)	During the three months and six months ended June 30, 2014 , $(3) million of net derivative assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters in which the transfers first occurred as per PSEG's policy.


(E)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $6 million and $(58) million in Operating Income for the three months and six months ended June 30, 2014, respectively. The $6 million in Operating Income is unrealized. Of the $(58) million in Operating Income, $1 million is unrealized.

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 assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of June 30, 2014 , PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $13 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of June 30, 2015 and December 31, 2014 .




	As of				As of
	June 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	9	$	15	$	14	$	22
PSE&G (B)	6,611		6,899		6,312		6,912
Transition Funding (PSE&G) (B)	134		137		251		261
Transition Funding II (PSE&G) (B)	—		—		8		8
Power -Recourse Debt (B)	2,544		2,885		2,543		2,930
Energy Holdings:
Project Level, Non-Recourse Debt (C)	16		16		16		16
Total Long-Term Debt	$	9,314	$	9,952	$	9,144	$	10,149


(A)	Fair value represents net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. Carrying amount represents such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.


(B)	The debt fair valuation is based on the present value of each bond’s future cash flows. The discount rates used in the present value analysis are based on an estimate of new issue bond yields across the treasury curve. When a bond has embedded options, an interest rate model is used to reflect the impact of interest rate volatility into the analysis (primarily Level 2 measurements).


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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Note 12. Other Income and Deductions




Other Income	PSE&G		Power		Other (A)		Consolidated
	Millions
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
Three Months Ended June 30, 2014
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	46	$	—	$	46
Allowance for Funds Used During Construction	7		—		—		7
Solar Loan Interest	6		—		—		6
Other	1		—		2		3
Total Other Income	$	14	$	46	$	2	$	62
Six Months Ended June 30, 2014
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	78	$	—	$	78
Allowance for Funds Used During Construction	13		—		—		13
Solar Loan Interest	12		—		—		12
Other	3		1		3		7
Total Other Income	$	28	$	79	$	3	$	110

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
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
Three Months Ended June 30, 2014
NDT Fund Realized Losses and Expenses	$	—	$	8	$	—	$	8
Other	1		1		—		2
Total Other Deductions	$	1	$	9	$	—	$	10
Six Months Ended June 30, 2014
NDT Fund Realized Losses and Expenses	$	—	$	14	$	—	$	14
Other	1		5		2		8
Total Other Deductions	$	1	$	19	$	2	$	22


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

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, 2015 and 2014 were as follows:




	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2015	2014	2015	2014
PSEG	35.0%	34.8%	38.5%	38.4%
PSE&G	38.4%	36.5%	39.0%	38.6%
Power	30.3%	28.9%	37.9%	37.8%

An explanation of the material changes in the effective tax rates is as follows:

For the three months ended June 30, 2015, PSE&G's effective tax rate was lower than the statutory tax rate of 40.85% due primarily to the beneficial impact of plant related flow-through items.

For the three months ended June 30, 2015, Power’s effective tax rate was lower than the statutory tax rate of 40.85% due primarily to the beneficial impact of the manufacturing deduction under Section 199 of the Internal Revenue Code (IRC) and the benefit associated with the income tax rate differential of carrying back federal net operating tax losses under section 172(f) of the IRC.

For the three months ended June 30, 2015, as compared to the same period in the prior year, PSE&G's increase was due primarily to the absence of the 2014 tax flow-through benefit associated with injuries and damages and an unfavorable increase in the flow-through of bad debt expense for 2015.

For the three months ended June 30, 2015, as compared to the same period in the prior year, Power's increase was due primarily to the net reduction in the manufacturing deduction under Section 199 of the Internal Revenue Code and a reduction in purchased state income tax credits, partially offset by the tax benefit associated with the income tax rate differential of carrying back federal net operating tax losses under section 172(f) of the IRC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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




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)
	Three Months Ended June 30, 2014
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2014	$	—		$	(234	)	$	147		$	(87	)
Other Comprehensive Income before Reclassifications	1			—			23			24
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			2			(12		)	(10		)
Net Current Period Other Comprehensive Income (Loss)	1			2			11			14
Balance as of June 30, 2014	$	1		$	(232	)	$	158		$	(73	)

	Other Comprehensive Income (Loss)
PSEG	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	)

PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2014
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2013	$	(2	)	$	(238	)	$	145		$	(95	)
Other Comprehensive Income before Reclassifications	(4		)	—			34			30
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	7			6			(21		)	(8		)
Net Current Period Other Comprehensive Income (Loss)	3			6			13			22
Balance as of June 30, 2014	$	1		$	(232	)	$	158		$	(73	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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)
	Three Months Ended June 30, 2014
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2014	$	—		$	(201	)	$	144		$	(57	)
Other Comprehensive Income before Reclassifications	2			—			21			23
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			2			(12		)	(10		)
Net Current Period Other Comprehensive Income (Loss)	2			2			9			13
Balance as of June 30, 2014	$	2		$	(199	)	$	153		$	(44	)

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	)

Power	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2014
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2013	$	(1	)	$	(204	)	$	142		$	(63	)
Other Comprehensive Income before Reclassifications	(4		)	—			31			27
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	7			5			(20		)	(8		)
Net Current Period Other Comprehensive Income (Loss)	3			5			11			19
Balance as of June 30, 2014	$	2		$	(199	)	$	153		$	(44	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
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		)
Other-Than-Temporary Impairments (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	)




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, 2014									June 30, 2014
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	(12	)	$	5		$	(7	)
Total Cash Flow Hedges		—			—			—			(12		)	5			(7		)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	3			(1		)	2			5			(2		)	3
Amortization of Actuarial Loss	O&M Expense	(6		)	2			(4		)	(14		)	5			(9		)
Total Pension and OPEB Plans		(3		)	1			(2		)	(9		)	3			(6		)
Available-for-Sale Securities
Realized Gains	Other Income	33			(17		)	16			58			(30		)	28
Realized Losses	Other Deductions	(6		)	3			(3		)	(10		)	5			(5		)
OTTI	OTTI	(2		)	1			(1		)	(4		)	2			(2		)
Total Available-for-Sale Securities		25			(13		)	12			44			(23		)	21
Total		$	22		$	(12	)	$	10		$	23		$	(15	)	$	8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
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		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, 2014									June 30, 2014
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	(12	)	$	5		$	(7	)
Total Cash Flow Hedges		—			—			—			(12		)	5			(7		)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	2			(1		)	1			4			(2		)	2
Amortization of Actuarial Loss	O&M Expense	(6		)	3			(3		)	(12		)	5			(7		)
Total Pension and OPEB Plans		(4		)	2			(2		)	(8		)	3			(5		)
Available-for-Sale Securities
Realized Gains	Other Income	33			(17		)	16			56			(29		)	27
Realized Losses	Other Deductions	(6		)	3			(3		)	(10		)	5			(5		)
OTTI	OTTI	(2		)	1			(1		)	(4		)	2			(2		)
Total Available-for-Sale Securities		25			(13		)	12			42			(22		)	20
Total		$	21		$	(11	)	$	10		$	22		$	(14	)	$	8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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 our 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,
	2015				2014				2015				2014
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Net Income	$	345	$	345	$	212	$	212	$	931	$	931	$	598	$	598
EPS Denominator (Millions)
Weighted Average Common Shares Outstanding	506		506		506		506		506		506		506		506
Effect of Stock Based Compensation Awards	—		2		—		2		—		2		—		2
Total Shares	506		508		506		508		506		508		506		508

EPS
Net Income	$	0.68	$	0.68	$	0.42	$	0.42	$	1.84	$	1.83	$	1.18	$	1.18




	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2015		2014		2015		2014
Per Share	$	0.39	$	0.37	$	0.78	$	0.74
In Millions	$	197	$	187	$	394	$	374

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Note 16. Financial Information by Business Segments




	PSE&G		Power		Other (A)		Eliminations (B)			Consolidated
	Millions
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
Total 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
Three Months Ended June 30, 2014
Total Operating Revenues	$	1,435	$	986	$	131	$	(303	)	$	2,249
Net Income (Loss)	151		54		7		—			212
Gross Additions to Long-Lived Assets	515		100		5		—			620
Six Months Ended June 30, 2014
Total Operating Revenues	$	3,580	$	2,686	$	236	$	(1,030	)	$	5,472
Net Income (Loss)	365		218		15		—			598
Gross Additions to Long-Lived Assets	996		226		7		—			1,229
As of June 30, 2015
Total Assets	$	22,721	$	12,166	$	3,017	$	(1,692	)	$	36,212
Investments in Equity Method Subsidiaries	$	—	$	116	$	2	$	—		$	118
As of December 31, 2014
Total Assets	$	22,223	$	12,046	$	2,799	$	(1,735	)	$	35,333
Investments in Equity Method Subsidiaries	$	—	$	121	$	2	$	—		$	123


(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 related 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 .

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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 presented as follows:




	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2015		2014		2015		2014
	Millions
Billings from Affiliates:
Billings from Power primarily through BGS and BGSS (A)	$	297	$	297	$	993	$	1,028
Administrative Billings from Services (B)	65		64		131		124
Total Billings from Affiliates	$	362	$	361	$	1,124	$	1,152




	As of		As of
Related-Party Transactions	June 30, 2015		December 31, 2014
	Millions
Receivable from PSEG (C)	$	52	$	274
Payable to Power (A)	$	158	$	313
Payable to Services (B)	57		66
Accounts Payable—Affiliated Companies	$	215	$	379
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	161	$	116

Power

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




	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2015		2014		2015		2014
	Millions
Billings to Affiliates:
Billings to PSE&G primarily through BGS and BGSS Contracts (A)	$	297	$	297	$	993	$	1,028
Billings from Affiliates:
Administrative Billings from Services (B)	$	46	$	46	$	91	$	88

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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	As of		As of
Related-Party Transactions	June 30, 2015		December 31, 2014
	Millions
Receivables from PSE&G (A)	$	158	$	313
Payable to Services (B)	$	27	$	23
Payable to PSEG (C)	101		95
Accounts Payable—Affiliated Companies	$	128	$	118
Short-Term Loan (to) from Affiliate (Demand Note (to) PSEG) (E)	$	950	$	584
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	56	$	41


(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.


(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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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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.




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Three Months Ended June 30, 2014
Operating Revenues	$	—		$	972		$	42		$	(28	)	$	986
Operating Expenses	5			903			40			(29		)	919
Operating Income (Loss)	(5		)	69			2			1			67
Equity Earnings (Losses) of Subsidiaries	57			(3		)	3			(54		)	3
Other Income	8			47			—			(9		)	46
Other Deductions	—			(8		)	—			(1		)	(9		)
Other-Than-Temporary Impairments	—			(2		)	—			—			(2		)
Interest Expense	(27		)	(6		)	(5		)	9			(29		)
Income Tax Benefit (Expense)	21			(43		)	—			—			(22		)
Net Income (Loss)	$	54		$	54		$	—		$	(54	)	$	54
Comprehensive Income (Loss)	$	67		$	66		$	—		$	(66	)	$	67
Six Months Ended June 30, 2014
Operating Revenues	$	—		$	2,656		$	82		$	(52	)	$	2,686
Operating Expenses	9			2,307			74			(53		)	2,337
Operating Income (Loss)	(9		)	349			8			1			349
Equity Earnings (Losses) of Subsidiaries	234			(3		)	7			(231		)	7
Other Income	16			80			—			(17		)	79
Other Deductions	(4		)	(14		)	—			(1		)	(19		)
Other-Than-Temporary Impairments	—			(4		)	—			—			(4		)
Interest Expense	(55		)	(13		)	(10		)	17			(61		)
Income Tax Benefit (Expense)	36			(168		)	(1		)	—			(133		)
Net Income (Loss)	$	218		$	227		$	4		$	(231	)	$	218
Comprehensive Income (Loss)	$	237		$	242		$	4		$	(246	)	$	237
Six Months Ended June 30, 2014
Net Cash Provided By (Used In) Operating Activities	$	292		$	950		$	32		$	(460	)	$	814
Net Cash Provided By (Used In) Investing Activities	$	138		$	(415	)	$	(16	)	$	57		$	(236	)
Net Cash Provided By (Used In) Financing Activities	$	(430	)	$	(534	)	$	(17	)	$	403		$	(578	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated
	Millions
As of June 30, 2015
Current Assets	$	4,613	$	1,678	$	136	$	(4,216	)	$	2,211
Property, Plant and Equipment, net	80		6,290		1,337		—			7,707
Investment in Subsidiaries	4,409		289		—		(4,698		)	—
Noncurrent Assets	258		2,026		132		(168		)	2,248
Total Assets	$	9,360	$	10,283	$	1,605	$	(9,082	)	$	12,166
Current Liabilities	$	987	$	3,532	$	774	$	(4,216	)	$	1,077
Noncurrent Liabilities	465		2,534		350		(168		)	3,181
Long-Term Debt	2,244		—		—		—			2,244
Member's Equity	5,664		4,217		481		(4,698		)	5,664
Total Liabilities and Member's Equity	$	9,360	$	10,283	$	1,605	$	(9,082	)	$	12,166
As of December 31, 2014
Current Assets	$	4,263	$	2,037	$	150	$	(4,091	)	$	2,359
Property, Plant and Equipment, net	81		6,265		1,169		—			7,515
Investment in Subsidiaries	4,516		120		—		(4,636		)	—
Noncurrent Assets	278		1,952		137		(195		)	2,172
Total Assets	$	9,138	$	10,374	$	1,456	$	(8,922	)	$	12,046
Current Liabilities	$	883	$	3,606	$	786	$	(4,091	)	$	1,184
Noncurrent Liabilities	454		2,442		360		(195		)	3,061
Long-Term Debt	2,243		—		—		—			2,243
Member's Equity	5,558		4,326		310		(4,636		)	5,558
Total Liabilities and Member's Equity	$	9,138	$	10,374	$	1,456	$	(8,922	)	$	12,046

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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 primarily provides electric transmission services and distribution of electric energy and natural gas, implements demand response and energy efficiency programs and invests in solar generation in New Jersey, and


•	Power, our wholesale energy supply company that integrates its nuclear, fossil and renewable generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid-Atlantic United States.

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 2014 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 2014 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2015 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 2014 Form 10-K.

EXECUTIVE OVERVIEW OF 2015 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:


•	Growing our utility operations through continued investment in T&D infrastructure projects with greater diversity of regulatory oversight, and


•	Maintaining 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, 2015 and 2014 are presented as follows:




	Three Months Ended				Six Months Ended
	June 30,				June 30,
Earnings	2015		2014		2015		2014
	Millions
PSE&G	$	167	$	151	$	409	$	365
Power (A)	166		54		501		218
Other (B)	12		7		21		15
PSEG Net Income	$	345	$	212	$	931	$	598

PSEG Net Income Per Share (Diluted)	$	0.68	$	0.42	$	1.83	$	1.18


(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. See Note 8. Commitments and Contingent Liabilities .


(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 forward 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,
	2015		2014			2015		2014
	Millions, after tax
NDT Fund Income (Expense) (A)	$	1	$	14		$	3	$	23
Non-Trading MTM Gains (Losses)	$	28	$	(42	)	$	8	$	(174	)

(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.

Our $133 million and $333 million increases in Net Income for the three months and six months ended June 30, 2015 were driven primarily by:


•	MTM gains in 2015 as compared to MTM losses in 2014,


•	lower generation costs due to lower fuel costs,


•	higher revenues due to increased investments in transmission projects, and


•	insurance recoveries of Superstorm Sandy costs, primarily at Power.

At PSE&G, our regulated utility, we continued to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers. Effective January 1, 2015, PSE&G's formula rate increased our annual transmission revenues by approximately $182 million. Each year, transmission revenues are filed based on estimated data and subject to true up with actual current year data. The true-up adjustment for 2015 will primarily include the impact on rate base due to the extension of bonus depreciation, which was enacted after the filing was made, and is estimated to reduce our 2015 annual revenue increase by approximately $21 million. Over the past few years, these types of investments have altered the business mix of our overall results of operations to reflect a higher percentage contribution by PSE&G.

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Power’s results benefited from access to natural gas supplies through its existing firm pipeline transportation contracts during the cold weather experienced in the first quarter of 2015. Power manages these contracts for the benefit of PSE&G’s customers through the basic gas supply service (BGSS) arrangement. The contracts are sized to ensure 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.

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 Planning

The FERC’s rule under Order 1000 altered the right of first refusal (ROFR) previously held by incumbent utilities to build transmission within their respective service territories, creating the potential that new transmission projects in our service territory could be assigned to third parties rather than PSE&G. Order 1000 also presents opportunities for us to construct transmission outside of our service territory. In April 2013, PJM Interconnection, L.L.C. (PJM) initiated a solicitation process in which we participated to review technical solutions to improve the operational performance in the Artificial Island area, consisting of our Salem and Hope Creek nuclear generation facilities. On April 28, 2015, the PJM staff advised stakeholders that it intended to recommend a transmission project that would primarily be awarded to another entity, but that a portion at an estimated construction cost of between $100 million and $130 million would be assigned to PSE&G. We subsequently filed comments with the PJM Board of Managers (PJM Board) identifying what we believed were deficiencies in the PJM staff recommendation. On July 29, 2015, the PJM Board approved the PJM staff's recommendation. See Part II. Item 5. Other Information—Transmission Regulation—Transmission Policy Developments for additional information.

Wholesale Power Market Design

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. In May 2014, a federal court issued a rule that vacated a FERC Order in which the FERC had determined that demand response (DR) providers should receive full market compensation for power and held that the FERC has no jurisdiction over DR. The U.S. Supreme Court has accepted this case for review. The U.S. Supreme Court's decision could have a material impact on capacity market outcomes in which DR currently participates as a supply resource under FERC jurisdiction.

In a separate development of significance to the wholesale capacity market, in December 2014 PJM filed at the FERC its proposal for a capacity performance product to include generators, DR and energy efficiency providers who would need to certify their availability during emergency conditions, as a supplement to base capacity. The proposal includes enhanced performance-based incentives and penalties. On June 9, 2015, the FERC conditionally accepted the proposal. The capacity performance market design will be implemented for the 2015 base residual auction, which is scheduled to begin on August 10, 2015. It further provides generation owners with greater flexibility in submitting capacity market bids that reflect the additional costs and risks of the more rigorous performance requirements. See Part II, Item 5. Other Information—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 U.S. Environmental Protection Agency (EPA) and state environmental regulators. In particular, the EPA’s 316(b) rule on cooling water intake could adversely impact future nuclear and fossil operations and costs. As adopted by the EPA, the rule requires that cooling water intake structures reflect the best technology available for minimizing environmental impacts. Under this standard, power facilities have the flexibility to select one of several options as their method of compliance. However, the EPA has structured the rule so that each state will continue to consider renewal permits for power facilities on a case by case basis. On June 30, 2015, the New Jersey Department of Environmental Protection (NJDEP) issued a draft New Jersey Pollutant Discharge Elimination Systems (NJPDES) permit governing cooling water intake structures for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The draft permit is subject to a public notice and comment period after which the NJDEP may make revisions before issuing the final permit expected during the first half of 2016. See Part II, Item 5. Other Information—Water Pollution Control—Cooling Water Intake Structure Regulation for further information.

The EPA’s proposed greenhouse gas emissions regulations are also of potential consequence to our results. We continue to work with the FERC and other federal and state regulators, as well as industry partners, to determine the potential impact of these regulations. Clean Air Act (CAA) regulations governing hazardous air pollutants under the EPA's Maximum Achievable Control Technology rules are also of significance; however, we believe our generation business remains well-positioned for such air pollution control regulations if and when they are implemented. For additional information, see Part II, Item 5. Other

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Information—Air Pollution Control—Hazardous Air Pollutants Control. In addition, state environmental regulations governing emissions from power plants also have a significant impact on our operations. In the second quarter of 2015, we retired 1,545 MW of fully depreciated combustion turbine capacity that would not be able to comply with the more stringent emission standards for high electric demand day units (HEDD) under the New Jersey HEDD regulations for nitrous oxide, which will reduce capacity revenues for this year.

Other Developments

In the first half of 2015, 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 New Jersey Board of Public Utilities (BPU) in 2014. As approved, the Energy Strong program provides for $1.22 billion of investment, with cost recovery at a 9.75% rate of return on equity on the first $1.0 billion of the investment, plus associated allowance for funds used during construction, through an accelerated recovery mechanism. We will seek recovery of the remaining $220 million of investment in PSE&G's next base rate case, which is to be filed no later than November 1, 2017.

In February 2015, we filed a petition with the BPU seeking approval of a Gas System Modernization Program (GSMP) through which we propose to invest approximately $1.6 billion over the next five years, or about $320 million per year, to modernize PSE&G’s gas systems. The matter is pending.

In June 2015, we acquired a development project to construct a 755 MW gas-fired combined cycle generating station (Keys Energy Center) in Maryland with completion expected in 2018 at an estimated investment of $825 million - $875 million.

The preliminary non-public staff investigation initiated by the FERC into Power's discovery and investigation of (i) incorrect calculations for certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market and (ii) differences in the quantity of energy that Power offered into the energy market for its fossil peaking units from the amount for which Power was compensated in the capacity market for those units continues. Power has an ongoing process of implementing improved procedures to help mitigate the risk of similar issues occurring in the future. This investigation could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies. It is not possible at this time to reasonably estimate the ultimate impact or predict any resulting penalties, other costs associated with this matter, or the applicability of mitigating factors. For more detailed information, refer to Item 1. Note 8. Commitments and Contingent Liabilities—FERC Compliance.

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. In the first six months of 2015 , our


•	total nuclear fleet achieved an average capacity factor of 91%,


•	nuclear output increased by 2.6% and combined cycle output by 20.8% as compared to the first half of 2014,


•	diverse fuel mix and dispatch flexibility allowed us to generate approximately 28 TWh while addressing unit outages and balancing fuel availability and price volatility, and


•	construction of transmission projects proceeded on schedule and within budget.

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 2015 as we


•	had cash flow from operations of $2.2 billion as of June 30, 2015 ,


•	maintained solid investment grade credit ratings,


•	extended the expiration dates for approximately $2.0 billion of five-year credit facilities for PSEG, PSE&G and Power from 2018 to 2020, and


•	increased our indicated annual dividend for 2015 to $1.56 per share.

We expect to be able to fund our transmission projects required under PJM's reliability program, our Energy Strong program, Keys Energy Center and other planned projects, as well as our proposed GSMP, without the issuance of new equity.

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Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first six months of 2015 , in addition to our acquisition of the Keys Energy Center, we


•	made additional investments in transmission infrastructure projects,


•	secured approval to extend three Energy Efficiency Economic Stimulus subprograms to allow for $95 million of additional capital expenditures and $12 million of additional administrative expenses to provide energy efficiency assistance to hospitals, healthcare facilities and residential multi-family housing units,


•	continued to execute our existing BPU-approved utility programs,


•	completed the power ascension for the extended power uprate at our co-owned Peach Bottom 2 nuclear station, and


•	completed installation of equipment to increase output and improve efficiency at our Bergen 2 combined cycle gas unit similar to our 2014 installation at our Linden plant.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a slow-moving economy and a cost-constrained environment, 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 capital investment program, including our Energy Strong program, proposed 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 Energy Center and other generation projects,


•	advocate for measures to ensure the implementation by PJM and the 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 2015 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,


•	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,


•	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, and


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

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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,				Increase/ (Decrease)					June 30,				Increase/ (Decrease)
	2015		2014		2015 vs. 2014					2015		2014		2015 vs. 2014
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	2,314	$	2,249	$	65		3		$	5,449	$	5,472	$	(23	)	—
Energy Costs	668		789		(121		)	(15	)	1,762		2,145		(383		)	(18	)
Operation and Maintenance	761		800		(39		)	(5	)	1,424		1,656		(232		)	(14	)
Depreciation and Amortization	317		295		22			7		647		601		46			8
Income from Equity Method Investments	4		3		1			33		7		7		—			—
Other Income and (Deductions)	66		52		14			27		102		88		14			16
Other-Than-Temporary Impairments	10		2		8			N/A		15		4		11			N/A
Interest Expense	97		94		3			3		195		191		4			2
Income Tax Expense	186		112		74			66		584		372		212			57

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

PSE&G




	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,				Increase/ (Decrease)					June 30,				Increase/ (Decrease)
	2015		2014		2015 vs. 2014					2015		2014		2015 vs. 2014
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,466	$	1,435	$	31		2		$	3,468	$	3,580	$	(112	)	(3	)
Energy Costs	544		565		(21		)	(4	)	1,436		1,610		(174		)	(11	)
Operation and Maintenance	368		362		6			2		780		824		(44		)	(5	)
Depreciation and Amortization	234		217		17			8		481		444		37			8
Other Income (Deductions)	18		13		5			38		35		27		8			30
Interest Expense	67		67		—			—		136		135		1			1
Income Tax Expense	104		86		18			21		261		229		32			14

Three Months Ended June 30, 2015 as Compared to 2014

Operating Revenues increased $31 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $69 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $49 million higher due to net rate increases resulting primarily from increased capital investments.


•	Electric distribution revenues increased $13 million due primarily to higher sales volumes of $9 million and higher CIP II related revenues of $3 million due to the inclusion in base rates beginning in July 2014.

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•	Gas distribution revenues increased $7 million due primarily to higher Weather Normalization Clause (WNC) revenue of $6 million as a result of warmer than normal weather in the second quarter of 2015.

Commodity Revenue decreased $21 million as a result of lower Gas revenues partially offset by higher Electric revenues. Commodity revenue for both electric and gas is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of basic generation service (BGS) and BGSS to retail customers.


•	Gas revenues decreased $51 million due primarily to lower BGSS prices.


•	Electric revenues increased $30 million due primarily to a $41 million or 11% increase in BGS revenues due to higher sales volumes . This increase was partially offset by an $11 million reduction in revenues due to lower collections of Non-Utility Generation Charges (NGC) and lower volumes of Non-Utility Generation (NUG) energy sold at lower prices.

Clause Revenues decreased $18 million due primarily to lower Societal Benefit Charges (SBC) of $12 million , lower Margin Adjustment Clause (MAC) revenue of $6 million and lower Solar Pilot Recovery Charges (SPRC) of $2 million , partially offset by higher Securitization Transition Charges (STC) of $2 million . The changes in the SBC, MAC, SPRC and STC amounts were entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC, SPRC or STC collections.

Other Operating Revenues experienced no material change.

Operating Expenses

Energy Costs decreased $21 million due to lower Gas costs partially offset by higher Electric costs. This is entirely offset by decreased Commodity Revenue.


•	Gas costs decreased $51 million or 34% due to lower prices.


•	Electric costs increased by $30 million or 7% due to $11 million of higher BGS and NUG prices and $37 million in higher BGS volumes. BGS volumes increased 10% due primarily to reverse customer migration. These increases were partially offset by $14 million of lower NUG volumes and $4 million of decreased deferred cost recovery.

Operation and Maintenance increased $6 million , of which the most significant components were


•	a $9 million increase in pension and OPEB expenses,


•	increased gas bad debt expense of $5 million , and


•	$12 million in operating expenses, including increases of $3 million in storm damages, $3 million of higher wages, $2 million in appliance service costs and $1 million for injuries and damages,


•	partially offset by a $20 million decrease in costs related to a net decrease in SBC, MAC, GPRC, SPRC and STC. Due to the nature of the SBC, MAC, SPRC and STC clause mechanisms, these are entirely offset in revenues.

Depreciation and Amortization increased $17 million due primarily to a $13 million increase in depreciation of additional plant in service related to increased investments in various transmission and distribution projects and an increase of $4 million in amortization of Regulatory Assets.

Other Income and (Deductions) increased $5 million due primarily to an increase in Allowance for Funds used During Construction (AFUDC).

Income Tax Expense increased $18 million due primarily to higher pre-tax income.

Six Months Ended June 30, 2015 as Compared to 2014

Operating Revenues decreased $112 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $109 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $82 million higher due to net rate increases resulting primarily from increased capital investments.


•	Electric distribution revenues increased $14 million due primarily to higher sales volumes of $9 million and an

increase in CIP revenues of $4 million due to the inclusion of CIP II in base rates beginning in July 2014.


•	Gas distribution revenues increased $13 million due primarily to $20 million from higher sales volumes outside the WNC clause, partially offset by lower WNC revenue of $9 million due to colder weather in 2015 compared to 2014.

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Commodity Revenue decreased $174 million due to lower Gas revenues offset partially by higher Electric revenues. Commodity revenue for both electric and gas is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.


•	Gas revenues decreased $200 million due primarily to lower BGSS prices of $278 million , of which $207 million was due to lower residential rates resulting from $133 million in residential bill credits and $74 million of lower commodity prices , partially offset by higher BGSS volumes of $78 million due to colder weather in 2015.


•	Electric revenues increased $26 million due primarily to $58 million of higher net BGS revenues . BGS revenues increased by $87 million or 11% , due to higher sales volumes , which were partially offset by $29 million due to lower BGS prices. The increase from BGS was partially offset by $32 million in lower revenues from lower collection of NGC and lower sales prices and volumes of NUG energy.

Clause Revenues decreased $47 million due primarily to lower SBC of $25 million , lower MAC revenue of $24 million and lower SPRC of $1 million , partially offset by higher STC of $3 million . The changes in the SBC, MAC, SPRC and STC amounts were entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC, SPRC or STC collections.

Other Operating Revenues experienced no material change.

Operating Expenses

Energy Costs decreased $174 million due to lower Gas costs partially offset by higher Electric costs. This is entirely offset by decreased Commodity Revenue.


•	Gas costs decreased $200 million or 28% due to a $278 million or 39% decline in prices, partially offset by $78 million or 11% in higher sales volumes due to colder than normal weather.


•	Electric costs increased $26 million or 3% due to a $72 million or 9% increase in BGS volumes, primarily reflecting reverse customer migration and a $23 million increase due to higher BGS and NUG prices, partially offset by $50 million of decreased deferred cost recovery and $19 million in lower NUG sales volumes.

Operation and Maintenance decreased $44 million , of which the most significant components were


•	a $60 million decrease in costs related primarily to a net decrease in SBC, MAC, GPRC, CIP, SPRC and STC. Due to the nature of the SBC, MAC, SPRC and STC clause mechanisms, these are entirely offset in revenues.


•	storm insurance recovery proceeds of $10 million ,

• partially offset by an $18 million increase in pension and OPEB expenses, and


•	increased gas bad debt expense of $5 million .

Depreciation and Amortization increased $37 million due primarily to a $28 million increase in depreciation of additional plant in service related to increased investments in various transmission and distribution projects and an increase of $10 million in amortization of Regulatory Assets.

Other Income and (Deductions) increased $8 million due primarily to an increase in AFUDC.

Interest Expense increased $1 million due primarily to net issuances of Medium Term Notes in the first half 2015 and latter half of 2014, partially offset by partial redemption of securitization debt.

Income Tax Expense increased $32 million due primarily to higher pre-tax income.

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Power




	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,				Increase/ (Decrease)					June 30,				Increase/ (Decrease)
	2015		2014		2015 vs. 2014					2015		2014		2015 vs. 2014
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,025	$	986	$	39		4		$	2,750	$	2,686	$	64		2
Energy Costs	409		520		(111		)	(21	)	1,302		1,564		(262		)	(17	)
Operation and Maintenance	313		327		(14		)	(4	)	485		629		(144		)	(23	)
Depreciation and Amortization	75		72		3			4		151		144		7			5
Income from Equity Method Investments	5		3		2			67		8		7		1			14
Other Income (Deductions)	48		37		11			30		66		60		6			10
Other-Than-Temporary Impairments	10		2		8			N/A		15		4		11			N/A
Interest Expense	33		29		4			14		64		61		3			5
Income Tax Expense	72		22		50			N/A		306		133		173			N/A

Three Months Ended June 30, 2015 as Compared to 2014

Operating Revenues increased $39 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues increased $92 million due primarily to


•	higher net revenues of $112 million due primarily to MTM gains in 2015 compared to MTM losses in 2014, coupled with higher generation volumes at higher average realized sales prices in the PJM region,


•	an increase of $24 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM and New England (NE) regions, and


•	an increase of $10 million due to higher volumes of electricity sold under our BGS contract,


•	partially offset by a decrease of $54 million due to lower capacity revenues resulting from lower average auction prices coupled with a decrease in operating reserve revenue in the PJM region in 2015.

Gas Supply Revenues decreased $55 million due primarily to


•	a decrease of $24 million in sales under the BGSS contract substantially comprised of lower average sales prices, and


•	a decrease of $31 million due to lower sales volumes at lower average sales prices to third party customers.

Operating Revenues increased $2 million due to higher fees received from fuel management and power supply management contracts with LIPA.

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 $111 million due to


•	Generation costs decreased $55 million due primarily to lower fuel costs, reflecting lower average realized natural gas prices, coupled with a 2014 unfavorable MTM impact from lower average unrealized natural gas prices on forward purchases. These decreased costs were partially offset by the utilization of higher volumes of natural gas and higher congestion costs in the PJM region.


•	Gas costs decreased $56 million related to lower average gas inventory costs on both obligations under the BGSS contract and sales to third parties, coupled with lower volumes sold to third parties.

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Operation and Maintenance decreased $14 million due primarily to


•	a decrease of $17 million due to insurance recovery related to Superstorm Sandy, and


•	a net decrease of $17 million related to our fossil plants largely due to higher costs incurred in 2014 for planned outages and maintenance and installation of upgraded technology at our Linden combined cycle gas generating plant, partly offset by installation of upgraded technology in 2015 at our combined cycle Bergen generating plant,


•	partially offset by an increase of $23 million at our nuclear facilities, primarily due to a planned outage at our 100%-owned Hope Creek nuclear plant in 2015 as compared to a planned outage at our 57%-owned Salem nuclear unit 2 in 2014.

Depreciation and Amortization increased $3 million due primarily to a higher depreciable fossil and nuclear asset base.

Income from Equity Method Investments experienced no material change.

Other Income and (Deductions) increased $11 million due primarily to a $28 million insurance recovery related to Superstorm Sandy partly offset by lower realized gains from the NDT Fund.

Other-Than-Temporary Impairments increased $8 million due to an increase in impairments of the NDT Fund.

Interest Expense experienced no material change.

Income Tax Expense increased $50 million in 2015 due primarily to higher pre-tax income.

Six Months Ended June 30, 2015 as Compared to 2014

Operating Revenues increased $64 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues increased $200 million due primarily to


•	higher net revenues of $239 million due primarily to MTM gains in 2015 compared to MTM losses in 2014, partially offset by lower energy volumes sold in the NE region at lower average realized sales prices, and


•	an increase of $105 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM and NE regions,


•	partially offset by a net decrease of $153 million due primarily to lower capacity revenues resulting from lower average auction prices coupled with lower ancillary and operating reserve revenues in the PJM region.

Gas Supply Revenues decreased $138 million due primarily to


•	a net decrease of $71 million in sales under the BGSS contract, substantially comprised of lower average sales prices partially offset by higher sales volumes due to colder average temperatures in the 2015 winter heating season, and


•	a decrease of $67 million due to lower average sales prices and volumes to third party customers.

Other Operating Revenues increased $2 million due to higher fees received from fuel management and power supply management contracts with LIPA.

Operating Expenses

•

Generation costs decreased $90 million due primarily to lower fuel costs, reflecting lower average realized natural gas prices and the utilization of lower volumes of oil, coupled with a 2014 unfavorable MTM impact from lower average unrealized natural gas prices on forward purchases. These decreased costs were partially offset by the utilization of higher volumes of natural gas and higher congestion costs in the PJM region.


•	Gas costs decreased $172 million related to lower average gas inventory costs on both obligations under the BGSS contract and sales to third parties. This was partially offset by higher volumes sold under the BGSS contract due to colder average temperatures during the 2015 winter heating season.

Operation and Maintenance decreased $144 million due primarily to


•	a decrease of $145 million due to insurance recoveries related to Superstorm Sandy, and

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•

a net decrease of $36 million related to our fossil plants largely due to higher costs incurred in 2014 for planned outage costs, including maintenance and installation of upgraded technology at our Linden combined cycle gas generating plant, partly offset by planned outage costs in 2015 at our Bethlehem Energy Center generating plant and installation of upgraded technology at our combined cycle Bergen plant,


•	partially offset by an increase of $37 million at our nuclear facilities, primarily due to higher planned outage costs at our Hope Creek nuclear plant in 2015 as compared to our Salem nuclear unit 2 in 2014.

Depreciation and Amortization increased $7 million due primarily to a higher depreciable fossil and nuclear asset base.

Income from Equity Method Investments experienced no material change.

Other Income and (Deductions) increased $6 million due primarily to a $28 million insurance recovery related to Superstorm Sandy offset by lower realized gains from the NDT Fund.

Other-Than-Temporary Impairments increased $11 million due to an increase in impairments of the NDT Fund.

Interest Expense experienced no material change.

Income Tax Expense increased $173 million in 2015 due primarily to higher 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

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

For the six months ended June 30, 2015 , our operating cash flow increased $786 million as compared to the same period in 2014 . The net change was due primarily to higher tax payments in 2014 at the parent company and Energy Holdings and the net changes from PSE&G and Power as discussed below.

PSE&G

PSE&G’s operating cash flow increased $172 million from $737 million to $909 million for the six months ended June 30, 2015 , as compared to the same period in 2014 , due primarily to higher earnings , a $176 million reduction in tax payments and increased customer collections of $9 million . These amounts were partially offset by a decrease of $227 million due to a change in regulatory deferrals primarily driven by the return of prior year overcollections to customers for BGSS gas costs, Gas Weather Normalization charges and Non-Utility Generation charges.

Power

Power’s operating cash flow increased $478 million from $814 million to $1,292 million for the six months ended June 30, 2015 , as compared to the same period in 2014 , primarily due to higher earnings and a reduction in margin deposit requirements, partially offset by an increase of $171 million 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.

The commitments under our $4.3 billion credit facilities are provided by a diverse bank group. As of June 30, 2015 , our total available credit capacity was $4.1 billion .

As of June 30, 2015 , no single institution represented more than 8% of the total commitments in our credit facilities.

As of June 30, 2015 , our total credit capacity was in excess of our anticipated maximum liquidity requirements.

Each of our credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries' liquidity needs. Our total credit facilities and available liquidity as of June 30, 2015 were as follows:

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	As of June 30, 2015
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	8	$	492	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	$	8	$	992
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	$	198	$	1,402	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	1,000		—		1,000		Apr 2020	Funding/Letters of Credit
Bilateral Credit Facility	100		—		100		Sept 2015	Letters of Credit
Total Power	$	2,700	$	198	$	2,502
Total	$	4,300	$	220	$	4,080

(A) PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018.

(B) PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018.

Long-Term Debt Financing

PSE&G has $171 million of 6.75% Mortgage Bonds maturing in January 2016 . Power has $300 million of 5.50% Senior Notes maturing in December 2015 .

For a discussion of our long-term debt transactions during 2015 , see

Note 9. Changes in Capitalization .

Common Stock Dividends

On July 21, 2015 , our Board of Directors approved a $0.39 per share common stock dividend for the third quarter of 2015. This reflects an indicated annual dividend rate of $1.56 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

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 Fitch) 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 May 2015, Moody’s published research reports on PSEG, PSE&G and Power and the existing ratings and outlooks were unchanged. In May 2015, S&P published updated research reports and revised the outlook to stable from positive for PSEG’s Corporate Credit Rating and Power’s Senior Notes. S&P also affirmed the senior unsecured rating of BBB+ at Power and the mortgage bond rating of A at PSE&G.

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	Moody’s (A)	S&P (B)	Fitch (C)
PSEG
Outlook	Stable	Stable	Stable
Commercial Paper	P2	A2	F2
PSE&G
Outlook	Stable	Stable	Stable
Mortgage Bonds	Aa3	A	A+
Commercial Paper	P1	A2	F2
Power
Outlook	Stable	Stable	Stable
Senior Notes	Baa1	BBB+	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.


(C)	Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities.

CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing.

In February 2015, we filed a petition with the BPU seeking authority to invest $1.6 billion over the next 5 years, or about $320 million per year, to modernize PSE&G’s gas systems.

In June 2015, we acquired a development project to construct a 755 MW gas-fired combined cycle generating station in Maryland (Keys Energy Center). We plan to start constructing this year with expected completion in 2018 at an estimated investment of $825 million - $875 million.

The estimated project expenditures related to the gas system modernization program at PSE&G and the Maryland project at Power are not included in the $8.7 billion three-year capital forecast table in our 2014 Form 10-K. There were no material changes to our projected capital expenditures at Services as compared to amounts disclosed in our 2014 Form 10-K.

PSE&G

During the six months ended June 30, 2015 , PSE&G made capital expenditures of $1,230 million , primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of $58 million , which are included in operating cash flows.

Power

During the six months ended June 30, 2015 , Power made capital expenditures of $360 million , excluding $127 million for nuclear fuel, primarily related to various projects at its fossil and nuclear generation stations, including the new Maryland generating station noted above.

ACCOUNTING MATTERS

For information related to recent accounting matters, see 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 2015, MTM VaR remained relatively stable. The range of VaR was narrower for the three months ended June 30, 2015 as compared with the year ended December 31, 2014 .




	MTM VaR
	Three Months Ended June 30, 2015		Year Ended December 31, 2014
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	15	$	36
Average for the Period	$	18	$	30
High	$	23	$	195
Low	$	12	$	14
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	23	$	56
Average for the Period	$	28	$	46
High	$	36	$	306
Low	$	18	$	22

See

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 2015 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 2014 Annual Report on Form 10-K, see

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 2014 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 2015 .




Three Months Ended June 30, 2015	Total Number of Shares Purchased	Average Price Paid per Share
April 1 - April 30	—	$	—
May 1- May 31	49,360	$	42.70
June 1- June 30	—	$	—

ITEM 5. OTHER INFORMATION

Certain information reported in the 2014 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 2014 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 . References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.

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Federal Regulation

FERC

Regulation of Wholesale Sales—Generation/Market Issues

Capacity Market Issues — PJM

December 31, 2014 Form 10-K page 16 and March 31, 2015 Form 10-Q page 69 . The RPM is the locational installed capacity market design for the PJM region, including a forward auction for installed capacity. There is currently significant activity concerning two topics: (i) the future role of DR in the RPM market in light of a decision by the D.C. Circuit Court of Appeals (D.C. Court) holding that DR is not a FERC-jurisdictional product, and (ii) PJM’s development of a new capacity product called a Capacity Performance (CP) product.

In May 2014, the D.C. Court held that DR is not a FERC-jurisdictional product, thereby calling into question DR resources’ ability to participate in either the energy or capacity markets in the future. The U.S. Supreme Court has agreed to hear this case. A decision upholding the lower court decision would be expected to have a significant impact on the amount and manner of participation by DR in PJM's markets. However, until the U.S. Supreme Court rules on the case, DR will be allowed to participate in RPM for the upcoming base residual auction and capacity performance transitional auctions as supply resources under the recently accepted capacity performance rules described below.

On December 12, 2014, PJM filed a proposal at the FERC to implement a CP mechanism. Under this mechanism, PJM created a more robust capacity product definition with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. On June 9, 2015, the FERC conditionally accepted the CP mechanism which will be phased in over the next few years, with the participation of both the CP product and a base product that has less rigorous performance obligations. The CP mechanism will be implemented for the 2015 base residual auction which will begin on August 10, 2015. The CP product will be implemented fully for the 2020-2021 Delivery Year. The CP mechanism may provide the opportunity for enhanced capacity market revenue streams for Power. However, there may be requirements for additional investment and there are additional performance risks, as well as risks associated with our ability to bid in a manner that would ensure recovery of any required capital investment.

On June 30, 2015, a consumer coalition filed a complaint requesting that the load forecast that PJM is currently analyzing and updating to determine the amount of capacity it will procure in the 2016 base residual auction be implemented immediately for the upcoming 2015 transition auctions and base residual auction. If granted, use of the forecast values would likely decrease the amount of capacity to be procured and have an adverse impact on clearing prices in the 2015 base residual auction.

Capacity Market Issues — NYISO

December 31, 2014 Form 10-K page 17 and March 31, 2015 Form 10-Q page 70. Matters are pending before the FERC concerning potential changes to the NYISO capacity markets, including rules to govern payments and bidding requirements for generators proposing to exit the market but required to remain in service for reliability reasons. On March 19, 2015, the FERC issued an order which held that units receiving special reliability payments could properly take those payments into account in formulating capacity market bids. We believe that this ruling could have impacts on efficient price formation in the capacity market and could artificially suppress capacity market outcomes. On April 20, 2015, a trade association of which we are a member filed for rehearing by the FERC of this ruling. On May 8, 2015, the New York Public Service Commission and other New York agencies filed a complaint at the FERC requesting certain exemptions from the NYISO rules that prevent capacity suppliers from submitting bids that are not market competitive. If the exemptions are granted, market prices could be suppressed.

Transmission Regulation — Transmission Policy Developments

December 31, 2014 Form 10-K page 18 and March 31, 2015 Form 10-Q page 70. The 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 last year. The current PJM rules retain carve-outs for projects that will continue to default to incumbents for construction responsibility, including projects being built on existing right-of-way and whose construction would interfere with incumbents’ use of their right-of-way. While these carve-outs ameliorate the impacts of the Order 1000 ruling, we and several other companies appealed various aspects of the FERC order approving PJM’s implementation of Order 1000 on the grounds that the FERC had not met the requisite legal burden in eliminating the ROFR from the PJM Tariff. This appeal remains pending in federal court.

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 at Artificial Island off the shore of New Jersey. On April 28, 2015, the PJM staff advised stakeholders that it intended to recommend a transmission project to the PJM Board of Managers consisting of various components to be constructed by LS Power, PSE&G and Potomac Holding Company. Based on PJM’s presentation, the total construction cost of the project components that would be assigned to PSE&G

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ranged between $100 million and $130 million. Interested parties were allowed to submit comments to the PJM Board of Managers (PJM Board) until May 29, 2015. We filed timely comments identifying what we believed were deficiencies in the PJM staff recommendation. On July 29, 2015, the PJM Board approved the PJM staff's recommendation. In a related matter, the FERC denied a complaint filed by PSE&G contending that PJM had failed to follow its rules during the Artificial Island solicitation process.

There have also been developments on two additional matters. In November 2014, Con Edison had brought a complaint against PJM at the FERC challenging PJM's allocation of costs for two PSE&G projects in northern New Jersey, including the Bergen-Linden Corridor Project. We had opposed Con Edison's complaint and, in June 2015, the FERC issued an order upholding our position. Con Edison has sought judicial review of certain aspects of FERC’s order and has the right to seek rehearing of other aspects of the order. Also, in June 2015, a transmission developer filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. According to the complaint, PJM and certain transmission owners wrongfully inflated the scope and associated costs of mitigation work needed to accommodate the developer’s proposal in order to prevent it from pursuing its projects. Although not named as a respondent in the complaint, PSE&G is identified as one of the companies claimed to have been involved. On July 10, 2015, PJM filed a response, which included a supporting affidavit from PSE&G, contesting the allegations.

State Regulation

Energy Efficiency Economic Stimulus Extension II (EEE Ext II)

December 31, 2014 Form 10-K page 22 and March 31, 2015 Form 10-Q page 71 . On April 15, 2015, the BPU approved our petition for an EEE Ext II Program to extend three EEE subprograms (multi-family, direct install and hospital efficiency). The Order allows us to extend the subprogram offerings under the same clause recovery process as our existing EEE Program and allows for $95 million of additional capital expenditures over the next three years and $12 million of additional administrative expenses over the next 15 years. The EEE Ext II Program was added as a ninth component of the Green Program Recovery Charges rate effective May 1, 2015.

Connecticut Rate Filing

In June 2015, 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 2016 revenues of $22 million. This matter is pending.

Environmental Matters

Air Pollution Control

Hazardous Air Pollutants Regulation

December 31, 2014 Form 10-K page 22. In February 2012 , the Environmental Protection Agency ( 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 Clean Air Act. The MATS established allowable levels for mercury as well as other hazardous air pollutants and went into effect in April 2015. On June 29, 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. The case has been remanded back to the D.C. Circuit Court of Appeals (D.C. Court) and as a result the future of MATS remains unclear. If the D.C. Court decides to remand the rule to the EPA with a stay or vacate the rule in its entirety, power plants located in states with less stringent air pollution control requirements may choose to cease operating their newly installed controls. In addition, such a decision could impact decisions by other generators on plant retirements. Such uncertainty puts a downward pressure on power prices in the region. While the outcome of MATS remains uncertain, our power generation plants are already in compliance with MATS.

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

December 31, 2014 Form 10-K page 23. I n 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 final EPA rule includes 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). 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 May 1, 2015, the D.C. Court vacated the 100 hour

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exemption. The impact of this ruling will likely benefit Power's and its competitors' operations of their power generation peaking units. The D.C. Court's decision on the 50 hour exemption remains pending.

Climate Change

CO ₂ Regulation Under the Clean Air Act (CAA)

December 31, 2014 Form 10-K page 23 and March 31, 2015 Form 10-Q page 72. In June 2014, the EPA issued a proposed greenhouse gas (GHG) emissions regulation under the CAA for existing power plants. The regulation establishes state-specific emission rate targets based on implementation of the best system of emission reduction (BSER). The BSER consists of four components: (i) heat rate improvements at existing coal-fired power plants, (ii) increased use of existing natural gas combined cycle capacity, (iii) operation of zero-emitting generation (renewables and nuclear), and (iv) increased use of demand-side energy efficiency. States may choose these or other methodologies to achieve the necessary reductions of CO ₂ emissions.

Since the EPA has requested comments on many aspects of the proposal, the final rule may look considerably different than the proposal. We continue to work with state and federal regulators, as well as industry partners, to determine the potential impact. A final rule is expected in August 2015.

The FERC held a series of technical conferences ending in early April 2015 to discuss the implications of compliance approaches to the EPA’s proposed GHG regulation for existing power plants. The conferences focused on issues related to electric reliability, wholesale electric markets and operations and energy infrastructure. The FERC also solicited and received written comments. On May 15, 2015, the FERC issued a letter to the EPA expressing its willingness to work with the EPA to address reliability concerns as the EPA moves toward finalizing the rule.

Water Pollution Control

Cooling Water Intake Structure Regulation

December 31, 2014 Form 10-K page 25. On June 30, 2015, the NJDEP issued a draft permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The draft permit is subject to a sixty-day public notice and comment period after which the NJDEP may make revisions before issuing the final permit expected in the first half of 2016. We are reviewing the details of the draft, evaluating its potential impact and will participate in the comment process. For additional information, see Part I, Item 1. Note 8. Commitments and Contingent Liabilities.

Waters of the United States

December 31, 2014 Form 10-K page 25. In April 2014, the EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published a proposed rule to clarify the definition of waters of the U.S. under the Clean Water Act (CWA) programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. On November 14, 2014, we participated with other energy companies in submitting comments on the proposed rule. The final rule was published on June 29, 2015 and we are reviewing it to determine the materiality of the impacts that might result from the final rule.

Endangered Species Act

On June 16, 2015, the Sierra Club and another environmental group submitted to the NJDEP a sixty-day notice of intent to sue alleging the agency has caused violations of the Endangered Species Act by allowing our Mercer generation station to operate in a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a permit renewal action for Mercer which addresses the alleged Endangered Species Act violations. We cannot predict the outcome of this action.

Fuel and Waste Disposal

Coal Combustion Residuals (CCRs)

December 31, 2014 Form 10-K page 26 and March 31, 2015 Form 10-Q page 72 . 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. Our Hudson and Mercer generating stations, along with our 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 14, 2015. The impacts of this final rule were not material to our results of operations, financial condition or cash flows. See Part I, Item 1. Note 8. Commitments and Contingent Liabilities for additional information.

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ITEM 6.	EXHIBITS

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



a. PSEG:
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 Caroline Dorsa 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 Caroline Dorsa 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. PSE&G:
Exhibit 4 (a) (23)		Supplemental Indenture dated May 1, 2015
Exhibit 12.1:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.2:		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.2:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:		Certification by Caroline Dorsa 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 Caroline Dorsa 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. Power:
Exhibit 12.3:		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 Caroline Dorsa 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 Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

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SIGNATURE

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



P UBLIC S ERVICE E NTERPRISE G ROUP I NCORPORATED
(Registrant)

By:	/ S / S TUART J. B LACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: July 31, 2015

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SIGNATURE



P UBLIC S ERVICE E LECTRIC A ND G AS C OMPANY
(Registrant)

By:	/ S / S TUART J. B LACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: July 31, 2015

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SIGNATURE



PSEG P OWER LLC
(Registrant)

By:	/ S / S TUART J. B LACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: July 31, 2015

TABLE OF CONTENTS

Note 1. Organization and Basis Of Presentationprint Note 2. Recent Accounting Standardsprint Note 3. Variable Interest Entities (vies)print Note 7. Pension and Other Postretirement Benefitsprint Note 4. Rate Filingsprint Note 5. Financing Receivablesprint Note 6. Available-for-sale Securitiesprint Note 7. Pension and Other Postretirement Benefits (opeb)print Note 3. Variable Interest Entitiesprint Note 8. Commitments and Contingent Liabilitiesprint Note 10. Financial Risk Management Activitiesprint Note 17. Related-party Transactionsprint Note 9. Changes in Capitalizationprint Note 11. Fair Value Measurementsprint Note 12. Other Income and Deductionsprint Note 13. Income Taxesprint Note 14. Accumulated Other Comprehensive Income (loss), Net Of Taxprint Note 15. Earnings Per Share (eps) and Dividendsprint Note 16. Financial Information By Business Segmentsprint Note 18. Guarantees Of Debtprint Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations (md&a)print Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 5. Other Informationprint Item 6. Exhibitsprint

DIRECTORS	AGE	BIO
Vagt	78	Mr. Vagt has served as a director of KMI since 2012. He served as a director of EP from 2005 until we acquired it in 2012. Mr. Vagt joined the board of directors of EQT Corporation (NYSE: EQT) in July 2024. He previously served as the lead independent director of Equitrans Midstream Corp. (NYSE: ETRN) from 2018 until July 2024. Mr. Vagt also previously served as a member of the board of directors of EQT Corporation from 2017 until the separation of EQT Corporation and Equitrans Midstream Corp. in 2018. He served as Chairman of the board of directors of Rice Energy Inc. from 2014 until its acquisition by EQT Corporation in 2017. Mr. Vagt served as President of The Heinz Endowments from 2008 through 2014. Prior to that time, he served as President of Davidson College from 1997 to 2007. Mr. Vagt served as President and Chief Operating Officer of Seagull Energy Corporation from 1996 to 1997. From 1992 to 1996, he served as President, Chairman and Chief Executive Officer of Global Natural Resources. Mr. Vagt served as President and Chief Operating Officer of Adobe Resources Corporation from 1989 to 1992. Prior to 1989, he served in various positions with Adobe Resources Corporation and its predecessor entities. Mr. Vagt’s professional background in both the public and private sectors make him an important advisor and member of our Board. Mr. Vagt brings to our Board operations and management expertise in both the public and private sectors. In addition, Mr. Vagt provides our Board with a welcome diversity of perspective gained from his service as an executive officer of multiple energy companies, the president of a major charitable foundation and the president of an independent liberal arts college.
Smith	35	Mr. Smith has served as a director of KMI since 2014. He served as a director of EPB GP from 2008 to 2014. From 2003 until his retirement as an active partner in 2012, Mr. Smith was a partner in Galway Group, L.P., an investment banking/energy advisory firm headquartered in Houston, Texas. In 2002, Mr. Smith retired from EP, where he was an Executive Vice President and Chairman of El Paso Merchant Energy’s Global Gas Group. Mr. Smith had a 29-year career with Sonat Inc. prior to its merger with EP in 1999. At the time of the merger, Mr. Smith was Executive Vice President and General Counsel. He previously served as Chairman and President of Southern Natural Gas Company and as Vice Chairman of Sonat Exploration Company. Mr. Smith served as a director of Eagle Rock Energy G&P LLC from 2004 until the sale of that company in 2015. Mr. Smith previously served on the board of directors of Maritrans Inc. until 2006. With over 40 years of experience in the energy industry, Mr. Smith brings to the Board a wealth of knowledge and understanding of our industry, including valuable legal and business expertise. His experience as an executive and attorney provides the Board with an important skill set and perspective. In addition, his experience on the board of directors of other domestic and international energy companies further augments his knowledge and experience.
Shaper	56	Mr. Shaper has served as a director of KMI since 2007. He was a director of KMR and KMGP from 2003 until 2013 and a director of EPB GP from 2012 until 2013. He served in various management roles for the Kinder Morgan companies from 2000 until 2013, when he retired as President. Mr. Shaper has been a director of Service Corporation International (NYSE: SCI) since May 2022. He was appointed Chairman of the Board of Sunnova Energy International (NYSE: NOVA) in March 2025, where he has served as a director since 2019 and serves as chair of its audit committee. From 2007 until August 2021, he served as a trust manager of Weingarten Realty Investors and as the chair of its compensation committee. Mr. Shaper was a member of the board of directors of Star Peak Energy Transition Corp. (NYSE: STPK) from August 2020 until its merger with Stem, Inc. in April 2021 and Star Peak Corp II (NYSE: STPC) from January 2021 until its merger with Benson Hill in September 2021, and he served as the chair of their respective audit, compensation and nominating and governance committees. Mr. Shaper’s previous experience as our President, and as an executive officer of various Kinder Morgan entities, provides him valuable management and operational expertise and intimate knowledge of our business operations, finances and strategy.
Reichstetter	78	Mr. Reichstetter has served as a director of KMI since 2014. He served as a director of EPB GP from 2007 until 2014. He has been a private investor since 2007. Mr. Reichstetter served as Managing Director of Lazard Freres from 2002 until his retirement in 2007. From 1998 to 2002, Mr. Reichstetter was a Managing Director with Dresdner Kleinwort Wasserstein, formerly Wasserstein Parella & Co. Mr. Reichstetter was a Managing Director with Merrill Lynch from 1993 until 1996. Prior to that time, Mr. Reichstetter worked as an investment banker in various positions at The First Boston Corporation from 1974 until 1993, becoming a managing director with that company in 1982. Mr. Reichstetter brings to the Board extensive experience in investment management and capital markets, as highlighted by his years of service at Lazard Freres, Dresdner Klienwort Wasserstein, Merrill Lynch and
Macdonald	80
Hall	40	Mr. Hall has served as a director of KMI since 2012. Previously, he served as a director of EP from 2001 until the closing of our acquisition of EP in 2012. Mr. Hall has been engaged in the private practice of law since 2010. He previously served as Chief Administrative Officer of the City of Houston from 2004 to 2010 and as the City Attorney for the City of Houston from 1998 to 2004. Prior to 1998, Mr. Hall was a partner in the Houston law firm of Jackson Walker, LLP. Mr. Hall is the past Chairman of the Houston Endowment Inc. and served on its board of directors for 12 years. He is also Chairman of the Boulé Foundation. Mr. Hall’s extensive experience in both the public and private sectors, and his affiliations with many different business and philanthropic organizations, provides our Board with important insight from many perspectives. Mr. Hall’s more than 40 years of legal experience provides the Board with valuable guidance on governance issues and initiatives. As an African American, Mr. Hall also brings a diversity of experience and perspective that is welcomed by our Board.
Gardner	67	Mr. Gardner has served as a director of KMI since 2014. He served as a director of KMR and KMGP from 2011 until 2014, and he was a director of the predecessor of KMI from 1999 to 2007. Mr. Gardner has been a Managing Partner of Silverhawk Capital Partners since 2005. Mr. Gardner has served as a director of Incline Energy Partners, LP since 2015. He became chairman of the board of the general partner of CSI Compressco LP following its acquisition by Spartan Energy Partners in January 2021 and served in that role until CSI Compressco LP merged into Kodiak Gas Services in April 2024. Formerly, he served as a director of Encore Acquisition Company from 2001 to 2010, a director of Athlon Energy Inc. from 2013 to 2014, a director of Summit Materials Inc. from 2009 to May 2020, and a director of Spartan Energy Partners from 2010 until November 2021. We believe Mr. Gardner’s
Chronis	30	Ms. Chronis was elected as a director of KMI at the 2024 annual meeting of stockholders. She was a Senior Partner with Deloitte LLP until her retirement in June 2024. Ms. Chronis served as Deloitte’s Vice Chair and US Energy & Chemicals Industry Leader from January 2021 to January 2024 and as the Managing Partner of Deloitte’s Houston practice from February 2018 to January 2024. She joined Deloitte as a Partner in June 2002. Ms. Chronis has served on the board of directors of the Greater Houston Partnership since April 2018 and served as its chairman for 2021. She has served on the board of directors of Texas 2036, a nonpartisan data driven public policy think tank, since September 2019. Ms. Chronis is a CPA, status retired, licensed in the State of Texas and is NACD (National Association of Corporate Directors) certified. Ms. Chronis has over 30 years of experience as a finance and public accounting executive focusing on the energy, chemicals, technology and manufacturing industries. In addition to her financial and accounting expertise and knowledge of the energy industry, she brings to the Board notable expertise in executive leadership, strategic planning, business transformation, technology, sustainability and enterprise risk management. Ms. Chronis also provides a diverse perspective that is important to our Board.

Name and Principal Position		Year		Salary ($)		Bonus ($)		Stock Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value ($)		All Other Comp-ensation ($)		Total ($)
Kimberly A. Dang Chief Executive Officer		2024		500,000		—		11,000,015		—		16,917		17,250		11,534,182
		2023		498,077		—		11,000,016		850,000		40,917		16,500		12,405,510
		2022		473,077		—		5,000,011		1,400,000		—		15,250		6,888,338
David P. Michels Vice President and Chief Financial Officer		2024		500,000		—		2,400,019		735,000		7,912		17,250		3,660,181
		2023		498,077		—		2,100,004		735,000		27,197		16,500		3,376,778
		2022		473,077		—		1,500,015		750,000		—		15,250		2,738,342
Sital K. Mody Vice President (President, Natural Gas Pipelines)		2024		500,000		—		2,400,019		1,050,000		15,834		17,250		3,983,103
	Dax A. Sanders Vice President (President, Products Pipelines)		2024		500,000		—		2,400,019		725,000		11,245		17,250		3,653,514
			2023		498,077		—		2,250,012		675,000		37,380		16,500		3,476,969
		2022		473,077		—		1,875,002		688,000		—		15,250		3,051,329
John W. Schlosser Vice President (President, Terminals)		2024		500,000		—		2,400,012		725,000		27,503		45,118		3,697,633

Supplier name	Ticker
Exxon Mobil Corporation	XOM
Honeywell International Inc.	HON
3M Company	MMM
Dominion Energy, Inc.	D
The Southern Company	SO
Air Products and Chemicals, Inc.	APD
Eaton Corporation plc	ETN
General Electric Company	GE

Owner	Position	Direct Shares	Indirect Shares
KEAN STEVEN J	-	7,101,060	265,000
MARTIN THOMAS A	-	1,016,770	277,950
MARTIN THOMAS A	-	789,652	277,950
Dang Kimberly A	-	515,756	2,026,050
Sanders Dax	-	309,069	0
GARDNER TED A	-	302,988	196,610
Sanders Dax	-	256,069	0
Schlosser John W	-	220,681	0
Michels David Patrick	-	146,468	0
Michels David Patrick	-	114,700	0
Mathews Denise R	-	79,217	1,761
Grahmann Kevin P	-	58,653	0
ASHLEY ANTHONY B	-	54,242	0
VAGT ROBERT F	-	47,579	0
ASHLEY ANTHONY B	-	41,863	0
Chronis Amy W	-	32,005	0
Mody Sital K	-	26,710	0
Mody Sital K	-	25,169	0
Schlosser John W	-	10,719	0
MORGAN MICHAEL C	-	0	22,811

PEG 10-Q Quarter ended June 30, 2015