Edgar Filing: PUBLIC SERVICE ENTERPRISE GROUP INC

PSEG-9/30/2013-Q3

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 September 30, 2013

¨ 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
001-34232	PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza—T25 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com	22-3663480
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

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

PSEG Power LLC	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	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

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 October 15, 2013, Public Service Enterprise Group Incorporated had outstanding 505,861,262 shares of its sole class of Common Stock, without par value.

As of October 15, 2013, 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.

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



		Page
FORWARD-LOOKING STATEMENTS		ii

PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated	1
	PSEG Power LLC	6
	Public Service Electric and Gas Company	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. Asset Disposition	18
	Note 5. Rate Filings	18
	Note 6. Financing Receivables	18
	Note 7. Available-for-Sale Securities	21
	Note 8. Pension and Other Postretirement Benefits (OPEB)	26
	Note 9. Commitments and Contingent Liabilities	27
	Note 10. Changes in Capitalization	35
	Note 11. Financial Risk Management Activities	36
	Note 12. Fair Value Measurements	42
	Note 13. Other Income and Deductions	51
	Note 14. Income Taxes	52
	Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax	53
	Note 16. Earnings Per Share (EPS) and Dividends	56
	Note 17. Financial Information by Business Segments	57
	Note 18. Related-Party Transactions	58
	Note 19. Guarantees of Debt	60
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	63
	Overview of 2013 and Future Outlook	63
	Results of Operations	68
	Liquidity and Capital Resources	74
	Capital Requirements	77
	Accounting Matters	77
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	77
Item 4.	Controls and Procedures	78

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	79
Item 1A.	Risk Factors	79
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	79
Item 5.	Other Information	79
Item 6.	Exhibits	84
	Signatures	85

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this communication about us 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 regulation, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, transmission planning and cost allocation rules, including rules regarding how transmission is planned and who is permitted to build transmission in the future, and reliability standards,


•	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 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 balance our energy obligations, available supply and risks,


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


•	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 coverage or recover proceeds of insurance on such matters,


•	increases in competition in energy supply markets as well as competition for certain rate-based 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, and


•	changes in technology, such as distributed generation and microgrids, and resultant changes in customer usage patterns, including energy efficiency 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.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
OPERATING REVENUES	$	2,554		$	2,402		$	7,650		$	7,375
OPERATING EXPENSES
Energy Costs	801			879			2,711			2,819
Operation and Maintenance	713			619			2,069			1,876
Depreciation and Amortization	313			286			886			797
Taxes Other Than Income Taxes	15			24			50			73
Total Operating Expenses	1,842			1,808			5,716			5,565
OPERATING INCOME	712			594			1,934			1,810
Income from Equity Method Investments	4			7			9			9
Other Income	59			121			172			216
Other Deductions	(12		)	(26		)	(54		)	(61		)
Other-Than-Temporary Impairments	(3		)	(2		)	(7		)	(14		)
Interest Expense	(100		)	(106		)	(303		)	(310		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	660			588			1,751			1,650
Income Tax Expense	(270		)	(241		)	(708		)	(599		)
NET INCOME	$	390		$	347		$	1,043		$	1,051
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC	505,858			505,914			505,900			505,942
DILUTED	507,694			507,111			507,433			507,037
EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS	$	0.77		$	0.69		$	2.06		$	2.08
NET INCOME	$	0.77		$	0.69		$	2.06		$	2.08
DILUTED
INCOME FROM CONTINUING OPERATIONS	$	0.77		$	0.68		$	2.06		$	2.07
NET INCOME	$	0.77		$	0.68		$	2.06		$	2.07
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.3600		$	0.3550		$	1.0800		$	1.0650

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
NET INCOME	$	390		$	347		$	1,043		$	1,051
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(16), $5, $(27) and $(16) for the three and nine months ended 2013 and 2012, respectively	16			(10		)	27			12
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $8, $4 and $14 for the three and nine months ended 2013 and 2012, respectively	(1		)	(10		)	(5		)	(20		)
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(6), $(5), $(20) and $(16) for the three and nine months ended 2013 and 2012, respectively	9			8			28			23
Other Comprehensive Income (Loss), net of tax	24			(12		)	50			15
COMPREHENSIVE INCOME	$	414		$	335		$	1,093		$	1,066

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	448		$	379
Accounts Receivable, net of allowances of $57 and $56 in 2013 and 2012, respectively	1,069			1,069
Tax Receivable	225			227
Unbilled Revenues	211			314
Fuel	599			583
Materials and Supplies, net	450			422
Prepayments	210			283
Derivative Contracts	107			138
Deferred Income Taxes	31			49
Regulatory Assets	348			349
Other	43			56
Total Current Assets	3,741			3,869
PROPERTY, PLANT AND EQUIPMENT	29,206			27,402
Less: Accumulated Depreciation and Amortization	(8,127		)	(7,666		)
Net Property, Plant and Equipment	21,079			19,736
NONCURRENT ASSETS
Regulatory Assets	3,519			3,830
Regulatory Assets of Variable Interest Entities (VIEs)	532			713
Long-Term Investments	1,320			1,324
Nuclear Decommissioning Trust (NDT) Fund	1,635			1,540
Other Special Funds	181			191
Goodwill	16			16
Other Intangibles	52			34
Derivative Contracts	184			153
Restricted Cash of VIEs	23			23
Other	328			296
Total Noncurrent Assets	7,790			8,120
TOTAL ASSETS	$	32,610		$	31,725

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2013			December 31, 2012
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	775		$	1,026
Securitization Debt of VIEs Due Within One Year	235			226
Commercial Paper and Loans	—			263
Accounts Payable	1,024			1,304
Derivative Contracts	36			46
Accrued Interest	114			91
Accrued Taxes	83			17
Deferred Income Taxes	48			72
Clean Energy Program	185			153
Obligation to Return Cash Collateral	118			122
Regulatory Liabilities	171			67
Other	446			390
Total Current Liabilities	3,235			3,777
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	6,807			6,542
Regulatory Liabilities	213			209
Regulatory Liabilities of VIEs	11			10
Asset Retirement Obligations	653			627
Other Postretirement Benefit (OPEB) Costs	1,274			1,285
Accrued Pension Costs	710			876
Environmental Costs	431			537
Derivative Contracts	163			122
Long-Term Accrued Taxes	183			164
Other	115			108
Total Noncurrent Liabilities	10,560			10,480
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt	7,134			6,148
Securitization Debt of VIEs	326			496
Project Level, Non-Recourse Debt	16			43
Total Long-Term Debt	7,476			6,687
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2013 and 2012—533,556,660 shares	4,852			4,833
Treasury Stock, at cost, 2013— 27,695,398 shares; 2012— 27,664,188 shares	(615		)	(607		)
Retained Earnings	7,439			6,942
Accumulated Other Comprehensive Loss	(338		)	(388		)
Total Common Stockholders’ Equity	11,338			10,780
Noncontrolling Interest	1			1
Total Stockholders’ Equity	11,339			10,781
Total Capitalization	18,815			17,468
TOTAL LIABILITIES AND CAPITALIZATION	$	32,610		$	31,725

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Nine Months Ended
	September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,043		$	1,051
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	886			797
Amortization of Nuclear Fuel	145			129
Provision for Deferred Income Taxes (Other than Leases) and ITC	242			221
Non-Cash Employee Benefit Plan Costs	182			203
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(7		)	(81		)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	3			116
Change in Accrued Storm Costs	(87		)	5
Net Change in Other Regulatory Assets and Liabilities	134			(82		)
Cost of Removal	(66		)	(71		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(76		)	(107		)
Net Change in Tax Receivable	2			16
Net Change in Certain Current Assets and Liabilities	173			305
Employee Benefit Plan Funding and Related Payments	(210		)	(193		)
Other	71			2
Net Cash Provided By (Used In) Operating Activities	2,435			2,311
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,102		)	(1,969		)
Proceeds from Sale of Capital Leases and Investments	42			—
Proceeds from Sales of Available-for-Sale Securities	914			1,473
Investments in Available-for-Sale Securities	(922		)	(1,497		)
Other	(20		)	(58		)
Net Cash Provided By (Used In) Investing Activities	(2,088		)	(2,051		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(263		)	—
Issuance of Long-Term Debt	1,500			850
Redemption of Long-Term Debt	(750		)	(439		)
Redemption of Securitization Debt	(162		)	(154		)
Repayment of Non-Recourse Debt	—			(1		)
Cash Dividends Paid on Common Stock	(546		)	(538		)
Other	(57		)	(32		)
Net Cash Provided By (Used In) Financing Activities	(278		)	(314		)
Net Increase (Decrease) in Cash and Cash Equivalents	69			(54		)
Cash and Cash Equivalents at Beginning of Period	379			834
Cash and Cash Equivalents at End of Period	$	448		$	780
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	222		$	109
Interest Paid, Net of Amounts Capitalized	$	274		$	280
Accrued Property, Plant and Equipment Expenditures	$	258		$	259

See Notes to Condensed Consolidated Financial Statements.

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
OPERATING REVENUES	$	1,169		$	1,038		$	3,806		$	3,584
OPERATING EXPENSES
Energy Costs	430			456			1,786			1,725
Operation and Maintenance	304			255			866			780
Depreciation and Amortization	66			60			195			175
Total Operating Expenses	800			771			2,847			2,680
OPERATING INCOME	369			267			959			904
Other Income	45			104			127			171
Other Deductions	(11		)	(20		)	(49		)	(52		)
Other-Than-Temporary Impairments	(3		)	(2		)	(7		)	(14		)
Interest Expense	(26		)	(35		)	(85		)	(97		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	374			314			945			912
Income Tax Expense	(153		)	(133		)	(383		)	(374		)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	221		$	181		$	562		$	538

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

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
NET INCOME	$	221		$	181		$	562		$	538
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(18), $6, $(29) and $(16) for the three and nine months ended 2013 and 2012, respectively	17			(11		)	30			11
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $8, $4 and $14 for the three and nine months ended 2013 and 2012, respectively	(1		)	(11		)	(6		)	(21		)
Pension/OPEB adjustment, net of tax (expense) benefit of $(6), $(4), $(17) and $(14) for the three and nine months ended 2013 and 2012, respectively	8			7			25			21
Other Comprehensive Income (Loss), net of tax	24			(15		)	49			11
COMPREHENSIVE INCOME	$	245		$	166		$	611		$	549

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

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	9		$	7
Accounts Receivable	211			269
Accounts Receivable—Affiliated Companies, net	34			340
Short-Term Loan to Affiliate	417			574
Fuel	599			583
Materials and Supplies, net	329			307
Derivative Contracts	72			118
Prepayments	16			17
Deferred Income Taxes	3			—
Other	—			19
Total Current Assets	1,690			2,234
PROPERTY, PLANT AND EQUIPMENT	10,035			9,697
Less: Accumulated Depreciation and Amortization	(2,973		)	(2,679		)
Net Property, Plant and Equipment	7,062			7,018
NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund	1,635			1,540
Goodwill	16			16
Other Intangibles	52			34
Other Special Funds	38			36
Derivative Contracts	89			49
Other	139			105
Total Noncurrent Assets	1,969			1,780
TOTAL ASSETS	$	10,721		$	11,032

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

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2013			December 31, 2012
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	—		$	300
Accounts Payable	404			498
Derivative Contracts	36			46
Deferred Income Taxes	—			16
Accrued Interest	37			26
Other	109			81
Total Current Liabilities	586			967
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	1,732			1,575
Asset Retirement Obligations	385			369
Other Postretirement Benefit (OPEB) Costs	230			221
Derivative Contracts	23			15
Accrued Pension Costs	225			272
Long-Term Accrued Taxes	50			50
Other	90			84
Total Noncurrent Liabilities	2,735			2,586
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
LONG-TERM DEBT
Total Long-Term Debt	2,041			2,040
MEMBER’S EQUITY
Contributed Capital	2,028			2,028
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,596			4,725
Accumulated Other Comprehensive Loss	(279		)	(328		)
Total Member’s Equity	5,359			5,439
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	10,721		$	11,032

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

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Nine Months Ended
	September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	562		$	538
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	195			175
Amortization of Nuclear Fuel	145			129
Provision for Deferred Income Taxes and ITC	96			189
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	3			116
Non-Cash Employee Benefit Plan Costs	50			53
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(76		)	(107		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	(38		)	(10		)
Margin Deposit	17			(107		)
Accounts Receivable	69			50
Accounts Payable	(63		)	(31		)
Accounts Receivable/Payable-Affiliated Companies, net	306			193
Accrued Interest Payable	11			17
Other Current Assets and Liabilities	20			2
Employee Benefit Plan Funding and Related Payments	(45		)	(40		)
Other	32			5
Net Cash Provided By (Used In) Operating Activities	1,284			1,172
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(419		)	(493		)
Proceeds from Sales of Available-for-Sale Securities	849			1,295
Investments in Available-for-Sale Securities	(864		)	(1,315		)
Short-Term Loan—Affiliated Company, net	157			17
Other	(13		)	(10		)
Net Cash Provided By (Used In) Investing Activities	(290		)	(506		)
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid	(690		)	(600		)
Redemption of Long-Term Debt	(300		)	(66		)
Other	(2		)	(7		)
Net Cash Provided By (Used In) Financing Activities	(992		)	(673		)
Net Increase (Decrease) in Cash and Cash Equivalents	2			(7		)
Cash and Cash Equivalents at Beginning of Period	7			12
Cash and Cash Equivalents at End of Period	$	9		$	5
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	107		$	130
Interest Paid, Net of Amounts Capitalized	$	72		$	73
Accrued Property, Plant and Equipment Expenditures	$	58		$	84

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
OPERATING REVENUES	$	1,666		$	1,683		$	5,084		$	5,029
OPERATING EXPENSES
Energy Costs	661			756			2,208			2,380
Operation and Maintenance	408			366			1,204			1,092
Depreciation and Amortization	236			216			658			594
Taxes Other Than Income Taxes	15			24			50			73
Total Operating Expenses	1,320			1,362			4,120			4,139
OPERATING INCOME	346			321			964			890
Other Income	13			16			41			39
Other Deductions	(1		)	(6		)	(3		)	(8		)
Interest Expense	(75		)	(73		)	(223		)	(220		)
INCOME BEFORE INCOME TAXES	283			258			779			701
Income Tax Expense	(115		)	(103		)	(311		)	(248		)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	168		$	155		$	468		$	453

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013			2012
NET INCOME	$	168	$	155	$	468		$	453
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $(1), $1 and $0 for the three and nine months ended 2013 and 2012, respectively	—		1		(1		)	—
COMPREHENSIVE INCOME	$	168	$	156	$	467		$	453

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	253		$	116
Accounts Receivable, net of allowances of $57 and $56 in 2013 and 2012, respectively	839			783
Accounts Receivable-Affiliated Companies, net	94			—
Unbilled Revenues	211			314
Materials and Supplies	118			114
Prepayments	138			29
Regulatory Assets	348			349
Derivative Contracts	19			5
Deferred Income Taxes	31			49
Other	24			24
Total Current Assets	2,075			1,783
PROPERTY, PLANT AND EQUIPMENT	18,503			17,006
Less: Accumulated Depreciation and Amortization	(4,916		)	(4,726		)
Net Property, Plant and Equipment	13,587			12,280
NONCURRENT ASSETS
Regulatory Assets	3,519			3,830
Regulatory Assets of VIEs	532			713
Long-Term Investments	356			348
Other Special Funds	41			61
Derivative Contracts	69			62
Restricted Cash of VIEs	23			23
Other	128			123
Total Noncurrent Assets	4,668			5,160
TOTAL ASSETS	$	20,330		$	19,223

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	September 30, 2013		December 31, 2012
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	775	$	725
Securitization Debt of VIEs Due Within One Year	235		226
Commercial Paper and Loans	—		263
Accounts Payable	473		630
Accounts Payable—Affiliated Companies, net	—		73
Accrued Interest	77		65
Clean Energy Program	185		153
Deferred Income Taxes	55		60
Obligation to Return Cash Collateral	118		122
Regulatory Liabilities	171		67
Other	306		269
Total Current Liabilities	2,395		2,653
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	4,354		4,223
Other Postretirement Benefit (OPEB) Costs	989		1,011
Accrued Pension Costs	360		463
Regulatory Liabilities	213		209
Regulatory Liabilities of VIEs	11		10
Environmental Costs	380		486
Asset Retirement Obligations	260		250
Derivative Contracts	140		107
Long-Term Accrued Taxes	48		32
Other	46		38
Total Noncurrent Liabilities	6,801		6,829
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt	5,066		4,070
Securitization Debt of VIEs	326		496
Total Long-Term Debt	5,392		4,566
STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2013 and 2012—132,450,344 shares	892		892
Contributed Capital	520		420
Basis Adjustment	986		986
Retained Earnings	3,343		2,875
Accumulated Other Comprehensive Income	1		2
Total Stockholder’s Equity	5,742		5,175
Total Capitalization	11,134		9,741
TOTAL LIABILITIES AND CAPITALIZATION	$	20,330	$	19,223

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)




	Nine Months Ended
	September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	468		$	453
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	658			594
Provision for Deferred Income Taxes and ITC	153			131
Non-Cash Employee Benefit Plan Costs	117			134
Cost of Removal	(66		)	(71		)
Change in Accrued Storm Costs	(87		)	5
Net Change in Other Regulatory Assets and Liabilities	134			(82		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	48			97
Materials and Supplies	(4		)	(11		)
Prepayments	(109		)	(28		)
Net Change in Tax Receivable	—			16
Accounts Payable	3			(20		)
Accounts Receivable/Payable-Affiliated Companies, net	(171		)	(41		)
Other Current Assets and Liabilities	29			22
Employee Benefit Plan Funding and Related Payments	(147		)	(137		)
Other	23			(21		)
Net Cash Provided By (Used In) Operating Activities	1,049			1,041
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,628		)	(1,369		)
Proceeds from Sales of Available-for-Sale Securities	35			73
Investments in Available-for-Sale Securities	(16		)	(73		)
Solar Loan Investments	(11		)	(56		)
Restricted Funds	—			1
Net Cash Provided By (Used In) Investing Activities	(1,620		)	(1,424		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	(263		)	—
Issuance of Long-Term Debt	1,500			850
Redemption of Long-Term Debt	(450		)	(373		)
Redemption of Securitization Debt	(162		)	(154		)
Contributed Capital	100			—
Other	(17		)	(12		)
Net Cash Provided By (Used In) Financing Activities	708			311
Net Increase (Decrease) In Cash and Cash Equivalents	137			(72		)
Cash and Cash Equivalents at Beginning of Period	116			143
Cash and Cash Equivalents at End of Period	$	253		$	71
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	174		$	(30	)
Interest Paid, Net of Amounts Capitalized	$	199		$	205
Accrued Property, Plant and Equipment Expenditures	$	200		$	175

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. Power and PSE&G 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 four principal direct wholly owned subsidiaries are:

•

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 three principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the states in which they operate.

•

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

•

PSEG Energy Holdings L.L.C. (Energy Holdings)—which primarily has investments in leases and solar generation projects through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by the FERC and the states in which they operate. A subsidiary of Energy Holdings has been awarded a contract to manage the transmission and distribution assets of the Long Island Power Authority (LIPA) starting in 2014.


•	PSEG Services Corporation (Services)—which provides 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, 2012 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013.

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 significant intercompany accounts and transactions are eliminated in consolidation, except as discussed in Note 18. Related-Party Transactions. 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, 2012.

Note 2. Recent Accounting Standards

New Standards Adopted during 2013

Disclosures about Offsetting Assets and Liabilities

This accounting standard requires enhanced disclosures regarding assets and liabilities that are either offset in the financial statements, or are subject to an enforceable master netting arrangement or similar agreement. The guidance is applicable to certain financial instruments (e.g. derivatives) and securities borrowing and lending transactions. This standard requires entities:


•	to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on an entity's financial position, and

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


•	to present both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities.

We adopted this standard retrospectively effective January 1, 2013. As this standard requires disclosures only, it did not have any impact on our consolidated financial position, results of operations or cash flows. For additional information, see Note 11. Financial Risk Management Activities.

Reclassification Adjustments out of Accumulated Other Comprehensive Income

This accounting standard requires entities to disclose the following information about reclassification adjustments related to Accumulated Other Comprehensive Income:


•	changes in Accumulated Other Comprehensive Income balances by component, and


•	significant amounts reclassified out of Accumulated Other Comprehensive Income by respective line items of net income (for amounts that are required by GAAP to be reclassified to net income in their entirety in the same reporting period).

We adopted this standard prospectively effective January 1, 2013. As this standard requires disclosures only, it did not have any impact on our consolidated financial position, results of operations or cash flows. For additional information, see Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax.

New Accounting Standards Issued But Not Yet Adopted

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

This accounting standard was issued to address diversity in practice related to the presentation of an unrecognized tax benefit in certain cases. This standard requires entities to present an unrecognized tax benefit or a portion thereof on the Balance Sheet as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward.

However, in cases in which a net operating loss carryforward, a similar tax loss or a tax credit carryforward is not available at the reporting date under the tax law of the jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or the tax law of the jurisdiction does not require an entity to use, and the entity does not intend to use the deferred tax asset for such purpose, the unrecognized tax benefit will be presented on the Balance Sheet as a liability and will not be combined with deferred tax assets.

The standard is effective for fiscal years and interim periods beginning after December 15, 2013. We are currently analyzing the impact of this standard to our financial statements.

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 these VIEs are presented separately on the face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the Transition Funding and Transition Funding II assets 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, respectively.

PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of September 30, 2013 and December 31, 2012. 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 nine months of 2013 or in 2012. PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 4. Asset Disposition

In June 2013, Energy Holdings closed on the sale of its investments in a commercial office complex for proceeds of $41 million, resulting in an after-tax gain of $6 million.

Note 5. Rate Filings

The following information discusses significant updates regarding orders and pending rate filings. This Note should be read in conjunction with Note 6. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2012.

•

Weather Normalization Clause (WNC)—In April 2013, the BPU approved PSE&G's filing with respect to deficiency revenues from the 2011-2012 Winter Period. As a result, provisional rates were approved to recover $41 million from customers during the 2012-2013 Winter Period, with a carryover deficiency of $24 million to the 2013-2014 Winter Period. In July 2013, PSE&G filed a petition with the BPU seeking approval to recover $26 million in revenues from its customers during the 2013-2014 Winter Period inclusive of the $24 million carryover deficiency. In September 2013, the BPU approved PSE&G's petition for $26 million of deficiency revenues which will be recovered from customers during the 2013-2014 Winter Period (October 1 through May 31).


•	Universal Service Fund (USF) Lifeline—In June 2013, New Jersey’s electric and gas utilities, including PSE&G, filed requests to reset the statewide rates for the USF and Lifeline program. In September 2013, the BPU approved rates set to recover $274 million on a statewide basis. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.


•	Transmission Filing—In October 2013, PSE&G filed its 2014 Annual Formula Rate Update with the FERC, which provides for approximately $176 million in increased annual transmission revenues effective January 1, 2014.


•	BGSS—In October 2013, PSE&G filed a self-implementing two-month BGSS bill credit with the BPU. This bill credit will be 35 cents per therm for the months of November and December 2013 and is designed to provide approximately $115 million to residential customers over the two months and reduce the BGSS deferred balance. The BGSS rate will revert back to the current rate on January 1, 2014.

Note 6. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with Solar Renewable Energy Certificates (SRECs) generated from the installed solar electric system. 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	September 30, 2013		December 31, 2012
	Millions
Commercial/Industrial	$	183	$	174
Residential	15		15
Total	$	198	$	189

Energy Holdings

Energy Holdings, through various 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 table below shows Energy Holdings’ gross and net lease investment as of September 30, 2013 and December 31, 2012, respectively.




	As of			As of
	September 30, 2013			December 31, 2012
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	701		$	721
Estimated Residual Value of Leased Assets	529			535
	1,230			1,256
Unearned and Deferred Income	(405		)	(416		)
Gross Investments in Leases	825			840
Deferred Tax Liabilities	(705		)	(723		)
Net Investments in Leases	$	120		$	117

The corresponding receivables associated with the lease portfolio are reflected below, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. "Not Rated" counterparties represent investments in lease receivables related to coal-fired assets and commercial real estate properties.




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating (Standard & Poor's (S&P))	As of		As of
As of September 30, 2013	September 30, 2013		December 31, 2012
	Millions
AA	$	20	$	21
AA-	56		73
BBB+ - BBB-	316		316
B	165		166
Not Rated	144		145
Total	$	701	$	721

The “B” rating and the "Not Rated" above include lease receivables related to coal-fired assets in Pennsylvania and Illinois, respectively. As of September 30, 2013, the gross investment in the leases of such assets, net of non-recourse debt, was $562 million ($23 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




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	Not Rated	Edison Mission Energy
Joliet Station Units 7 and 8	IL	$	84	64	%	1,044	Coal	Not Rated	Edison Mission Energy
Keystone Station Units 1 and 2	PA	$	117	17	%	1,711	Coal	B	GenOn REMA, LLC
Conemaugh Station Units 1 and 2	PA	$	117	17	%	1,711	Coal	B	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	110	100	%	603	Coal	B	GenOn 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).

Indirect subsidiary companies of Energy Holdings lease three coal-fired generation facilities in Pennsylvania (Keystone, Conemaugh and Shawville) to GenOn REMA, LLC (GenOn REMA), a subsidiary of GenOn Energy Inc. (GenOn), which was acquired by NRG Energy, Inc. (NRG) in December 2012. With respect to addressing various environmental controls: Keystone has installed a flue gas desulfurization (FGD) system for sulfur dioxide (SO₂), selective catalytic reduction (SCR) equipment for nitrogen oxide (NO_X) and mercury control; Conemaugh has a FGD system, while SCR and mercury control equipment are scheduled to be installed and operational by the first quarter of 2015; and GenOn has disclosed its plan to place Shawville in a “long-term protective layup” by April 2015. GenOn has stated that it is evaluating whether to continue to pay the required rent and maintain the facility in accordance with the lease terms or terminate the lease for obsolescence in which case the lessee would be required, among other things, to pay the contractual termination value structured to recover Energy Holdings' indirect subsidiaries' lease investment as specified in the lease agreement.

Although all lease payments from the GenOn REMA leases 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.

Nesbitt Asset Recovery, LLC (Nesbitt), (an indirect, wholly owned subsidiary of Energy Holdings), owns approximately 64% of the lease interest in the Powerton and Joliet coal units in Illinois, with the balance held by Associates Capital Investments, L.L.P. (Associates) (an affiliate of Citigroup, and, together with Nesbitt, the "Equity Investors"). These facilities are leased to Midwest Generation (MWG), an indirect subsidiary of Edison Mission Energy (EME).

MWG has substantially completed investments in mercury removal (Activated Carbon Injection) and NO_X emission controls (low NO_X burners and Selective Non-Catalytic Reduction systems). On April 4, 2013, MWG obtained approval from the Illinois Pollution Control Board to defer capital investments for up to two additional years to meet upcoming air emission compliance deadlines under Illinois law. Also, on July 8, 2013, the U.S. Court of Appeals affirmed the judgment of the lower court dismissing claims brought by the U.S. Environmental Protection Agency (EPA) and the State of Illinois against EME and MWG for alleged violations of the Clean Air Act.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

On December 17, 2012, EME and MWG filed for relief under Chapter 11 of the U.S. Bankruptcy Code. Immediately prior to that filing, EME, MWG and the Equity Investors, as well as certain affiliated owner lessors, entered into a forbearance agreement with holders of a majority of the lease debt that financed the original sale-leaseback transaction. The forbearance agreement, which was approved by the Bankruptcy Court, expired on April 5, 2013. In June 2013, the parties reached an agreement, which was approved by the Bankruptcy Court, to again extend the deadline for MWG to assume or reject the leases until September 30, 2013, and in September 2013, extended it to December 31, 2013. As part of this agreement, (i) MWG will make partial lease payments of $4 million each month during the extension period starting in July 2013, (ii) MWG will continue to make certain environmental capital expenditures at the units, and (iii) the parties reserve their rights, claims, and defenses with respect to whether the leases are secured financings, rent amounts due under the leases, and the classification of claims under the leases, among other things.

On October 18, 2013, NRG, EME, MWG, the Equity Investors and other creditor parties involved in the bankruptcy executed a new agreement, which was approved by the Bankruptcy Court on October 24, 2013. The new agreement contains the terms and conditions under which NRG would acquire substantially all of EME’s assets, including the Powerton and Joliet leased assets. As part of the proposed transaction, (i) the leases for the Powerton and Joliet coal units would be assumed on their existing terms, (ii) all past due rent under the leases would be paid in full, (iii) NRG would assume EME’s tax indemnity and guarantee obligations, and (iv) NRG would invest up to $350 million in the Powerton and Joliet coal units so they could be operated in compliance with all environmental regulations. The proposed transaction also requires approval by the FERC and other regulatory bodies, and there can be no assurances that the above transaction will be consummated. The terms of the aforementioned forbearance agreement will remain in effect beyond December 31, 2013 until such time as the NRG acquisition is consummated or terminated.

Note 7. 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 September 30, 2013
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	615	$	234	$	(6	)	$	843
Debt Securities
Government Obligations	411		5		(6		)	410
Other Debt Securities	313		11		(4		)	320
Total Debt Securities	724		16		(10		)	730
Other Securities	62		—		—			62
Total NDT Available-for-Sale Securities	$	1,401	$	250	$	(16	)	$	1,635

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	As of December 31, 2012
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	648	$	147	$	(6	)	$	789
Debt Securities
Government Obligations	274		11		—			285
Other Debt Securities	320		22		—			342
Total Debt Securities	594		33		—			627
Other Securities	124		—		—			124
Total NDT Available-for-Sale Securities	$	1,366	$	180	$	(6	)	$	1,540

These 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
	September 30, 2013		December 31, 2012
	Millions
Accounts Receivable	$	43	$	18
Accounts Payable	$	47	$	53

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 September 30, 2013									As of December 31, 2012
	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)	$	78	$	(6	)	$	—	$	—	$	139	$	(6	)	$	—	$	—
Debt Securities
Government Obligations (B)	158		(6		)	—		—		34		—			1		—
Other Debt Securities (C)	131		(4		)	—		—		31		—			6		—
Total Debt Securities	289		(10		)	—		—		65		—			7		—
Other Securities	—		—			—		—		—		—			—		—
NDT Available-for-Sale Securities	$	367	$	(16	)	$	—	$	—	$	204	$	(6	)	$	7	$	—


(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 September 30, 2013.


(B)	Debt Securities (Government)—Unrealized losses on Power’s NDT investments in United States Treasury obligations and Federal Agency asset-backed securities were caused by interest rate changes. Since these investments are

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 September 30, 2013.

(C)

Debt Securities (Corporate)—Power’s investments in corporate bonds 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 September 30, 2013.

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




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	Millions
Proceeds from NDT Fund Sales	$	220		$	617		$	837		$	1,252
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	35			94			95			136
Gross Realized Losses	(9		)	(19		)	(34		)	(41		)
Net Realized Gains (Losses) on NDT Fund	$	26		$	75		$	61		$	95

Gross realized gains and gross realized losses disclosed in the above 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 $115 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of September 30, 2013.

The NDT available-for-sale debt securities held as of September 30, 2013 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	57
1 - 5 years	167
6 - 10 years	186
11 - 15 years	44
16 - 20 years	19
Over 20 years	257
Total NDT Available-for-Sale Debt Securities	$	730

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). In 2013, other-than-temporary impairments of $7 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Rabbi Trust

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

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




	As of September 30, 2013
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	14	$	7	$	—		$	21
Debt Securities
Government Obligations	110		—		(2		)	108
Other Debt Securities	45		—		(1		)	44
Total Debt Securities	155		—		(3		)	152
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	171	$	7	$	(3	)	$	175

Securities in the Rabbi Trust in a gross unrealized loss position have been in such position for less than twelve months.




	As of December 31, 2012
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	13	$	5	$	—	$	18
Debt Securities
Government Obligations	114		3		—		117
Other Debt Securities	45		2		—		47
Total Debt Securities	159		5		—		164
Other Securities	3		—		—		3
Total Rabbi Trust Available-for-Sale Securities	$	175	$	10	$	—	$	185

These 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
	September 30, 2013		December 31, 2012
	Millions
Accounts Receivable	$	3	$	4
Accounts Payable	$	3	$	5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013			2012
	Millions
Proceeds from Rabbi Trust Sales	$	13	$	6	$	77		$	221
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	—	$	—	$	4		$	6
Gross Realized Losses	—		—		(3		)	—
Net Realized Gains (Losses) on Rabbi Trust	$	—	$	—	$	1		$	6

Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains of $2 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of September 30, 2013. The Rabbi Trust available-for-sale debt securities held as of September 30, 2013 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	—
1 - 5 years	59
6 - 10 years	29
11 - 15 years	7
16 - 20 years	4
Over 20 years	53
Total Rabbi Trust Available-for-Sale Debt Securities	$	152

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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




	As of		As of
	September 30, 2013		December 31, 2012
	Millions
Power	$	38	$	36
PSE&G	41		61
Other	96		88
Total Rabbi Trust Available-for-Sale Securities	$	175	$	185

Note 8. 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 are detailed as follows:




	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Nine Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2013			2012			2013			2012			2013			2012			2013			2012
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	29		$	26		$	6		$	5		$	87		$	76		$	16		$	13
Interest Cost	54			56			15			17			161			167			47			49
Expected Return on Plan Assets	(87		)	(76		)	(6		)	(4		)	(261		)	(229		)	(16		)	(13		)
Amortization of Net
Transition Obligation	—			—			—			1			—			—			—			2
Prior Service Cost (Credit)	(5		)	(5		)	(4		)	(4		)	(14		)	(14		)	(11		)	(11		)
Actuarial Loss	47			41			11			7			141			125			32			23
Net Periodic Benefit Cost	$	38		$	42		$	22		$	22		$	114		$	125		$	68		$	63
Special Termination Benefits	—			1			—			—			—			1			—			—
Effect of Regulatory Asset	—			—			—			4			—			—			—			14
Total Benefit Costs, Including Effect of Regulatory Asset	$	38		$	43		$	22		$	26		$	114		$	126		$	68		$	77

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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




	Pension Benefits				OPEB				Pension Benefits				OPEB
	Three Months Ended				Three Months Ended				Nine Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
	2013		2012		2013		2012		2013		2012		2013		2012
	Millions
Power	$	11	$	14	$	6	$	5	$	33	$	39	$	17	$	14
PSE&G	23		24		16		21		68		73		49		61
Other	4		5		—		—		13		14		2		2
Total Benefit Costs	$	38	$	43	$	22	$	26	$	114	$	126	$	68	$	77

During the three months ended March 31, 2013, PSEG contributed its entire planned contributions for the year 2013 of $145 million and $14 million into its pension and postretirement healthcare plans, respectively.

Note 9. Commitments and Contingent Liabilities

Guaranteed Obligations

Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.

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

(UNAUDITED)

The face value of Power's outstanding guarantees, current exposure and margin positions as of September 30, 2013 and December 31, 2012 are shown below:




	As of		As of
	September 30, 2013		December 31, 2012
	Millions
Face Value of Outstanding Guarantees	$	1,551	$	1,508
Exposure under Current Guarantees	$	201	$	226
Letters of Credit Margin Posted	$	121	$	124
Letters of Credit Margin Received	$	29	$	69
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	12	$	15
Counterparty Cash Margin Received	$	—	$	(4	)
Net Broker Balance Deposited (Received)	$	8	$	26
In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that Could be Required	$	588	$	654
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,537	$	3,531
Additional Amounts Posted
Other Letters of Credit	$	42	$	45

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 11. Financial Risk Management Activities for further discussion. In accordance with PSEG's accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the 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's, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

The SEC and the Commodity Futures Trading Commission (CFTC) continue efforts to implement new rules to effect stricter regulation over swaps and derivatives, including imposing reporting and record-keeping requirements. In August 2013, PSEG began reporting its swap transactions to a CFTC-approved swap data repository. We continue to monitor developments in this area, as the CFTC considers additional requirements such as a new position limits rule for energy commodity swaps.

In addition to amounts for outstanding guarantees, current exposure and margin positions, Power had posted letters of credit to support various other non-energy contractual and environmental obligations. See table above.

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.

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)

The EPA has determined that an eight-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under CERCLA. The EPA has determined the need to perform a study of the entire 17-mile tidal reach of the lower Passaic River.

PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to 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. When the Essex Site was transferred from PSE&G to Power,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

The EPA notified the potentially responsible parties (PRPs) that the cost of its Remedial Investigation and Feasibility Study (RI/FS) is now estimated at approximately $117 million. Seventy-three PRPs, including Power and PSE&G, agreed to assume responsibility for the RI/FS and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently seventy members, is presently executing the RI/FS. Approximately five percent of the RI/FS costs were attributable to PSE&G's former MGP sites and approximately one percent to Power's generating stations on an interim basis under the CPG's group agreement. Power has provided notice to insurers concerning this potential claim.

In 2007, the EPA released a draft “Focused Feasibility Study” (FFS) that proposed various options to address the contamination cleanup of the lower eight miles of the Passaic River. The EPA estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the FFS is not subject to the cost sharing agreement discussed above. The EPA's revised proposed FFS may be released for public comment before the end of 2013.

In June 2008, an agreement was announced between the EPA and Tierra Solutions, Inc. and Maxus Energy Corporation (Tierra/Maxus) for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. Phase I of the removal work has been completed. Phase II is contingent on the approval of an appropriate sediment disposal facility. Tierra/Maxus have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

The EPA has advised that the levels of contaminants at Passaic River mile 10.9 will require removal in advance of the completion of the RI/FS. The CPG members, with the exception of Tierra/Maxus, which are no longer members, have agreed to and are funding the removal, currently estimated at approximately $30 million. PSEG's share of that effort is approximately three percent.

Except for the Passaic River mile 10.9 removal, Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to the Passaic River matters.

New Jersey Spill Compensation and Control Act (Spill Act)

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP (Occidental Chemical Corporation (OCC)) and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRP's discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed hazardous substances to a total of 11 sites or facilities that impacted these water bodies. In 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances it allegedly discharged into the Passaic River and the Newark Bay Complex. Power and PSE&G filed answers to the complaints in 2010. On March 22, 2013, Power and PSE&G signed an agreement to settle the NJDEP vs. OCC litigation at a nominal cost. That settlement is contingent upon a public comment and NJDEP response period and the issuance of an order approving the settlement by the Court after conducting a fairness hearing. A stay of third-party discovery remains in place and has been extended. Power and PSE&G believe they have good and valid defenses to the allegations contained in the third party complaints and will vigorously assert those defenses should the matter not settle. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.

Natural Resource Damage Claims

In 2003, the 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 Spill 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 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. PSEG is unable to estimate its portion of the possible loss or range of loss related to this matter.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 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 and encouraged the PRPs to contact OCC to discuss participating in the RI/FS that OCC was conducting. 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 it is uncertain at this time whether the PSEG companies will consent to fund the third phase. Power and PSE&G are unable to estimate their portion 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 $476 million and $552 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $476 million as of September 30, 2013. Of this amount, $107 million was recorded in Other Current Liabilities and $369 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $476 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.

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 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.

Hazardous Air Pollutants Regulation

In accordance with a ruling of the U.S. Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation in February 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the Court of Appeals in support of the EPA's implementation of MATS. Litigation of these matters remains pending and the impact on the implementation schedule is unknown at this time.

Power believes that it will not be necessary to install any additional material controls at its New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulations, a decision was reached to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal-fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. Power's share of this investment is estimated to be up to $147 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOx Regulation

In April 2009, the NJDEP finalized revisions to NO_xemission control regulations that impose new NO_xemission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 30, 2015. Retirement notifications for the combustion turbines, except for Salem Unit 3, have been filed with the PJM Interconnection, LLC (PJM). The Salem Unit 3 combustion turbine (38 MW) will be transitioning to an emergency generator. Evaluations are ongoing for the steam electric generation units.

Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NO_x emission limitations that were incorporated into the facilities’ operating permits. In 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System (NPDES) permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

One of the most significant NJPDES permits governing cooling water intake structures at Power is for Salem. 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 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. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004.

As a result of several legal challenges to the 2004 316(b) rule by certain northeast states, environmentalists and industry groups, the rule has been suspended and has been returned to the EPA to be consistent with a 2009 United States Supreme Court decision which concluded that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations.

In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012. In April 2011, the EPA published a proposed rule to establish marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. In July 2012, the EPA and environmental groups agreed to delay the deadline to June 27, 2013 for finalization of the Rule. On June 27, 2013, the EPA and environmental groups agreed to further extend the deadline to November 4, 2013.

Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition, results of operations or cash flows. The results of further proceedings on this matter 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. These cost estimates have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

On October 1, 2013, the Delaware Riverkeeper Network and several other environmental groups filed a lawsuit in the Superior Court of New Jersey seeking to compel the NJDEP to take action on Power's pending application for permit renewal at Salem either by denying the application or issuing a draft for public comment. Power is unable to predict the outcome of this proceeding.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Capital Expenditures

The construction programs of PSEG and its subsidiaries are currently estimated to include a base level total investment of approximately $6.4 billion for the three years ended 2015. The three-year projected capital expenditures for PSEG, Power and PSE&G are as follows:




	2013		2014		2015
	Millions
Power	$	400	$	365	$	305
PSE&G	2,045		1,765		1,305
Other	95		40		30
Total PSEG	$	2,540	$	2,170	$	1,640

Power's projected capital expenditures include baseline maintenance (investments to replace major parts and enhance operational performance), investments in response to environmental, regulatory or legal mandates and nuclear expansion. PSE&G's projections include material additions and replacements in its transmission and distribution systems to meet expected growth and manage reliability.

In May 2013, the BPU approved increased spending on renewable energy under PSE&G's Solar Loan and Solar 4 All investment programs (Solar Loan III and Solar 4 All Extension, respectively). PSE&G's projected expenditures through 2015 in the table above have been updated to include $215 million under its Solar Loan III and Solar 4 All Extension programs.

Power

During the nine months ended September 30, 2013, Power made $243 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $176 million for nuclear fuel, primarily related to various projects at its fossil and nuclear generation stations.

PSE&G

During the nine months ended September 30, 2013, PSE&G made $1,648 million of capital expenditures, including $1,628 million of investment in plant, primarily for reliability of transmission and distribution systems and $20 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $66 million, which is included in operating cash flows.

Energy Holdings

Included in Other for 2013 in the preceding table is a solar project currently under construction in Arizona for which Energy Holdings had issued an outstanding guarantee of $10 million as of September 30, 2013.

Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)

PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. 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 Power, as well as with other winning BGS suppliers, 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.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

PSE&G has contracted for its anticipated BGS-Fixed Price eligible load, as follows:




	Auction Year
	2010	2011	2012	2013
36-Month Terms Ending	May 2013	May 2014	May 2015	May 2016	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per kWh	0.09577	0.09430	0.08388	0.09218


(A)	Prices set in the 2013 BGS auction became effective on June 1, 2013 when the 2010 BGS auction agreements expired.

PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 18. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power has various long-term fuel purchase commitments for coal through 2017 to support its fossil generation stations and for supply of nuclear fuel for the Salem, Hope Creek and Peach Bottom nuclear generating stations and for firm transportation and storage capacity for natural gas.

Power’s strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2015 and a portion through 2017 at Salem, Hope Creek and Peach Bottom.

Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.

As of September 30, 2013, the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	Power’s Share of Commitments through 2017
	Millions
Nuclear Fuel
Uranium	$	470
Enrichment	$	386
Fabrication	$	146
Natural Gas	$	880
Coal	$	446

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Regulatory Proceedings

New Jersey Clean Energy Program

In June 2013, the BPU established the funding level for fiscal 2014 applicable to its Renewable Energy and Energy Efficiency programs. The fiscal year 2014 aggregate funding for all EDCs is $345 million with PSE&G's share of the funding at $200 million. PSE&G has a remaining current liability of $185 million as of September 30, 2013 for its outstanding share of the fiscal 2014 and remaining fiscal 2013 funding. 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).

Long-Term Capacity Agreement Pilot Program (LCAPP)

In 2011, New Jersey enacted the LCAPP Act that resulted in the selection of three generators to build a total of approximately 2,000 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the selected generators, but did so under protest preserving their legal rights. The SOCA provides for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement. In July 2013, the SOCA contract with New Jersey Power Development LLC, a subsidiary of NRG Energy, Inc., was terminated early as a result of a default by the generator. SOCA contracts are for a 15-year term, which are scheduled to commence for one of the generators in the 2015/2016 delivery year and for the other generator in the 2016/2017 delivery year. These contracts are for the aggregate notional amount of approximately 1,300 MWs of installed capacity. Based upon the expected percentage of state load that PSE&G will be serving during the term of these contracts, the contracts provide that PSE&G would be responsible for the positive difference of the contract price and the annual RPM clearing price for approximately 52% or 676 MW of this amount provided that these generators satisfy their obligations under the SOCA, including the requirement that the specific generation units set forth in the contract achieve commercial operation.

The current estimated fair value of the SOCAs is recorded as a Derivative Asset or Liability with an offsetting Regulatory Asset or Liability on PSE&G’s Condensed Consolidated Balance Sheets. See Note 12. Fair Value Measurements for additional information.

PSE&G has taken several steps to challenge these subsidies, including joining several parties in challenging the LCAPP Act on constitutional grounds in federal court. On October 11, 2013, the U.S. District Court issued a decision finding that the LCAPP Act violated the Supremacy Clause of the U.S. Constitution and declaring the LCAPP Act null and void. On October 25, 2013, a final judgment was issued implementing the federal court's decision in this proceeding and also finding the SOCA contracts void, invalid and unenforceable and denying the request of the defendants to stay the decision pending appeal. The defendants may appeal the decision and may seek a stay from the U.S. Third Circuit Court of Appeals. Additionally, PSE&G joined an appeal in New Jersey state court challenging the BPU’s implementation of the LCAPP Act. The New Jersey State Appellate Court dismissed that appeal, without prejudice, based on the fact that the federal court had found the LCAPP Act unconstitutional and void.

Superstorm Sandy

In late October 2012, Superstorm Sandy caused damage to PSE&G's transmission and distribution 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. Power's estimate of the total costs required to restore its damaged facilities to their pre-Superstorm Sandy condition is approximately $364 million.

Power incurred an additional $17 million and $67 million of storm-related expense for the three months and nine months ended September 30, 2013, respectively, primarily for repairs at certain generating stations in Power's fossil fleet. Power had incurred $85 million of costs in 2012. These costs were recognized in Operation and Maintenance Expense, offset by $25 million and $19 million of insurance recoveries in the second quarter of 2013 and the fourth quarter of 2012, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Leveraged Lease Investments

In January 2012, PSEG entered into a specific matter closing agreement with the IRS settling all matters related to cross border lease transactions. This agreement settled the leasing dispute with finality for all tax periods in which PSEG realized tax deductions from these transactions. In January 2012, PSEG also signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. In March 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These agreements concluded the audits for these years for PSEG and the leasing issue for all tax years. For PSEG, the impact of these agreements was an increase in financial statement Income Tax Expense of approximately $175 million in the first quarter of 2012. In prior periods, PSEG had established financial statement tax liabilities for uncertain tax positions in the amount of $246 million with respect to these tax years. Accordingly, the settlement resulted in a net $71 million decrease in the first quarter of 2012 in the Income Tax Expense of PSEG.

Cash Impact

For tax years 1997 through 2003, the tax and interest PSEG owes the IRS as a result of this settlement will be reduced by the $320 million PSEG has on deposit with the IRS for this matter. PSEG paid a net deficiency for these years of approximately $4 million during the second quarter of 2012. Based upon the closing agreement and the Form 870-AD for tax years 2004 through 2006, PSEG owes the IRS approximately $620 million in tax and interest. Based on the settlement of the leasing dispute, for tax years 2007 through 2010, the IRS owes PSEG approximately $676 million. PSEG has filed amended returns for tax years 2007-2010 reflecting the impact of the settlement. These returns have been audited by the IRS and accepted as filed. As required by statute, the IRS presented the refund claim to the Joint Committee on Taxation for approval. In October 2012, PSEG was notified that the Joint Committee took no exception to the refund claim. In April 2013, PSEG received confirmation from the IRS which shows that overpayments from the 2008 through 2010 tax years have been applied to satisfy the liabilities due with respect to tax years 2004 through 2007. Accordingly, no further cash payments will be required with respect to the contested leasing transactions. In addition to the above, PSEG claimed a tax deduction for the accrued deficiency interest associated with this settlement in 2012, which gives rise to a cash tax savings of approximately $100 million.

Note 10. Changes in Capitalization

The following capital transactions occurred in the nine months ended September 30, 2013:

Power


•	paid cash dividends of $690 million to PSEG, and


•	paid $300 million of 2.50% Senior Notes at maturity.

PSE&G


•	issued $350 million of 2.30% Secured Medium-Term Notes, Series I due September 2018,


•	issued $250 million of 3.75% Secured Medium-Term Notes, Series I due March 2024,


•	paid $300 million of 5.375% Secured Medium-Term Notes at maturity,


•	issued $500 million of 2.375% Secured Medium-Term Notes, Series I due May 2023,


•	paid $150 million of 5.00% Secured Medium-Term Notes at maturity,


•	issued $400 million of 3.80% Secured Medium-Term Notes, Series H due January 2043,


•	received a $100 million capital contribution from PSEG,


•	paid $156 million of Transition Funding's securitization debt, and


•	paid $6 million of Transition Funding II's securitization debt.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 11. 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.

Commodity Prices

The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power uses physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Derivative contracts that do not qualify for hedge accounting or normal purchases/normal sales treatment are marked to market (MTM) with changes in fair value recorded in the income statement. 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

Power uses forward sale and purchase contracts, swaps and futures contracts to hedge


•	forecasted energy sales from its generation stations and the related load obligations, and


•	certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G.

Certain of these derivative transactions are designated and effective as cash flow hedges. During the second quarter of 2012, Power de-designated certain of its commodity derivative transactions that had previously qualified as cash flow hedges as they were deemed to no longer be highly effective as required by the relevant accounting guidance. As a result, subsequent to June 1, 2012, Power recognizes all gains and losses from changes in the fair value of these derivatives immediately in earnings rather than deferring any such amounts in Accumulated Other Comprehensive Income (Loss). The fair values of Power’s de-designated hedges were frozen in Accumulated Other Comprehensive Income (Loss) as the original forecasted transactions are still expected to occur and are reclassified into earnings as the original derivative transactions settle.

As of September 30, 2013 and December 31, 2012, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity were as follows:




	As of		As of
	September 30, 2013		December 31, 2012
	Millions
Fair Value of Cash Flow Hedges	$	1	$	3
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	3	$	9

The expiration date of the longest-dated cash flow hedge at Power is in 2014. Power’s remaining $3 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 September 30, 2013.

Trading Derivatives

The primary purpose of Power’s wholesale marketing operation is to optimize the value of the output of the generating facilities via various products and services available in the markets it serves. Historically, Power engaged in trading of electricity and energy-related products where such transactions were not associated with the output or fuel purchase requirements of its facilities. This trading consisted mostly of energy supply contracts where Power secured sales commitments with the intent to supply the energy services from purchases in the market rather than from its owned generation. Such trading activities were marked to market through the income statement and represented less than one percent of gross margin (revenues

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

less energy costs) on an annual basis. Effective July 2011, Power discontinued trading activities and anticipates that it will not enter into any more trading derivative contracts.

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of its expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. 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 contracts to optimize its pipeline capacity utilization. In addition, as further described in Note 9. Commitments and Contingent Liabilities, PSE&G was directed to execute long-term SOCAs with certain generators to support the LCAPP Act. These contracts qualify as derivatives and are marked to fair value with the offset recorded to Regulatory Assets and 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, interest rate swaps and interest rate lock agreements.

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of September 30, 2013, PSEG had seven 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 September 30, 2013 and December 31, 2012, the fair value of all the underlying hedges was $42 million and $57 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 $(1) million and $(2) million as of September 30, 2013 and December 31, 2012, 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. See Note 2. Recent Accounting Standards. 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 in 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	As of September 30, 2013
	Power (A)											PSE&G(A)			PSEG (A)		Consolidated
	Cash Flow Hedges		Non Hedges									Non Hedges			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	$	228		$	(157	)	$	72		$	19		$	16	$	107
Noncurrent Assets	—		164			(75		)	89			69			26		184
Total Mark-to-Market Derivative Assets	$	1	$	392		$	(232	)	$	161		$	88		$	42	$	291
Derivative Contracts
Current Liabilities	$	—	$	(193	)	$	157		$	(36	)	$	—		$	—	$	(36	)
Noncurrent Liabilities	—		(96		)	73			(23		)	(140		)	—		(163		)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(289	)	$	230		$	(59	)	$	(140	)	$	—	$	(199	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	1	$	103		$	(2	)	$	102		$	(52	)	$	42	$	92




	As of December 31, 2012
	Power (A)											PSE&G (A)			PSEG (A)		Consolidated
	Cash Flow Hedges		Non Hedges									Non Hedges			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	$	3	$	332		$	(217	)	$	118		$	5		$	15	$	138
Noncurrent Assets	—		75			(26		)	49			62			42		153
Total Mark-to-Market Derivative Assets	$	3	$	407		$	(243	)	$	167		$	67		$	57	$	291
Derivative Contracts
Current Liabilities	$	—	$	(265	)	$	219		$	(46	)	$	—		$	—	$	(46	)
Noncurrent Liabilities	—		(41		)	26			(15		)	(107		)	—		(122		)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(306	)	$	245		$	(61	)	$	(107	)	$	—	$	(168	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	3	$	101		$	2		$	106		$	(40	)	$	57	$	123


(A)	Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of September 30, 2013 and December 31, 2012. 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

the right of offset exists, has been offset in the statement of financial position. As of September 30, 2013 and December 31, 2012, net cash collateral (received) paid of $(2) million and $2 million, respectively, were netted against the corresponding net derivative contract positions. Of the $(2) million as of September 30, 2013, $(1) million of cash collateral was netted against current assets, $(2) million was netted against noncurrent assets and $1 million was netted against current liabilities. Of the $2 million as of December 31, 2012, cash collateral of $(3) million and $5 million were netted against current assets and current 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 or lose its investment grade credit 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 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 NYMEX and ICE that are fully collateralized) was $75 million and $98 million as of September 30, 2013 and December 31, 2012, respectively. As of September 30, 2013 and December 31, 2012, Power had the contractual right of offset of $42 million and $61 million, respectively, related to derivative instruments that are assets with the same counterparty under agreements and net of margin posted. If Power had been downgraded or lost its investment grade rating, it would have had additional collateral obligations of $33 million and $37 million as of September 30, 2013 and December 31, 2012, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $588 million and $654 million as of September 30, 2013 and December 31, 2012, respectively, discussed in Note 9. 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 September 30, 2013 and 2012:




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
	September 30,						September 30,					September 30,
	2013		2012				2013		2012			2013			2012
	Millions
PSEG
Energy-Related Contracts	$	1	$	(3	)	Operating Revenues	$	3	$	15	Operating Revenues	$	(1	)	$	(1	)
Total PSEG	$	1	$	(3	)		$	3	$	15		$	(1	)	$	(1	)
Power
Energy-Related Contracts	$	1	$	(3	)	Operating Revenues	$	3	$	15	Operating Revenues	$	(1	)	$	(1	)
Total Power	$	1	$	(3	)		$	3	$	15		$	(1	)	$	(1	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following shows the effect on the Condensed Consolidated Statements of Operations and on AOCI of derivative instruments designated as cash flow hedges for the nine months ended September 30, 2013 and 2012:




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)
	Nine Months Ended						Nine Months Ended							Nine Months Ended
	September 30,						September 30,							September 30,
	2013		2012				2013			2012				2013			2012
	Millions
PSEG (A)
Energy-Related Contracts	$	1	$	27		Operating Revenues	$	11		$	67		Operating Revenues	$	(1	)	$	(1	)
Energy-Related Contracts	—		(4		)	Energy Costs	—			(9		)		—			—
Interest Rate Swaps	—		—			Interest Expense	(1		)	(1		)		—			—
Total PSEG	$	1	$	23			$	10		$	57			$	(1	)	$	(1	)
Power
Energy-Related Contracts	$	1	$	27		Operating Revenues	$	11		$	67		Operating Revenues	$	(1	)	$	(1	)
Energy-Related Contracts	—		(4		)	Energy Costs	—			(9		)		—			—
Total Power	$	1	$	23			$	11		$	58			$	(1	)	$	(1	)

(A) Includes amounts for PSEG parent.

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, 2012	$	12		$	7
Less: Gain Reclassified into Income	(7		)	(4		)
Balance as of June 30, 2013	$	5		$	3
Gain Recognized in AOCI	$	1		1
Less: Gain Reclassified into Income	(3		)	(2		)
Balance as of September 30, 2013	$	3		$	2

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 nine months ended September 30, 2013 and 2012:




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2013		2012			2013			2012
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	14	$	(90	)	$	(32	)	$	145
Energy-Related Contracts	Energy Costs	10		6			63			(17		)
Total PSEG and Power		$	24	$	(84	)	$	31		$	128

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 normal purchase/normal sales 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 $4 million and $6 million for the three month periods and $14 million and $17 million for the nine month periods ended September 30, 2013 and 2012, respectively.

The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2013 and December 31, 2012:




Type	Notional	Total	PSEG	Power	PSE&G
	Millions
As of September 30, 2013
Natural Gas	Dth	537	—	377	160
Electricity	MWh	247	—	247	—
Capacity	MW days	4	—	—	4
FTRs	MWh	22	—	22	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—
As of December 31, 2012
Natural Gas	Dth	596	—	404	192
Electricity	MWh	208	—	208	—
Capacity	MW days	4	—	—	4
FTRs	MWh	19	—	19	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—
Coal	Tons	1	—	1	—

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of September 30, 2013, 95% of the credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

The following table provides information on Power’s credit risk from others, net of cash collateral, as of September 30, 2013. 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	$	180	$	17	$	180	1	$	90	(A)
Non-Investment Grade—External Rating	2		—		2		—	—
Investment Grade—No External Rating	7		—		7		—	—
Non-Investment Grade—No External Rating	8		—		8		—	—
Total	$	197	$	17	$	197	1	$	90


(A)	Represents net exposure with PSE&G.

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 September 30, 2013, Power had 142 active counterparties.

Note 12. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G 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 September 30, 2013, these consist primarily of electric swaps whose basis is deemed significant to the fair value measurement, long-term electric load contracts, gas supply contracts and long-term capacity contracts.

The following tables present information about PSEG’s, Power’s and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012, 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 Power and PSE&G.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	Recurring Fair Value Measurements as of September 30, 2013
Description	Total			Cash Collateral Netting (D)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	249		$	(3	)	$	—	$	156		$	96
Interest Rate Swaps (B)	$	42		$	—		$	—	$	42		$	—
NDT Fund (C)
Equity Securities	$	843		$	—		$	842	$	1		$	—
Debt Securities—Govt Obligations	$	410		$	—		$	—	$	410		$	—
Debt Securities—Other	$	320		$	—		$	—	$	320		$	—
Other Securities	$	62		$	—		$	—	$	62		$	—
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	21		$	—		$	21	$	—		$	—
Debt Securities—Govt Obligations	$	108		$	—		$	—	$	108		$	—
Debt Securities—Other	$	44		$	—		$	—	$	44		$	—
Other Securities	$	2		$	—		$	—	$	2		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(199	)	$	1		$	—	$	(58	)	$	(142	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	161		$	(3	)	$	—	$	156		$	8
NDT Fund (C)
Equity Securities	$	843		$	—		$	842	$	1		$	—
Debt Securities—Govt Obligations	$	410		$	—		$	—	$	410		$	—
Debt Securities—Other	$	320		$	—		$	—	$	320		$	—
Other Securities	$	62		$	—		$	—	$	62		$	—
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	23		$	—		$	—	$	23		$	—
Debt Securities—Other	$	10		$	—		$	—	$	10		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(59	)	$	1		$	—	$	(58	)	$	(2	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	88		$	—		$	—	$	—		$	88
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	10		$	—		$	—	$	10		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(140	)	$	—		$	—	$	—		$	(140	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	Recurring Fair Value Measurements as of December 31, 2012
Description	Total			Cash Collateral Netting (D)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	234		$	(3	)	$	—	$	157		$	80
Interest Rate Swaps (B)	$	57		$	—		$	—	$	57		$	—
NDT Fund (C)
Equity Securities	$	789		$	—		$	789	$	—		$	—
Debt Securities—Govt Obligations	$	285		$	—		$	—	$	285		$	—
Debt Securities—Other	$	342		$	—		$	—	$	342		$	—
Other Securities	$	124		$	—		$	—	$	124		$	—
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	18		$	—		$	18	$	—		$	—
Debt Securities—Govt Obligations	$	117		$	—		$	—	$	117		$	—
Debt Securities—Other	$	47		$	—		$	—	$	47		$	—
Other Securities	$	3		$	—		$	—	$	3		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(168	)	$	5		$	—	$	(62	)	$	(111	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	167		$	(3	)	$	—	$	157		$	13
NDT Fund (C)
Equity Securities	$	789		$	—		$	789	$	—		$	—
Debt Securities—Govt Obligations	$	285		$	—		$	—	$	285		$	—
Debt Securities—Other	$	342		$	—		$	—	$	342		$	—
Other Securities	$	124		$	—		$	—	$	124		$	—
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	3		$	—		$	3	$	—		$	—
Debt Securities—Govt Obligations	$	23		$	—		$	—	$	23		$	—
Debt Securities—Other	$	9		$	—		$	—	$	9		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(61	)	$	5		$	—	$	(62	)	$	(4	)
PSE&G
Assets:
Derivative Contracts:
Energy Related Contracts (A)	$	67		$	—		$	—	$	—		$	67
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	6		$	—		$	6	$	—		$	—
Debt Securities—Govt Obligations	$	39		$	—		$	—	$	39		$	—
Debt Securities—Other	$	15		$	—		$	—	$	15		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(107	)	$	—		$	—	$	—		$	(107	)

(A)

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.


(B)	Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(C)

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 (primarily Level 1). The Rabbi Trust equity index fund is valued based on quoted prices in an active market (Level 1).

Level 2—NDT and Rabbi Trust fixed income securities are limited to investment grade corporate bonds and United States Treasury 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 (primarily Level 2). Short-term investments and certain commingled temporary investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2).


(D)	Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under the accounting guidance for Offsetting of Amounts Related to Certain Contracts.

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 Power, in general, electric swaps are measured at fair value based on at least two pricing inputs, the underlying price of electricity at a liquid reference point and the basis difference between electricity prices at the liquid reference point and electricity prices at the respective delivery locations. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as Level 3. The fair value of Power's electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. 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. For Power and PSE&G, natural gas supply contracts are measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. For PSE&G, long-term electric capacity contracts are measured at fair value using both observable capacity auction prices and unobservable future long-term capacity prices. The measurement of these contracts include adjustments for contingencies, such as the potential outcome of litigation specifically related to the contract and the risk related to the construction of the specified capacity facilities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Accordingly, the fair value measurements are classified as Level 3. The following tables provide details surrounding significant Level 3 valuations as of September 30, 2013 and December 31, 2012.




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	September 30, 2013					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Swaps	$	7	$	—		Discounted Cash Flow	Power Basis	$0 to $10/MWh
Electricity	Electric Load Contracts	—		(2		)	Discounted Cash Flow	Historic Load Variability	-5% to +10%
Other	Various (A)	1		—
Total Power		$	8	$	(2	)
PSE&G
Gas and Capacity	Forward Contracts (B)	$	88	$	(140	)	Discounted Cash Flow	Long-Term Capacity Prices and Transportation Costs	(B)
Total PSE&G		$	88	$	(140	)
TOTAL PSEG		$	96	$	(142	)




	Quantitative Information About Level 3 Fair Value Measurements
Commodity	Level 3 Position	Fair Value as of December 31, 2012					Valuation Technique(s)	Significant Unobservable Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Swaps	$	7	$	(1	)	Discounted Cash Flow	Power Basis	$0 to $10/MWh
Electricity	Electric Load Contracts	1		(2		)	Discounted Cash Flow	Historic Load Variability	-5% to +10%
Other	Various (A)	5		(1		)
Total Power		$	13	$	(4	)
PSE&G
Gas and Capacity	Forward Contracts (C)	$	67	$	(107	)	Discounted Cash Flow	Long-Term Gas Basis and Capacity Prices	(C)
Total PSE&G		$	67	$	(107	)
TOTAL PSEG		$	80	$	(111	)


(A)	Includes gas supply positions which are immaterial as of September 30, 2013 and December 31, 2012. Also includes long-term electric capacity positions which are immaterial as of December 31, 2012.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


(B)	Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of $100 to $400/MW day. Unobservable inputs for gas supply contracts include the weighted average cost of transporting gas in the range of $0.70 to $1 per dekatherm.


(C)	Includes long-term electric capacity and long-term gas supply positions with various unobservable inputs. Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of $100 to $400/MW day. Significant unobservable inputs for the gas supply contracts include long-term basis prices in the range of $0 to $4/MMBTU of natural gas.

Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power is a seller, an increase in either the power basis or the load variability or the longer-term gas basis amounts would decrease the fair value. For long-term electric capacity contracts where PSE&G is a buyer, an increase in the capacity price would increase the fair value. For gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value.

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and nine months ended September 30, 2013 and 2012, respectively, follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended September 30, 2013




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2013			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2013
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(35	)	$	1	$	(11	)	$	—	$	(1	)	$	—	$	(46	)
Power
Net Derivative Assets (Liabilities)	$	6		$	1	$	—		$	—	$	(1	)	$	—	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(41	)	$	—	$	(11	)	$	—	$	—		$	—	$	(52	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

for the Nine Months Ended September 30, 2013




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2013			Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)		Transfers In/Out (D)		Balance as of September 30, 2013
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(31	)	$	(16	)	$	(12	)	$	—	$	9	$	4	$	(46	)
Power
Net Derivative Assets (Liabilities)	$	9		$	(16	)	$	—		$	—	$	9	$	4	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(40	)	$	—		$	(12	)	$	—	$	—	$	—	$	(52	)

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended September 30, 2012




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2012			Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2012
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(36	)	$	(1	)	$	25	$	—	$	(9	)	$	—	$	(21	)
Non-Recourse Debt	$	—		$	—		$	—	$	—	$	—		$	—	$	—
Power
Net Derivative Assets (Liabilities)	$	22		$	(1	)	$	—	$	—	$	(9	)	$	—	$	12
PSE&G
Net Derivative Assets (Liabilities)	$	(58	)	$	—		$	25	$	—	$	—		$	—	$	(33	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

for the Nine Months Ended September 30, 2012




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2012			Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2012
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21		$	40	$	(30	)	$	—	$	(52	)	$	—	$	(21	)
Non-Recourse Debt	$	(50	)	$	50	$	—		$	—	$	—		$	—	$	—
Power
Net Derivative Assets (Liabilities)	$	24		$	40	$	—		$	—	$	(52	)	$	—	$	12
PSE&G
Net Derivative Assets (Liabilities)	$	(3	)	$	—	$	(30	)	$	—	$	—		$	—	$	(33	)

(A)

PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1 million and $(1) million in Operating Income in 2013 and 2012, respectively. The $1 million in Operating Income in 2013 is unrealized. Of the $(1) million in Operating Income in 2012, $(10) million is unrealized. Energy Holdings' release from its obligation under the non-recourse debt is included in PSEG's Operating Income for 2012 and is offset by the write-off of the related assets.


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


(C)	Represents $(1) million and $(9) million in settlements for the three months ended September 30, 2013 and 2012. Includes $9 million and $(52) million in settlements for the nine months ended September 30, 2013 and 2012, respectively.

(D)

During the nine months ended September 30, 2013, $4 million of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred), as per PSEG's policy. There were no transfers among levels during the three months ended September 30, 2013 and 2012 and the nine months ended September 30, 2012.

(E)

PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $(16) million and $40 million in Operating Income in 2013 and 2012, respectively. Of the $(16) million in Operating Income in 2013, $(7) million is unrealized. Of the $40 million in Operating Income in 2012, $(12) million is unrealized. Energy Holdings' release from its obligation under the non-recourse debt is included in PSEG's Operating Income for 2012 and is offset by the write-off of the related assets.

As of September 30, 2013, PSEG carried $1.9 billion of net assets that are measured at fair value on a recurring basis, of which $46 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of September 30, 2012, PSEG carried $1.8 billion of net assets that are measured at fair value on a recurring basis, of which $21 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of September 30, 2013 and December 31, 2012.




	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	27	$	42	$	38	$	57
Power -Recourse Debt (B)	2,041		2,355		2,340		2,818
PSE&G (B)	5,841		6,058		4,795		5,606
Transition Funding (PSE&G) (B)	534		578		690		765
Transition Funding II (PSE&G) (B)	27		28		32		34
Energy Holdings:
Project Level, Non-Recourse Debt (C)	16		16		44		44
Total Long-Term Debt	$	8,486	$	9,077	$	7,939	$	9,324


(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

(UNAUDITED)

Note 13. Other Income and Deductions




Other Income	Power		PSE&G		Other (A)		Consolidated
	Millions
Three Months Ended September 30, 2013
NDT Fund Gains, Interest, Dividend and Other Income	$	45	$	—	$	—	$	45
Allowance of Funds Used During Construction	—		5		—		5
Solar Loan Interest	—		7		—		7
Other	—		1		1		2
Total Other Income	$	45	$	13	$	1	$	59
Three Months Ended September 30, 2012
NDT Fund Gains, Interest, Dividend and Other Income	$	103	$	—	$	—	$	103
Allowance of Funds Used During Construction	—		6		—		6
Solar Loan Interest	—		5		—		5
Other	1		5		1		7
Total Other Income	$	104	$	16	$	1	$	121
Nine Months Ended September 30, 2013
NDT Fund Gains, Interest, Dividend and Other Income	$	125	$	—	$	—	$	125
Allowance of Funds Used During Construction	—		17		—		17
Solar Loan Interest	—		18		—		18
Other	2		6		4		12
Total Other Income	$	127	$	41	$	4	$	172
Nine Months Ended September 30, 2012
NDT Fund Gains, Interest, Dividend and Other Income	$	167	$	—	$	—	$	167
Allowance of Funds Used During Construction	—		17		—		17
Solar Loan Interest	—		13		—		13
Other	4		9		6		19
Total Other Income	$	171	$	39	$	6	$	216

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




Other Deductions	Power		PSE&G		Other (A)		Consolidated
	Millions
Three Months Ended September 30, 2013
NDT Fund Realized Losses and Expenses	$	11	$	—	$	—	$	11
Other	—		1		—		1
Total Other Deductions	$	11	$	1	$	—	$	12
Three Months Ended September 30, 2012
NDT Fund Realized Losses and Expenses	$	20	$	—	$	—	$	20
Other	—		6		—		6
Total Other Deductions	$	20	$	6	$	—	$	26
Nine Months Ended September 30, 2013
NDT Fund Realized Losses and Expenses	$	40	$	—	$	—	$	40
Other	9		3		2		14
Total Other Deductions	$	49	$	3	$	2	$	54
Nine Months Ended September 30, 2012
NDT Fund Realized Losses and Expenses	$	45	$	—	$	—	$	45
Other	7		8		1		16
Total Other Deductions	$	52	$	8	$	1	$	61


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

Note 14. Income Taxes

PSEG’s, Power’s and PSE&G’s effective tax rates for the three months and nine months ended September 30, 2013 and 2012 were as follows:




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
PSEG	41.0	%	41.0	%	40.5	%	36.3	%
Power	41.0	%	42.4	%	40.6	%	41.0	%
PSE&G	40.6	%	39.9	%	40.0	%	35.4	%

For the three months ended September 30, 2013, as compared to the same period in the prior year, the decrease in Power's effective tax rate was due primarily to higher NDT income in 2012.

For the nine months ended September 30, 2013, PSEG's and PSE&G's effective tax rates were higher than last year's effective tax rates due primarily to a settlement in 2012 with the IRS in regard to leveraged leases and the federal tax audit for tax years 1997 through 2006.

In September 2013, the U.S. Department of the Treasury and the IRS released final regulations that provide guidance on applying Section 263(a) of the Internal Revenue Code to amounts paid to acquire, produce, or improve tangible property, as well as rules for materials and supplies. Implementation of these final regulations in September 2013 had no material impact on PSEG’s and its subsidiaries’ results of operations, financial condition or cash flows.

The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 included a provision making qualified property placed into service after September 8, 2010 and before January 1, 2012, eligible for 100% bonus depreciation for tax purposes. In addition, qualified property placed into service in 2012 was eligible for 50% bonus depreciation for tax purposes. On January 2, 2013, the President signed into law the American Taxpayer Relief Act of 2012 that further extends the 50% bonus depreciation for qualified property placed into service before January 1, 2014. These provisions have generated cash for

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

PSEG through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period.

In June 2009, September 2008 and December 2007, PSEG made tax deposits with the IRS in the amounts of $140 million, $80 million and $100 million, respectively, to defray potential interest costs associated with disputed tax assessments associated with certain lease investments. On January 31, 2012, PSEG signed a specific matter closing agreement with the IRS regarding this matter. Based on this agreement, these deposits were applied against tax and interest due pursuant to the closing agreement. Further, on the same date, PSEG signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. In March 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These agreements concluded the audits for these years for PSEG and the leasing issue for all tax years. The financial statement impacts of these agreements, net of existing financial statement reserves, was a net decrease in tax expense in the first quarter of 2012 of $71 million for PSEG, including $30 million and $1 million for PSE&G and Power, respectively.

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




	Other Comprehensive Income (Loss)
PSEG	Three Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss)	Derivative Contracts			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of June 30, 2013	$	3		$	(466	)	$	101		$	(362	)
Other Comprehensive Income before Reclassifications	1			—			27			28
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(2		)	9			(11		)	(4		)
Net Current Period Other Comprehensive Income (Loss)	(1		)	9			16			24
Balance as of September 30, 2013	$	2		$	(457	)	$	117		$	(338	)




	Other Comprehensive Income (Loss)
Power	Three Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss)	Derivative Contracts			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of June 30, 2013	$	4		$	(405	)	$	98		$	(303	)
Other Comprehensive Income before Reclassifications	1			—			28			29
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(2		)	8			(11		)	(5		)
Net Current Period Other Comprehensive Income (Loss)	(1		)	8			17			24
Balance as of September 30, 2013	$	3		$	(397	)	$	115		$	(279	)




	Other Comprehensive Income (Loss)
PSEG	Nine Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss)	Derivative Contracts			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2012	$	7		$	(485	)	$	90		$	(388	)
Other Comprehensive Income before Reclassifications	1			—			53			54
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(6		)	28			(26		)	(4		)
Net Current Period Other Comprehensive Income (Loss)	(5		)	28			27			50
Balance as of September 30, 2013	$	2		$	(457	)	$	117		$	(338	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	Other Comprehensive Income (Loss)
Power	Nine Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss)	Derivative Contracts			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2012	$	9		$	(422	)	$	85		$	(328	)
Other Comprehensive Income before Reclassifications	1			—			56			57
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(7		)	25			(26		)	(8		)
Net Current Period Other Comprehensive Income (Loss)	(6		)	25			30			49
Balance as of September 30, 2013	$	3		$	(397	)	$	115		$	(279	)




		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
PSEG		Three Months Ended									Nine Months Ended
		September 30, 2013									September 30, 2013
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy Related Contracts	Operating Revenues	$	3		$	(1	)	$	2		$	11		$	(4	)	$	7
Interest Rate Swaps	Interest Expense	—			—			—			(1		)	—			$	(1	)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Operation and Maintenance Expense	3			(1		)	2			8			(3		)	5
Amortization of Actuarial Loss	Operation and Maintenance Expense	(18		)	7			(11		)	(56		)	23			(33		)
Available-for-Sale Securities
Realized Gains	Other Income	35			(18		)	17			99			(51		)	48
Realized Losses	Other Deductions	(9		)	4			(5		)	(37		)	18			(19		)
Other-Than-Temporary Impairments	Other-Than-Temporary Impairments	(3		)	2			(1		)	(7		)	4			(3		)
Total		$	11		$	(7	)	$	4		$	17		$	(13	)	$	4

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Power		Three Months Ended									Nine Months Ended
		September 30, 2013									September 30, 2013

Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy Related Contracts	Operating Revenues	$	3		$	(1	)	$	2		$	11		$	(4	)	$	7
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Operation and Maintenance Expense	3			(1		)	2			7			(3		)	4
Amortization of Actuarial Loss	Operation and Maintenance Expense	(17		)	7			(10		)	(49		)	20			(29		)
Available-for-Sale Securities
Realized Gains	Other Income	35			(18		)	17			95			(49		)	46
Realized Losses	Other Deductions	(9		)	4			(5		)	(34		)	17			(17		)
Other-Than-Temporary Impairments	Other-Than-Temporary Impairments	(3		)	2			(1		)	(7		)	4			(3		)
Total		$	12		$	(7	)	$	5		$	23		$	(15	)	$	8




	Balance as of December 31, 2011			Other Comprehensive Income (Loss) Nine Months Ended September 30, 2012							Balance as of September 30, 2012
	Balance as of December 31, 2011			Power			PSE&G		Other		Balance as of September 30, 2012
	Millions
Derivative Contracts	$	31		$	(21	)	$	—	$	1	$	11
Pension and OPEB Plans	(438		)	21			—		2		(415		)
Available-for-Sale Securities	70			11			—		1		82
Accumulated Other Comprehensive Income (Loss)	$	(337	)	$	11		$	—	$	4	$	(322	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 16. Earnings Per Share (EPS) and Dividends

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




	Three Months Ended September 30,								Nine Months Ended September 30,
	2013				2012				2013				2012
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Net Income	$	390	$	390	$	347	$	347	$	1,043	$	1,043	$	1,051	$	1,051
EPS Denominator (Thousands)
Weighted Average Common Shares Outstanding	505,858		505,858		505,914		505,914		505,900		505,900		505,942		505,942
Effect of Stock Based Compensation Awards	—		1,836		—		1,197		—		1,533		—		1,095
Total Shares	505,858		507,694		505,914		507,111		505,900		507,433		505,942		507,037

EPS
Net Income	$	0.77	$	0.77	$	0.69	$	0.68	$	2.06	$	2.06	$	2.08	$	2.07




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Dividend Payments on Common Stock	2013		2012		2013		2012
Per Share	$	0.3600	$	0.3550	$	1.0800	$	1.0650
in Millions	$	182	$	180	$	546	$	538

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 17. Financial Information by Business Segments




	Power		PSE&G		Energy Holdings			Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2013
Total Operating Revenues	$	1,169	$	1,666	$	8		$	(289	)	$	2,554
Income (Loss) From Continuing Operations	221		168		(3		)	4			390
Net Income (Loss)	221		168		(3		)	4			390
Segment Earnings (Loss)	221		168		(3		)	4			390
Gross Additions to Long-Lived Assets	197		480		13			6			696
Three Months Ended September 30, 2012
Total Operating Revenues	$	1,038	$	1,683	$	15		$	(334	)	$	2,402
Income (Loss) From Continuing Operations	181		155		7			4			347
Net Income (Loss)	181		155		7			4			347
Segment Earnings (Loss)	181		155		7			4			347
Gross Additions to Long-Lived Assets	149		499		30			11			689
Nine Months Ended September 30, 2013
Total Operating Revenues	$	3,806	$	5,084	$	42		$	(1,282	)	$	7,650
Income (Loss) From Continuing Operations	562		468		1			12			1,043
Net Income (Loss)	562		468		1			12			1,043
Segment Earnings (Loss)	562		468		1			12			1,043
Gross Additions to Long-Lived Assets	419		1,628		40			15			2,102
Nine Months Ended September 30, 2012
Total Operating Revenues	$	3,584	$	5,029	$	49		$	(1,287	)	$	7,375
Income (Loss) From Continuing Operations	538		453		49			11			1,051
Net Income (Loss)	538		453		49			11			1,051
Segment Earnings (Loss)	538		453		49			11			1,051
Gross Additions to Long-Lived Assets	493		1,369		85			22			1,969
As of September 30, 2013
Total Assets	$	10,721	$	20,330	$	1,448		$	111		$	32,610
Investments in Equity Method Subsidiaries	$	40	$	—	$	100		$	—		$	140
As of December 31, 2012
Total Assets	$	11,032	$	19,223	$	1,454		$	16		$	31,725
Investments in Equity Method Subsidiaries	$	40	$	—	$	94		$	—		$	134

(A)

Other activities include amounts applicable to PSEG (as parent company), Services and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are priced in accordance with applicable regulations, including affiliate pricing rules, or in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 18. Related-Party Transactions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 18. Related-Party Transactions

The following discussion relates to intercompany transactions, the majority of which are eliminated during the PSEG consolidation process in accordance with GAAP.

Power

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




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Related-Party Transactions	2013			2012			2013			2012
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)	$	48		$	67		$	654		$	630
Billings to PSE&G through BGS (A)	236			258			621			639
Total Revenue from Affiliates	$	284		$	325		$	1,275		$	1,269
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(43	)	$	(38	)	$	(131	)	$	(110	)
Total Expense Billings from Affiliates	$	(43	)	$	(38	)	$	(131	)	$	(110	)




	As of			As of
Related-Party Transactions	September 30, 2013			December 31, 2012
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	87		$	238
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)	28			27
Receivable from (Payable to) Services (B)	(26		)	(31		)
Tax Receivable from (Payable to) PSEG (C)	(54		)	111
Receivable from (Payable to) PSEG	(1		)	(5		)
Accounts Receivable (Payable)—Affiliated Companies, net	$	34		$	340
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)	$	417		$	574
Working Capital Advances to Services (E)	$	17		$	17
Long-Term Accrued Taxes Receivable (Payable) (C)	$	(50	)	$	(50	)

PSE&G

The financial statements for PSE&G include transactions with related parties presented as follows:




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Related-Party Transactions	2013			2012			2013			2012
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)	$	(48	)	$	(67	)	$	(654	)	$	(630	)
Billings from Power through BGS (A)	(236		)	(258		)	(621		)	(639		)
Administrative Billings from Services (B)	(61		)	(58		)	(184		)	(165		)
Total Expense Billings from Affiliates	$	(345	)	$	(383	)	$	(1,459	)	$	(1,434	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	As of			As of
Related-Party Transactions	September 30, 2013			December 31, 2012
	Millions
Payable to Power through BGS and BGSS Contracts (A)	$	(87	)	$	(238	)
Payable to Power Related to Gas Supply Hedges for BGSS (A)	(28		)	(27		)
Payable to Power for SREC Liability (F)	—			(7		)
Receivable from (Payable to) Services (B)	(58		)	(65		)
Tax Receivable from (Payable to) PSEG (C)	263			256
Receivable from (Payable to) PSEG	3			6
Receivable from Energy Holdings	1			2
Accounts Receivable (Payable)—Affiliated Companies, net	$	94		$	(73	)
Working Capital Advances to Services (E)	$	33		$	33
Long-Term Accrued Taxes Receivable (Payable) (C)	$	(48	)	$	(32	)


(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 Power and PSE&G at cost. In addition, Power and PSE&G 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)	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.


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

(F)

Pursuant to a 2008 BPU Order, certain BGS suppliers, including Power, would be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) or per Solar Alternative Compliance Payment (SACP) during the period June 1, 2008 through May 31, 2010 and such excess cost would be passed onto ratepayers. In accordance with a Stipulation of Settlement approved by the BPU in a December 2012 Order describing the mechanism for BGS suppliers to recover these costs, PSE&G, as a New Jersey EDC, estimated and accrued a total liability for the excess SREC cost expected to be recovered from ratepayers of $17 million, including approximately $7 million for Power’s share which was included in PSE&G’s Accounts Receivable (Payable)-Affiliated Companies, as of December 31, 2012. Under current accounting guidance, Power was unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet until the BPU issued an Order approving such payments. As a result, PSE&G’s liability to Power was not eliminated in consolidation and was included in Other Current Liabilities on PSEG’s Condensed Consolidated Balance Sheet as of December 31, 2012. In May 2013, the BPU issued an Order approving the BGS payments for these SRECs. This Order was not appealed and went into effect in July 2013. As a result, Power recorded its $9 million then outstanding receivable from PSE&G. In August 2013, PSE&G reimbursed Power and its other BGS suppliers for the excess SREC costs.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 19. 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 table presents 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 September 30, 2013
Operating Revenues	$	—		$	1,511		$	66		$	(408	)	$	1,169
Operating Expenses	2			1,145			62			(409		)	800
Operating Income (Loss)	(2		)	366			4			1			369
Equity Earnings (Losses) of Subsidiaries	226			(1		)	—			(225		)	—
Other Income	8			47			—			(10		)	45
Other Deductions	1			(11		)	—			(1		)	(11		)
Other-Than-Temporary Impairments	—			(3		)	—			—			(3		)
Interest Expense	(19		)	(13		)	(4		)	10			(26		)
Income Tax Benefit (Expense)	7			(160		)	—			—			(153		)
Net Income (Loss)	$	221		$	225		$	—		$	(225	)	$	221
Comprehensive Income (Loss)	$	245		$	242		$	—		$	(242	)	$	245
Three Months Ended September 30, 2012
Operating Revenues	$	—		$	1,358		$	36		$	(356	)	$	1,038
Operating Expenses	(1		)	1,095			32			(355		)	771
Operating Income (Loss)	1			263			4			(1		)	267
Equity Earnings (Losses) of Subsidiaries	191			—			—			(191		)	—
Other Income	11			106			—			(13		)	104
Other Deductions	—			(20		)	—			—			(20		)
Other-Than-Temporary Impairments	—			(2		)	—			—			(2		)
Interest Expense	(29		)	(15		)	(5		)	14			(35		)
Income Tax Benefit (Expense)	7			(142		)	1			1			(133		)
Net Income (Loss)	$	181		$	190		$	—		$	(190	)	$	181
Comprehensive Income (Loss)	$	166		$	168		$	—		$	(168	)	$	166

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Nine Months Ended September 30, 2013
Operating Revenues	$	—		$	4,849		$	133		$	(1,176	)	$	3,806
Operating Expenses	6			3,894			123			(1,176		)	2,847
Operating Income (Loss)	(6		)	955			10			—			959
Equity Earnings (Losses) of Subsidiaries	588			(3		)	—			(585		)	—
Other Income	27			130			—			(30		)	127
Other Deductions	(9		)	(40		)	—			—			(49		)
Other-Than-Temporary Impairments	—			(7		)	—			—			(7		)
Interest Expense	(72		)	(29		)	(14		)	30			(85		)
Income Tax Benefit (Expense)	34			(419		)	2			—			(383		)
Net Income (Loss)	$	562		$	587		$	(2	)	$	(585	)	$	562
Comprehensive Income (Loss)	$	611		$	612		$	(2	)	$	(610	)	$	611
Nine Months Ended September 30, 2013
Net Cash Provided By (Used In) Operating Activities	$	425		$	1,360		$	5		$	(506	)	$	1,284
Net Cash Provided By (Used In) Investing Activities	$	569		$	(869	)	$	(1	)	$	11		$	(290	)
Net Cash Provided By (Used In) Financing Activities	$	(990	)	$	(492	)	$	(4	)	$	494		$	(992	)
Nine Months Ended September 30, 2012
Operating Revenues	$	—		$	4,560		$	93		$	(1,069	)	$	3,584
Operating Expenses	(1		)	3,663			87			(1,069		)	2,680
Operating Income (Loss)	1			897			6			—			904
Equity Earnings (Losses) of Subsidiaries	567			(4		)	—			(563		)	—
Other Income	35			176			—			(40		)	171
Other Deductions	(7		)	(45		)	—			—			(52		)
Other-Than-Temporary Impairments	—			(14		)	—			—			(14		)
Interest Expense	(89		)	(35		)	(13		)	40			(97		)
Income Tax Benefit (Expense)	31			(409		)	3			1			(374		)
Net Income (Loss)	$	538		$	566		$	(4	)	$	(562	)	$	538
Comprehensive Income (Loss)	$	549		$	556		$	(4	)	$	(552	)	$	549
Nine Months Ended September 30, 2012
Net Cash Provided By (Used In) Operating Activities	$	409		$	1,259		$	(3	)	$	(493	)	$	1,172
Net Cash Provided By (Used In) Investing Activities	$	257		$	(897	)	$	(24	)	$	158		$	(506	)
Net Cash Provided By (Used In) Financing Activities	$	(666	)	$	(368	)	$	26		$	335		$	(673	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated
	Millions
As of September 30, 2013
Current Assets	$	4,065	$	8,609	$	957	$	(11,941	)	$	1,690
Property, Plant and Equipment, net	81		6,059		922		—			7,062
Investment in Subsidiaries	4,331		730		—		(5,061		)	—
Noncurrent Assets	197		1,842		56		(126		)	1,969
Total Assets	$	8,674	$	17,240	$	1,935	$	(17,128	)	$	10,721
Current Liabilities	$	752	$	10,778	$	997	$	(11,941	)	$	586
Noncurrent Liabilities	522		2,130		208		(125		)	2,735
Long-Term Debt	2,041		—		—		—			2,041
Member’s Equity	5,359		4,332		730		(5,062		)	5,359
Total Liabilities and Member’s Equity	$	8,674	$	17,240	$	1,935	$	(17,128	)	$	10,721
As of December 31, 2012
Current Assets	$	3,922	$	8,084	$	940	$	(10,712	)	$	2,234
Property, Plant and Equipment, net	80		5,988		950		—			7,018
Investment in Subsidiaries	4,317		733		—		(5,050		)	—
Noncurrent Assets	201		1,660		60		(141		)	1,780
Total Assets	$	8,520	$	16,465	$	1,950	$	(15,903	)	$	11,032
Current Liabilities	$	482	$	10,187	$	1,010	$	(10,712	)	$	967
Noncurrent Liabilities	559		1,960		207		(140		)	2,586
Long-Term Debt	2,040		—		—		—			2,040
Member’s Equity	5,439		4,318		733		(5,051		)	5,439
Total Liabilities and Member’s Equity	$	8,520	$	16,465	$	1,950	$	(15,903	)	$	11,032


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

This combined MD&A is separately filed by PSEG, Power and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations whatsoever as to any other company.

PSEG’s business consists of three reportable segments, which are:


•	Power, our wholesale energy supply company that integrates its 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,


•	PSE&G, our public utility company which provides electric transmission services and distribution of electric energy and natural gas in New Jersey; implements demand response and energy efficiency programs and invests in solar generation, and


•	Energy Holdings, which principally owns energy-related leveraged leases and solar generation projects. A subsidiary of Energy Holdings has been awarded a contract to manage the transmission and distribution assets of LIPA beginning on January 1, 2014.

Our business discussion in Part I, Item 1. Business of our 2012 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 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 Overview of 2012 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2013 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, the 2012 Form 10-K and the Quarterly Reports on Form 10-Q for the quarters ended June 30, 2013 and March 31, 2013.

OVERVIEW OF 2013 AND FUTURE OUTLOOK

Our business plan is designed to maintain earnings stability while achieving growth in recognition of market, regulatory and economic trends. We continue to focus on operational excellence to provide the foundation for our financial strength, which enables us to invest in a disciplined way.

Financial Results

The results for PSEG, PSE&G, Power and Energy Holdings for the three months and nine months ended September 30, 2013 and 2012 are presented below:




	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Earnings (Losses)	2013			2012		2013		2012
	Millions
Power	$	221		$	181	$	562	$	538
PSE&G	168			155		468		453
Energy Holdings	(3		)	7		1		49
Other (A)	4			4		12		11
PSEG Net Income	$	390		$	347	$	1,043	$	1,051

Earnings Per Share (Diluted)
PSEG Net Income	$	0.77		$	0.68	$	2.06	$	2.07


(A)	Other primarily includes parent company interest and financing activity and certain administrative and general expenses.

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 chart below:




	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2013		2012			2013			2012
	Millions, after tax
NDT Fund Income (Expense) (A)	$	12	$	40		$	29		$	49
Non-Trading MTM Gains (Losses)	$	3	$	(76	)	$	(22	)	$	(34	)

(A)

NDT Fund Income (Expense) includes the net realized gains, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions. This also includes impairments on certain NDT securities which are included in Other-Than-Temporary Impairments and the interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO), which is recorded in Operation and Maintenance Expense and the depreciation related to the ARO asset.

Our $43 million increase in Net Income for the three months ended September 30, 2013 includes the MTM and NDT activity above and was also impacted by:


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


•	higher capacity revenues, and


•	higher Operation and Maintenance Costs due primarily to planned maintenance costs at our gas-fired Bethlehem Energy Center (BEC) in New York and costs related to damage caused by Superstorm Sandy at our fossil plants, partly offset by cost control measures.

Our $8 million decrease in Net Income for the nine months ended September 30, 2013 was driven primarily by:


•	lower volumes of electricity sold under our basic generation service (BGS) contracts at lower average prices,


•	lower volumes of wholesale load contracts in the PJM and NE regions,


•	higher generation costs due to higher fuel costs,


•	higher Operation and Maintenance Costs in 2013, including costs related to damage caused by Superstorm Sandy, partially offset by cost control measures,


•	higher Income Tax Expense at PSE&G and Energy Holdings due to the absence of tax benefits related to the settlement of the 1997-2006 Internal Revenue Service (IRS) audits in 2012, and


•	net realized gains in September 2012 resulting from restructuring our NDT Fund.

These decreases were largely offset by


•	higher capacity pricing in the PJM region resulting from higher auction prices as well as higher generation sold primarily in the PJM region,


•	higher average gas prices on sales to third party customers, and


•	higher revenues due to increased investments in transmission projects,

Under the PJM capacity auction conducted in May 2013, Power cleared 8,637 MW of its generating capacity at an average price of $166 per MW-day for the 2016-2017 delivery period. While this year's auction resulted in lower clearing prices for the PJM Regional Transmission Organization (RTO), Power benefited from higher prices than the rest of the RTO, as the majority of its generation fleet is situated in the relatively constrained Eastern part of PJM.

Power’s results also benefited from access to low cost natural gas from the Marcellus region through its existing transportation and storage contracts. Power manages these contracts primarily for the benefit of PSE&G’s customers through the basic gas supply service (BGSS) arrangement. During times of low customer demand for gas, Power can use the remaining transportation that is available to supply the Marcellus gas to its generating units in New Jersey.

At our regulated utility, we continued to invest capital in transmission and distribution infrastructure projects, aimed at maintaining the reliability of our service to our customers. PSE&G’s results for 2013 reflect the favorable impacts from these investments. We filed our 2014 Annual Formula Rate Update with the FERC in October of this year, which would provide for approximately $176 million in increased annual transmission revenues effective January 1, 2014. Over the past few years, these types of investments have altered the business mix of PSEG’s overall results of operations to reflect a higher percentage contribution by PSE&G.

Regulatory, Legislative and Other Developments

In developing and implementing our strategy of operational excellence, financial strength and disciplined investment, we monitor significant regulatory and legislative developments. Competitive wholesale power market design is of particular importance to our results and we continue to advocate for policies and rules that promote competitive electricity markets. This includes opposing efforts by states to subsidize generation and supporting rule changes which we believe are necessary to avoid artificial price suppression and other distortions in the energy and capacity markets. For a more detailed discussion of the status of these efforts, refer to Part II. Item 5. Other Information—Federal Regulation—Capacity Market Issues—LCAPP.

We continue to advocate for the development and implementation of fair and reasonable rules by the U.S. Environmental Protection Agency (EPA). In particular, the EPA's 316(b) rule on cooling water intake could adversely impact future nuclear and fossil operations and costs. Clean Air Act (CAA) regulations governing hazardous air pollutants under the EPA's Maximum Achievable Control Technology (MACT) rules are also of significance; however, we believe our generation business remains well-positioned for such regulations if and when they are implemented. These matters are discussed in Part II. Item 5. Other Information—Environmental Matters—Climate Change—CO₂Regulation under the CAA.

As discussed in further detail under Part II. Item 5. Other Information—Federal Regulation—Transmission Regulation— Transmission Policy Developments, the FERC's rules under Order 1000 altered the right of first refusal previously held by incumbent utilities to build all transmission within their respective service territories. We are challenging the FERC's determination in court as we do not believe that the FERC sufficiently justified its decision to alter this right embedded in the FERC-approved contracts and tariffs. At the same time, the FERC's action presents opportunities for us to construct transmission outside of our service territory.

In the fourth quarter of 2012, we were severely impacted by Superstorm Sandy, which resulted in the highest level of customer outages in our history. We sustained significant damage to some of our generation, transmission and distribution facilities. The New Jersey Board of Public Utilities (BPU) issued an order allowing us to defer actually incurred prudent, incremental storm restoration costs not otherwise recoverable through base rates or insurance. In February 2013, the BPU initiated a generic proceeding to evaluate the prudency of extraordinary storm-related costs incurred by all of the regulated utilities as a result of the natural disasters experienced in New Jersey in 2011 and 2012. In June 2013, we made a compliance filing with the BPU providing the details of our storm restoration costs for Superstorm Sandy as well as other major storms and seeking to demonstrate that we responded to these extreme weather events in a timely, diligent and thorough manner and that the costs incurred were prudent. We requested that the BPU issue an Order approving the compliance filing and specifically finding that the storm costs incurred were reasonable and prudent, and should be recovered from ratepayers.

Power also incurred significant storm-related expenses, primarily for repairs at certain of its coal and gas-fired generating stations in the first nine months of 2013 (See Note 9. Commitments and Contingent Liabilities). We are seeking recovery from our insurers for the property damage, above our self-insured retentions; however, no assurances can be given relative to the timing or amount of any such recovery. In June 2013, we filed suit against the insurance carriers seeking legal interpretation of certain terms in the insurance policies regarding losses resulting from damage caused by Superstorm Sandy's storm surge. For a more detailed discussion concerning this proceeding, refer to Part II. Item 1. Legal Proceedings—Superstorm Sandy.

On February 20, 2013, we filed a petition with the BPU describing our Energy Strong program, consisting of $3.9 billion of proposed improvements we recommend making to our gas and electric distribution systems over a ten-year period to harden and improve resiliency. In the petition, we sought approval for $2.6 billion of the $3.9 billion of investments over an initial five year period, plus associated expenses, and to receive contemporaneous recovery of and on such investments. We cannot predict the outcome of this pending proceeding, including whether the program will be approved or the terms under which it would be approved. We anticipate seeking BPU approval to complete our investment under the program at a later date. In addition, we anticipate investing an additional $1.5 billion in our transmission system for the same reason. As proposed, we believe that the rate impacts of the Energy Strong program will be significantly muted as a result of scheduled reductions to customer bills that will be taking place over the next few years and assuming continued low gas prices. See Part II Item 5. Other Information—State Regulation—Energy Strong Program for additional details.

We continue to take all necessary steps in connection with the expected January 1, 2014 commencement of our management of the Long Island Power Authority (LIPA) transmission and distribution (T&D) system. Legislation enacted in New York in July 2013 authorized an expanded role for us in the management of LIPA's T&D system. A revised contract with LIPA was approved by the LIPA Board in October 2013, but implementation of the new contract remains subject to a number of factors,

including LIPA’s receipt of a Private Letter Ruling from the IRS on the continued tax-exempt status of certain LIPA debt securities and LIPA’s approval of the proposed 2014 and 2015 operating and capital pass-through budgets. See Part II. Item 5. Other Information—Business Operations and Strategy—Energy Holdings—Products and Services for additional details.

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 in the first nine months of the year as we remain diligent in managing costs. In the first nine months of 2013, our


•	outstanding performance allowed us to increase generation to meet loads, and


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

Financial Strength

Our financial position remained strong during the first nine months of 2013 as we:


•	had cash on hand of $448 million as of September 30, 2013,


•	extended the expiration date of approximately half of our credit facilities, and maintained substantial liquidity and solid investment grade credit ratings, as evidenced by the recent credit rating upgrades by Standard & Poor's (S&P) of PSEG, Power and PSE&G as disclosed below in Liquidity and Capital Resources—Credit Ratings,


•	completed pension and other postretirement benefit funding for 2013,


•	issued bonds at PSE&G to refinance its maturing debt at historically low rates and fund its capital program,


•	repaid Power's maturing debt with cash on hand, and


•	increased our indicated annual dividend to $1.44.

We expect to be able to fund our proposed Energy Strong program with internally generated cash and external debt financing.

Disciplined Investment

We seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first nine months of 2013 we


•	made additional investments in transmission infrastructure projects,


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


•	obtained approval from the BPU to increase our spending up to $247 million and $199 million under our Solar 4 All Extension and Solar Loan III investment programs, respectively, and


•	continued construction of a 19 MW solar project in Arizona.

Delays in the construction schedules of our projects could impact their costs as well as the timing of expected revenues.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a difficult economy and cost-constrained environment, to capitalize on or otherwise address appropriately regulatory and legislative developments 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 re-contract our open supply positions,


•	execute our capital investment program, including 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,


•	advocate for measures to ensure the implementation by PJM and the FERC of market design rules that continue to protect competition and achieve appropriate Reliability Pricing Model (RPM) and BGS pricing, and


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

For the remainder of 2013 and beyond, the key issues and challenges we expect our business to confront include


•	regulatory and political uncertainty, particularly with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation,


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


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


•	the aftermath of Hurricane Irene and Superstorm Sandy, including addressing the BPU's review of performance and communications, as well as cost recovery and opportunities for investment in system strengthening, including our proposed Energy Strong program,


•	financially-stressed power plant leveraged lease investments,


•	delays and other obstacles that might arise in connection with the construction of our transmission and distribution projects, including in connection with permitting and regulatory approvals, and


•	the successful transition to our management of the LIPA T&D system.

RESULTS OF OPERATIONS

PSEG

Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, charitable contributions and general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 18. Related-Party Transactions. For an explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings that follow the table below:




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2013		2012		2013 vs. 2012					2013		2012		2013 vs. 2012
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	2,554	$	2,402	$	152		6		$	7,650	$	7,375	$	275		4
Energy Costs	801		879		(78		)	(9	)	2,711		2,819		(108		)	(4	)
Operation and Maintenance	713		619		94			15		2,069		1,876		193			10
Depreciation and Amortization	313		286		27			9		886		797		89			11
Taxes Other than Income Taxes	15		24		(9		)	(38	)	50		73		(23		)	(32	)
Income from Equity Method Investments	4		7		(3		)	(43	)	9		9		—			N/A
Other Income and (Deductions)	47		95		(48		)	(51	)	118		155		(37		)	(24	)
Other-Than-Temporary Impairments	3		2		1			50		7		14		(7		)	(50	)
Interest Expense	100		106		(6		)	(6	)	303		310		(7		)	(2	)
Income Tax Expense	270		241		29			12		708		599		109			18

Power




	Three Months Ended				Increase/ (Decrease)		Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)		September 30,				Increase/ (Decrease)
	2013		2012		2013 vs. 2012		2013		2012		2013 vs. 2012
	Millions
Net Income	$	221	$	181	$	40	$	562	$	538	$	24

For the three months ended September 30, 2013, the primary reasons for the $40 million increase in Net Income were:


•	significant MTM losses in 2012 resulting from an increase in prices on forward positions, and


•	higher capacity revenues in 2013.

These increases were partially offset by


•	higher Operation and Maintenance Costs, due primarily to planned maintenance costs at our BEC plant and costs related to damage caused by Superstorm Sandy at our fossil plants, and


•	$59 million of net realized gains in September 2012 resulting from restructuring our NDT Fund.

For the nine months ended September 30, 2013, the primary reasons for the $24 million increase in Net Income were:


•	higher capacity pricing in the PJM region resulting from higher auction prices as well as higher generation sold primarily in the PJM region, and


•	higher average gas prices on sales to third party customers.

These increases were largely offset by


•	lower volumes of electricity sold under our BGS contracts at lower average prices,


•	lower volumes of wholesale load contracts in the PJM and NE regions,


•	higher generation costs due to higher fuel costs,


•	higher Operation and Maintenance Costs in 2013, including costs related to damage caused by Superstorm Sandy at our fossil plants, and


•	$59 million of net realized gains in September 2012 resulting from restructuring our NDT Fund.

The quarter and year-to date details for these variances are discussed below:




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2013		2012		2013 vs. 2012					2013		2012		2013 vs. 2012
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,169	$	1,038	$	131		13		$	3,806	$	3,584	$	222		6
Energy Costs	430		456		(26		)	(6	)	1,786		1,725		61			4
Operation and Maintenance	304		255		49			19		866		780		86			11
Depreciation and Amortization	66		60		6			10		195		175		20			11
Other Income (Deductions)	34		84		(50		)	(60	)	78		119		(41		)	(34	)
Other-Than-Temporary Impairments	3		2		1			50		7		14		(7		)	(50	)
Interest Expense	26		35		(9		)	(26	)	85		97		(12		)	(12	)
Income Tax Expense	153		133		20			15		383		374		9			2

Three Months Ended September 30, 2013 as Compared to 2012

Operating Revenues increased $131 million due to changes in generation and gas supply revenues.

Generation Revenues increased $133 million due primarily to


•	an increase of $147 million largely due to a $137 million increase primarily attributable to significant MTM losses in 2012 in the PJM region resulting from increases in prices on forward positions, and


•	an increase of $78 million due to higher capacity revenues resulting from higher average auction prices and an increase in operating reserve revenues in the PJM region,


•	partially offset by a decrease of $74 million due primarily to lower volumes of electricity sold under our BGS contracts and lower average pricing, and


•	a net decrease of $18 million due primarily to lower volumes in the NE region as well as lower average prices in the PJM and NE regions on wholesale load contracts.

Gas Supply Revenues decreased $2 million due primarily to


•	a net decrease of $5 million in sales under the BGSS contract, primarily due to lower average gas prices partly offset by higher sales volumes,


•	partially offset by a net increase of $3 million partially due to higher sales volumes to third party customers.

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 $26 million due to

•

Generation costs decreased $20 million due primarily to $28 million of lower fuel costs, reflecting utilization of lower volumes of coal and natural gas at lower average prices, partially offset by higher nuclear fuel prices. This decrease was partially offset by a net increase of $8 million due to energy purchases at higher average prices partly offset by the recovery of excess solar renewable energy credit (SREC) cost in PJM.


•	Gas costs decreased $6 million due primarily to lower average prices under the BGSS contract and on sales to third party customers offset in part by higher sales volumes in 2013.

Operation and Maintenance increased $49 million due primarily to planned maintenance costs at our BEC plant and costs incurred from Superstorm Sandy in 2013 at our New Jersey fossil plants.

Depreciation and Amortization increased $6 million due primarily to a higher depreciable fossil asset base and completion of a steam path retrofit upgrade at our co-owned nuclear Peach Bottom Unit 2 in October 2012.

Other Income and (Deductions) decreased $50 million due primarily to net realized gains of $59 million resulting from restructuring our NDT Fund in September 2012, partially offset by lower NDT Fund realized losses in 2013.

Other-Than-Temporary Impairments increased $1 million due to higher impairments on the NDT Fund in 2013.

Interest Expense decreased $9 million due primarily to a decrease from lower outstanding debt in 2013 resulting from certain debt redeemed prior to maturity in December 2012, as well as the maturity of Senior Notes in April 2013, and lower interest expense due to interest costs we capitalized for projects under construction.

Income Tax Expense increased $20 million in 2013 due primarily to higher pre-tax income.

Nine Months Ended September 30, 2013 as Compared to 2012

Operating Revenues increased $222 million due to changes in generation and gas supply revenues.

Generation Revenues increased $130 million due primarily to


•	an increase of $275 million due to higher capacity revenues resulting from higher average auction prices and an increase in operating reserve revenues in PJM, and


•	higher revenues of $91 million due primarily to higher generation sold in the PJM and NE regions partly offset by lower average prices in PJM,


•	partially offset by a decrease of $144 million due primarily to lower volumes of electricity sold under our BGS contracts and lower average pricing, and


•	a net decrease of $92 million due to lower volumes on wholesale load contracts in the PJM and NE regions.

Gas Supply Revenues increased $92 million due primarily to


•	a net increase of $60 million in sales under the BGSS contract, substantially comprised of higher sales volumes due to colder average temperatures during the 2013 winter heating season, partially offset by lower average gas prices, and


•	a net increase of $32 million due primarily to higher average gas prices, partially offset by lower sales volumes to third party customers.

Operating Expenses

•

Generation costs increased $18 million due primarily to $83 million of higher fuel costs, reflecting higher average realized natural gas prices, higher nuclear fuel costs, and the utilization of higher volumes of coal and oil, partially offset by lower average coal prices. The increase was partially offset by $21 million of lower energy purchases, recovery of excess SREC costs and a decrease of $44 million in congestion costs in PJM.


•	Gas costs increased $43 million, principally related to obligations under the BGSS contract, reflecting higher sales volumes in 2013 due to colder average temperatures during the 2013 winter heating season, partially offset by lower average gas inventory costs.

Operation and Maintenance increased $86 million due primarily to $63 million in costs incurred from Superstorm Sandy in 2013 at our fossil plants, and $48 million of higher planned outage and maintenance costs in 2013, mainly at BEC, our Bergen gas-fired plant in New Jersey and Conemaugh coal-fired plant in Pennsylvania. This was partially offset by the recognition of a $25 million insurance recovery related to Superstorm Sandy.

Depreciation and Amortization increased $20 million due primarily to a higher depreciable asset base at Fossil, including placing into service the new gas-fired peaking units at Kearny, New Jersey and New Haven, Connecticut in June 2012 and completion of the steam path retrofit upgrade at our co-owned Peach Bottom Unit 2 in October 2012.

Other Income and (Deductions) decreased $41 million due primarily to the factors disclosed in the above analysis for the three months ended September 30, 2013 versus 2012.

Other-Than-Temporary Impairments decreased $7 million due to lower impairments on the NDT Fund in 2013.

Interest Expense decreased $12 million due primarily to a decrease from lower outstanding debt in 2013 resulting from certain debt redeemed prior to maturity in December 2012, as well as the maturity of Senior Notes in April 2013, partially offset by higher interest costs in 2013 since interest capitalization ceased for our Kearny and New Haven gas-fired peaking projects on their June 2012 in-service date.

Income Tax Expense increased $9 million in 2013 due primarily to higher pre-tax income.

PSE&G




	Three Months Ended				Increase/ (Decrease)		Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)		September 30,				Increase/ (Decrease)
	2013		2012		2013 vs. 2012		2013		2012		2013 vs. 2012
	Millions
Net Income	$	168	$	155	$	13	$	468	$	453	$	15

For the three months ended September 30, 2013, the primary reason for the $13 million increase in Net Income was higher transmission revenues due to increased investments in transmission projects.

For the nine months ended September 30, 2013, the primary reasons for the $15 million increase in Net Income were


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


•	partially offset by higher Income Tax Expense due to the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in 2012.

The quarter and year-to-date details for these variances are discussed below:




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2013		2012		2013 vs. 2012					2013		2012		2013 vs. 2012
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,666	$	1,683	$	(17	)	(1	)	$	5,084	$	5,029	$	55		1
Energy Costs	661		756		(95		)	(13	)	2,208		2,380		(172		)	(7	)
Operation and Maintenance	408		366		42			11		1,204		1,092		112			10
Depreciation and Amortization	236		216		20			9		658		594		64			11
Taxes Other Than Income Taxes	15		24		(9		)	(38	)	50		73		(23		)	(32	)
Other Income (Deductions)	12		10		2			20		38		31		7			23
Interest Expense	75		73		2			3		223		220		3			1
Income Tax Expense	115		103		12			12		311		248		63			25

Three Months Ended September 30, 2013 as Compared to 2012

Operating Revenues decreased $17 million due to changes in delivery, clause, commodity and other operating revenues.

Commodity Revenue decreased $95 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.


•	Electric revenues decreased $92 million due primarily to $40 million in lower BGS revenues and $52 million in lower revenues from a reduced volume of sales of Non-Utility Generation (NUG) energy and lower Non-Utility Generation Charges (NGC) due to lower tariff rates. BGS sales decreased 6% due to customer migration to third party suppliers (TPS) and weather.


•	Gas revenues decreased $3 million due to lower BGSS prices of $5 million, partially offset by higher BGSS volumes of $2 million primarily due to weather. The average price of natural gas was 7% lower in 2013 than in 2012.

Delivery Revenues increased $52 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $46 million higher due to net rate increases resulting primarily from increased capital investments.


•	Electric distribution revenues increased $7 million due primarily to an increase in Capital Infrastructure Program (CIP) related revenues of $14 million and higher Green Program Recovery Charges (GPRC) of $17 million, partially offset by lower sales volumes of $16 million, and lower Transitional Energy Facilities Assessment (TEFA) revenue of $8 million due to a lower TEFA rate.


•	Gas distribution revenues decreased $1 million due primarily to lower Weather Normalization Clause (WNC) revenue of $6 million due to more normal weather compared to the prior period, partially offset by $3 million from higher sales volumes and $2 million from CIP related revenues.

Clause Revenues increased $22 million due primarily to higher Securitization Transition Charge (STC) revenues of $10 million, higher Solar Pilot Recovery Charge (SPRC) revenue of $5 million and higher Margin Adjustment Clause (MAC) revenue of $7 million. The changes in STC, SPRC and MAC amounts were entirely offset by the amortization of Regulatory Assets and related costs in Operation and Maintenance (O&M), Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SPRC or MAC collections.

Other Operating Revenues increased $4 million due primarily to increased revenues from our miscellaneous electric operating revenues.

Energy Costs decreased $95 million. This is entirely offset by Commodity Revenue.


•	Electric costs decreased $92 million or 14% due to $73 million in lower BGS and NUG volumes, $10 million of lower BGS and NUG prices and $9 million for decreased deferred cost recovery. BGS and NUG volumes decreased 11% due primarily to customer migration to TPS and weather.


•	Gas costs decreased $3 million or 4% due to $5 million or 7% in lower prices, partially offset by $2 million or 3% in higher sales volumes due primarily to weather.

Operation and Maintenance increased $42 million, of which the most significant components were


•	a $37 million increase in costs related primarily to Societal Benefit Charges (SBC), CIP and GPRC. Due to the nature of the SBC, CIP and GPRC clause mechanisms, these are entirely offset in revenues, and


•	a $3 million increase in appliance service costs.

Depreciation and Amortization increased $20 million due primarily to


•	an $11 million increase in amortization of Regulatory Assets, and


•	an $8 million increase in depreciation of additional plant in service.

Taxes Other Than Income Taxes decreased $9 million due to a lower TEFA rate for electric and gas, partially offset by higher sales volumes for gas.

Other Income and (Deductions) net increase of $2 million was due primarily to an increase in Solar Loan interest income.

Interest Expense increased due primarily to higher average long-term debt partially offset by lower average securitization debt.

Income Tax Expense increased $12 million due primarily to higher pre-tax income.

Nine Months Ended September 30, 2013 as Compared to 2012

Operating Revenues increased $55 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $143 million due primarily to an increase in transmission revenues.


•	Transmission revenues were $131 million higher due to net rate increases resulting primarily from increased capital investments.


•	Gas distribution revenues increased $10 million due primarily to $58 million from higher sales volumes and an increase of $16 million in CIP related revenues, partially offset by lower WNC revenue of $61 million due to more normal weather compared to the prior period.


•	Electric distribution revenues increased $2 million due primarily to an increase in CIP related revenues of $14 million and higher GPRC of $21 million, partially offset by lower TEFA revenue of $18 million due to a lower TEFA rate and lower sales volumes of $15 million.

Clause Revenues increased $74 million due primarily to higher STC revenues of $35 million, higher SBC of $29 million, higher SPRC revenue of $8 million and higher MAC revenue of $2 million. The changes in STC, SBC, SPRC and MAC 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 STC, SBC, SPRC or MAC collections.

Other Operating Revenues increased $10 million due primarily to increased revenues from our appliance repair business and miscellaneous electric operating revenues.

Commodity Revenue decreased $172 million due to lower Electric revenues, partially offset by higher Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.


•	Electric revenues decreased $267 million due primarily to $164 million in lower BGS revenues and $103 million in lower revenues from a lower volume of sales of NUG energy and lower NGC due to lower tariff rates. BGS sales decreased 6% due primarily to customer migration to TPS.


•	Gas revenues increased $95 million due primarily to higher BGSS volumes.

Energy Costs decreased $172 million. This is entirely offset by Commodity Revenue.


•	Electric costs decreased $267 million or 15% due to $177 million in lower BGS and NUG volumes, $54 million of lower BGS and NUG prices, and $36 million for decreased deferred cost recovery. BGS and NUG volumes decreased 10% due primarily to customer migration to TPS.


•	Gas costs increased $95 million or 15% due primarily to higher sales volumes.

Operation and Maintenance increased $112 million, of which the most significant components were


•	an $87 million increase in costs recognized related primarily to SBC, CIP and GPRC. Due to the nature of the SBC, CIP and GPRC clause mechanisms, these are entirely offset in revenues,


•	an $8 million increase in costs relating to repairs from Superstorm Sandy and a colder winter, and


•	a $9 million increase in appliance service costs.

Depreciation and Amortization increased $64 million due primarily to


•	a $41 million increase in amortization of Regulatory Assets, and


•	a $21 million increase in depreciation of additional plant in service.

Taxes Other Than Income Taxes decreased $23 million due to a lower TEFA rate for electric and gas, partially offset by higher sales volumes for gas.

Other Income and (Deductions) net increase of $7 million was due primarily to an increase in Solar Loan interest income.

Interest Expense increased due primarily to higher average long-term debt partially offset by lower average securitization debt.

Income Tax Expense increased $63 million due primarily to the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in 2012 and higher pre-tax income.

Energy Holdings




	Three Months Ended					Increase/ (Decrease)			Nine Months Ended				Increase/ (Decrease)
	September 30,					Increase/ (Decrease)			September 30,				Increase/ (Decrease)
	2013			2012		2013 vs. 2012			2013		2012		2013 vs. 2012
	Millions
Net Income	$	(3	)	$	7	$	(10	)	$	1	$	49	$	(48	)

For the three months ended September 30, 2013, the primary reasons for the $10 million decrease in Net Income were the impairment of real estate assets and legal expenses related to the LIPA contract expansion in 2013 and a gain on an asset sale in 2012.

For the nine months ended September 30, 2013, the primary reason for the $48 million decrease in Net Income was the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in the prior year.

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 three direct operating subsidiaries.

Operating Cash Flows

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

For the nine months ended September 30, 2013, our operating cash flow increased $124 million as compared to the same period in 2012. The net change was due primarily to net changes from Power and PSE&G, as discussed below.

Power

Power’s operating cash flow increased $112 million from $1,172 million to $1,284 million for the nine months ended September 30, 2013, as compared to the same period in 2012, primarily resulting from higher earnings and an increase of $124 million related to margin deposits.

PSE&G

PSE&G’s operating cash flow increased $8 million from $1,041 million to $1,049 million for the nine months ended September 30, 2013, as compared to the same period in 2012, due primarily to higher earnings and an increase from a net change in regulatory deferrals primarily related to BGSS gas costs and the collection of Gas Weather Normalization Charges, offset by higher payments for storm related costs. The increases were partially offset by higher 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 credit facilities are provided by a diverse bank group. In March 2013, Power, PSEG and PSE&G amended their respective 5-year credit agreements scheduled to end in 2016, extending the expiration dates from April 2016 to March 2018. Of the total commitments of $2.1 billion under these agreements, $2.0 billion has been extended until 2018. The commitments for the $100 million balance will terminate in 2016. As of September 30, 2013, our total credit capacity was $4.3 billion.

As of September 30, 2013, no single institution represented more than 8% of the total commitments in our credit facilities.

As of September 30, 2013, 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 below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of September 30, 2013 were as follows:




	As of September 30, 2013
Company/Facility	Total Facility		Usage			Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	5	(D)	$	495	Mar 2017	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—			500		Mar 2018	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	5		$	995
Power
5-year Credit Facility	$	1,600	$	58	(D)	$	1,542	Mar 2017	Funding/Letters of Credit
5-year Credit Facility (B)	1,000		—			1,000		Mar 2018	Funding/Letters of Credit
Bilateral Credit Facility	100		100		(D)	—		Sept 2015	Letters of Credit
Total Power	$	2,700	$	158		$	2,542
PSE&G
5-year Credit Facility (C)	$	600	$	13	(D)	$	587	Mar 2018	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	13		$	587
Total	$	4,300	$	176		$	4,124


(A)	In April 2016, this facility will be reduced by $23 million.


(B)	In April 2016, this facility will be reduced by $48 million.


(C)	In April 2016, this facility will be reduced by $29 million.


(D)	Includes amounts related to letters of credit outstanding.

Long-Term Debt Financing

PSE&G has $275 million of 6.33% Medium-Term Notes maturing in November 2013. For a discussion of our long-term debt transactions during 2013, see Note 10. Changes in Capitalization.

Common Stock Dividends

On July 16, 2013, the Board of Directors declared a quarterly dividend of $0.36 per share of common stock for the third quarter of 2013. 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 16. Earnings Per Share 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. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies' ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

In April 2013, S&P upgraded the corporate credit ratings on PSEG, Power and PSE&G to BBB+ from BBB and PSE&G's Mortgage Bond rating to A from A-. PSEG's, Power's and PSE&G's outlooks were changed to stable from positive. In May 2013, Moody's published updated credit opinions on PSEG, Power and PSE&G. PSEG's, Power's and PSE&G's ratings and outlooks remained unchanged. In July 2013, Fitch published updated research on PSEG, Power and PSE&G which kept their ratings and outlooks unchanged.




	Moody’s (A)	S&P (B)	Fitch (C)
PSEG
Outlook	Stable	Stable	Stable
Commercial Paper	P2	A2	F2
Power
Outlook	Stable	Stable	Stable
Senior Notes	Baa1	BBB+	BBB+
PSE&G
Outlook	Stable	Stable	Stable
Mortgage Bonds	A1	A	A+
Commercial Paper	P2	A2	F2


(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.


(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 the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, PSE&G reported an increase in its projected base level capital expenditures of $215 million through 2015, as compared to the amounts disclosed in our Form 10-K for the year ended December 31, 2012. This increase primarily reflects our projected additional spending during the period under our Solar Loan III and Solar 4 All Extension programs which were approved by the BPU in May 2013. There have been no additional material changes to our projected capital expenditures at Power, PSE&G and Energy Holdings as compared to amounts disclosed in our Form 10-K for the year ended December 31, 2012. See Note 9. Commitments and Contingent Liabilities for additional information.

ACCOUNTING MATTERS

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


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The market 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.




	MTM VaR
	Three Months Ended September 30, 2013		Year Ended December 31, 2012
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	9	$	18
Average for the Period	$	14	$	16
High	$	19	$	29
Low	$	9	$	7
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	15	$	28
Average for the Period	$	22	$	25
High	$	30	$	46
Low	$	14	$	11

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


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, PSEG Power LLC, and Public Service Electric and Gas Company. 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, PSEG Power LLC, and Public Service Electric and Gas Company 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

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the third quarter of 2013 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. Certain information reported under Item 3 of Part I of the 2012 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013 are updated below. For additional information regarding material legal proceedings, including updates to information reported in Item 3 of Part I of the 2012 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Report on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013, see Note 9. Commitments and Contingent Liabilities and Item 5. Other Information.

Superstorm Sandy

June 30, 2013 Form 10-Q page 81. 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. PSEG is seeking recovery from its insurers for the property damage, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. PSEG has recorded proceeds of $50 million from its insurance carriers as advance payments, $25 million of which was recognized in the second quarter of 2013 and $25 million was recognized in the fourth quarter of 2012. PSEG does not believe that it has a basis for estimating additional probable insurance recoveries at this time. In June 2013, PSEG, Power and PSE&G filed suit in New Jersey state court against the insurance carriers seeking legal interpretation of certain terms in the insurance policies regarding losses resulting from damage caused by Superstorm Sandy's storm surge. The dispute concerns whether certain sub-limits in the policies apply to damage to property caused by Superstorm Sandy's storm surge. In that Complaint, PSEG stated that its estimate of the total costs required to restore damaged facilities to their pre-Superstorm Sandy condition was approximately $426 million. Of these costs, $364 million and $62 million related to Power and PSE&G, respectively. In August 2013, the insurance carriers filed an answer in which they denied most of the allegations made in the Complaint. Discovery is proceeding.


ITEM 1A.	RISK FACTORS

There no additional Risk Factors to be added to those disclosed in Part I Item 1A of our 2012 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 third quarter of 2013:




Three Months Ended September 30, 2013	Total Number of Shares Purchased	Average Price Paid per Share
July 1 - July 31	—	$	—
August 1 - August 31	22,500	$	33.70
September 1 -September 30	—	$	—


ITEM 5.	OTHER INFORMATION

Certain information reported in the 2012 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q for the Quarters Ended March 31, 2013 and June 30, 2013 are updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2012 Annual Report on Form 10-K and the Quarterly Reports on Form 10-Q for the Quarters Ended March 31, 2013 and June 30, 2013. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.

BUSINESS OPERATIONS AND STRATEGY

Energy Holdings

Products and Services

December 31, 2012 Form 10-K page 13 and June 30, 2013 Form 10-Q page 82. Our December 2011 ten-year contract, Operations Services Agreement (OSA), for the management of the Long Island Power Authority (LIPA) transmission and distribution system by PSEG Long Island LLC (PSEG LI) is scheduled to commence on January 1, 2014. We continue to take all necessary steps in connection with the expected January 1, 2014 commencement of our management responsibilities in accordance with this OSA.

On July 29, 2013, the Governor of New York signed legislation that will restructure LIPA, pursuant to which PSEG LI may undertake an expanded role in the management of LIPA's transmission and distribution system and other aspects of its operations. During September 2013, PSEG and LIPA concluded negotiations on an amendment to the OSA and several related agreements, including contracts to manage LIPA's fuel procurement and power supply obligations. The economic construct of the amended OSA is consistent with the original OSA, with PSEG LI taking on greater management responsibilities, using its brand and more fully integrating its support functions in return for greater compensation and an extension of the contract from the original ten years to twelve. In addition, there is an option for the parties to agree to extend the contract for an additional eight years. On September 27, 2013, the New York Department of Public Service issued its recommendation to LIPA to enter into those agreements. On October 3, 2013, the LIPA Board approved the agreements. On October 2, 2013, PSEG LI received its requested disclaimer of jurisdiction from the FERC. With those approvals received, the agreements’ effectiveness is contingent upon LIPA’s receipt of a Private Letter Ruling from the IRS on the continued tax-exempt status of certain LIPA debt securities and LIPA's approval of the proposed 2014 and 2015 operating and capital pass-through budgets.

FEDERAL REGULATION

FERC

Market Power

December 31, 2012 Form 10-K page 15. Under FERC regulations, public utilities must receive FERC authorization to sell power in interstate commerce. For a requesting company to receive market based rate (“MBR”) authority, the FERC must first make a determination that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated.

PSE&G, PSEG Energy Resources & Trade LLC, PSEG Power Connecticut, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG New Haven LLC all have been granted MBR authority from the FERC. Each of these companies, except PSEG New Haven LLC (which received MBR authority in May 2012), will be filing a market power update with the FERC at the end of 2013, which the FERC must accept in order for these companies to retain MBR authority. Retention of MBR authority is important to the maintenance of our current generation business’ revenues.

Capacity Market Issues

December 31, 2012 Form 10-K page 16 and June 30, 2013 Form 10-Q page 82. PJM, the New York Independent System Operator (NYISO), and the Independent System Operator-New England (ISO-NE) each have capacity markets that have been approved by the FERC. The FERC regulates these markets and recently held a technical conference to examine whether the market design for these three capacity markets is working optimally. One of the specific issues being considered by the FERC is whether capacity market rules are properly responding to, and fostering the development of, state public policies, demand response and emerging technologies.

Capacity Market Issues—NYISO

December 31, 2012 Form 10-K page 16. The NYISO capacity model currently recognizes only two separate zones that potentially may separate in price: New York City and Long Island. On August 13, 2013, the FERC issued an order approving NYISO’s April 30, 2013 filing establishing the boundaries of a third capacity zone that will encompass the super zone that includes the lower Hudson Valley and New York City to take effect May 1, 2014. The NYISO is also currently considering what type of generation unit should be used as the reference unit for the purposes of establishing the Cost of New Entry in the “rest of State” zone (excluding the lower Hudson Valley, New York City and Long Island). This issue is significant since it will set the demand curve on which future capacity prices paid to generators will be based.

Capacity Market Issues—Long-Term Capacity Agreement Pilot Program Act (LCAPP)

December 31, 2012 Form 10-K page 16, March 31, 2013 Form 10-Q page 70 and June 30, 2013 Form 10-Q page 82. In 2011, the State of New Jersey concluded that new natural gas-fired generation was needed and enacted the LCAPP Act to subsidize approximately 2,000 MW of new generation. The LCAPP Act provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey Electric Distribution Companies (EDCs). The SOCA required each New Jersey EDC to provide the generators with guaranteed capacity payments funded by ratepayers. Each of the New Jersey EDCs, including PSE&G, entered into the SOCAs as directed by the State, but did so under protest reserving their rights. In July 2013, the SOCA contract with New Jersey Power Development LLC, a subsidiary of NRG Energy, Inc., was terminated early as a result of a default by the generator.

We have taken several steps to challenge these subsidies, including joining several other parties in challenging the LCAPP Act

on constitutional grounds in federal court. On October 11, 2013, the U.S. District Court found that the LCAPP Act violated

the Supremacy Clause of the U.S. Constitution and declared the LCAPP Act null and void. On October 25, 2013, a final judgment was issued implementing the federal court's decision and also finding the SOCA contracts void, invalid and unenforceable and denying the request of the defendants to stay the decision pending appeal. The defendants may appeal the decision and may seek a stay from the U.S. Third Circuit Court of Appeals. We also filed a challenge to the BPU's implementation of the LCAPP Act in the New Jersey State Appellate Court. This appeal was dismissed without prejudice on October 23, 2013 on the basis that the U.S. District Court found the LCAPP Act to be preempted by the Federal Power Act and in violation of the Supremacy Clause of the U.S. Constitution, and therefore null and void. In the event that the U.S. District Court decision is overturned on appeal, the New Jersey State Appellate Court action could be reopened.

Maryland also took action to subsidize above-market new generation. On April 16, 2013, the Maryland Public Service Commission (PSC) issued an order directing the Maryland utility companies to execute a contract with CPV Shore, LLC (CPV) to build a new 661 MW natural gas-fired, combined cycle station in Maryland. We joined other parties in challenging Maryland's actions on constitutional grounds in federal court in Maryland. On September 30, 2013, the U.S. District Court in Maryland ruled on our complaint and found that Maryland's actions violated the Supremacy Clause of the U.S. Constitution. This federal court decision invalidates the Maryland action, including the contract subsidizing CPV. On October 25, 2013, a final judgment in this proceeding was issued. This decision may be appealed.

These efforts by various states to artificially depress prices in the wholesale capacity markets were intended to be mitigated by the Minimum Offer Price Rule (MOPR) approved by the FERC. The MOPR was intended to restrict new generation from bidding in RPM at less than a minimum level established by PJM's Tariff, or a cost-based bid to the extent that the generator can demonstrate that its costs are lower than the MOPR. However, we do not believe these rules have worked as intended and have not protected the market against price suppression efforts. At the direction of the FERC, PJM is currently conducting a stakeholder proceeding, the purpose of which is to develop an enhanced process applicable to subsidized generation seeking to bid into RPM at less than MOPR. The outcome of this stakeholder process and eventual FERC review is uncertain at this time.

Transmission Regulations—Transmission Policy Developments

December 31, 2012 Form 10-K page 17, March 31, 2013 Form 10-Q page 71 and June 30, 2013 Form 10-Q page 83. The FERC has concluded in Order No. 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 have challenged the FERC's elimination of the ROFR in federal court, which challenge remains pending. PJM is currently implementing new rules under which the construction of certain types of transmission projects is no longer subject to a ROFR for incumbents. The FERC has also approved the “state agreement approach” to cost allocation under which transmission projects being built to address public policy concerns may be placed into PJM's planning process if the state sponsoring the project agrees to pay the costs of the project. To date, no such projects have been placed into the planning process but this mechanism could potentially facilitate transmission projects that are not needed for reliability or market efficiency under PJM standards for transmission, including potential offshore wind projects proposed by third parties, should a state or states agree to fund the costs of such projects.

Transmission Regulations—Transmission Expansion

December 31, 2012 Form 10-K page 17 and March 31, 2013 Form 10-Q page 71. In February 2013, the federal court denied certain environmental groups’ action to seek an injunction to halt construction of the Susquehanna-Roseland transmission line by us and PPL Corporation and set aside the National Park Service’s (NPS) final Environmental Impact Statement (EIS) for the line, allowing its construction in certain federal park lands subject to the NPS' jurisdiction that follows the existing right of way. On August 19, 2013, the environmental groups filed a renewed preliminary injunction motion. On August 30, 2013, the court ruled in favor of NPS, PPL Corporation and us and denied the environmental groups’ renewed summary judgment and preliminary injunction motions. Construction activities in the park are ongoing.

Transmission Regulations—Transmission Rate Proceedings

December 31, 2012 Form 10-K page 18, March 31, 2013 Form 10-Q page 71 and June 30, 2013 Form 10-Q page 83. In September 2011, a complaint was filed by several state utility commissions and consumer advocates against transmission owners in New England challenging their base return on equity (ROE). In August 2013, a FERC Administrative Law Judge (ALJ) issued a decision finding the utilities' base ROE to no longer be just and reasonable. In February 2013, several state utility commissions and consumer advocates, including the BPU and the New Jersey Division of Rate Counsel, also filed a complaint at the FERC challenging the base ROE and formula transmission rate implementation protocols of transmission owners in Maryland, Pennsylvania, Delaware and New Jersey. This complaint remains pending. While the August 2013 decision is subject to review by the FERC, and the February 2013 complaint is pending, the results of these proceedings could set a precedent for the FERC-regulated transmission owners with formula rates in place, such as ours.

The FERC has issued an order setting for hearing and settlement procedures certain rate challenges raised by a municipal electric cooperative against a transmission owner in PJM. Specifically, the electric cooperative challenged the prudency of categories of costs included by the transmission owner in its formula rate. The FERC found that the challenges raised issues of fact that warranted examination at hearing. While we are not the subject of the challenge, the result of this proceeding could set a precedent for other transmission owners with formula rates in place, including PSE&G.

STATE REGULATION

Rates

Weather Normalization Clause

December 31, 2012 Form 10-K page 20. In September 2013, the BPU approved recovery of $26 million in deficiency revenues, including $24 million of the carryover deficiency from the 2012-2013 Winter Period which we will recover from customers during the 2013-2014 Winter Period (October 1- May 31).

Energy Strong Program

December 31, 2012 Form 10-K page 20, March 31, 2013 Form 10-Q page 71 and June 30, 2013 Form 10-Q page 84. In February 2013, we filed a petition with the BPU seeking approval of certain investments we recommend making to our BPU jurisdictional electric and gas system to harden and improve resiliency for the future through a clause recovery mechanism. We have continued to respond to data requests from the BPU, the New Jersey Division of Rate Counsel and intervenors. All required public hearings were completed in October 2013, and the review of PSE&G’s proposal is ongoing at the BPU. We cannot predict the outcome of this matter.

Energy Supply

BGSS

December 31, 2012 Form 10-K page 21 and June 30, 2013 Form 10-Q page 84. In September 2012, the BPU approved the Stipulation which lowered our BGSS rate effective October 1, 2012 on a provisional basis. In May 2013, the BPU approved a Stipulation that made the current BGSS rate final. Additionally, in May 2013 we made our annual BGSS filing with the BPU requesting no change to the current rate for the next BGSS period effective October 1, 2013 through September 30, 2014. In September 2013, the BPU approved our request to retain the current rate for the next BGSS period effective October 1, 2013 through September 30, 2014.

On October 23, 2013, we filed a self-implementing two-month BGSS bill credit with the BPU. This bill credit will be 35 cents per therm for the months of November and December 2013 and is designed to provide approximately $115 million to residential customers over the two months. The BGSS rate will revert back to the current rate on January 1, 2014.

ENVIRONMENTAL MATTERS

Air Pollution Control

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

March 31, 2013 Form 10-Q page 72 and June 30, 2013 Form 10-Q page 85. On March 29 and April 1, 2013, we filed petitions at the EPA and in federal court, respectively, challenging the National Emission Standards for Hazardous Air Pollutants (NESHAP) for RICE issued on January 30, 2013. Among other things, the final EPA rule allows owners and operators of stationary emergency RICE to operate their engines as part of an emergency DR program without the installation and operation of emission controls or compliance with emission limits otherwise applicable to non-emergency counterparts. This waiver of NESHAP standards results in disparate treatment of different generation technology types. In our appeal, we are seeking more stringent emission control standards for RICE to support more competitive markets, particularly the PJM capacity market. On September 6, 2013, the EPA published its intent to reconsider certain items included in the final rule that are also subject to the appeal, with a 60 day comment period.

Climate Change

CO₂ Regulation Under the Clean Air Act (CAA)

December 31, 2012 Form 10-K page 24 and June 30, 2013 Form 10-Q page 85. In April 2013, several industrial groups petitioned the Supreme Court to review various EPA rules issued under the CAA, including the Tailoring Rule, to regulate greenhouse gas (GHG) emissions, including CO_2.The Tailoring Rule requires a new source or an existing source which undergoes a major modification, to evaluate and perhaps install best available control technology (BACT) for GHG emissions.

On October 15, 2013, the Supreme Court agreed to add the case to the docket for its current term to consider whether the EPA has authority to regulate CO₂ emissions of stationary sources, including power plants.

In April 2012, the EPA published the proposed New Source Performance Standards (NSPS) for GHG for new power plants only. On June 25, 2013, the President directed the EPA to propose revised NSPS for new power plants by September 20, 2013, propose GHG regulations for existing power plants by June 1, 2014, finalize such regulations by June 1, 2015 and require states to submit GHG implementation regulations by June 30, 2016.

On September 20, 2013, the EPA proposed revised NSPS for new power plants. The revised NSPS differs from those initially proposed in April 2012 in that standards would vary for different types of new power plants as opposed to the application of a single standard for all new power plants. The EPA is also requesting comment on use of an electric output sales threshold to determine applicability to the NSPS. This electric output sales threshold would eliminate the outright exclusion of simple cycle combustion turbines. Comments on the rule must be submitted within 60 days after publication.

Water Pollution Control

Cooling Water Intake Structure Regulation

December 31, 2012 Form 10-K page 25 and June 30, 2013 Form 10-Q page 85. In April 2011, the EPA published a proposed rule to establish marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. In July 2012, the EPA and environmental groups agreed to delay the deadline to June 27, 2013 for finalization of the Rule. On June 27, 2013, the EPA and environmental groups agreed to further extend the deadline to November 4, 2013.

If the rule were to be adopted as proposed, the impact on us would be material since the majority of our electric generating stations would be affected. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material. See Note 9. Commitments and Contingent Liabilities for additional information.

On October 1, 2013, the Delaware Riverkeeper Network and several other environmental groups filed a lawsuit in the Superior Court of New Jersey seeking to force the New Jersey Department of Environmental Protection to take action on our pending application for permit renewal at Salem either by denying the application or issuing a draft for public comment. The permit is currently pending the EPA’s finalization of the Clean Water Act Section 316(b) regulations. We were not named in the lawsuit nor do we know how this legal action will proceed but it could have a material impact on us.


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

b. Power:
Exhibit 12.1:		Computation of Ratios of Earnings to Fixed Charges
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

c. PSE&G:
Exhibit 12.2:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.3:		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
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

SIGNATURE

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



PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:	/S/ DEREK M. DIRISIO
	Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: October 30, 2013

SIGNATURE



PSEG POWER LLC
(Registrant)

By:	/S/ DEREK M. DIRISIO
	Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: October 30, 2013

SIGNATURE



PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:	/S/ DEREK M. DIRISIO
	Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: October 30, 2013