10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED September 30, 2011

OR

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

SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM          TO         

Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	22-2625848
	(A New Jersey Corporation)
	80 Park Plaza, P.O. Box 1171
	Newark, New Jersey 07101-1171
	973 430-7000
	http://www.pseg.com
001-34232	PSEG POWER LLC	22-3663480
	(A Delaware Limited Liability Company)
	80 Park Plaza—T25
	Newark, New Jersey 07102-4194
	973 430-7000
	http://www.pseg.com
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY	22-1212800
	(A New Jersey Corporation)
	80 Park Plaza, P.O. Box 570
	Newark, New Jersey 07101-0570
	973 430-7000
	http://www.pseg.com

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 x 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).

Public Service Enterprise Group Incorporated	Yes x	No ¨
PSEG Power LLC	Yes x	No ¨
Public Service Electric and Gas Company	Yes x	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 ¨	Non-accelerated filer ¨	Smaller reporting company ¨
PSEG Power LLC	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨
Public Service Electric and Gas Company	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨

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 x

As of October 14, 2011, Public Service Enterprise Group Incorporated had outstanding 505,904,850 shares of its sole class of Common Stock, without par value.

As of October 14, 2011, 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		5
	Public Service Electric and Gas Company		8
	Notes to Condensed Consolidated Financial Statements		12
	Note 1. Organization and Basis of Presentation		12
	Note 2. Recent Accounting Standards		13
	Note 3. Variable Interest Entities (VIEs)		14
	Note 4. Discontinued Operations and Dispositions		14
	Note 5. Financing Receivables		15
	Note 6. Available-for-Sale Securities		18
	Note 7. Pension and Other Postretirement Benefits (OPEB)		22
	Note 8. Commitments and Contingent Liabilities		23
	Note 9. Changes in Capitalization		34
	Note 10. Financial Risk Management Activities		34
	Note 11. Fair Value Measurements		41
	Note 12. Other Income and Deductions		48
	Note 13. Income Taxes		49
	Note 14. Comprehensive Income, Net of Tax		50
	Note 15. Earnings Per Share (EPS)		52
	Note 16. Financial Information by Business Segments		53
	Note 17. Related-Party Transactions		54
	Note 18. Guarantees of Debt		56
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		59
	Overview of 2011 and Future Outlook		59
	Results of Operations		66
	Liquidity and Capital Resources		74
	Capital Requirements		77
	Accounting Matters		77
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		78
Item 4.	Controls and Procedures		79
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		80
Item 1A.	Risk Factors		81
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		81
Item 5.	Other Information		81
Item 6.	Exhibits		89
	Signatures		91

i

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report 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 “will,” “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 Item 1. Financial Statements—Note 8. Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to:

• 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 trading 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,

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

• 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,

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

• increase in competition in energy markets in which we compete,

• 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 discount rates and funding requirements, and

• changes in technology and customer usage patterns.

Additional information concerning these factors is set forth in Part II under Item 1A. Risk Factors.

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 only apply 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.

ii

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)

	For The Three Months Ended September 30,						For The Nine Months Ended September 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	2,620		$	3,114		$	8,443		$	9,048
OPERATING EXPENSES
Energy Costs		1,167			1,261			3,740			4,021
Operation and Maintenance		603			591			1,829			1,862
Depreciation and Amortization		263			260			739			716
Taxes Other Than Income Taxes		31			31			102			101
Total Operating Expenses		2,064			2,143			6,410			6,700
OPERATING INCOME		556			971			2,033			2,348
Income from Equity Method Investments		1			4			8			12
Other Income		45			75			176			165
Other Deductions		(11	)		(9	)		(39	)		(37	)
Other-Than-Temporary Impairments		(8	)		(3	)		(13	)		(9	)
Interest Expense		(117	)		(120	)		(361	)		(356	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		466			918			1,804			2,123
Income Tax (Expense) Benefit		(201	)		(371	)		(757	)		(856	)
INCOME FROM CONTINUING OPERATIONS		265			547			1,047			1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(11) for the three months and $(51) and $(10) for the nine months ended 2011 and 2010, respectively		29			20			96			15
NET INCOME	$	294		$	567		$	1,143		$	1,282
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC		505,909			505,945			505,959			506,001
DILUTED		506,999			506,968			506,963			507,068
EARNINGS PER SHARE
BASIC
INCOME FROM CONTINUING OPERATIONS	$	0.52		$	1.08		$	2.07		$	2.50
NET INCOME	$	0.58		$	1.12		$	2.26		$	2.53
DILUTED
INCOME FROM CONTINUING OPERATIONS	$	0.52		$	1.08		$	2.06		$	2.50
NET INCOME	$	0.58		$	1.12		$	2.25		$	2.53
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.3425		$	0.3425		$	1.0275		$	1.0275

See Notes to Condensed Consolidated Financial Statements.

1

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	September 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	1,242		$	280
Accounts Receivable, net of allowances of $64 and $68 in 2011 and 2010, respectively		1,164			1,387
Tax Receivable		377			689
Unbilled Revenues		251			400
Fuel		740			666
Materials and Supplies, net		365			359
Prepayments		416			204
Derivative Contracts		113			182
Assets of Discontinued Operations		0			564
Deferred Income Taxes		96			43
Regulatory Assets		86			155
Other		120			122
Total Current Assets		4,970			5,051
PROPERTY, PLANT AND EQUIPMENT		24,618			23,272
Less: Accumulated Depreciation and Amortization		(7,336	)		(6,882	)
Net Property, Plant and Equipment		17,282			16,390
NONCURRENT ASSETS
Regulatory Assets		3,354			3,736
Regulatory Assets of Variable Interest Entities (VIEs)		968			1,128
Long-Term Investments		1,406			1,623
Nuclear Decommissioning Trust (NDT) Funds		1,280			1,363
Other Special Funds		170			160
Goodwill		16			16
Other Intangibles		164			136
Derivative Contracts		75			79
Restricted Cash of VIEs		22			21
Other		204			206
Total Noncurrent Assets		7,659			8,468
TOTAL ASSETS	$	29,911		$	29,909

See Notes to Condensed Consolidated Financial Statements.

2

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	September 30,			December 31,
	2011			2010
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	1,275		$	915
Securitization Debt of VIEs Due Within One Year		214			206
Commercial Paper and Loans		0			64
Accounts Payable		1,144			1,176
Derivative Contracts		94			103
Accrued Interest		131			108
Accrued Taxes		30			49
Clean Energy Program		224			195
Obligation to Return Cash Collateral		107			104
Regulatory Liabilities		161			174
Liabilities of Discontinued Operations		0			72
Other		312			319
Total Current Liabilities		3,692			3,485
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		5,652			5,129
Regulatory Liabilities		235			285
Regulatory Liabilities of VIEs		9			8
Asset Retirement Obligations		482			461
Other Postretirement Benefit (OPEB) Costs		948			967
Accrued Pension Costs		189			788
Clean Energy Program		70			235
Environmental Costs		651			669
Derivative Contracts		31			22
Long-Term Accrued Taxes		234			248
Other		77			152
Total Noncurrent Liabilities		8,578			8,964
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		6,651			6,834
Securitization Debt of VIEs		784			939
Project Level, Non-Recourse Debt		45			46
Total Long-Term Debt		7,480			7,819
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2011 and 2010—533,556,660 shares		4,818			4,807
Treasury Stock, at cost, 2011—27,651,927 shares; 2010—27,582,437 shares		(601	)		(593	)
Retained Earnings		6,198			5,575
Accumulated Other Comprehensive Loss		(256	)		(156	)
Total Common Stockholders’ Equity		10,159			9,633
Noncontrolling Interest		2			8
Total Stockholders’ Equity		10,161			9,641
Total Capitalization		17,641			17,460
TOTAL LIABILITIES AND CAPITALIZATION	$	29,911		$	29,909

See Notes to Condensed Consolidated Financial Statements.

3

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

	For the Nine Months Ended September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,143		$	1,282
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations		(122	)		0
Depreciation and Amortization		745			730
Amortization of Nuclear Fuel		114			102
Provision for Deferred Income Taxes (Other than Leases) and ITC		629			205
Non-Cash Employee Benefit Plan Costs		138			236
Net (Gain) Loss on Lease Investments		0			(51	)
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes		(16	)		(391	)
Leveraged Lease Reserve, net of tax		170			0
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(14	)		(42	)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		100			35
Over (Under) Recovery of Societal Benefits Charge (SBC)		(26	)		(55	)
Market Transition Charge Refund		(47	)		98
Cost of Removal		(43	)		(47	)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(110	)		(73	)
Realized Gains from Rabbi Trusts		(5	)		(31	)
Net Change in Tax Receivable		312			0
Net Change in Certain Current Assets and Liabilities		(44	)		(237	)
Employee Benefit Plan Funding and Related Payments		(486	)		(483	)
Other		(29	)		61
Net Cash Provided By (Used In) Operating Activities		2,409			1,339
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(1,479	)		(1,517	)
Proceeds from Sale of Discontinued Operations		687			0
Proceeds from the Sale of Capital Leases and Investments		0			427
Proceeds from Sales of Available-for-Sale Securities		1,088			886
Investments in Available-for-Sale Securities		(1,110	)		(905	)
Other		(13	)		13
Net Cash Provided By (Used In) Investing Activities		(827	)		(1,096	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans		(64	)		(530	)
Issuance of Long-Term Debt		750			1,608
Redemption of Long-Term Debt		(606	)		(548	)
Repayment of Non-Recourse Debt		(1	)		(3	)
Redemption of Securitization Debt		(147	)		(140	)
Cash Dividends Paid on Common Stock		(520	)		(520	)
Redemption of Preferred Securities		0			(80	)
Other		(32	)		(48	)
Net Cash Provided By (Used In) Financing Activities		(620	)		(261	)
Net Increase (Decrease) in Cash and Cash Equivalents		962			(18	)
Cash and Cash Equivalents at Beginning of Period		280			350
Cash and Cash Equivalents at End of Period	$	1,242		$	332
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	60		$	1,080
Interest Paid, Net of Amounts Capitalized	$	341		$	299

See Notes to Condensed Consolidated Financial Statements.

4

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)

	For The Three Months Ended September 30,						For The Nine Months Ended September 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	1,398		$	1,523		$	4,650		$	4,983
OPERATING EXPENSES
Energy Costs		597			620			2,335			2,483
Operation and Maintenance		262			253			810			764
Depreciation and Amortization		56			43			166			130
Total Operating Expenses		915			916			3,311			3,377
OPERATING INCOME		483			607			1,339			1,606
Other Income		37			44			156			126
Other Deductions		(10	)		(9	)		(37	)		(36	)
Other-Than-Temporary Impairments		(8	)		(2	)		(10	)		(8	)
Interest Expense		(42	)		(37	)		(134	)		(119	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		460			603			1,314			1,569
Income Tax (Expense) Benefit		(187	)		(239	)		(539	)		(632	)
INCOME FROM CONTINUING OPERATIONS		273			364			775			937
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(11) for the three months and $(51) and $(10) for the nine months ended 2011 and 2010, respectively		29			20			96			15
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	302		$	384		$	871		$	952

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

5

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	September 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	14		$	11
Accounts Receivable		432			511
Accounts Receivable—Affiliated Companies, net		127			782
Short-Term Loan to Affiliate		1,574			398
Fuel		740			666
Materials and Supplies, net		273			269
Derivative Contracts		95			163
Prepayments		42			80
Assets of Discontinued Operations		0			564
Total Current Assets		3,297			3,444
PROPERTY, PLANT AND EQUIPMENT		9,118			8,643
Less: Accumulated Depreciation and Amortization		(2,552	)		(2,301	)
Net Property, Plant and Equipment		6,566			6,342
NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds		1,280			1,363
Goodwill		16			16
Other Intangibles		164			130
Other Special Funds		33			32
Derivative Contracts		24			42
Long-Term Accrued Taxes		19			16
Other		85			67
Total Noncurrent Assets		1,621			1,666
TOTAL ASSETS	$	11,484		$	11,452
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	710		$	650
Accounts Payable		635			643
Derivative Contracts		79			91
Deferred Income Taxes		8			64
Accrued Interest		63			40
Liabilities of Discontinued Operations		0			72
Other		111			91
Total Current Liabilities		1,606			1,651
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		1,211			1,146
Asset Retirement Obligations		255			242
Other Postretirement Benefit (OPEB) Costs		158			151
Derivative Contracts		17			22
Accrued Pension Costs		75			253
Environmental Costs		51			51
Other		34			104
Total Noncurrent Liabilities		1,801			1,969
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT
Total Long-Term Debt		2,640			2,805
MEMBER’S EQUITY
Contributed Capital		2,028			2,028
Basis Adjustment		(986	)		(986	)
Retained Earnings		4,602			4,080
Accumulated Other Comprehensive Loss		(207	)		(95	)
Total Member’s Equity		5,437			5,027
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,484		$	11,452

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

6

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

	For the Nine Months Ended
	September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	871		$	952
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations		(122	)		0
Depreciation and Amortization		173			144
Amortization of Nuclear Fuel		114			102
Provision for Deferred Income Taxes and ITC		74			145
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(14	)		(42	)
Non-Cash Employee Benefit Plan Costs		33			53
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(110	)		(73	)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies		(82	)		(2	)
Margin Deposit		(63	)		(26	)
Accounts Receivable		157			16
Accounts Payable		(103	)		(99	)
Accounts Receivable/Payable-Affiliated Companies, net		650			186
Accrued Interest Payable		23			41
Other Current Assets and Liabilities		48			(42	)
Employee Benefit Plan Funding and Related Payments		(127	)		(131	)
Other		(35	)		32
Net Cash Provided By (Used In) Operating Activities		1,487			1,256
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(530	)		(579	)
Proceeds from Sale of Discontinued Operations		687			0
Proceeds from Sales of Available-for-Sale Securities		1,088			759
Investments in Available-for-Sale Securities		(1,106	)		(778	)
Short-Term Loan—Affiliated Company, net		(1,176	)		(309	)
Other		19			28
Net Cash Provided By (Used In) Investing Activities		(1,018	)		(879	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt		500			594
Cash Dividend Paid		(350	)		(550	)
Redemption of Long-Term Debt		(606	)		(248	)
Short-Term Loan—Affiliated Company, net		0			(194	)
Other		(10	)		(17	)
Net Cash Provided By (Used In) Financing Activities		(466	)		(415	)
Net Increase (Decrease) in Cash and Cash Equivalents		3			(38	)
Cash and Cash Equivalents at Beginning of Period		11			64
Cash and Cash Equivalents at End of Period	$	14		$	26
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	110		$	558
Interest Paid, Net of Amounts Capitalized	$	111		$	85

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

7

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)

	For the Three Months Ended September 30,						For The Nine Months Ended September 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	1,841		$	2,007		$	5,718		$	5,987
OPERATING EXPENSES
Energy Costs		943			1,115			3,124			3,572
Operation and Maintenance		342			327			1,014			1,084
Depreciation and Amortization		197			209			548			563
Taxes Other Than Income Taxes		31			31			102			101
Total Operating Expenses		1,513			1,682			4,788			5,320
OPERATING INCOME		328			325			930			667
Other Income		7			14			16			22
Other Deductions		(1	)		(1	)		(2	)		(2	)
Other-Than-Temporary Impairments		0			0			(1	)		0
Interest Expense		(77	)		(82	)		(234	)		(239	)
INCOME BEFORE INCOME TAXES		257			256			709			448
Income Tax (Expense) Benefit		(103	)		(101	)		(287	)		(172	)
NET INCOME		154			155			422			276
Preferred Stock Dividends		0			0			0			(1	)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	154		$	155		$	422		$	275

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

8

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	September 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	242		$	245
Accounts Receivable, net of allowances of $64 in 2011 and $67 in 2010, respectively		720			832
Tax Receivable		21			0
Accounts Receivable—Affiliated Companies, net		304			0
Unbilled Revenues		251			400
Materials and Supplies		91			90
Prepayments		320			117
Regulatory Assets		86			155
Other		35			19
Total Current Assets		2,070			1,858
PROPERTY, PLANT AND EQUIPMENT		14,917			14,068
Less: Accumulated Depreciation and Amortization		(4,500	)		(4,326	)
Net Property, Plant and Equipment		10,417			9,742
NONCURRENT ASSETS
Regulatory Assets		3,354			3,736
Regulatory Assets of VIEs		968			1,128
Long-Term Investments		258			230
Other Special Funds		57			54
Derivative Contracts		0			17
Restricted Cash of VIEs		22			21
Other		89			87
Total Noncurrent Assets		4,748			5,273
TOTAL ASSETS	$	17,235		$	16,873

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

9

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

	September 30,		December 31,
	2011		2010
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	564	$	264
Securitization Debt of VIEs Due Within One Year		214		206
Accounts Payable		396		406
Accounts Payable—Affiliated Companies, net		0		85
Accrued Interest		66		65
Clean Energy Program		224		195
Derivative Contracts		15		12
Deferred Income Taxes		21		19
Obligation to Return Cash Collateral		107		104
Regulatory Liabilities		161		174
Other		190		229
Total Current Liabilities		1,958		1,759
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC		3,690		3,127
Other Postretirement Benefit (OPEB) Costs		743		770
Accrued Pension Costs		18		377
Regulatory Liabilities		235		285
Regulatory Liabilities of VIEs		9		8
Clean Energy Program		70		235
Environmental Costs		600		617
Asset Retirement Obligations		223		216
Derivative Contracts		11		0
Long-Term Accrued Taxes		54		74
Other		21		23
Total Noncurrent Liabilities		5,674		5,732
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		3,971		4,019
Securitization Debt of VIEs		784		939
Total Long-Term Debt		4,755		4,958
STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2011 and 2010—132,450,344 shares		892		892
Contributed Capital		420		420
Basis Adjustment		986		986
Retained Earnings		2,548		2,126
Accumulated Other Comprehensive Income		2		0
Total Stockholder’s Equity		4,848		4,424
Total Capitalization		9,603		9,382
TOTAL LIABILITIES AND CAPITALIZATION	$	17,235	$	16,873

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

10

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

	For The Nine Months Ended September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	422		$	276
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		548			563
Provision for Deferred Income Taxes and ITC		563			41
Non-Cash Employee Benefit Plan Costs		92			162
Cost of Removal		(43	)		(47	)
Market Transition Charge (MTC) Refund		(47	)		98
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		100			35
Over (Under) Recovery of SBC		(26	)		(55	)
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		261			117
Materials and Supplies		(1	)		(17	)
Prepayments		(203	)		(126	)
Net Change in Tax Receivable		(21	)		0
Accounts Receivable/Payable-Affiliated Companies, net		(381	)		(318	)
Other Current Assets and Liabilities		(66	)		19
Employee Benefit Plan Funding and Related Payments		(311	)		(305	)
Other		(15	)		(16	)
Net Cash Provided By (Used In) Operating Activities		872			427
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(939	)		(871	)
Proceeds from Sales of Available-for-Sale Securities		0			54
Investments in Available-for-Sale Securities		0			(54	)
Solar Loan Investments		(34	)		(11	)
Other		(1	)		(4	)
Net Cash Provided By (Used In) Investing Activities		(974	)		(886	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt		250			1,014
Redemption of Long-Term Debt		0			(300	)
Redemption of Securitization Debt		(147	)		(140	)
Redemption of Preferred Securities		0			(80	)
Common Stock Dividend		0			(150	)
Other		(4	)		(10	)
Net Cash Provided By (Used In) Financing Activities		99			334
Net Increase (Decrease) In Cash and Cash Equivalents		(3	)		(125	)
Cash and Cash Equivalents at Beginning of Period		245			240
Cash and Cash Equivalents at End of Period	$	242		$	115
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(44	)	$	182
Interest Paid, Net of Amounts Capitalized	$	225		$	213

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

11

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, energy trading and marketing and risk management 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 an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC. PSE&G is also investing in the development of solar generation projects and energy efficiency programs, which are regulated by the BPU.

• PSEG Energy Holdings L.L.C. (Energy Holdings)—which has invested in leveraged leases and owns and operates primarily domestic projects engaged in the generation of energy through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings has also invested in solar generation projects and is exploring opportunities for other investments in renewable generation.

• PSEG Services Corporation (Services)—which provides management and 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, 2010 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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. 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, 2010.

During 2011, Power sold its two generating facilities located in Texas that were owned and operated by its subsidiary, PSEG Texas. As a result, amounts related to these plants were reclassified as Discontinued Operations in the financial statements. See Note 4. Discontinued Operations and Dispositions for additional information.

12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 2. Recent Accounting Standards

New Standard Adopted during 2011

Revenue Arrangements with Multiple Deliverables

• amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist,

• establishes a selling price hierarchy, such as, “vendor-specific objective evidence,” “third-party evidence” and “estimated selling price” for determining the selling price of a deliverable, and

• provides guidance for allocating and recognizing revenue based on separate deliverables.

We adopted this standard, prospectively, effective January 1, 2011, for new and significantly modified revenue arrangements. Upon adoption, there was no material impact on our financial statements and we do not anticipate any changes to the pattern or general timing of revenue recognition for our significant units of account in future periods.

New Accounting Standards Issued But Not Yet Adopted

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)

This accounting standard was issued to update guidance related to fair value measurements and disclosures as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• clarifies intent about application of existing fair value measurements and disclosures,

• changes some requirements for fair value measurements, and

• requires expanded disclosures.

This guidance is effective for interim and annual periods beginning after December 15, 2011. We believe our adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows; however, it will result in expanded disclosures.

Presentation of Comprehensive Income

This accounting standard was issued on the presentation of comprehensive income as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and

• eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.

This guidance is effective for fiscal years and interim periods beginning after December 15, 2011. We believe that the adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows, but will change the presentation of the components of other comprehensive income.

Testing Goodwill for Impairment

This accounting standard was issued to simplify testing for goodwill impairment. The updated guidance allows an entity to first perform a qualitative assessment to determine if it is more likely than not that the fair value of the reporting unit is less than its carrying value. Only if it is concluded that this is the case is it necessary to perform the two-step goodwill impairment test.

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Earlier adoption is permitted. We believe that if we adopt the new optional guidance, it will not have a material impact on our consolidated financial position, results of operations or cash flows.

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, 2011 and December 31, 2010. 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 2011 or in 2010. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.

Note 4. Discontinued Operations and Dispositions

Discontinued Operations

Power

In March 2011, Power completed the sale of its 1,000 MW gas-fired Guadalupe generating facility for a total purchase price of $352 million, resulting in an after-tax gain of $54 million.

In July 2011, Power completed the sale of its 1,000 MW gas-fired Odessa generating facility for a total purchase price of $335 million, resulting in an after-tax gain of $25 million. The closing of the Odessa sale completed the Texas asset sale process announced by Power in early 2011.

PSEG Texas’ operating results for the three months and nine months ended September 30, 2011 and 2010, which were reclassified to Discontinued Operations, are summarized below:

	Three Months Ended, September 30,				Nine Months Ended, September 30,
	2011		2010		2011		2010
	Millions
Operating Revenues	$	20	$	140	$	112	$	341
Income (Loss ) Before Income Taxes	$	6	$	31	$	26	$	25
Net Income (Loss)	$	4	$	20	$	17	$	15

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The carrying amounts of PSEG Texas’ assets and liabilities as of December 31, 2010 are summarized in the following table:

	As of December 31,
	2010
	Millions
Current Assets	$	28
Noncurrent Assets		536
Total Assets of Discontinued Operations	$	564
Current Liabilities	$	28
Noncurrent Liabilities		44
Total Liabilities of Discontinued Operations	$	72

Dispositions

Leveraged Leases

During the first nine months of 2010, Energy Holdings sold its interest in five leveraged leases, including four international leases for which the IRS has indicated its intention to disallow certain tax deductions taken in prior years.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2010		2010
	Millions
Proceeds from Sales	$	204	$	365
Gains on Sales, after-tax	$	15	$	27

Proceeds from the sales of the international leases were used to reduce the tax exposure related to these lease investments. For additional information see Note 8. Commitments and Contingent Liabilities.

Note 5. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout our electric service area. The loans are generally paid back with Solar Renewable Energy Certificates (SRECS) generated from the installed solar electric systems. The following table reflects the outstanding short and long-term loans by class of customer, none of which would be considered “non-performing.”

Credit Risk Profile Based on Payment Activity	As of		As of
	September 30,		December 31,
Consumer Loans	2011		2010
	Millions
Commercial/Industrial	$	86	$	62
Residential		7		4
	$	93	$	66

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Energy Holdings

Energy Holdings has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings’ investments in the leases are comprised of the total expected lease receivables on its investments over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Condensed Consolidated Balance Sheets. The table below shows Energy Holdings’ gross and net lease investment as of September 30, 2011 and December 31, 2010, respectively.

	As of September 30,			As of December 31,
	2011			2010
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	763		$	896
Estimated Residual Value of Leased Assets		684			905
		1,447			1,801
Unearned and Deferred Income		(450	)		(546	)
Gross Investments in Leases		997			1,255
Deferred Tax Liabilities		(804	)		(899	)
Net Investment in Leases	$	193		$	356

Note: The above table does not include $264 million of Gross Investment in Leases to subsidiaries of Dynegy Incorporated (Dynegy) as of September 30, 2011 as we have fully reserved our Gross Investment in the Dynegy leases.

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 relate to investments in leases of commercial real estate properties.

	Lease Receivables, net of Non-Recourse Debt
	As of September 30,		As of December 31,
Counterparties’ Credit Rating (S&P)	2011		2010
	Millions
AAA - AA	$	21	$	21
A		110		112
BBB - BB		316		316
B - B-		300		430
Not Rated		16		17
	$	763	$	896

Note: The above table does not include $121 million of lease receivables as of September 30, 2011 related to subsidiaries of Dynegy as we fully reserved our Gross Investments in the Dynegy leases.

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The “B” and “B-” ratings above represent lease receivables underlying coal fired assets in Illinois and Pennsylvania. As of September 30, 2011, the gross investment in the leases of such assets, net of non-recourse debt, was $550 million ($54 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the table below.

Asset	Location		Gross Investment		% Owned		Total		Fuel Type	Counterparties’ S&P Credit Rating	Counterparty
			Millions				MW
Powerton Station Units 5 and 6		IL	$	135		64%		1,538	Coal	B-	Edison Mission Energy
Joliet Station Units 7 and 8		IL	$	84		64%		1,044	Coal	B-	Edison Mission Energy
Keystone Station Units 1 and 2		PA	$	112		17%		1,711	Coal	B	GenOn REMA, LLC
Conemaugh Station Units 1 and 2		PA	$	112		17%		1,711	Coal	B	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 and 4		PA	$	107		100%		603	Coal	B	GenOn REMA, LLC

Although all payments of equity rent, debt service and other fees are current, no assurances can be given that all payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flow 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 and electricity, overall financial condition of lease counterparties and the quality and condition of assets under lease.

The credit exposure to the lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverage ratios are not met and similar cash flow restrictions if ratings are not maintained at stated levels. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased assets. In the event of a default in any of the lease transactions, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. 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.

Energy Holdings’ collateral related to the lease to two affiliates (the Dynegy lessees) of Dynegy Incorporated (Dynegy), includes a guarantee from Dynegy Holdings LLC (DH), a subsidiary of Dynegy. In early August 2011, Dynegy reorganized the legal entity structure for its generation assets. It transferred substantially all of its coal and natural gas-fired generation assets, other than the Dynegy lessees that lease the Roseton Station Units 1 and 2 and Danskammer Station Units 3 and 4, to new subsidiaries which Dynegy termed as “bankruptcy remote”. This resulted in a lowering of certain credit ratings of Dynegy and DH. Dynegy’s credit is currently rated “CC” by S&P and “Caa3” by Moody’s. On July 22, 2011, subsidiaries of Energy Holdings that hold the lessor interests filed a lawsuit in Delaware Chancery Court to halt the proposed transfer of assets to the new subsidiaries alleging that the proposed transfers would violate DH’s obligations under its Roseton and Danskammer guarantees. The request for a temporary restraining order was denied on July 29, 2011 and on August 5, 2011, the Delaware Supreme Court denied Energy Holdings’ application for certification of an interlocutory appeal and motions to expedite and for injunctive relief. Thereafter on August 8, 2011, Energy Holdings voluntarily dismissed this lawsuit without prejudice.

In September 2011, Dynegy continued its corporate reorganization, transferring DH’s interests in its newly formed coal generation subsidiary directly to the parent company, Dynegy, in exchange for an undertaking. It

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

also launched an exchange offer for a substantial portion of DH’s debt in exchange for Dynegy debt at various discounts. Dynegy has indicated that in the absence of a debt restructuring and/or refinancing, it may not have sufficient resources to pay its indebtedness under the lease. The consummation of these transactions triggered the filing of two separate lawsuits, one by a group of corporate unsecured bondholders of DH and a second on behalf of a majority of the holders of certain debt certificates related to the Dynegy lessee facilities; these lawsuits asserted fraudulent conveyance claims among several other causes of action. In addition to claims asserted against DH, one of the suits included claims against several members of DH’s Board of Directors.

As a result of the above actions, Energy Holdings has evaluated its likely recovery under the lease arrangements for the Roseton and Danskammer facilities leased to subsidiaries of DH, considering the overall value of the underlying assets subject to lease, and has fully reserved its $264 million gross investment. This gross charge is reflected as a reduction to Operating Revenues and resulted in an after-tax charge of approximately $170 million. In the absence of a negotiated resolution of the disputes with Dynegy, Energy Holdings intends to assert claims against DH, its directors and various Dynegy affiliates relative to the reorganization activities which have diminished the value of assets available to satisfy DH’s lease guarantee obligations. In addition, Energy Holdings has a tax indemnity agreement, which is designed to protect it from adverse tax consequences should the lease structure not be maintained. Should there be adverse consequences, Energy Holdings intends to assert its claims under this agreement, notwithstanding any attempt by Dynegy in contravention of current case law to limit such claims in a bankruptcy proceeding of DH. In the event of a bankruptcy filing or the failure of DH to honor its obligations under the lease guarantee, it is possible that the lease certificate holders could foreclose on the underlying facilities in partial satisfaction of their indebtedness. Should this occur, Energy Holdings could be required to pay approximately $100 million to satisfy income tax obligations, an amount for which it would seek reimbursement from DH under the tax indemnity agreement. This potential cash tax obligation is fully reflected in the overall estimate of the aggregate after-tax charge.

Note 6. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Funds

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 two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisors who operate under investment guidelines developed by Power.

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

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	537	$	93	$	(55	)	$	575
Debt Securities
Government Obligations		340		16		(1	)		355
Other Debt Securities		273		14		(3	)		284
Total Debt Securities		613		30		(4	)		639
Other Securities		66		0		0			66
Total Available-for-Sale Securities	$	1,216	$	123	$	(59	)	$	1,280

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	525	$	213	$	(3	)	$	735
Debt Securities
Government Obligations		301		6		(4	)		303
Other Debt Securities		247		10		(2	)		255
Total Debt Securities		548		16		(6	)		558
Other Securities		70		0		0			70
Total Available-for-Sale Securities	$	1,143	$	229	$	(9	)	$	1,363

These amounts 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 September 30,		As of December 31,
	2011		2010
	Millions
Accounts Receivable	$	100	$	35
Accounts Payable	$	95	$	60

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

	As of September 30, 2011										As of December 31, 2010
	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)	$	252	$	(55	)	$	0	$	0		$	55	$	(3	)	$	0	$	0
Debt Securities
Government Obligations (B)		72		(1	)		2		0			106		(4	)		1		0
Other Debt Securities (C)		65		(2	)		6		(1	)		65		(1	)		8		(1	)
Total Debt Securities		137		(3	)		8		(1	)		171		(5	)		9		(1	)
Other Securities		1		0			0		0			0		0			0		0
Total Available-for-Sale Securities	$	390	$	(58	)	$	8	$	(1	)	$	226	$	(8	)	$	9	$	(1	)

(A) Equity Securities—Investments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(B) Debt Securities (Government)—Unrealized losses on Power’s NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(C) Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2011.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	Millions						Millions
Proceeds from Sales	$	431		$	302		$	1,088		$	728
Net Realized Gains (Losses)
Gross Realized Gains	$	26		$	26		$	121		$	86
Gross Realized Losses		(10	)		(8	)		(28	)		(31	)
Net Realized Gains	$	16		$	18		$	93		$	55

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $32 million (after-tax) were recognized in Accumulated Other Comprehensive Income (OCI) on Power’s Condensed Consolidated Balance Sheet as of September 30, 2011. The available-for-sale debt securities held as of September 30, 2011 had the following maturities:

Time Frame	Fair Value
	Millions
Less than 1 Year	$	11
1 - 5 Years		141
6 - 10 Years		172
11 - 15 Years		43
16 - 20 Years		18
Over 20 Years		254
	$	639

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 OCI. In

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2011, other-than-temporary impairments of $10 million were recognized on securities in the NDT funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is 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 detail of the securities.

Rabbi Trusts

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 grantor trusts commonly known as “Rabbi Trusts.” In August 2010, PSEG revised the asset structure of the Rabbi Trust and realized gains of $31 million as the investments were transitioned to a new asset allocation and investment manager. The new structure resulted in lower investment management fees.

PSEG classifies investments in the Rabbi Trusts 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 Trusts.

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		147		5		0		152
Total PSEG Available-for-Sale Securities	$	163	$	7	$	0	$	170

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		142		0		0		142
Total PSEG Available-for-Sale Securities	$	158	$	2	$	0	$	160

The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, 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 the nine months ended September 30, 2011, other-than-temporary impairments of $3 million were recognized on the bond portfolio of the Rabbi Trusts.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	Millions				Millions
Proceeds from Sales	$	0	$	158	$	0	$	158
Net Realized Gains (Losses)
Gross Realized Gains	$	0	$	31	$	0	$	31
Gross Realized Losses		0		0		0		0
Net Realized Gains (Losses)	$	0	$	31	$	0	$	31

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

21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

	As of September 30, 2011		As of December 31, 2010
	Millions
Power	$	33	$	32
PSE&G		57		54
Other		80		74
Total PSEG Available-for-Sale Securities	$	170	$	160

Note 7. Pension and 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. In early June 2011, PSEG amended certain provisions of its pension and OPEB plans, including revisions to the benefit formulas for certain participants of PSEG’s qualified and nonqualified pension and OPEB plans. The weighted average discount rate for the pension plans decreased from 5.51% to 5.31% while the discount rate for the OPEB plans decreased from 5.50% to 5.30%. The expected long-term rate of return on plan assets remained at 8.50%. The pension benefit and OPEB obligations, as well as the asset values, were re-measured as of May 31, 2011 (the closest month-end date to the time the revisions were made). As a result, the annual net periodic pension benefit cost for 2011 will decrease by $32 million and the 2011 annual net OPEB cost will decrease by $6 million compared to costs that would have been expensed in 2011 if PSEG did not re-measure. The re-measured pension projected benefit obligations and accumulated OPEB obligation as of May 31, 2011 were $4.3 billion and $1.2 billion, respectively. The year-to-date rate of return on plan assets through the May 31 remeasurement date was 6.70%.

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. The costs for January through May 2011 are calculated under the prior plans’ assumptions. The costs for June 2011 and subsequent months are being calculated under the revised plan provisions. OPEB costs are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. New federal health care legislation enacted in March 2010 eliminates the tax deductibility of retiree health care costs beginning in 2013, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. See Note 13. Income Taxes for additional information.

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Pension and OPEB costs for PSEG are detailed as follows:

	Pension Benefits Three Months Ended September 30,						OPEB Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	22		$	21		$	3		$	4		$	69		$	65		$	10		$	12
Interest Cost		56			58			15			18			172			173			45			54
Expected Return on Plan Assets		(85	)		(67	)		(5	)		(4	)		(248	)		(200	)		(13	)		(11	)
Amortization of Net
Transition Obligation		0			0			1			6			0			0			4			20
Prior Service Cost (Credit)		(4	)		0			(4	)		4			(6	)		0			(10	)		10
Actuarial Loss		29			31			4			2			89			92			11			6
Net Periodic Benefit Cost		18			43			14			30			76			130			47			91
Effect of Regulatory Asset		0			0			5			5			0			0			15			15
Total Benefit Costs, Including Effect of Regulatory Asset	$	18		$	43		$	19		$	35		$	76		$	130		$	62		$	106

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

	Pension Benefits Three Months Ended September 30,				OPEB Three Months Ended September 30,				Pension Benefits Nine Months Ended September 30,				OPEB Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
	Millions
Power	$	6	$	13	$	3	$	4	$	24	$	40	$	9	$	13
PSE&G		9		24		16		30		41		72		51		90
Other		3		6		0		1		11		18		2		3
Total Benefit Costs	$	18	$	43	$	19	$	35	$	76	$	130	$	62	$	106

During the three months ended March 31, 2011, PSEG contributed its entire planned contributions for the year 2011 of $415 million and $11 million into its pension and postretirement healthcare plans, respectively.

Note 8. Commitments and Contingent Liabilities

Guaranteed Obligations—PSEG and Power

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.

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

The face value of outstanding guarantees, current exposure and margin positions as of September 30, 2011 and December 31, 2010 are shown below:

	As of September 30, 2011			As of December 31, 2010
	Millions
Face Value of Outstanding Guarantees	$	1,758		$	1,936
Exposure under Current Guarantees	$	283		$	330
Letters of Credit Margin Posted	$	135		$	137
Letters of Credit Margin Received	$	53		$	109
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	1		$	0
Counterparty Cash Margin Received		(5	)		(2	)
Net Broker Balance Deposited (Received)		37			(28	)
In the Event Power Were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	765		$	828
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,466		$	2,750
Additional Amounts Posted
Other Letters of Credit	$	99		$	98

Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Receivable.

24

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

In addition, during 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. Power will carefully monitor these new rules as they are developed to analyze the potential impact on its swap and derivatives transactions, including any potential increase to collateral requirements.

In April 2011, PSEG and Power entered into new 5-year credit agreements resulting in an increase of $650 million in Power’s total credit capacity.

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 United States Environmental Protection Agency (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, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. The total cost of the study is now estimated at approximately $86 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 71 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G’s former MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim.

In 2007, the EPA released a draft “Focused Feasibility Study” that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study may be released as early as the second quarter of 2012.

In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

25

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to these 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 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 February 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 they allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaint in June 2010. A special master for discovery has been appointed by the court and document production has commenced. 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. 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. PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study 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 is participating in and partially funding 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 next 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.

26

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

During the third quarter of 2011, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $643 million and $741 million from September 30, 2011 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $643 million on its Condensed Consolidated Balance Sheet as of September 30, 2011. Of this amount, $53 million was recorded in Other Current Liabilities and $590 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $643 million Regulatory Asset with respect to these costs.

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

The PSD/NSR regulations, promulgated under the Clean Air Act, 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 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Power’s generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at the Hudson and Mercer facilities designed to meet targeted reductions in emissions of sulfur dioxide (SO₂), nitrogen oxide (NO_x ), particulate matter and mercury. Power completed the construction of all plant modifications by the end of 2010 at a cost of $1.3 billion. Performance testing to validate the agreed-upon emission reductions was completed in the second quarter of 2011 and all performance metrics were met.

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 Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act 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 court ruling, the EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which is expected to be finalized by December 2011. This regulation prescribes reduced levels of mercury and other hazardous air pollutants pursuant to the Clean Air Act. Until the final rule is adopted, the impact cannot be determined; however, if the rule is adopted as proposed, Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rule’s requirements. Some additional controls could be necessary at Power’s Connecticut facilities and some of its other New Jersey facilities, pending engineering evaluation. The impact to Power’s jointly owned coal fired generating facilities in Pennsylvania is under evaluation.

New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.

With newly installed controls at its plants in New Jersey, Power expects to achieve the required mercury reductions that are part of Power’s multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

27

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NO_x Regulation

In April 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel fired electric generating units. The rule has a significant impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW) by April 30, 2015. Power is unable to estimate the possible loss or range of loss related to this matter.

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.

Cross-State Air Pollution Rule (CSAPR)

On July 6, 2011, the EPA issued the CSAPR. CSAPR limits power plant emissions in 27 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions will be governed by this rule beginning on January 1, 2012 for SO₂ and “annual NO_x” and May 1, 2012 for “Ozone season NO_x”. Certain states will be required to make additional SO₂ reductions in 2014.

PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. As Power has made major capital investments over the past several years to lower the SO₂ and NO_X emissions of its fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania), Power does not foresee the need to make significant additional expenditures to its generation fleet to comply with the regulation. As such, Power believes this rule will not have a material impact to its capital investment program or units’ operations.

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability related to these obligations, which was included in Environmental Costs on Power’s and PSEG’s Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NJPDES) 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.

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 February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.

28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established impingement and entrainment mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power’s electric generating stations would be affected. 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 or results of operations. 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.

In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies may ultimately impact the EPA’s rulemaking.

In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that company’s nuclear generating station located in New Jersey. In December 2010, the NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit will be issued in substitution for the draft NJPDES permit issued in January 2010. Power cannot predict at this time the final outcome of the NJDEP decision and the impact, if any, such a decision would have on any of Power’s once-through cooled generating stations.

New Generation and Development

Nuclear

Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed on schedule in October 2011. Unit 2 upgrades are expected to result in an increase of Power’s share of nominal capacity by approximately 18 MW in 2012. Total expenditures through September 30, 2011 were $94 million and are expected to continue through 2012. The actual increase in nominal capacity is under evaluation.

Power has begun expenditures in pursuit of additional output through an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power’s

29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

share of the increased capacity is expected to be approximately 133 MW with an anticipated cost of approximately $400 million. Total expenditures through September 30, 2011 were $28 million and are expected to continue through 2016.

Connecticut

Power was selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $140 million to $150 million. Total capitalized expenditures through September 30, 2011 were $99 million, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power. The initial filing is expected to be made in the fourth quarter of 2011. Costs for this project will be recovered subject to regulatory review and approval.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. Construction began in the second quarter of 2011. The projects are expected to be in service by June 2012. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Capacity in the amount of 267 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 and 2014-2015 periods. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through September 30, 2011 were $148 million which are included in Property, Plant and Equipment on Power’s and PSEG’s Condensed Consolidated Balance Sheets.

PSE&G—Solar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&G’s commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units PSE&G estimates the total cost of this project to be $264 million. Approximately 23 MW have been installed as of September 30, 2011. PSE&G’s cumulative investments for these solar units were approximately $164 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available.

Another aspect of the Solar 4 All program is the installation of 40 MW of solar systems on land and buildings owned by PSE&G and third parties. PSE&G estimates the total cost of this phase of the program to be $189 million. Through September 30, 2011, 23 MW representing 15 projects were placed into service with an investment of approximately $116 million.

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

30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.

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

	Auction Year
	2008		2009		2010		2011
36-Month Terms Ending		May 2011		May 2012		May 2013		May 2014	(A)
Load (MW)		2,800		2,900		2,800		2,800
$ per kWh		0.11150		0.10372		0.09577		0.09430

(A) Prices set in the 2011 BGS auction became effective on June 1, 2011 when the 2008 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. The contract extends through March 31, 2012, and year-to-year thereafter. 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. For additional information, see Note 17. Related-Party Transactions. 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.

Minimum Fuel Purchase Requirements

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

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.

Power’s strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below 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 2013 and a portion for 2014 through 2015 at Salem, Hope Creek and Peach Bottom.

As of September 30, 2011, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Commitments through 2015 Power’s Share
	Millions
Nuclear Fuel
Uranium	$	493
Enrichment	$	383
Fabrication	$	130
Natural Gas	$	903
Coal/Oil	$	896

31

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Included in the $896 million commitment for coal is $647 million related to a certain coal contract under which Power can cancel future contractual deliveries at no cost. In 2011, Power has not cancelled any related coal deliveries.

Regulatory Proceedings

Electric Discount and Energy Competition Act (Competition Act)

In 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

Also in 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In October 2007, the Court granted PSE&G’s motion to dismiss the amended Complaint and in November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court (Appellate Division). In February 2009, the Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division’s decision.

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G’s motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. In June 2011, the plaintiff/petitioner filed a notice of appeal of the BPU action with the Appellate Division. A briefing schedule has been established.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey EDC applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&G’s share is $705 million. PSE&G has recorded a discounted liability of $294 million as of September 30, 2011. Of this amount, $224 million was recorded as a current liability and $70 million as a noncurrent liability. 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 expected to be recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. It has no impact on current SBC assessments.

Long-Term Capacity Agreement Pilot Program (LCAPP)

In January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of approximately 1,949 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, executed standard offer capacity agreements (SOCA) with each of the three selected generators in compliance with the BPU’s directive, but did so under protest preserving its respective legal rights. The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The LCAPP Act and the

32

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. PSE&G will not make or receive payments under the three contracts unless (1) the plant successfully bids into and clears the capacity auction, and (2) the proposed plant is constructed. In April 2011, the BPU approved the executed contracts. Both PSE&G and Power joined other parties, including the EDCs, and appealed the BPU’s implementation of the LCAPP Act to the Appellate Division. The Division of Rate Counsel filed a motion to dismiss the EDCs’ appeal, which was denied by the Appellate Division.

Leveraged Lease Investments

The IRS has issued reports with respect to its audits of PSEG’s consolidated federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.

PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, six cases have been decided at the trial court level, five of which were decided in favor of the government. The appeals of three of these decisions were affirmed, each in favor of the government. The sixth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer.

In order to reduce the cash tax exposure related to these leases, Energy Holdings pursued opportunities to terminate international leases with lessees that were willing to meet certain economic thresholds. As of December 31, 2010, Energy Holdings had terminated all of these leasing transactions and reduced the related cash tax exposure by $1.1 billion. PSEG has completely eliminated its gross investment in such transactions.

Cash Impact

As of September 30, 2011, an aggregate of approximately $266 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, eliminating its cash exposure completely. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. Penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure will grow at an average rate of $2 million per quarter during 2011. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $20 million to $40 million of tax would be due for tax positions through September 30, 2011.

Unless this matter is resolved with the IRS, PSEG currently anticipates that it may be required to pay between $110 million and $300 million in tax, interest and penalties for the tax years 1997-2000 during 2011 and subsequently commence litigation to recover those amounts. It is possible that an additional payment of between $220 million and $560 million could be required during 2011 for tax years 2001-2003 followed by further litigation to recover those amounts. The amounts that may be required to litigate differ from the potential net cash exposure noted above, as the former amounts include all potential deficiencies for only contested tax years 1997 through 2003. These litigation amounts also include penalties which are not included in the computation of potential net cash exposure as PSEG believes it has strong defenses. These amounts also

33

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

exclude an offset for taxes paid on lease terminations, which is netted in the potential net cash exposure as PSEG would be entitled to a refund of such amounts under a loss scenario. Any potential claims PSEG would make to recover such amounts would include the deposit noted above.

Earnings Impact

PSEG’s current reserve position represents its view of the earnings impact that could result from a settlement related to these transactions, although a total loss, consistent with the broad settlement offer previously proposed by the IRS, would result in an additional earnings charge of $120 million to $140 million.

Note 9. Changes in Capitalization

The following capital transactions occurred in the first nine months of 2011:

Power

• issued $250 million of 2.75% Senior Notes due September 2016 in September,

• issued $250 million of 4.15% Senior Notes due September 2021 in September,

• paid $606 million of 7.75% Senior Notes at maturity in April, and

• paid cash dividends of $350 million to PSEG.

PSE&G

• issued $250 million of 0.85% Medium Term Notes due August 2014 in August, and

• paid $142 million of Transition Funding’s securitization debt, and

• paid $5 million of Transition Funding II’s securitization debt.

Energy Holdings

• paid $1 million of nonrecourse project debt.

PSE&G

In addition, $164 million of tax-exempt bonds of the Pollution Control Financing Authority of Salem County (Authority Bonds), which are serviced and secured by PSE&G’s first mortgage bonds of like tenor, are subject to a mandatory put in November 2011. PSE&G intends to buy the Authority Bonds in on their mandatory put date. The Authority Bonds had an initial term rate of 0.95%.

Also, $100 million of tax-exempt bonds of the New Jersey Economic Development Authority (EDA Bonds), which are serviced and secured by PSE&G’s first mortgage bonds of like tenor, are subject to a mandatory put in December 2011. PSE&G intends to buy the EDA Bonds in on their mandatory put date. The EDA Bonds had an initial term rate of 1.20%.

Note 10. Financial Risk Management Activities

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

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

34

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

• the price of fuel to meet its fuel purchase requirements.

These derivative transactions are designated and effective as cash flow hedges. As of September 30, 2011 and December 31, 2010, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:

	As of September 30, 2011		As of December 31, 2010
	Millions
Fair Value of Cash Flow Hedges	$	79	$	196
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	34	$	114

The expiration date of the longest-dated cash flow hedge at Power is in 2013. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $33 million. There was ineffectiveness of $3 million associated with these hedges as of September 30, 2011.

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 we serve. 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 are marked to market through the income statement and represented less than one percent of gross margin (revenues less energy costs) on an annual basis. Effective July 2011, Power anticipates that it will only enter into transactions that are associated with the output or fuel purchase requirements of its facilities.

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These asset backed transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of our expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of September 30, 2011 and December 31, 2010 was $19 million and $(4) million, respectively.

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, we have used a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.

35

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. Since 2009, PSEG has entered into eleven interest rate swaps totaling $1.4 billion. These swaps convert $300 million of Power’s $600 million of 6.95% Senior Notes due June 2012, Power’s $250 million of 5% Senior Notes due April 2014, 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 debt. As of September 30, 2011 and December 31, 2010, the fair value of all the underlying hedges was $66 million and $39 million, respectively.

Cash Flow Hedges

PSEG and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of September 30, 2011, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of September 30, 2011 and December 31, 2010. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(3) million and $(3) million as of September 30, 2011 and December 31, 2010, respectively.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets:

	As of September 30, 2011
	Power												PSE&G			PSEG			Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	76		$	232		$	(213	)	$	95		$	0		$	18		$	113
Noncurrent Assets		7			44			(27	)		24			0			51			75
Total Mark-to-Market Derivative Assets	$	83		$	276		$	(240	)	$	119		$	0		$	69		$	188
Derivative Contracts
Current Liabilities	$	(2	)	$	(281	)	$	204		$	(79	)	$	(15	)	$	0		$	(94	)
Noncurrent Liabilities		(2	)		(41	)		26			(17	)		(11	)		(3	)		(31	)
Total Mark-to-Market Derivative (Liabilities)	$	(4	)	$	(322	)	$	230		$	(96	)	$	(26	)	$	(3	)	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	79		$	(46	)	$	(10	)	$	23		$	(26	)	$	66		$	63

36

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	As of December 31, 2010
	Power												PSE&G			PSEG		Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			FairValue Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	204		$	403		$	(444	)	$	163		$	0		$	19	$	182
Noncurrent Assets		3			80			(41	)		42			17			20		79
Total Mark-to-Market Derivative Assets	$	207		$	483		$	(485	)	$	205		$	17		$	39	$	261
Derivative Contracts
Current Liabilities	$	(11	)	$	(454	)	$	374		$	(91	)	$	(12	)	$	0	$	(103	)
Noncurrent Liabilities		0			(72	)		50			(22	)		0			0		(22	)
Total Mark-to-Market Derivative (Liabilities)	$	(11	)	$	(526	)	$	424		$	(113	)	$	(12	)	$	0	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	196		$	(43	)	$	(61	)	$	92		$	5		$	39	$	136

(A) Represents the netting of fair value balances with the same counterparty and the application of collateral. As of September 30, 2011 and December 31, 2010, net cash collateral received of $10 million and $61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $10 million as of September 30, 2011, cash collateral of $(9) million and $(1) million were netted against current assets and noncurrent assets, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively.

The aggregate fair value of energy-related contracts in a liability position as of September 30, 2011 that contain triggers for additional collateral was $182 million. This potential additional collateral is included in the $765 million discussed in Note 8. Commitments and Contingent Liabilities.

37

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, 2011 and 2010:

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 September 30,					Three Months Ended September 30,					Three Months Ended September 30,
	2011		2010			2011		2010			2011		2010
	Millions
PSEG
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Interest Rate Swaps		0		0	Interest Expense		0		0			0		0
Total PSEG	$	21	$	62		$	60	$	60		$	0	$	0
Power
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Total Power	$	21	$	62		$	60	$	60		$	0	$	0

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, 2011 and 2010:

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 September 30,					Nine Months Ended September 30,							Nine Months Ended September 30,
	2011		2010			2011			2010				2011		2010
	Millions
PSEG (A)
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Interest Rate Swaps		0		0	Interest Expense		(1	)		(1	)			0		0
Total PSEG	$	19	$	172		$	153		$	175			$	1	$	(3	)
Power
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Total Power	$	19	$	172		$	154		$	176			$	1	$	(3	)

(A) Includes amounts for PSEG parent.

38

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, 2010	$	188		$	111
Loss Recognized in AOCI (Effective Portion)		(2	)		(1	)
Less: Gain Reclassified into Income (Effective Portion)		(93	)		(56	)
Balance as of June 30, 2011	$	93		$	54
Gain Recognized in AOCI (Effective Portion)		21			12
Less: Gain Reclassified into Income (Effective Portion)		(60	)		(35	)
Balance as of September 30, 2011	$	54		$	31

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, 2011 and 2010:

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 September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
		Millions						Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	24		$	(6	)	$	(18	)	$	3
Energy-Related Contracts	Energy Costs		(11	)		0			(10	)		(8	)
Total PSEG and Power		$	13		$	(6	)	$	(28	)	$	(5	)

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity 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 $6 million for each of the three month periods and $19 million and $18 million for the nine month periods ended September 30, 2011 and 2010, respectively.

39

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2011 and December 31, 2010:

Type	Notional	Total		PSEG		Power		PSE&G
	Millions
As of September 30, 2011
Natural Gas	Dth		593		0		350		243
Electricity	MWh		145		0		145		0
Financial Transmission Rights (FTRs)	MWh		20		0		20		0
Interest Rate Swaps	US Dollars		1,400		1,400		0		0
As of December 31, 2010
Natural Gas	Dth		704		0		424		280
Electricity	MWh		154		0		154		0
Capacity	MW days		1		0		1		0
FTRs	MWh		23		0		23		0
Interest Rate Swaps	US Dollars		1,150		1,150		0		0

Credit Risk

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

As of September 30, 2011, 95% of the credit for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

The following table provides information on Power’s credit risk from others, net of cash collateral, as of September 30, 2011. 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	$	396	$	46	$	392		3	$	242	(A)
Non-Investment Grade—External Rating		11		0		11		0		0
Investment Grade—No External Rating		9		0		9		0		0
Non-Investment Grade—No External Rating		9		0		9		0		0
Total Credit Risk	$	425	$	46	$	421		3	$	242

(A) Includes net exposure of $129 million with PSE&G. The remaining net exposure of $113 million is with two nonaffiliated power purchasers which are regulated investment grade counterparties.

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

40

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, 2011, Power had 190 active counterparties.

Note 11. Fair Value Measurements

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

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, 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. These consist mainly of various FTRs, certain full requirements contracts and other longer term capacity and transportation contracts.

41

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, 2011 and December 31, 2010, 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.

	Recurring Fair Value Measurements as of September 30, 2011
Description	Total			Cash Collateral Netting (E)			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)	$	119		$	(10	)	$	0	$	99		$	30
Interest Rate Swaps (B)	$	69		$	0		$	0	$	69		$	0
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	170		$	0		$	17	$	153		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(122	)	$	0		$	0	$	(88	)	$	(34	)
Interest Rate Swaps (B)	$	(3	)	$	0		$	0	$	(3	)	$	0
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	119		$	(10	)	$	0	$	99		$	30
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	33		$	0		$	3	$	30		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(96	)	$	0		$	0	$	(88	)	$	(8	)
PSE&G
Assets:
Rabbi Trust—Mutual Funds (C)	$	57		$	0		$	6	$	51		$	0
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(26	)	$	0		$	0	$	0		$	(26	)

42

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Recurring Fair Value Measurements as of December 31, 2010
Description	Total			Cash Collateral Netting (E)			Quoted Market Prices of Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	222		$	(135	)	$	0	$	228		$	129
Interest Rate Swaps (B)	$	39		$	0		$	0	$	39		$	0
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	160		$	0		$	18	$	142		$	0
Other Long-Term Investments (D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(125	)	$	74		$	0	$	(117	)	$	(82	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	205		$	(135	)	$	0	$	228		$	112
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	32		$	0		$	4	$	28		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(113	)	$	74		$	0	$	(117	)	$	(70	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	17		$	0		$	0	$	0		$	17
Rabbi Trusts—Mutual Funds (C)	$	54		$	0		$	6	$	48		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(12	)	$	0		$	0	$	0		$	(12	)

(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.

43

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 is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.

(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) Power’s NDT funds maintain investments in various equity and fixed income securities classified as “available for sale.” These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the NDT funds 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).

Power’s NDT investments in fixed income securities are primarily with investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities (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).

The Rabbi Trust mutual funds are mainly invested in a United States bond index fund, an S&P 500 index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

(D) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices.

(E) 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.

44

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and nine months ended September 30, 2011 follows:

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

for the Three Months Ended September 30, 2011

				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1,    2011			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)		Transfers In (Out)		Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(3	)	$	13	$	(27	)	$	10	$	3	$	0	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	(4	)	$	13	$	0		$	10	$	3	$	0	$	22
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	0	$	(27	)	$	0	$	0	$	0	$	(26	)

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

for the Nine Months Ended September 30, 2011

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2011		Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)			Transfers In (Out)			Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	47	$	(27	)	$	(31	)	$	29	$	(22	)	$	0		$	(4	)
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
Power
Net Derivative Assets	$	42	$	(27	)	$	0		$	29	$	(22	)	$	0		$	22
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
PSE&G
Net Derivative Assets (Liabilities)	$	5	$	0		$	(31	)	$	0	$	0		$	0		$	(26	)

45

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and nine months ended September 30, 2010 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2010		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	168	$	33	$	(11	)	$	(2	)	$	188
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	16	$	0	$	0		$	(16	)	$	0
Power
Net Derivative Assets	$	117	$	33	$	0		$	(2	)	$	148
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	3	$	0	$	0		$	(3	)	$	0
PSE&G
Net Derivative Assets	$	51	$	0	$	(11	)	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0		$	(5	)	$	0

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

for the Nine Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2010		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)		Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	105	$	61	$	34	$	(12	)	$	188
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	14	$	0	$	0	$	(14	)	$	0
Power
Net Derivative Assets	$	99	$	61	$	0	$	(12	)	$	148
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	3	$	0	$	0	$	(3	)	$	0
PSE&G
Net Derivative Assets	$	6	$	0	$	34	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0	$	(5	)	$	0

(A) PSEG’s and Power’s gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $12 million and $17 million are included in Operating Income, $1 million and $14 million are included in OCI, and less than $1 million and $2 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $12 million in Operating Income in 2011, $31 million is unrealized and $(19) million is realized. Of the $17 million in Operating Income in 2010, $32 million is unrealized and $(15) million is realized.

(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.

46

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(C) Represents $10 million in purchases for the three months ended September 30, 2011. Includes $65 million in purchases and $(36) million in sales for the nine months ended September 30, 2011.

(D) Includes $(5) million in issuances and $8 million in settlements for the three months ended September 30, 2011. Includes $(25) million in issuances and $3 million in settlements for the nine months ended September 30, 2011.

(E) PSEG’s and Power’s gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(28) million and $8 million are included in Operating Income, $(2) million and $28 million are included in OCI, and $3 million and $25 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $(28) million in Operating Income in 2011, $(25) million is unrealized and $(3) million is realized. Of the $8 million in Operating Income in 2010, $9 million is unrealized and $(1) million is realized.

As of September 30, 2011, PSEG carried $1.5 billion of net assets that are measured at fair value on a recurring basis, of which $4 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets. During the nine months ended September 30, 2011, $8 million of assets in the NDT fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. As per PSEG’s policy, this transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred).

As of September 30, 2010, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $197 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no transfers among levels during the three months and nine months ended September 30, 2010.

Non-recurring Fair Value Measurements

In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset’s carrying amount may not be recoverable. There were no material impairments recorded during 2011.

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, 2011 and December 31, 2010.

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value (A)		Carrying Amount		Fair Value (A)
	Millions
Long-Term Debt:
PSEG (Parent)	$	40	$	66	$	10	$	39
Power -Recourse Debt		3,350		3,710		3,455		3,831
PSE&G		4,535		5,099		4,283		4,615
Transition Funding (PSE&G)		948		1,080		1,090		1,245
Transition Funding II (PSE&G)		50		54		55		59
Energy Holdings:
Project Level, Non-Recourse Debt		46		46		47		47
Total Long-Term Debt	$	8,969	$	10,055	$	8,940	$	9,836

(A) Fair value excludes unamortized discounts, including amounts related to the Debt Exchange between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company.

47

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 12. Other Income and Deductions

Other Income	Power		PSE&G		Other (A)		Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	36	$	0	$	0	$	36
Other		1		7		1		9
Total Other Income	$	37	$	7	$	1	$	45
Three Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	35	$	0	$	0	$	35
Realized Gains from Rabbi Trust		7		11		13		31
Other		2		3		4		9
Total Other Income	$	44	$	14	$	17	$	75
Nine Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	153	$	0	$	0	$	153
Other		3		16		4		23
Total Other Income	$	156	$	16	$	4	$	176
Nine Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	115	$	0	$	0	$	115
Realized Gains from Rabbi Trust		7		11		13		31
Other		4		11		4		19
Total Other Income	$	126	$	22	$	17	$	165

Other Deductions	Power		PSE&G		Other (A)			Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	10	$	0	$	0		$	10
Other		0		1		0			1
Total Other Deductions	$	10	$	1	$	0		$	11
Three Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	9	$	0	$	0		$	9
Other		0		1		(1	)		0
Total Other Deductions	$	9	$	1	$	(1	)	$	9
Nine Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	32	$	0	$	0		$	32
Other		5		2		0			7
Total Other Deductions	$	37	$	2	$	0		$	39
Nine Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	35	$	0	$	0		$	35
Other		1		2		(1	)		2
Total Other Deductions	$	36	$	2	$	(1	)	$	37

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

48

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 13. Income Taxes

PSEG’s, Power’s and PSE&G’s effective tax rates for the three months and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
PSEG		43.1	%		40.4	%		42.0	%		40.3	%
Power		40.7	%		39.6	%		41.0	%		40.3	%
PSE&G		40.1	%		39.5	%		40.5	%		38.4	%

For the three months ended September 30, 2011, the increase in PSEG’s effective tax rate was due primarily to Energy Holdings’ 2011 charge against earnings applicable to the Dynegy leases. (See Note 5. Financing Receivables) and a lower manufacturer’s deduction under the American Job Creation Act of 2004 as compared to the same period in 2010. There was no material change in the effective tax rate for Power and PSE&G.

For the nine months ended September 30, 2011, the increase in PSEG’s effective tax rate was due primarily to Energy Holdings’ 2011 charge against earnings applicable to the Dynegy leases and a lower manufacturer’s deduction as compared to the same period in 2010. PSE&G’s effective tax rate was lower in 2010, primarily due to tax benefits from uncollectible accounts and plant-related adjustments. There was no material change in the effective tax rate for Power.

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 include various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. As a result, in the first quarter of 2010, PSEG recorded noncash after-tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&G’s income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.

Two other tax provisions enacted during 2010 will have a significant impact on PSEG’s cash position. The Small Business Jobs Act of 2010, enacted in September 2010, extended the tax deduction for 50% bonus depreciation through 2010 for qualified property. The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, enacted in December 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 will be eligible for 50% bonus depreciation for tax purposes. These provisions will generate cash for PSEG through tax benefits related to the accelerated depreciation, most of which is anticipated to be realized in 2011. Also, for the third quarter of 2011, Power and PSE&G completed an analysis of industry specific tax accounting method changes resulting in current tax benefits. These tax benefits would have otherwise been received over the longer lives of the related depreciable property.

PSE&G has accrued $32 million of Investment Tax Credits (ITC) associated with alternative energy projects in the first nine months of 2011. Because the law provides an option to claim either a grant or the ITC, the ITC has been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense.

PSEG’s unrecognized tax benefits increased by approximately $53 million in the first nine months of 2011, attributable to PSE&G. This increase is due to a position raised by the IRS during its examination of the tax years 2004 to 2006 and a position taken for tax years 2004 to 2011 related to casualty loss deductions. Since December 31, 2010, the balance of unrecognized tax benefits that are reasonably likely to increase or decrease within the next 12 months changed by $19 million related to the positions discussed above.

49

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

PSEG made tax deposits with the IRS to defray interest costs associated with disputed tax assessments associated with certain lease investments. The deposits are fully refundable and are recorded as a reduction to Current Accrued Taxes on PSEG’s Condensed Consolidated Balance Sheets, but are not reflected in the unrecognized tax benefits.

As a result of a change in accounting method for the capitalization of indirect costs, PSEG reduced the net amount of its uncertain tax positions (including interest) by $97 million, approximately $43 million of which related to PSE&G. It is reasonably possible that PSE&G’s claim related to this matter will be settled with the IRS in the next 12 months, resulting in an increase in the uncertain tax positions.

It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 8. Commitments and Contingent Liabilities, will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase by as much as $205 million or decrease by as much as $297 million. It is not possible to predict the magnitude, timing or direction of any such change.

Note 14. Comprehensive Income, Net of Tax

Comprehensive Income	Power			PSE&G			Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Net Income	$	302		$	154		$	(162	)	$	294
Other Comprehensive Income (Loss)		(80	)		1			2			(77	)
Comprehensive Income	$	222		$	155		$	(160	)	$	217
Three Months Ended September 30, 2010
Net Income	$	384		$	155		$	28		$	567
Other Comprehensive Income (Loss)		38			(6	)		(4	)		28
Comprehensive Income	$	422		$	149		$	24		$	595
Nine Months Ended September 30, 2011
Net Income	$	871		$	422		$	(150	)	$	1,143
Other Comprehensive Income (Loss)		(112	)		2			10			(100	)
Comprehensive Income	$	759		$	424		$	(140	)	$	1,043
Nine Months Ended September 30, 2010
Net Income	$	952		$	276		$	54		$	1,282
Other Comprehensive Income (Loss)		13			(5	)		(3	)		5
Comprehensive Income	$	965		$	271		$	51		$	1,287

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

50

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Accumulated Other Comprehensive Income (Loss)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2010			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2011							Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2011
				Power (A)			PSE&G (B)		Other (C)
	Millions
Derivative Contracts	$	111		$	(80	)	$	0	$	0	$	31
Pension and OPEB Plans		(377	)		45			0		8		(324	)
NDT Funds		109			(77	)		0		0		32
Other		1			0			2		2		5
Accumulated Other Comprehensive Income (Loss)	$	(156	)	$	(112	)	$	2		10	$	(256	)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2009			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2010									Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2010
				Power (A)			PSE&G (B)			Other (C)
	Millions
Derivative Contracts	$	180		$	(2	)	$	0		$	0		$	178
Pension and OPEB Plans		(400	)		18			0			1			(381	)
NDT Funds		91			0			0			0			91
Other		13			(3	)		(5	)		(4	)		1
Accumulated Other Comprehensive Income (Loss)	$	(116	)	$	13		$	(5	)	$	(3	)	$	(111	)

(A) Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $54 million, $(31) million and $78 million, respectively for the nine months ended September 30, 2011. Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $1 million, $(12) million and $1 million, respectively for the nine months ended September 30, 2010.

(B) Net of tax of $(1) million for the nine months ended September 30, 2011 and $3 million for the nine months ended September 30, 2010.

(C) Net of tax of $(7) million for the nine months ended September 30, 2011 and $2 million for the nine months ended September 30, 2010.

51

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 15. Earnings Per Share (EPS)

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2011				2010
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Continuing Operations	$	265	$	265	$	547	$	547	$	1,047	$	1,047	$	1,267	$	1,267
Discontinued Operations		29		29		20		20		96		96		15		15
Net Income	$	294	$	294	$	567	$	567	$	1,143	$	1,143	$	1,282	$	1,282
EPS Denominator (Thousands)
Weighted Average Common Shares Outstanding		505,909		505,909		505,945		505,945		505,959		505,959		506,001		506,001
Effect of Stock Options		0		193		0		165		0		172		0		148
Effect of Stock Performance Share Units		0		599		0		662		0		607		0		785
Effect of Restricted Stock Units		0		298		0		196		0		225		0		134
Total Shares		505,909		506,999		505,945		506,968		505,959		506,963		506,001		507,068
EPS:
Continuing Operations	$	0.52	$	0.52	$	1.08	$	1.08	$	2.07	$	2.06	$	2.50	$	2.50
Discontinued Operations		0.06		0.06		0.04		0.04		0.19		0.19		0.03		0.03
Net Income	$	0.58	$	0.58	$	1.12	$	1.12	$	2.26	$	2.25	$	2.53	$	2.53

	Three Months Ended September 30,				Nine Months Ended September 30,
Dividend Payments on Common Stock	2011		2010		2011		2010
Per Share	$	0.3425	$	0.3425	$	1.0275	$	1.0275
in Millions	$	173	$	173	$	520	$	520

52

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 16. Financial Information by Business Segments

	Power		PSE&G			Energy Holdings			Other(A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Total Operating Revenues	$	1,398	$	1,841		$	(247	)	$	(372	)	$	2,620
Income (Loss) From Continuing Operations		273		154			(166	)		4			265
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		29		0			0			0			29
Net Income (Loss)		302		154			(166	)		4			294
Segment Earnings (Loss)		302		154			(166	)		4			294
Gross Additions to Long-Lived Assets		207		265			1			4			477
Three Months Ended September 30, 2010
Total Operating Revenues	$	1,523	$	2,007		$	58		$	(474	)	$	3,114
Income (Loss) From Continuing Operations		364		155			24			4			547
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		20		0			0			0			20
Net Income (Loss)		384		155			24			4			567
Segment Earnings (Loss)		384		155			24			4			567
Gross Additions to Long-Lived Assets		251		341			12			2			606
Nine Month Ended September 30, 2011
Total Operating Revenues	$	4,650	$	5,718		$	(206	)	$	(1,719	)	$	8,443
Income (Loss) From Continuing Operations		775		422			(164	)		14			1,047
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		96		0			0			0			96
Net Income (Loss)		871		422			(164	)		14			1,143
Segment Earnings (Loss)		871		422			(164	)		14			1,143
Gross Additions to Long-Lived Assets		530		939			2			8			1,479
Nine Months Ended September 30, 2010
Total Operating Revenues	$	4,983	$	5,987		$	114		$	(2,036	)	$	9,048
Income (Loss) From Continuing Operations		937		276			43			11			1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		15		0			0			0			15
Net Income (Loss)		952		276			43			11			1,282
Preferred Securities Dividends		0		(1	)		0			1			0
Segment Earnings (Loss)		952		275			43			12			1,282
Gross Additions to Long-Lived Assets		579		871			61			6			1,517
As of September 30, 2011
Total Assets	$	11,484	$	17,235		$	1,959		$	(767	)	$	29,911
Investments in Equity Method Subsidiaries	$	30	$	0		$	113		$	0		$	143
As of December 31, 2010
Total Assets	$	11,452	$	16,873		$	2,234		$	(650	)	$	29,909
Investments in Equity Method Subsidiaries	$	25	$	0		$	105		$	0		$	130

(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 at cost 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 17. Related-Party Transactions.

53

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 17. 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 September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)	$	91		$	118		$	958		$	1,102
Billings to PSE&G through BGS (A)		272			345			734			904
Total Revenue from Affiliates	$	363		$	463		$	1,692		$	2,006
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(37	)	$	(34	)	$	(109	)	$	(106	)
Total Expense Billings from Affiliates	$	(37	)	$	(34	)	$	(109	)	$	(106	)

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	110		$	372
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)		64			58
Payable to Services (B)		(23	)		(26	)
Tax Sharing Receivable from (Payable to) PSEG (C)		(18	)		380
Current Unrecognized Tax Receivable from (Payable to) PSEG (C)		(5	)		1
Payable to PSEG		(1	)		(3	)
Accounts Receivable—Affiliated Companies, net	$	127		$	782
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)	$	1,574		$	398
Working Capital Advances to Services (E)	$	17		$	17
Long-Term Accrued Taxes Receivable (C)	$	19		$	16

PSE&G

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)	$	(91	)	$	(118	)	$	(958	)	$	(1,102	)
Billings from Power through BGS (A)		(272	)		(345	)		(734	)		(904	)
Administrative Billings from Services (B)		(53	)		(47	)		(154	)		(151	)
Total Expense Billings from Affiliates	$	(416	)	$	(510	)	$	(1,846	)	$	(2,157	)

54

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Payable to Power through BGS and BGSS (A)	$	(110	)	$	(372	)
Payable to Power Related to Gas Supply Hedges for BGSS (A)		(64	)		(58	)
Payable to Power for SREC Liability (F)		(7	)		(7	)
Payable to Services (B)		(42	)		(48	)
Tax Sharing Receivable from PSEG (C)		467			321
Current Unrecognized Tax Receivable from PSEG (C)		59			73
Receivable from PSEG		1			6
Accounts Receivable (Payable)—Affiliated Companies, net	$	304		$	(85	)
Working Capital Advances to Services (E)	$	33		$	33
Long-Term Accrued Taxes Payable (C)	$	(54	)	$	(74	)

(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 through March 31, 2012 and year-to-year thereafter. 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) In 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU’s 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court’s ruling. PSE&G, along with other New Jersey utilities and Power participated at the hearing and filed comments. The BPU has not yet issued a decision. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of September 30, 2011 and December 31, 2010, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies as of December 31, 2010. Under current guidance, Power is unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G’s liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG’s Condensed Consolidated Balance Sheet as of September 30, 2011 and December 31, 2010.

55

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 18. Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). 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, 2011
Operating Revenues	$	0		$	1,725		$	29		$	(356	)	$	1,398
Operating Expenses		1			1,241			29			(356	)		915
Operating Income (Loss)		(1	)		484			0			0			483
Equity Earnings (Losses) of Subsidiaries		315			29			0			(344	)		0
Other Income		9			38			0			(10	)		37
Other Deductions		(1	)		(8	)		0			(1	)		(10	)
Other-Than-Temporary Impairments		1			(9	)		0			0			(8	)
Interest Expense		(33	)		(17	)		(3	)		11			(42	)
Income Tax Benefit (Expense)		12			(200	)		1			0			(187	)
Income (Loss) from Discontinued Operations, net of tax		0			0			29			0			29
Net Income (Loss)	$	302		$	317			27		$	(344	)	$	302
Three Months Ended September 30, 2010
Operating Revenues	$	0		$	1,817		$	30		$	(324	)	$	1,523
Operating Expenses		0			1,207			34			(325	)		916
Operating Income (Loss)		0			610			(4	)		1			607
Equity Earnings (Losses) of Subsidiaries		378			14			0			(392	)		0
Other Income		18			39			1			(14	)		44
Other Deductions		0			(9	)		0			0			(9	)
Other-Than-Temporary Impairments		0			(2	)		0			0			(2	)
Interest Expense		(26	)		(19	)		(5	)		13			(37	)
Income Tax Benefit (Expense)		14			(255	)		2			0			(239	)
Income (Loss) from Discontinued Operations, net of tax		0			0			20			0			20
Net Income (Loss)	$	384		$	378		$	14		$	(392	)	$	384

56

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Nine Months Ended September 30, 2011
Operating Revenues	$	0		$	5,622		$	106		$	(1,078	)	$	4,650
Operating Expenses		2			4,278			109			(1,078	)		3,311
Operating Income (Loss)		(2	)		1,344			(3	)		0			1,339
Equity Earnings (Losses) of Subsidiaries		917			88			0			(1,005	)		0
Other Income		28			159			0			(31	)		156
Other Deductions		(4	)		(32	)		0			(1	)		(37	)
Other-Than-Temporary Impairments		0			(10	)		0			0			(10	)
Interest Expense		(115	)		(38	)		(13	)		32			(134	)
Income Tax Benefit (Expense)		47			(592	)		6			0			(539	)
Income (Loss) from Discontinued Operations, net of tax		0			0			96			0			96
Net Income (Loss)	$	871		$	919		$	86		$	(1,005	)	$	871
Nine Months Ended September 30, 2011
Net Cash Provided By (Used In) Operating Activities	$	370		$	2,029		$	(319	)	$	(593	)	$	1,487
Net Cash Provided By (Used In) Investing Activities	$	86		$	(935	)	$	652		$	(821	)	($	1,018	)
Net Cash Provided By (Used In) Financing Activities	$	(456	)	$	(1,091	)	$	(332	)	$	1,413		$	(466	)
Nine Months Ended September 30, 2010
Operating Revenues	$	0		$	5,853		$	95		$	(965	)	$	4,983
Operating Expenses		0			4,236			107			(966	)		3,377
Operating Income (Loss)		0			1,617			(12	)		1			1,606
Equity Earnings (Losses) of Subsidiaries		968			(4	)		0			(964	)		0
Other Income		36			124			1			(35	)		126
Other Deductions		(1	)		(35	)		0			0			(36	)
Other-Than-Temporary Impairments		0			(8	)		0			0			(8	)
Interest Expense		(91	)		(45	)		(17	)		34			(119	)
Income Tax Benefit (Expense)		40			(681	)		9			0			(632	)
Income (Loss) from Discontinued Operations, net of tax		0			0			15			0			15
Net Income (Loss)	$	952		$	968		$	(4	)	$	(964	)	$	952
Nine Months Ended September 30, 2010
Net Cash Provided By (Used In) Operating Activities	$	239		$	1,979		$	(3	)	$	(959	)	$	1,256
Net Cash Provided By (Used In) Investing Activities	$	(18	)	$	(1,522	)	$	0		$	661		$	(879	)
Net Cash Provided By (Used In) Financing Activities	$	(216	)	$	(453	)	$	(43	)	$	297		$	(415	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated
	Millions
As of September 30, 2011
Current Assets	$	4,746	$	7,343	$	909	$	(9,701	)	$	3,297
Property, Plant and Equipment, net		58		5,576		932		0			6,566
Investment in Subsidiaries		4,194		800		0		(4,994	)		0
Noncurrent Assets		157		1,496		47		(79	)		1,621
Total Assets	$	9,155	$	15,215	$	1,888	$	(14,774	)	$	11,484
Current Liabilities	$	828	$	9,534	$	944	$	(9,700	)	$	1,606
Noncurrent Liabilities		250		1,488		143		(80	)		1,801
Long-Term Debt		2,640		0		0		0			2,640
Member’s Equity		5,437		4,193		801		(4,994	)		5,437
Total Liabilities and Member’s Equity	$	9,155	$	15,215	$	1,888	$	(14,774	)	$	11,484
As of December 31, 2010
Current Assets	$	3,988	$	6,807	$	1,117	$	(8,468	)	$	3,444
Property, Plant and Equipment, net		55		5,385		902		0			6,342
Investment in Subsidiaries		4,794		1,079		0		(5,873	)		0
Noncurrent Assets		170		1,549		41		(94	)		1,666
Total Assets	$	9,007	$	14,820	$	2,060	$	(14,435	)	$	11,452
Current Liabilities	$	751	$	8,519	$	849	$	(8,468	)	$	1,651
Noncurrent Liabilities		423		1,510		129		(93	)		1,969
Long-Term Debt		2,805		0		0		0			2,805
Member’s Equity		5,028		4,791		1,082		(5,874	)		5,027
Total Liabilities and Member’s Equity	$	9,007	$	14,820	$	2,060	$	(14,435	)	$	11,452

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

This combined MD&A is separately filed by 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 transmission and distribution of electric energy and gas in New Jersey; implements demand response and energy efficiency programs and invests in solar generation, and

• Energy Holdings, which owns our energy-related leveraged leases and other investments.

Our discussion in Part I, Item 1. Business of our 2010 Annual Report on 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. Our risk factors section in Part II Item 1A 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 2010 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2011 and any 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 information should be read in conjunction with such Statements, Notes and the 2010 Annual Report on Form 10-K.

OVERVIEW OF 2011 AND FUTURE OUTLOOK

During the first nine months of 2011, our results continued to be adversely impacted by lower prices for end users of electricity and natural gas in the markets we serve. We began experiencing a greater pricing impact due to a decline in both PJM Reliability Pricing Model (RPM) and Basic Generation Service (BGS) rates which became effective in the second quarter. Our pricing also continues to be impacted by customer migration away from our BGS supply contracts as these volumes are replaced with lower priced spot market sales. However, the impact of customer migration on our results has been reduced as average BGS rates have been declining to a level more closely resembling current market prices so that customers also have less incentive to switch to third party suppliers.

Partially offsetting this lower commodity pricing are higher revenues due to increased distribution rates at PSE&G as a result of the base rate case settlement in mid-2010. This included an increase of $73.5 million and $26.5 million in annual electric and gas revenues, respectively, with a return on equity (ROE) of 10.3%. We have also realized an increase in transmission revenues as a result of our 2011 Formula Rate Update which provides for approximately $45 million in increased revenues in our 2011 transmission rates effective January 1, 2011. We filed our 2012 Annual Formula Rate Update with FERC in October 2011, which would provide for approximately $94 million in increased annual transmission revenues effective January 1, 2012.

In addition, our gas sales volumes improved for the first nine months of 2011 compared to the same period in 2010, due primarily to much warmer winter weather last year. Heating degree days, as a measure of winter weather in 2011, were 9% higher than in 2010. The weather, the economy and other factors all contributed to an overall increase of approximately 4% in Power’s Basic Gas Supply Service (BGSS) sales volumes and PSE&G’s gas delivery volumes as compared to 2010.

Since January 2010, typical PSE&G residential customers who purchased their electric and gas supply from PSE&G have seen a reduction in both their electric and gas bills. The average residential customer has

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experienced a savings of 4% in electric supply costs and 17% in gas supply costs. Including changes for delivery charges, the average residential customer would have realized a net annual decrease of 2% for electric and 15% for gas.

For 2011 and beyond, the key issues our business will confront are:

• potential for sustained lower natural gas and electricity prices,

• uncertainty in the economic recovery,

• regulatory and political uncertainty, particularly with regard to future energy policy, legislative initiatives and environmental regulation, and

• pressure on competitive markets in many states, particularly in New Jersey.

In addition, recent conditions in the financial markets could have an adverse impact on the year end funded status of our pension obligation. This could result in increased pension expenses in 2012.

Our future success will also depend on our ability to respond to these challenges and take advantage of opportunities presented by these and other regulatory and legislative initiatives. In order to do this, we must:

• focus on controlling costs while maintaining our safety, reliability and compliance standards,

• successfully recontract Power’s open positions, and

• execute our capital investment program, including investments for growth that would yield contemporaneous and attractive risk adjusted returns.

There have also been other significant regulatory and legislative developments during the year which may affect our operations in the future as new rules and regulations are adopted. For additional information on these issues, see Part II, Item 5. Other Information.

• In an attempt to stimulate the development of new generation capacity in New Jersey through a subsidized rate mechanism, in January 2011, New Jersey enacted the long-term capacity agreement pilot program Act (LCAPP) directing the New Jersey Board of Public Utilities (BPU) to conduct a process to procure and subsidize up to 2,000 MW of baseload or mid-merit electric power generation. This could result in artificially depressed pricing in the competitive wholesale market and thus has the potential to harm competitive markets, on both a short-term and a long-term basis. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of 1,949 MW of new combined-cycle generating facilities located in New Jersey. Power and PSE&G appealed this order. Each of the New Jersey electric distribution companies (EDCs), including PSE&G, executed standard offer capacity agreements (SOCA) with the three generators in compliance with the BPU’s directive, but did so under protest, reserving its respective legal rights. The SOCA provides for each New Jersey EDC to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The SOCA requires that the generator bid in and clear in the PJM RPM base residual auction in each year of the SOCA term in order to receive a subsidized payment.

In April 2011, the Federal Energy Regulatory Commission (FERC) issued an order making effective changes to the PJM Tariff that would require new generation to clear in the RPM at competitive prices—i.e. applying a Minimum Offer Price Rule (MOPR) which would mitigate but not eliminate the impacts of the subsidized SOCA pricing upon RPM auction prices. This order has been challenged on rehearing. In addition, FERC convened a technical conference in July 2011 to consider whether resources that engage in self-supply should be exempt from such requirements. PJM has taken the position that it should be given more discretion to evaluate bids impacted by the MOPR and determine whether a bidder’s costs are legitimately below the MOPR level. In May 2011, the BPU initiated a proceeding to evaluate whether there is a need for additional generation capacity in the state. In October 2011, one of the three selected generators disputed the FERC order regarding the MOPR.

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The BPU held a second legislative-type hearing in October 2011 to take further comments on the possible impediments to the development of new generation capacity in New Jersey as well as other matters concerning the PJM Interconnection L.L.C. (PJM) Regional Transmission Expansion Planning (RTEP), the PJM interconnection processes and the competitiveness of the power market. Both PSE&G and Power participated in this proceeding, which calls for recommendations to be made to the BPU by the end of 2011. Another of the three selected generators has made a filing with the FERC challenging PJM’s interconnection process and claiming, among other things, that interconnection costs are a significant barrier to entry into New Jersey.

In the pending United States District Court challenge to the constitutionality of the LCAPP Act, in October 2011 the Court issued a decision denying the State’s motion to dismiss the complaint. In the state appellate litigation in which both Power (along with other generators) and PSE&G (along with the other EDCs) appealed the BPU’s order approving the SOCA contracts, the court recently denied the New Jersey Division of Rate Counsel’s motion to dismiss the EDCs’ appeal, while also denying a motion to consolidate both the Power and EDC appeals.

See Item 5. Other Information, Federal Regulation, FERC—Capacity Market Issues for further information.

• In September 2011, the Maryland Public Utility Commission issued an order requiring its EDCs to issue a Request for Proposal (RFP) by October 7, 2011 to procure up to 1,500 MW of new natural gas-fired generation located in the Southwest MAAC electrical region. Maryland also announced that it would hold hearings in January to evaluate the need for this procurement. The RFP would require up to a 20-year contract, with ratepayers paying the generator an amount that makes up the difference between the PJM price and the contract price (similar to the LCAPP SOCA). These developments in Maryland may influence developments in New Jersey regarding the construction of subsidized generation.

• The United States Environmental Protection Agency (EPA) published a proposed rule in April 2011 related to 316(b) Clean Water Act requirements. The proposed rule would establish a separate marine life entrainment mortality standard as well as new impingement mortality standards for certain existing cooling water intake structures. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take or the effect, if any, that they may have on our future capital requirements, financial condition or results of operations which could be material. If the rule were to be adopted as proposed, the impact would be material since the majority of our electric generating facilities would be affected.

• On July 6, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR). CSAPR limits power plant emissions in 27 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions will be governed by this rule beginning on January 1, 2012 for SO₂ and “annual NOx” and May 1, 2012 for “Ozone season NOx”. Certain states will be required to make additional SO₂ reductions in 2014.

On October 14, 2011, the EPA issued draft technical adjustments to the final CSAPR. Among the technical corrections proposed were adjustments to the annual NO_X, ozone season NO_X, and SO₂ emissions budgets for a number of states, including New Jersey and New York. Several of our plants in New Jersey had their emission allocations increased. Additionally, the EPA also proposed to delay the implementation of the assurance provision of the rule from 2012 to 2014 to promote the development of a liquid allowance market. These proposed changes will be open for public comment until November 28, 2011. The EPA will make a final determination shortly thereafter. We view the changes as proposed by the EPA as generally favorable.

We continue to evaluate the impact of this rule on us due to many of the uncertainties that still exist regarding implementation. As we have made major capital investments over the past several years to lower the SO₂ and NO_X emissions of our fossil plants in the states affected by CSAPR (New Jersey,

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New York and Pennsylvania), we believe we are competitively positioned as we do not foresee the need to make significant additional expenditures to our generation fleet to comply with the regulation. As such, we believe this rule will not have a material impact to our capital investment program or units’ operations.

• As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the Nuclear Regulatory Commission (NRC) has been performing additional operational and safety reviews of nuclear facilities in the United States. These reviews and the lessons learned from the events in Japan may result in additional regulation for the nuclear industry and could impact future operations and capital requirements for our facilities. We believe that our nuclear plants meet the stringent applicable design and safety specifications of the NRC.

In July 2011, the NRC task force submitted a report on the first 90 days of its nuclear power plant review. The report contained various recommendations to ensure plant protection, enhance accident mitigation, strengthen emergency preparedness and improve NRC program efficiency. These recommendations include proposed requirements for upgraded seismic and flooding protection, strengthening plants’ ability to deal with prolonged loss of power and development of emergency plans for events involving multiple reactors. In October 2011, the NRC issued a document which provides for a prioritization of the task force recommendations. The NRC is proposing to issue letters and orders to licensees and create new regulations over a six-to-52 month period to address the task force recommendations.

Separately, a petition was filed with the NRC in April 2011 seeking suspension of the operating licenses of all General Electric boiling water reactors utilizing the Mark 1 containment design in the United States, including our Hope Creek and Peach Bottom units, pending completion of the NRC review. The petition names 23 of the total 104 active commercial nuclear reactors in the United States. While we do not believe the petition will be successful, we are unable to predict the outcome of any action that the NRC may take in connection with its operational and safety reviews or any other regulatory or industry responses to the events in Japan.

We received our requested 20-year license extensions for the Salem and Hope Creek facilities in June and July 2011, respectively. Salem Units 1 and 2 are now licensed through 2036 and 2040, respectively, and Hope Creek is now licensed through 2046.

• During 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. The CFTC has issued Notices of Proposed Rulemakings (NOPRs) on many of the key issues. We cannot assess the exact scope of the new rules until they are issued by the SEC and CFTC. We currently expect the CFTC to finalize certain criteria under these rules, such as providing the definition of a swap dealer, establishing requirements for qualifying as an end user and determining any additional reporting requirements, by the end of 2011. We will carefully monitor these new rules as they are developed to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements.

• In June, the BPU issued a new draft Energy Master Plan (EMP). Our initial assessment is that if the EMP were finalized with the same provisions as drafted, it is generally favorable to our utility business direction, supportive of solar, nuclear power and off-shore wind development, but represents a serious threat to the PJM competitive electric wholesale market in that as a matter of policy it directs the BPU to subsidize new natural gas fired combined cycle generation in an effort to suppress wholesale market prices. The final EMP is expected to be issued later this year, following BPU hearings, in which we intend to participate.

• On July 21, 2011, the FERC issued a Final Rule which, among other things (i) directs regional planners such as PJM to modify their planning processes to “consider transmission needs driven by public policy requirements established by state or federal laws or regulations” (i.e. creating a new

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category of “public policy” transmission projects in addition to reliability and economic projects), (ii) directs these regional planners to remove the Right of First Refusal (ROFR)—which permits incumbent transmission owners such as PSE&G the first opportunity to construct transmission within their respective service territories—from its tariffs and agreements, subject to certain exceptions, and (iii) requires regional planners to allocate costs for transmission projects in a way that roughly matches costs with benefits, while leaving flexibility to the regions to determine precise cost allocation methodologies. Several parties, including PSEG, have sought rehearing of this Final Rule, which request remains pending. We cannot predict the final outcome or impact on us; however, specific implementation of the Final Rule in the various regions, including within PSE&G’s service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.

Operational Excellence

Our nuclear and fossil facilities continued their strong operating performance through the third quarter. Our nuclear units have achieved a capacity factor of 93% year to date and our combined cycle units have continued to improve their forced outage rates. Our generation fleet performed well during the July and August heat waves. During Hurricane Irene, the Salem and Hope Creek nuclear stations remained online. Overall, generation volumes for the first nine months of 2011 were 41.8 TWh, approximately 5% lower than in the same period in 2010 due primarily to reduced demands.

In addition, we continued to demonstrate our commitment to system reliability by limiting customer outages. In February 2011, our service territory experienced winter storms that impacted the electric transmission and distribution systems due to heavy icing and salt spray and in March 2011, our northern gas service territory was impacted by two heavy rainstorms that resulted in widespread flooding. Our personnel were prepared in each case for widespread outages and, as a result, were able to minimize the length of time our customers were without electric or gas service.

In August 2011, Hurricane Irene caused severe damage that resulted in flooding throughout our service territory, disrupting service to over 800,000 customers. With the assistance of mutual aid crews from other utilities, our associates worked to fully restore service to the majority of our customers within five days. On August 26, 2011 we filed a petition with the BPU asking permission to defer the incremental storm related costs and the opportunity to seek recovery in our next base rate proceeding. We have deferred approximately $29 million of incremental Operation and Maintenance (O&M) storm costs associated with Hurricane Irene.

Financial Strength

Our cash from operations has remained strong. During the first nine months of 2011, we made approximately $1.4 billion in capital expenditures, paid dividends of $520 million and made our entire planned pension contributions for the year 2011 of $415 million. Cash from operations for the year has and is expected to continue to benefit from two tax provisions enacted in 2010 which are expected to generate a total of approximately $800 million of cash benefits for us through accelerated depreciation, most of which is expected to be realized in 2011. See Note 13. Income Taxes for additional information. These funds, combined with proceeds from the sales of our Texas facilities, will be used to support our anticipated capital expenditures and dividend payments for the year.

In April 2011, PSEG, Power and PSE&G entered into new 5-year credit agreements resulting in an increase of $650 million in Power’s total credit capacity and increasing our total credit capacity to $4.3 billion.

Disciplined Investment

We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include upgrading critical energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. We also have several projects where we are investing to continue to improve our operational performance.

• During 2011, we reached agreements to sell our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions for a total of $687 million. In March 2011, we completed the sale of one

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plant for $352 million. The sale of the second plant closed in July 2011 for $335 million. See Note 4. Discontinued Operations and Dispositions for further information.

• We are continuing to pursue obtaining the necessary regulatory approvals for the Susquehanna-Roseland transmission project but have incurred delays in obtaining environmental approvals which have resulted in a delay to the project implementation date. The project, however, has just been placed on an initial list of projects for a new federal Rapid Response Team for Transmission. This team is focused on coordinating and expediting the federal permitting process for critical infrastructure upgrades. Although no assurances can be given, Susquehanna-Roseland’s placement on this list may help in obtaining timely environmental approvals for the project, including from the National Park Service. The estimated cost of construction is up to $750 million for this project. Our project estimate will be refined when we obtain additional information from the National Park Service process regarding the selected project route and mitigation-related requirements as well as contractor bids.

• In October 2010, PJM approved the North East Grid project, a 230 kV project running from Roseland to Hudson. This project has an expected in-service date of June 2015 with an estimated cost of construction of up to $895 million. We have also filed for BPU approval of the North-Central Reliability project, a 230 kV upgrade project located in the northern and central portions of New Jersey with an estimated cost of construction of approximately $336 million. The North-Central Reliability project has an expected in-service date of June 2014. Delays in the construction schedules of these projects could impact the timing of expected transmission revenues. The North East Grid project was approved in place of a previously approved 500 kV Branchburg-Roseland-Hudson (B-R-H) project. The FERC has ruled that, with the exception of abandonment cost recovery, rate incentives we previously received for the original B-R-H project were no longer applicable because the project had substantially changed. On October 31, 2011, we filed a petition with FERC seeking incentive rates for the North East Grid project, specifically, inclusion of 100% of Construction Work in Process (CWIP) in rate base, recovery of 100% of prudently incurred abandonment costs and a 100 basis point adder to ROE. We are seeking an effective date of January 1, 2012.

• In April 2011, we filed a petition with FERC seeking incentive rates with an effective date of June 14, 2011 for five 230 kV transmission projects, including the North-Central Reliability project. In June 2011, FERC granted incentive rates for three of these 230 kV projects, with a total capital investment of approximately $1.0 billion, representing approximately 80% of our request. The incentive rates include recovery for CWIP and 100% recovery of prudently-incurred abandonment costs. See Item 5. Other Information, Federal Regulation, Transmission Regulation—Transmission Expansion for further information.

• Our utility has made additional investments in solar initiatives. Under our solar loan program we have provided a total of $104 million in loans for 396 projects as of September 30, 2011, representing 30 MW to date. Under our Solar 4 All program we have made total program expenditures of approximately $298 million as of September 30, 2011. Approximately 23 MW of solar panels have been installed on distribution poles and another 23 MW representing 15 projects have been placed into service. Additional projects are in various stages of negotiation and development. Our total anticipated expenditures to develop all approved 80 MW is approximately $453 million. The BPU is currently conducting a generic stakeholder proceeding, however, to examine whether utility rate-based solar programs should be modified, expanded or terminated in the future.

• We made additional expenditures under our Capital Economic Stimulus and Energy Efficiency Economic Stimulus programs. As of September 30, 2011, total capital expenditures since inception of these projects were $702 million and $123 million, respectively. In July, the BPU approved extensions to both of these programs which provide for approximately $273 million in accelerated capital investments in our electric and gas infrastructure through 2012 and $95 million of additional capital expenditures for energy efficiency programs. In conjunction with the extension of the Capital Economic Stimulus programs, we agreed to additional electric and gas “base” spending of approximately $96 million during the program.

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• We continued various construction activities at Power, including a steam path retrofit and extended power uprate at Peach Bottom and construction of new gas fired peaking units at Kearny and in Connecticut (see Note 8. Commitments and Contingent Liabilities for additional information). This additional capacity at Kearny was bid into and has cleared the RPM capacity auction, and the additional capacity in Connecticut is subject to a contract with a Connecticut utility.

• We are continuing our efforts to obtain an Early Site Permit for a new nuclear generating station to be located at the current site of Salem and Hope Creek stations.

There is no guarantee that the projects described above or any future initiatives will be achieved since many issues need to be favorably resolved, such as regulatory approvals.

Energy Holdings’ collateral related to the lease to two affiliates (the Dynegy lessees) of Dynegy Incorporated (Dynegy), includes a guarantee from Dynegy Holdings LLC (DH), a subsidiary of Dynegy. In early August 2011, Dynegy reorganized the legal entity structure for its generation assets. It transferred substantially all of its coal and natural gas-fired generation assets, other than the Dynegy lessees that lease the Roseton Station Units 1 and 2 and Danskammer Station Units 3 and 4, to new subsidiaries which Dynegy termed as “bankruptcy remote”. This resulted in a lowering of certain credit ratings of Dynegy and DH. Dynegy’s credit is currently rated “CC” by S&P and “Caa3” by Moody’s.

In September 2011, Dynegy continued its corporate reorganization, transferring DH’s interests in its newly formed coal generation subsidiary directly to the parent company, Dynegy, in exchange for an undertaking. It also launched an exchange offer for a substantial portion of DH’s debt in exchange for Dynegy debt at various discounts. Dynegy has indicated that in the absence of a debt restructuring and/or refinancing, it may not have sufficient resources to pay its indebtedness under the lease. The consummation of these transactions triggered the filing of two separate lawsuits, one by a group of corporate unsecured bondholders of DH and a second on behalf of a majority of the holders of certain debt certificates related to the Dynegy lessee facilities; these lawsuits asserted fraudulent conveyance claims among several other causes of action. In addition to claims asserted against DH, one of the suits included claims against several members of DH’s Board of Directors.

As a result of the above actions, Energy Holdings has evaluated its likely recovery under the lease arrangements for the Roseton and Danskammer facilities leased to subsidiaries of DH, considering the overall value of the underlying assets subject to lease, and has fully reserved its $264 million gross investment. This resulted in an after-tax charge of approximately $170 million. In the absence of a negotiated resolution of the disputes with Dynegy, Energy Holdings intends to assert claims against DH, its directors and various Dynegy affiliates relative to the reorganization activities which have diminished the value of assets available to satisfy DH’s lease guarantee obligations. In addition, Energy Holdings has a tax indemnity agreement, which is designed to protect it from adverse tax consequences should the lease structure not be maintained. Energy Holdings intends to assert its claims under this agreement, notwithstanding any attempt by Dynegy in contravention of current case law to limit such claims in a bankruptcy proceeding of DH. In the event of a bankruptcy filing or the failure of DH to honor its obligations under the lease guarantee, it is possible that the lease certificate holders could foreclose on the underlying facilities in partial satisfaction of their indebtedness. Should this occur, Energy Holdings could be required to pay approximately $100 million to satisfy income tax obligations, an amount for which it would seek reimbursement from DH under the tax indemnity agreement. This potential cash tax obligation is fully reflected in the overall estimate of the aggregate after-tax charge.

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RESULTS OF OPERATIONS

The results for PSEG, PSE&G, Power and Energy Holdings for the three months and nine months ended September 30, 2011 and 2010 are presented below:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Earnings (Losses)	2011			2010		2011			2010
		Millions
Power	$	273		$	364	$	775		$	937
PSE&G		154			155		422			276
Energy Holdings		(166	)		24		(164	)		43
Other  (A)		4			4		14			11
PSEG Income from Continuing Operations		265			547		1,047			1,267
PSEG Income (Loss) from Discontinued Operations (B)		29			20		96			15
PSEG Net Income	$	294		$	567	$	1,143		$	1,282

	Three Months Ended     September 30,				Nine Months Ended     September 30,
Earnings Per Share (Diluted)	2011		2010		2011		2010
		Millions
PSEG Income from Continuing Operations	$	0.52	$	1.08	$	2.06	$	2.50
Income (Loss) from Discontinued Operations		0.06		0.04		0.19		0.03
PSEG Net Income	$	0.58	$	1.12	$	2.25	$	2.53

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

(B) See Note 4. Discontinued Operations and Dispositions.

Our results include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) funds and other related NDT activity. This includes the net realized gains, interest and dividend income and other costs related to the NDT funds which are recorded in Other Income and Deductions. This also includes credit-related 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 results also include the after-tax impacts of non-trading mark-to-market (MTM) activity.

The quarter-over-quarter and nine month-over-nine month variances in our Income from Continuing Operations include the changes related to NDT and MTM shown in the chart below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	Millions, after tax
NDT Fund Income	$	7	$	10	$	49	$	30
Non-Trading Mark-to-Market Gains	$	8	$	16	$	16	$	28

In addition to the changes in NDT and MTM, our $282 million decrease in Income from Continuing Operations for the three months ended September 30, 2011 was driven primarily by:

• the after-tax charge related to the reserve for assets underlying our lease receivable from Dynegy,

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• lower average pricing and volumes for electricity sold under our BGS contracts,

• higher Operation and Maintenance expense related to planned outage work at certain of our fossil plants, and

• higher depreciation expense related to the completion of installation of back-end technology at two of our fossil plants,

• partially offset by higher transmission and distribution revenues.

Our $220 million decrease in Income from Continuing Operations for the nine months ended September 30, 2011 was driven primarily by the same items impacting our quarterly results and also reflected the absence of a $122 million charge in 2010 related to our agreement to refund previous Market Transition Charge (MTC) collections.

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 17. 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 September 30,				Increase/ (Decrease)					Nine Months Ended September 30,				Increase/ (Decrease)
	2011		2010		2011 vs 2010					2011		2010		2011 vs 2010
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	2,620	$	3,114	$	(494	)	(16	)	$	8,443	$	9,048	$	(605	)	(7	)
Energy Costs		1,167		1,261		(94	)	(7	)		3,740		4,021		(281	)	(7	)
Operation and Maintenance		603		591		12		2			1,829		1,862		(33	)	(2	)
Depreciation and Amortization		263		260		3		1			739		716		23		3
Income from Equity Method Investments		1		4		(3	)	(75	)		8		12		(4	)	(33	)
Other Income and (Deductions)		34		66		(32	)	(48	)		137		128		9		7
Other-Than-Temporary Impairments		8		3		5		NA			13		9		4		44
Interest Expense		117		120		(3	)	(3	)		361		356		5		1
Income Tax Expense		201		371		(170	)	(46	)		757		856		(99	)	(12	)
Income (Loss) from Discontinued Operations		29		20		9		45			96		15		81		NA

Power

	Three Months Ended September 30,				Increase/ (Decrease)			Nine Months Ended September 30,				Increase/ (Decrease)
	2011		2010		2011 vs 2010			2011		2010		2011 vs 2010
						Millions
Income from Continuing Operations	$	273	$	364	$	(91	)	$	775	$	937	$	(162	)
Income (Loss) from Discontinued Operations, net of tax	$	29	$	20	$	9		$	96	$	15	$	81
Net Income	$	302	$	384	$	(82	)	$	871	$	952	$	(81	)

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For the three months ended September 30, 2011 the primary reasons for the $91 million decrease in Income from Continuing Operations were

• lower average pricing and volumes for electricity sold under our BGS contracts,

• higher Operation and Maintenance expense related to planned outage work at certain of our fossil plants, and

• higher depreciation expense related to the completion of installation of back-end technology at two of our fossil plants.

For the nine months ended September 30, 2011 the primary reasons for the $162 million decrease in Income from Continuing Operations were

• lower average pricing and volumes for electricity sold under our BGS contracts,

• higher Operation and Maintenance expense related to refurbishments at certain of our fossil plants, and

• higher interest costs and depreciation expense related to the completion of installation of back-end technology at two of our fossil plants,

• partially offset by favorable amounts related to our NDT activity.

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

	Three Months Ended September 30,				Increase/ (Decrease)					Nine Months Ended September 30,				Increase/ (Decrease)
	2011		2010		2011 vs 2010					2011		2010		2011 vs 2010
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	1,398	$	1,523	$	(125	)	(8	)	$	4,650	$	4,983	$	(333	)	(7	)
Energy Costs		597		620		(23	)	(4	)		2,335		2,483		(148	)	(6	)
Operation and Maintenance		262		253		9		4			810		764		46		6
Depreciation and Amortization		56		43		13		30			166		130		36		28
Other Income (Deductions)		27		35		(8	)	(23	)		119		90		29		32
Other-Than-Temporary Impairments		8		2		6		NA			10		8		2		25
Interest Expense		42		37		5		14			134		119		15		13
Income Tax Expense		187		239		(52	)	(22	)		539		632		(93	)	(15	)
Income (Loss) from Discontinued Operations		29		20		9		45			96		15		81		NA

For the three months ended September 30, 2011 as compared to 2010

Operating Revenues decreased $125 million due to

Generation Revenues decreased $122 million due primarily to

• a net decrease of $100 million due to lower average pricing and lower volumes sold under our BGS contracts as a result of customer migration in 2011,

• lower net revenues of $48 million due to lower generation volumes sold in the PJM, NY and New England (NE) power pools, partially offset by higher average prices realized in PJM, and

• a decrease of $28 million due to lower capacity payments primarily from PJM resulting from lower market prices,

• partially offset by an increase of $47 million from new wholesale load contracts in PJM and the NE regions commencing in January 2011 and April 2011, respectively, net of lower average realized prices in the NE region.

Gas Supply Revenues decreased $28 million due primarily to

• a net decrease of $23 million in sales under the BGSS contract, reflecting lower average gas sales prices and lower sales volumes due to economic conditions in 2011, and

68

• a net decrease of $5 million due to lower sales volumes at higher average prices to third party customers.

Trading Revenues increased $25 million due primarily to lower net losses in 2011 on certain electric energy supply contracts as well as the discontinuation of trading activities in the second quarter of 2011.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel purchases 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 by $23 million primarily due to

• Gas costs decreased $29 million principally related to Power’s obligations under the BGSS contract, reflecting lower average gas inventory costs and lower demand due to economic conditions in 2011.

Operation and Maintenance increased $9 million due primarily to

• a $7 million net increase due largely to planned higher outage costs at our coal-fired Conemaugh facility in Pennsylvania, and our gas-fired Bergen facility in New Jersey as well as baghouse filter replacement costs and coal unloading repair costs at Mercer in 2011 partially offset by higher outage costs at Mercer and our Connecticut facilities in 2010, and

• an increase of $4 million in materials and contract labor for refurbishment projects in 2011 related to the cooling, circulation and transfer of water, as well as grassing repairs at our Salem nuclear facilities and to maintenance resulting from damage due to Hurricane Irene.

Depreciation and Amortization increased $13 million due primarily to

• a $9 million increase due to completion of installation of back-end technology at the end of 2010 at our Mercer and Hudson generating facilities, and

• a $3 million increase due to higher depreciable asset bases at Nuclear and Fossil.

Other Income and (Deductions)—The net decrease of $8 million was due primarily to the absence of $7 million of gains realized in August 2010 from an asset restructuring of the Rabbi Trust and higher net realized losses in 2011 of $2 million on the NDT funds.

Other-Than-Temporary Impairments increased $6 million due to higher impairments on the NDT Funds recorded in 2011.

Interest Expense increased $5 million due primarily to

• Higher interest expense of $15 million resulting primarily from the installation by year-end 2010 of back-end technology at our Mercer and Hudson fossil stations for which we had been allowed to capitalize interest costs in 2010 while such projects were under construction,

• partially offset by lower interest expense of $11 million due to the redemption of $606 million of 7.75% Senior Notes in early April 2011.

Income Tax Expense decreased $52 million in 2011 due primarily to lower pre-tax income.

Income (Loss) from Discontinued Operations

In January 2011, we reached agreement to sell our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions. In March 2011, we completed the sale of one plant for proceeds of $352 million at an after-tax gain of $54 million. In July 2011, we completed the sale of the second plant for proceeds of $335 million at an after-tax gain of $25 million. The results of operations for both plants for the three months ended September 30, 2011 and 2010, including the gain in 2011 on the sale of the second plant, are included in this category. See Note 4. Discontinued Operations and Dispositions for additional information.

For the nine months ended September 30, 2011 as compared to 2010

Operating Revenues decreased $333 million due to

69

Generation Revenues decreased $232 million due primarily to

• a net decrease of $239 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts as a result of customer migration,

• lower net revenues of $84 million due to lower average realized prices in the PJM and NY power pools and lower volumes sold into the various power pools as a result of lower generation, and

• a decrease of $33 million due to lower capacity payments from the various power pools resulting from lower market prices,

• partially offset by an increase of $128 million from new wholesale load contracts in PJM and the NE regions commencing in January 2011 and April 2011, respectively, net of lower average realized prices in the NE region.

Gas Supply Revenues decreased $114 million due primarily to

• a net decrease of $128 million in sales under the BGSS contract, substantially comprised of lower average gas sales prices partially mitigated by increased volumes of sales due to colder average temperatures during the 2011 winter heating season,

• partially offset by a net increase of $14 million due to higher sales volumes at lower average prices to third party customers.

Trading Revenues increased $13 million due primarily to lower net losses in 2011 on certain electric energy supply contracts as well as the discontinuation of trading activities in the second quarter of 2011.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel purchases 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 $148 million due to

• Gas costs decreased $123 million, principally related to Power’s obligations under the BGSS contract, reflecting lower average gas inventory costs partially offset by higher demand due to colder average temperatures in the winter heating season in 2011, as well as higher demand by third party customers.

• Generation costs decreased $25 million due primarily to $147 million of lower fossil fuel costs, primarily reflecting the utilization of lower volumes of coal and natural gas and coal optimization partially offset by higher nuclear fuel costs. The decrease was also attributable to $9 million of lower impairment charges related to excess SO₂ emissions allowances. These decreases were partially offset by an increase of $130 million in higher energy purchases in 2011 in the PJM and NE power pools as a result of lower generation and the need to meet higher load contract demand in 2011.

Operation and Maintenance increased $46 million due primarily to

• a $35 million net increase due largely to planned outage costs, including hot gas path inspection outage costs at our gas-fired Bethlehem Energy and Linden facilities in New York and New Jersey, respectively, as well as to higher outage costs at our coal-fired Keystone facility in Pennsylvania, our gas-fired Bergen and our coal-fired Mercer facilities in New Jersey and baghouse filter replacement and coal unloading repair costs at Mercer, partially offset by refunds of easement costs related to certain of our fossil plants, and

• an increase of $12 million due to refurbishment projects at our Salem nuclear facilities.

Depreciation and Amortization increased $36 million due primarily to

• a $28 million increase due to completion of installation of back-end technology at the end of 2010 at our Mercer and Hudson generating facilities, and

• a $9 million increase due to higher depreciable asset bases at Nuclear and Fossil.

Other Income and (Deductions)—The net increase of $29 million was due primarily to $38 million of higher net realized gains on the NDT funds mainly resulting from the liquidation of an underperforming fund in March 2011 and a rebalancing to move toward our target asset allocation partially offset by the absence of $7 million of gains realized in 2010 from restructuring the Rabbi Trust.

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Other-Than-Temporary Impairments increased $2 million due to higher impairments on the NDT Funds in 2011.

Interest Expense increased $15 million due primarily to

• Higher interest expense of $36 million resulting primarily from the installation by year-end 2010 of back-end technology at our Mercer and Hudson fossil stations for which we had been allowed to capitalize interest costs in 2010 while such projects were under construction, and

• higher interest expense of $3 million due to the effects of a debt exchange that occurred in April 2010,

• partially offset by lower interest expense of $26 million due to the redemption of $606 million of 7.75% Senior Notes in early April 2011.

Income Tax Expense decreased $93 million in 2011 due primarily to lower pre-tax income.

Income from Discontinued Operations

As discussed above, we sold our two Texas plants in March 2011 and July 2011, respectively. The results of operations for both plants, including the 2011 after-tax gains on the sales, are included in this category. See Note 4. Discontinued Operations and Dispositions for additional information.

PSE&G

	Three Months Ended September 30,				Increase/ (Decrease)			Nine Months Ended September 30,				Increase/ (Decrease)
	2011		2010		2011 vs 2010			2011		2010		2011 vs 2010
		Millions
Income from Continuing Operations	$	154	$	155	$	(1	)	$	422	$	276	$	146
Net Income	$	154	$	155	$	(1	)	$	422	$	276	$	146

For the nine months ended September 30, 2011, the primary reasons for the $146 million increase in Income from Continuing Operations were

• the absence of a $122 million charge recorded in June 2010 related to the refund of previous MTC collections,

• higher annualized base rates for electric and gas delivery as well as transmission, and

• lower Operation and Maintenance expense.

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

	Three Months Ended September 30,				Increase/ (Decrease)					Nine Months Ended September 30,				Increase/ (Decrease)
	2011		2010		2011 vs 2010					2011		2010		2011 vs 2010
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	1,841	$	2,007	$	(166	)	(8	)	$	5,718	$	5,987	$	(269	)	(4	)
Energy Costs		943		1,115		(172	)	(15	)		3,124		3,572		(448	)	(13	)
Operation and Maintenance		342		327		15		5			1,014		1,084		(70	)	(6	)
Depreciation and Amortization		197		209		(12	)	(6	)		548		563		(15	)	(3	)
Other Income (Deductions)		6		13		(7	)	(54	)		14		20		(6	)	(30	)
Other-Than-Temporary Impairments		0		0		0		NA			1		0		1		NA
Interest Expense		77		82		(5	)	(6	)		234		239		(5	)	(2	)
Income Tax Expense (Benefit)		103		101		2		2			287		172		115		67

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For the three months ended September 30, 2011 as compared to 2010

Operating Revenues decreased $166 million due primarily to

Commodity Revenue decreased $172 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.

• Electric revenues decreased $153 million due primarily to $154 million in lower BGS revenues, partially offset by $1 million in higher revenues from the sale of Non-Utility Generation (NUG) energy and collections of non-utility generation charges (NGC). BGS sales decreased 14% due primarily to customer migration to third party suppliers (TPS); in contrast, delivery sales decreased only 1%.

• Gas revenues decreased $19 million due to lower BGSS prices of $17 million and lower BGSS volumes of $2 million. The average price of gas was 14% lower in 2011 than in 2010.

Clause Revenues decreased $10 million due primarily to lower Securitization Transition Charge (STC) revenues of $29 million, partially offset by higher Societal Benefits Charge (SBC) and Margin Adjustment Clause (MAC) of $19 million. The changes in STC, SBC and MAC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in Operation and Maintenance, Depreciation and Amortization and Interest Expense. PSE&G earns no margins on SBC, STC or MAC collections.

Delivery Revenues increased $11 million due primarily to an increase in prices for electric distribution and transmission.

• Transmission revenues were $8 million higher due primarily to net rate increases.

• Electric distribution revenues increased $2 million due primarily to higher stimulus revenue of $5 million, partially offset by lower sales volumes of $3 million.

Other Operating Revenues increased $5 million due primarily to increased revenues from our appliance repair business.

Energy Costs decreased $172 million. This is entirely offset by Commodity Revenue. Details are as follows:

• Electric costs decreased $153 million due to $112 million or 12% in lower BGS and NUG volumes due to customer migration to TPS and NUG operations and $73 million of lower BGS and NUG prices, partially offset by $32 million for increased deferred cost recovery.

• Gas costs decreased $19 million due to $17 million or 14% in lower prices and $2 million or 2% in lower sales volumes due primarily to weather.

Operation and Maintenance increased $15 million due primarily to higher labor and outside services, including storm restoration work and increased tree trimming costs, partially offset by lower pension and OPEB expenses.

Depreciation and Amortization decreased $12 million due primarily to

• a decrease of $21 million for amortization of Regulatory Assets,

• partially offset by an increase of $7 million for additional plant in service, and

• an increase of $3 million relating to asset retirements.

Other Income and (Deductions) The net decrease of $7 million was due primarily to the absence of $11 million of gains realized on the investments in our Rabbi Trust in 2010, partially offset by higher interest on Solar Loans and net other income of $4 million.

Other-Than-Temporary Impairments experienced no change.

Interest Expense decreased $5 million due primarily to the redemption of securitization debt in 2011, partially offset by the interest incurred on $250 million of Medium Term Notes (MTNs) issued in August 2011.

Income Tax Expense increased $2 million due to flow-through adjustments, primarily related to uncollectible accounts.

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For the nine months ended September 30, 2011 as compared to 2010

Operating Revenues decreased $269 million due primarily to

Commodity Revenue decreased $448 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.

• Electric revenues decreased $275 million due primarily to $348 million in lower BGS revenues, partially offset by $73 million in higher revenues from the sale of NUG energy and collections of NGC due primarily to higher prices. BGS sales decreased 15% due primarily to customer migration to TPS; in contrast, delivery sales decreased only 1%.

• Gas revenues decreased $173 million due to lower BGSS prices of $219 million, partially offset by higher BGSS volumes of $46 million due to colder weather. The average price of gas was 19% lower in 2011 than in 2010.

Clause Revenues increased $107 million due primarily to the absence of $122 million charge recorded in June 2010 related to our agreement to refund previous MTC collections over two years and higher SBC and MAC of $57 million, partially offset by lower STC revenues of $72 million. The changes in STC, SBC and MAC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in Operation and Maintenance, Depreciation and Amortization and Interest Expense. PSE&G earns no margins on SBC, STC or MAC collections.

Delivery Revenues increased $63 million due primarily to an increase in prices for electric and gas distribution and transmission.

• Gas distribution revenues increased $36 million due primarily to higher sales volumes of $24 million, the impact of base rate increase of $17 million and higher Weather Normalization Clause revenue of $3 million, partially offset by lower capital stimulus revenue of $9 million. The lower stimulus revenue is offset by a deferral in O&M.

• Transmission revenues were $25 million higher due primarily to net rate increases.

• Electric distribution revenues increased $2 million due primarily to the impact of base rate increases of $17 million, partially offset by lower sales volumes of $12 million and lower stimulus revenue of $3 million. The lower stimulus revenue is offset by a deferral in O&M.

Other Operating Revenues increased $9 million due primarily to increased revenues from our appliance repair business and miscellaneous electric operating revenues.

Energy Costs decreased $448 million. This is entirely offset by Commodity Revenue. Details are as follows:

• Electric costs decreased $275 million due to $308 million or 13% in lower BGS and NUG volumes due to customer migration to TPS and $62 million of lower BGS and NUG prices, partially offset by $95 million for increased deferred cost recovery.

• Gas costs decreased $173 million due to $219 million or 19% in lower prices, partially offset by $46 million or 4% in higher sales volumes due primarily to weather.

Operation and Maintenance decreased $70 million due primarily to

• $33 million of lower net deferred expenses associated with SBC, RGGI and Stimulus clauses,

• a $51 million decrease in pension and OPEB expenses, and

• the absence of $16 million in expenses relating to 2010 rate case disallowances,

• partially offset by a $18 million increase in bad debt expense, and

• a $4 million increase in costs relating to tree trimming.

Depreciation and Amortization decreased $15 million due primarily to

• a decrease of $44 million for amortization of Regulatory Assets,

• partially offset by an increase of $21 million for additional plant in service,

73

• an increase of $4 million in software amortization, and

• an increase of $4 million relating to asset retirements.

Other Income and (Deductions) The net decrease of $6 million was due primarily to the absence of $11 million of gains realized on the investments in our Rabbi Trust in 2010, partially offset by higher interest on Solar Loans and net other income of $5 million.

Other-Than-Temporary Impairments experienced no material change.

Interest Expense decreased $5 million due primarily to the redemption of securitization debt in 2011, partially offset by interest incurred on $250 million of MTNs issued in August 2011.

Income Tax Expense increased $115 million due primarily to an increase in pre-tax income.

Energy Holdings

	Three Months Ended September 30,					Increase/ (Decrease)			Nine Months Ended September 30,					Increase/ (Decrease)
	2011			2010		2011 vs 2010			2011			2010		2011 vs 2010
		Millions
Income (Loss) from Continuing Operations	$	(166	)	$	24	$	(190	)	$	(164	)	$	43	$	(207	)
Net Income (Loss)	$	(166	)	$	24	$	(190	)	$	(164	)	$	43	$	(207	)

For the three months and nine months ended September 30, 2011, the primary reason for the $190 million and $207 million respective decreases in Income from Continuing Operations was the $170 million after-tax charge on leveraged leases related to Dynegy. See Note 5. Financing Receivables for further information. Also contributing to the decrease was the absence of tax benefits related to two projects placed into service in 2010 and lower net lease-related gains.

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, 2011, our operating cash flow increased $1,070 million as compared to the same period in 2010. The net change was due primarily to net changes from Power, PSE&G and Energy Holdings, as discussed below.

Power

Power’s operating cash flow increased $231 million from $1,256 million to $1,487 million for the nine months ended September 30, 2011, as compared to the same period in 2010, primarily resulting from

• an increase of $448 million due to lower tax payments primarily related to the benefits of accelerated tax depreciation under new tax provisions enacted in 2010 (see Note 13. Income Taxes for additional information),

• partially offset by lower earnings for the period, and

• an $80 million net increase in spending on fuel inventories.

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PSE&G

PSE&G’s operating cash flow increased $445 million from $427 million to $872 million for the nine months ended September 30, 2011, as compared to the same period in 2010, due primarily to higher earnings for the period combined with

• an increase of $226 million due to lower tax payments primarily related to the benefits of accelerated tax depreciation under new tax provisions enacted in 2010 (see Note 13. Income Taxes for additional information),

• an increase of $144 million due to higher collections of customer receivables, and

• a $65 million net increase from recovery of deferred electric and gas costs.

Energy Holdings

Energy Holdings’ operating cash flow improved $324 million for the nine months ended September 30, 2011, as compared to the same period in 2010, primarily due to lower tax payments in 2011 related to the absence of lease sale activity in 2011.

Short-Term Liquidity

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

The commitments under our credit facilities are provided by a diverse bank group. As of September 30, 2011, no single institution represented more than 8% of the total commitments in our credit facilities.

As of September 30, 2011, our total credit capacity was in excess of our anticipated maximum liquidity requirements through the end of 2011.

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, 2011 were as follows:

	As of September 30, 2011
Company/Facility	Total Facility		Usage			Available Liquidity		Expiration     Date	Primary Purpose
		Millions
PSEG
5-year Credit Facility (A)	$	500	$	14	(C)	$	486	Dec 2012	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility		500		0			500	Apr 2016	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	14		$	986
Power
5-year Credit Facility (B)	$	1,600	$	120	(C)	$	1,480	Dec 2012	Funding/Letters of Credit
5-year Credit Facility		1,000		0			1,000	Apr 2016	Funding/Letters of Credit
Bilateral Credit Facility		100		100	(C)		0	Sept 2015	Letters of Credit
Total Power	$	2,700	$	220		$	2,480
PSE&G
5-year Credit Facility	$	600	$	0		$	600	Apr 2016	CP Support/Funding/ Letters of Credit
Total PSE&G	$	600	$	0		$	600
Total	$	4,300				$	4,066

(A) In December 2011, this facility will be reduced by $23 million.

(B) In December 2011, this facility will be reduced by $75 million.

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

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In April 2011, PSEG, Power and PSE&G entered into new 5-year credit agreements in the amounts of $500 million, $1 billion and $600 million, respectively. These new agreements will expire in April 2016. Concurrently, PSEG reduced its existing $1 billion credit facility to $500 million, Power terminated its existing $350 million credit facility, and PSE&G terminated its existing $600 million credit facility. As a result of these changes, Power’s total credit capacity increased by $650 million which increased our total credit capacity to $4.3 billion.

Long-Term Debt Financing

As of September 30, 2011, Power and PSE&G have $710 million and $564 million (excluding securitized debt), respectively, of Long-Term Debt due within one year. At Power, this includes $44 million of its senior notes servicing and securing the tax exempt bonds of the Pennsylvania Economic Development Financing Authority that have a letter of credit expiring in December 2011, $66 million of 5.00% Pollution Control Notes due in March 2012 and $600 million of 6.95% Senior Notes due in June 2012.

PSE&G’s amount includes $264 million of its Mortgage Bonds servicing and securing the tax exempt bonds of the Pollution Control Financing Authority of Salem County and the New Jersey Economic Development Authority (New Jersey Tax-Exempt Bonds), each of which is subject to a mandatory put in the fourth quarter of 2011, and $300 million of 5.125% Series B MTNs due in September 2012.

Power and PSE&G expect that they will have sufficient liquidity or be able to access the capital markets to redeem or refinance their remaining debt obligations as they mature.

PSE&G has filed a petition with the BPU for continued authority through 2013 to issue long-term debt to refund maturities and fund PSE&G’s capital program.

For a discussion of our long-term debt transactions during 2011, including actions related to the $264 million of the New Jersey Tax Exempt Bonds, see Note 9. Changes in Capitalization.

Common Stock Dividends

For information related to cash dividends on our common stock, see Note 15. Earnings Per Share.

We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.

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 2011, S&P published an updated credit opinion which left the ratings for PSEG, Power and PSE&G unchanged and improved their outlooks to positive from stable. In May 2011, Moody’s affirmed its ratings for PSEG, Power and PSE&G. PSE&G’s outlook was improved to positive from stable while the outlooks at PSEG and Power remain at stable. In August 2011, Fitch affirmed its ratings for PSEG, Power and PSE&G and kept all outlooks at stable. In October 2011, S&P published updated research on Power and PSE&G, which left their ratings and outlooks unchanged.

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

It is expected that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected construction and investment amounts for the years 2011 through 2013 were revised subsequent to the Annual Report on Form 10-K for the year ended December 31, 2010 and reported in the Quarterly Report on Form 10Q for the quarter ended June 30, 2011. The revised amounts reflected an increase of approximately $670 million for PSE&G, due primarily to extensions to the Capital Economic and Energy Efficiency Economic Stimulus Programs, which were approved by the BPU in July, and revisions to our anticipated spend for various transmission projects. In addition, we had removed $530 million of discretionary expenditures for non-utility renewables from our projections. We will continue to approach non-regulated solar and other renewables investments opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.

There were no material changes to our projected capital expenditures at Power or PSE&G as compared to the updated amounts disclosed in the Quarterly Report on Form 10Q for the quarter ended June 30, 2011.

Power

During the nine months ended September 30, 2011, Power made $410 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $120 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 8. Commitments and Contingent Liabilities.

PSE&G

During the nine months ended September 30, 2011, PSE&G made $973 million of capital expenditures, including $939 million of investment in plant, primarily for reliability of transmission and distribution systems and $34 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $43 million, which are included in operating cash flows.

ACCOUNTING MATTERS

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

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The 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

We use VaR models to assess the market risk of our commodity businesses. The portfolio VaR model includes our owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. 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.

Non-trading MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The non-trading 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 MTM derivatives that are not hedges are included in the trading VaR.

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

As of September 30, 2011, there was no trading VaR. As of December 31, 2010, trading VaR was $1 million.

For the Three Months Ended September 30, 2011	Trading     VaR		Non-Trading MTM VaR
	Millions
95% Confidence level,
Loss could exceed VaR one day in 20 days
Period End	$	0	$	7
Average for the Period	$	0	$	9
High	$	0	$	14
Low	$	0	$	7
99.5% Confidence level,
Loss could exceed VaR one day in 200 days
Period End	$	0	$	11
Average for the Period	$	0	$	14
High	$	0	$	22
Low	$	0	$	10

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

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer and Chief Financial Officer 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 Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each 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 2011 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. In addition, both PSE&G and Power have filed appeals of the March 2011 BPU order approving the SOCAs to the New Jersey Superior Court Appellate Division. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the 2010 Annual Report on Form 10-K, see Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.

Certain information reported under the 2010 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011 are updated below. References are to the related pages on the Form 10-K or Forms 10-Q as printed and distributed.

Long-Term Capacity Agreement Pilot Program (LCAPP)

December 31, 2010 Form 10-K page 47, March 31, 2011 Form 10-Q, page 66 and June 30. 2011 Form 10-Q page 80. In February 2011, we joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the LCAPP Act under the Supremacy and Commerce clauses of the United States Constitution. The complaint seeks declaratory and injunctive relief. The proceeding is now in the discovery phase. The BPU filed a motion to dismiss this federal action, which the court denied in October 2011. PSE&G and Power, along with other parties, including the New Jersey EDCs, have filed an appeal in the New Jersey Superior Court Appellate Division in the summer of 2011 of the BPU’s order implementing the LCAPP Act. The court denied the Division of Rate Counsel’s motion to dismiss the EDCs’ appeal, and this appeal remains pending. For additional information, see Item 5. Other Information.

Electric Discount and Energy Competition Act (Competition Act)

December 31, 2010 Form 10-K page 48, March 31, 2011 Form 10-Q, page 66 and June 30, 2011 Form 10-Q page 80 . In April 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

In July 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In October 2007, the Court granted PSE&G motion to dismiss the amended Complaint and in November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court. In February 2009, the New Jersey Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division’s decision.

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G’s motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. In June 2011, the plaintiff/petitioner filed a notice of appeal with the New Jersey Appellate Division. A briefing schedule has been established.

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ITEM 1A. RISK FACTORS

The Risk Factors shown below revise those disclosed in Part I Item 1A of our 2010 Annual Reports on Form 10-K and are to be added to those disclosed in Part II Item 1A of our March 31, 2011 and June 30, 2011 Quarterly Reports on Form 10-Q.

We are subject to comprehensive and evolving regulation by federal, state and local regulatory agencies that affects, or may affect, our businesses.

December 31, 2010 Form 10-K page 36. Comply with regulatory requirements—There are Federal standards, including mandatory cybersecurity standards, in place to ensure the reliability of the U. S. electric transmission and generation system and to prevent major system black-outs.

We have been, and will continue to be, periodically audited by NERC for compliance. FERC can impose penalties up to $1 million per day per violation. Further, FERC requires compliance with all of its rules and orders, including rules concerning Standards of Conduct, market behavior and anti-manipulation rules, interlocking directorate rules and cross-subsidization.

The BPU conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. We are in the process of undergoing a management audit and an affiliate transactions audit. While we believe that we are in compliance, we cannot predict the outcome of such audits.

Acts of war, terrorism or cybersecurity breaches could adversely affect our operations.

December 31, 2010 Form 10-K page 43. Our businesses and industry may be impacted by acts and threats of war, terrorism or cybersecurity breaches. These actions could result in increased political, economic and financial market instability and volatility in fuel prices which could materially adversely affect our operations. In addition, our infrastructure facilities, such as our generating stations, transmission and distribution facilities and information management systems for customer-related operations, could be direct or indirect targets or be affected by terrorist activity or cybersecurity incidents, which could impact operations and result in increased capital, insurance and operating costs, including increased security costs for our facilities.

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 2011:

Three Months Ended September 30, 2011	Total Number of Shares Purchased		Average Price Paid per Share
July 1-July 31		0	$	0
August 1-August 31		0	$	0
September 1-September 30		27,000	$	34.40

ITEM 5. OTHER INFORMATION

Certain information reported under the 2010 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2010 Annual Report on Form 10-K and the Quarterly Reports on Form 10-Q for the Quarters Ended March 31, 2011 and June 30, 2011. References are to the related pages on the Form 10-K or 10-Q as printed and distributed.

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FEDERAL REGULATION

FERC

Regulation of Wholesale Sales—Generation/Market Issues/Market Design Issues

December 31, 2010 Form 10-K page 18. Cost-Based RMR Agreements—FERC has permitted public utility generation owners to enter into RMR agreements that provide cost-based compensation to a generation owner when a unit proposed for retirement is asked to continue operating for reliability purposes. In November 2010, PJM officially notified Power that it would need the Hudson 1 generating station to remain in service through September 1, 2012 to ensure grid reliability during the summer of 2012 given the delays associated with the Susquehanna-Roseland project. In January 2011, we filed at FERC for extension of the RMR agreement for Hudson Unit 1 through September 1, 2012. FERC granted this extension in an order issued in May 2011. In June 2011, however, Power asked PJM to re-evaluate whether the extension of the RMR contract is necessary. In August 2011, PJM determined that such an extension was not needed and stated that it would be releasing the RMR contract. Accordingly, Power filed with FERC to notify FERC that PJM had terminated RMR services from Hudson Unit 1 as of December 7, 2011. Also in September, Power informed PJM that it was retiring Hudson Unit 1 as of December 8, 2011.

Capacity Market Issues

December 31, 2010 Form 10-K page 19, March 31, 2011 Form 10-Q page 67 and June 30, 2011 Form 10-Q page 82. In an attempt to stimulate the development of new generation capacity in New Jersey through a subsidized rate mechanism, in January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 MW of baseload or mid-merit electric power generation. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of 1,949 MW of new combined-cycle generating facilities located in New Jersey. The BPU decision required the New Jersey electric distribution companies, including PSE&G, to execute the BPU approved financially settled standard offer capacity agreements (SOCAs) with each of the three selected generators. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term in order to receive the subsidy. Each of the New Jersey EDCs, including PSE&G, executed SOCAs with the three generators in compliance with the BPU’s directive, but did so under protest reserving its legal rights. Both PSE&G and Power together with other parties, including the New Jersey EDCs, filed appeals of the BPU order to the New Jersey Superior Court Appellate Division. The Division of Rate Counsel filed a motion to dismiss the EDCs’ appeal, which was denied by the Appellate Division.

PSEG joined a group of generators and filed a complaint at FERC in February 2011. Also in February 2011, PJM filed with FERC to update and simplify the minimum offer price rule (MOPR). In April 2011, FERC issued an order making effective changes to the PJM Tariff that would require new generation to clear in the RPM at competitive prices which would mitigate, but not eliminate, the impacts of the subsidized SOCA pricing upon RPM auction prices. This order has been challenged by the BPU and other parties on rehearing. On July 29, 2011, the FERC held a technical conference to consider whether resources that engage in self-supply should be exempted from MOPR requirements. PJM has taken the position that it should be granted more discretion to evaluate bids impacted by the MOPR and determine whether a bidder’s costs are legitimately below the MOPR level. In October, one of the three selected generators served PSE&G with a notice of dispute under the SOCA claiming that the April 2011 FERC order regarding the MOPR and PJM’s subsequent compliance filing constitutes a material modification in PJM’s RPM that the generator alleges will adversely affect its performance under the SOCA.

There is also an ongoing stakeholder proceeding being held at PJM examining the scope of the self-supply exemption. The LCAPP Act is also being challenged in court. We joined a group filing a complaint in U.S. District Court in New Jersey arguing that the legislation is unconstitutional and should be invalidated. This court action is currently in the discovery phase. In October 2011, the Court denied the BPU’s motion to dismiss this complaint.

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In May 2011, the BPU initiated a proceeding to evaluate whether there is a need for additional generation capacity in the state. In October, the BPU held a second legislative-type hearing in this proceeding to take further comments on the possible impediments to the development of new generation capacity in New Jersey as well as other matters concerning the PJM Interconnection L.L.C. (PJM) RTEP, the PJM interconnection processes and the competitiveness of the power market. The BPU schedule provides for Staff recommendations to be made to the BPU by the end of 2011.

In October 2011, another of the three selected generators filed a request for a declaratory order, or in the alternative, a complaint at FERC with respect to its efforts to interconnect its proposed generation facility to the PSE&G transmission system. The generator claims that PJM has refused to make certain changes in its modeling of the interconnection that the generator claims would significantly reduce its interconnection costs.

In September 2011, the Maryland Public Utility Commission issued an order requiring its EDCs to issue a Request for Proposal (RFP) by October 7, 2011 to procure up to 1,500 MW of new natural gas-fired generation located in the Southwest MAAC electrical region. The RFP would require up to a 20-year contract, with ratepayers paying the generator an amount that makes up the difference between the PJM price and the contract price (similar to the LCAPP SOCA). Maryland also announced that it would hold hearings in January to evaluate the need for this procurement. These developments in Maryland may influence developments in New Jersey regarding the construction of subsidized generation.

Transmission Regulation—Transmission Expansion

December 31, 2010 Form 10-K page 20, March 31, 2011 Form 10-Q page 68 and June 30, 2011 Form 10-Q page 83. We have not received certain environmental approvals that are required for each of the Eastern and Western segments of the Susquehanna-Roseland line and believe that it is now unlikely that we will obtain these approvals until early 2013, at the earliest. The Western portion of the line also requires certain permits from the National Park Service. In May, we received a letter from the National Park Service that postpones the agency’s issuance of a Record of Decision for this project until January 2013, which represents a three month delay from the previous schedule. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and it is June 2015 for the Western segment. Further delays are also possible for both portions; however, in October, the project was added to an initial list of projects for a new federal Rapid Response Team for Transmission. This team is intended to coordinate and expedite the federal permitting process for critical infrastructure upgrades such as the project. It is possible that the project’s placement on this list could result in our obtaining of a permit from the National Park Service by October 2012 but this cannot be predicted with certainty. Delays in the construction schedule could impact the timing of expected transmission revenues.

In October 2010, PJM approved the North East Grid project, a 230 kV project running from Roseland to Hudson. This project has an expected in-service date of June 2015 with an estimated cost of construction of up to $895 million. The North East Grid project was approved in place of a previously approved 500 kV Branchburg-Roseland-Hudson (B-R-H) project. The FERC has ruled that, with the exception of abandonment cost recovery, rate incentives we previously received for the B-R-H project were no longer applicable because the project had substantially changed. In October 2011, we filed a petition with FERC seeking incentive rates for the North East Grid project, specifically, inclusion of 100% of CWIP in rate base, recovery of 100% of prudently incurred abandonment costs and a 100% basis point adder to ROE. We are seeking an effective date of January 1, 2012.

PJM has approved in its Regional Transmission Expansion Plan several other 230 kV transmission projects to be constructed by PSE&G. In April 2011, we filed a petition with FERC seeking incentive rates for five of these projects (Burlington-Camden project, North Central Reliability project, the Mickleton-Gloucester-Camden project, Middlesex Switch Rack project and Bayonne-Marion project). For each of these projects, PSE&G requested inclusion of 100% of CWIP in rate base and recovery of 100% of prudently incurred abandonment costs with an effective date of June 14, 2011. In June 2011, the FERC granted the requested incentives for three of the projects (Burlington-Camden, North Central Reliability and Mickleton-Gloucester-Camden) with a total estimated capital investment of $1.0 billion, representing approximately 80% of our request.

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In May 2011, PSE&G filed a petition with the BPU to site the North Central Reliability project. This project, which will involve upgrading certain circuits and switching stations from 138 kV to 230 kV, is currently estimated to cost $336 million and has an in-service date of June 2014. The siting proceeding is currently in the discovery phase and, under the current procedural schedule, will conclude with a BPU decision expected to be issued in the first quarter of 2012.

Transmission Regulation—Transmission Policy Developments

December 31, 2010 Form 10-K page 20 and June 30, 2011 Form-10-Q page 83. In 2010, the FERC initiated a rulemaking proceeding to evaluate whether reforms were necessary to current transmission planning and cost allocation rules to stimulate additional transmission development. The rulemaking also addressed the issue of whether the ROFR contained in FERC-approved tariffs and contracts, under which incumbent transmission companies have a ROFR to build transmission located within their respective service territories, should be eliminated. On July 21, 2011, the FERC issued a Final Rule in this proceeding. The Final Rule, among other things (i) directs regional planners such as PJM to modify their planning processes to “consider transmission needs driven by public policy requirements established by state or federal laws or regulations” (ii) directs regional planners to remove the ROFR from its tariffs and agreements, subject to exceptions for certain types of projects and subject to a back-stop mechanism that may permit incumbent transmission owners to step in and build transmission if third party developers’ projects are delayed (iii) requires regional planners to develop regional cost allocation methodologies consistent with certain articulated principles, including that costs be “roughly commensurate” with project benefits and (iv) requires regional planners in neighboring regions to have a common interregional cost allocation method for new interregional facilities. PSEG and many other parties to the proceeding have sought rehearing of the Final Rule, which remains pending. Ultimate judicial appeals are likely. An expected outcome of this Final Rule is the construction of more transmission through “public policy” planning and the opening up of transmission construction and ownership to third party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specific implementation of the Final Rule in the various regions, including within our service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.

Commodity Futures Trading Commission (CFTC)

December 31, 2010 Form 10-K page 22, March 31, 2011 Form 10-Q page 69 and June 30, 2011 Form 10-Q page 84. In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was passed in an attempt to reduce systemic risk in the financial markets thereby preventing future financial crises and market issues such as those experienced recently. As part of this new legislation, the SEC and the CFTC will be implementing new rules to enact stricter regulation over swaps and derivatives since many of the issues experienced were caused by derivative trading in connection with mortgage loans. Additionally, the Dodd-Frank Act will require many swaps and other derivative transactions to be standardized and traded on exchanges or other Derivative Clearing Organizations (DCOs).

The CFTC has issued NOPRs on many of the key issues, including:

• defining swaps,

• defining swap dealers and major swap participants,

• the end-user exception from clearing requirements,

• position limits,

• margin requirements,

• capital requirements, and

• reporting requirements.

Exchanges and DCOs typically require full collateralization of all transactions taking place on the exchange or DCO. Although the Dodd-Frank Act specifically recognizes a commercial end user exemption from posting additional collateral in the bilateral Over the Counter swap and derivative markets, we cannot assess the exact scope of the new rules until the SEC and CFTC issue them. Under the current NOPRs, the broad definition of

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swap dealer could result in us being classified as a dealer, which would limit the benefits of the commercial end-user exemption recognized in the Act. We believe that any regulatory change that deviates from the original intent would need to be addressed by additional legislation.

Under the margin requirement NOPR, no margin would be applied to any transaction with an end-user, except for a proposal for banks that would impose a one-way margin flowing from the end-user to the bank for any transaction that exceeds a credit threshold set by the bank. Additional rules have been proposed that re-examine this end-user exemption, which could have adverse consequences upon Power.

We will carefully monitor these new rules as they are developed to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements.

Nuclear Regulatory Commission (NRC)

March 31, 2011 Form 10-Q page 70 and June 30, 2011 From 10-Q page 84. As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the NRC will be performing additional operational and safety reviews of nuclear facilities in the United States. These reviews and the lessons learned from the events in Japan may result in additional regulation for the nuclear industry and could impact future operations and capital requirements for our facilities. We believe that our nuclear plants meet the stringent applicable design and safety specifications of the NRC.

In July 2011, the NRC task force submitted a report on the first 90 days of its nuclear power plant review. The report contained various recommendations to ensure plant protection, enhance accident mitigation, strengthen emergency preparedness and improve NRC program efficiency. These recommendations include proposed requirements for upgraded seismic and flooding protection, strengthening plants’ ability to deal with prolonged loss of power and development of emergency plans for events involving multiple reactors. In October 2011, the NRC issued a document which provides for a prioritization of the task force recommendations. The NRC is proposing to issue letters and orders to licensees and create new regulations over a six-to-52 month period to address the task force recommendations.

Separately, a petition was filed with the NRC in April 2011 seeking suspension of the operating licenses of all General Electric boiling water reactors utilizing the Mark 1 containment design in the United States, including our Hope Creek and Peach Bottom units, pending completion of the NRC review. The petition names 23 of the total 104 active commercial nuclear reactors in the United States. While we do not believe the petition will be successful, we are unable to predict the outcome of any action that the NRC may take in connection with its operational and safety reviews or any other regulatory or industry responses to the events in Japan.

STATE REGULATION

Rates

Recent Rate Adjustments-Universal Service Fund(USF)/Lifeline

December 31, 2010 Form 10-K page 25. On June 30, 2011, the State’s electric and gas utilities filed to reset the statewide rates for the USF and Lifeline programs. The filed rates were subsequently updated and approved in a written order effective November 1, 2011. The approved USF rates are set to recover $242 million on a statewide basis. Of this amount, the electric rates are set to recover $185 million and the gas rates $57 million. The rates for the Lifeline program are set to recover $71 million, $49 million and $22 million for electric and gas, respectively. We earn no margin on collection of the USF and Lifeline programs, resulting in no impact on Net Income.

BGSS

December 31, 2010 Form 10-K page 27, March 31, 2011 Form 10-Q page 70 and June 30, 2011 Form 10-Q page 85. On June 1, 2011, PSE&G made its annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $16.1 million, excluding sales and use tax, to be effective October 1, 2011. This would represent a reduction of approximately 1.1% for a typical residential gas heating customer. On September 22, 2011, the BPU approved the Stipulation of the parties, which implements the filed BGSS rate, on a provisional basis, effective October 1, 2011. The proceeding has been transferred to the Office of Administrative Law (OAL).

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RGGI Recovery Charge (RRC)

June 30, 2011 Form 10-Q page 85. On October 1, 2010, we filed a petition with the BPU for an increase in the RGGI Recovery Charge (RRC), seeking to recover approximately $48 million in electric revenue and $11 million in gas revenue on an annual basis. The required annual filing seeks to reset the RRC rate components for five programs. These include Carbon Abatement, the Energy Efficiency Economic Stimulus Program, the Demand Response Program, Solar 4 All, and the Solar Loan II Program. Hearings in this proceeding have been scheduled for November but settlement discussions are ongoing.

Hurricane Irene

On August 26, 2011, we filed a petition with the BPU requesting permission to defer incremental storm related costs and the opportunity to seek recovery in our next base rate proceeding. We have deferred approximately $29 million in incremental Operation and Maintenance storm costs associated with Hurricane Irene.

The BPU has commenced an investigation of all four New Jersey EDCs to examine their preparations for, and performance during and after, Hurricane Irene. PSE&G, along with the other three EDCs, has received and responded to sets of questions from the BPU regarding storm preparedness, responsiveness and communications with elected officials and the public. In addition, the BPU is in the process of conducting several public hearings. It is not known at this juncture how long this investigation will last, whether it will turn into a formal, docketed proceeding or what will be the final outcome.

Energy Policy

Capital Economic Stimulus Infrastructure Program

December 31, 2010 Form 10-K page 29, March 31, 2011 Form 10-Q page 71 and June 30, 2011 Form 10-Q page 87. In January 2009, we filed for approval of a capital economic stimulus infrastructure investment program. Under this initiative, we proposed to undertake $698 million of capital infrastructure investments over a 24 month period. The goal of these accelerated capital investments is to help improve the State’s economy through the creation of new jobs. We made this filing in response to the Governor of New Jersey’s proposal to help revive the economy through job growth and capital spending.

In April 2009, the BPU approved 38 qualifying projects totaling $694 million. The Capital Adjustment Charge (CAC) was established to provide recovery prior to the inclusion of the investments in rates. It will be adjusted each January based on forecasted program expenditures and will be subject to deferred accounting.

We spent $180 million on approved infrastructure projects in 2009 and collected approximately $11 million through the CAC.

The CAC rates were adjusted on a provisional basis on January 1, 2010. At the conclusion of our base rate case in June and July 2010, the infrastructure projects that were placed in service through the end of 2009 were rolled into rate base and the CAC rates were adjusted accordingly, again on a provisional basis. We spent $408 million on approved infrastructure projects in 2010 and collected approximately $36 million through the CAC.

In November 2010, we made our second annual filing seeking an update to the CAC rates that would provide for approximately $25 million through June 2011 to cover the remaining $108 million infrastructure investments under the program.

Also in November 2010, we filed for an extension of the gas capital stimulus program, seeking BPU approval for approximately $78 million in gas infrastructure investments over a two-year period. In February 2011, we filed for an extension of the electric capital stimulus program, seeking BPU approval for approximately $229 million in electric infrastructure investments over a 26-month period.

In July 2011, the BPU approved settlement agreements resolving our November 2010 annual filing to update the CAC rates and our November 2010 and February 2011 filings to extend our gas and electric Capital Stimulus programs. As part of the settlement, PSE&G agreed to an established “base” spending level that includes additional electric and gas spending of approximately $96 million, apart from Capital Stimulus, for 2011 through 2012 for gas and 2011 through 2013 for electric. In September 2011, we filed a petition with the

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BPU to roll into rate base the initial Capital Stimulus investments not yet in base rates. PSE&G has spent $702 million in gas and electric Capital Stimulus Investments which completed the construction phase of the program.

Regarding the Capital Stimulus extension, the BPU also approved 30 qualifying projects totaling approximately $78 million and $195 million in expenditures for gas and electric, respectively, to be completed and placed in service by December 2012. Filings to implement rates to recover these costs will be made by November 1, 2011 and at the conclusion of the final qualifying projects.

LCAPP

See Federal Regulation—Capacity Market Issues above.

ENVIRONMENTAL MATTERS

Air Pollution Control

Clean Air Interstate Rule (CAIR), Clean Air Transport Rule (CATR) and Cross-State Air Pollution Rule (CSAPR)

December 31, 2010 Form 10-K page 31 and June 30, 2011 10-Q page 88. On July 6, 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR). CSAPR limits power plant emissions in 27 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions will be governed by this rule beginning on January 1, 2012 for SO₂ and “annual NOx” and May 1, 2012 for “Ozone season NOx”. Certain states will be required to make additional SO₂ reductions in 2014.

We continue to evaluate the impact of this rule on us due to many of the uncertainties that still exist regarding implementation. As we have made major capital investments over the past several years to lower the lower the SO₂ and NOx emissions of our fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania), we do not foresee the need to make significant additional expenditures to our generation fleet to comply with the regulation. As such, we believe this rule will not have a material impact to our capital investment program or units’ operations.

A challenge to the rule has been filed before the DC Court of Appeals. PSEG has intervened in the case in support of the EPA rule.

On October 14, 2011, the EPA issued draft technical adjustments to the final Cross-State Air Pollution Rule (CSAPR). Among the technical corrections proposed were adjustments to the annual NOx, ozone season NOx, and SO₂ emissions budgets for a number of states, including New Jersey and New York. Several PSEG plants in New Jersey had their emission budgets increased. Additionally, the EPA also proposed to delay the implementation of the assurance provision of the rule from 2012 to 2014 to promote the development of a liquid allowance market. These proposed changes will be open for public comment until November 28, 2011. The EPA will make a final determination shortly thereafter. If the EPA’s final determination is the same as has been proposed, PSEG views these changes as generally favorable.

Water Pollution Control

Permit Renewals

December 31, 2010 Form 10-K page 33, March 31, 2011 Form 10-Q page 72 and June 30, 2011 10-Q page 88. The use of cooling water is a significant part of the generation of electricity at steam-electric generating stations. Section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. The impact of regulations under Section 316(b) can be significant, particularly at steam-electric generating stations which do not have closed cycle cooling through the use of cooling towers to recycle water for cooling purposes. The installation of cooling towers at an existing generating station can impose significant

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engineering challenges and significant costs, which can affect the economic viability of a particular plant. In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule.

In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established impingement and entrainment mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power’s electric generating stations would be affected. 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 or results of operations. See Note 8. Commitments and Contingent Liabilities for additional information.

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ITEM 6. EXHIBITS

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

a. PSEG:

Exhibit 10: Amendment to Employment Agreement with William Levis, dated September 19, 2011

Exhibit 10.1: Supplemental Executive Retirement Income Plan as Amended

Exhibit 10.2: Retirement Income Reinstatement Plan for Non-Represented Employees as Amended

Exhibit 10.3: Deferred Compensation Plan for Certain Employees as Amended

Exhibit 10.4: Equity Deferred Plan for Employees

Exhibit 10.5: 2007 Equity Compensation Plan for Outside Directors as Amended

Exhibit 10.6: Deferred Compensation Plan for Directors as Amended

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 United States Code

Exhibit 32.1: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States 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 10: Amendment to Employment Agreement with William Levis, dated September 19, 2011

Exhibit 10.1: Supplemental Executive Retirement Income Plan as Amended

Exhibit 10.2: Retirement Income Reinstatement Plan for Non-Represented Employees as Amended

Exhibit 10.3: Deferred Compensation Plan for Certain Employees as Amended

Exhibit 10.4: Equity Deferred Plan for Employees

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 United States Code

Exhibit 32.3: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Exhibit 101.INS: XBRL Instance Document*

Exhibit 101.SCH: XBRL Taxonomy Extension Schema*

Exhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase*

Exhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase*

Exhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase*

Exhibit 101.DEF: XBRL Taxonomy Extension Definition Document*

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c. PSE&G:

Exhibit 10.1: Supplemental Executive Retirement Income Plan as Amended

Exhibit 10.2: Retirement Income Reinstatement Plan for Non-Represented Employees as Amended

Exhibit 10.3: Deferred Compensation Plan for Certain Employees as Amended

Exhibit 10.4: Equity Deferral Plan for Employees

Exhibit 10.5: 2007 Equity Compensation Plan for Outside Directors as Amended

Exhibit 10.6: Deferred Compensation Plan for Directors as Amended

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 United States Code

Exhibit 32.5: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States 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*

* XBRL information is furnished, not filed.

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SIGNATURE

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

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)
By:	/S/ DEREK M. DIRISIO
	Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: November 1, 2011

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SIGNATURE

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

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

Date: November 1, 2011

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SIGNATURE

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)
By:	/S/ DEREK M. DIRISIO
	Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: November 1, 2011

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EX-10

Exhibit 10

Margaret M. Pego Senior Vice President-Human Resources and Chief Human Resources Officer Human Resources 80 Park Plaza, T4, Newark, NJ 07102 tel: 973-430-7243 fax: 973-643-6063 email: Margaret.Pego@pseg.com

September 19, 2011

Mr. William Levis

25 South Lincoln Avenue

Newtown, Pennsylvania 18940

RE: CHANGE TO LIMITED PLAN BENEFIT

Dear Bill:

This letter addresses the change to the Supplemental Executive Retirement Income for Non-Represented Employees (“SERP”) as a result of the changes in the benefit formula to the Pension Plan for Public Service Enterprise Group Incorporated (the “Pension Plan”).

Your December 8, 2006 employment offer letter provides that your Limited Plan Benefit is a percentage of your final average earnings, less the aggregate value of certain other benefits. Although you are not a Pension Plan participant, the 5-year final average earnings calculation currently used in the Limited Plan Benefit formula under the SERP is the same as that used in the Pension Plan formula. Effective January 1, 2012, the formula under the Pension Plan for MAST employees is changing from a 5-year final average earnings calculation to a 7-year final average earnings calculation. For consistency with the current plan design of the Pension Plan and the SERP, the Company decided to also change the formula for Limited Plan Benefits to a 7-year final average earnings calculation.

As such, it is requested that you consent to the following as a modification to your Limited Plan Benefit:

Effective January 1, 2012, your Limited Plan Benefit will be equal to (a) amount calculated as of December 31, 2011 using 5-year final average earnings, plus (b) amount calculated after December 31, 2011 using 7-year final average earnings.

W. Levis 2 9/19/11            

All other components of your Limited Plan Benefit will be calculated in accordance with the terms of the SERP, including but not limited to the application of the 30 points in the Limited Plan Benefit formula. The 30 points will be prorated based on the number of your actual years of credited service that you have as of December 31, 2011 and that you accrue during the period beginning on January 1, 2012 and ending on your termination date.

If you are in agreement with the above, please confirm below and return to me.

Sincerely,

/s/ Margaret M. Pego

Margaret M. Pego

Senior Vice President – Human Resources and Chief Human Resources Officer

Agreed to on this 20th day of Sep 2011

/s/ William Levis

William Levis

EX-10.1

Exhibit 10.1

SUPPLEMENTAL EXECUTIVE RETIREMENT INCOME PLAN

FOR NON-REPRESENTED EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

Effective as of May 31, 2011

TABLE OF CONTENTS

Section 1.	Definitions	3
Section 2.	Additional Service Credit Participants	9
Section 3.	Additional Service Credit Supplemental Retirement Benefit	10
Section 4.	Additional Service Credit Supplemental Surviving Spouse Benefit	13
Section 5.	Additional Limited Benefits	14
Section 6.	Administration of the Plan	20
Section 7.	Claims Procedure and Status Determination	21
Section 8.	Amendment or Termination	22
Section 9.	General Provisions	22
Section 10.	Miscellaneous	24
	Schedule A	25
.	Schedule B	26

SUPPLEMENTAL EXECUTIVE RETIREMENT INCOME PLAN

FOR NON-REPRESENTED EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

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

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

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

Effective as of January 1, 2012, the benefit formula under the Pension Plan is changing from a 5-year final average pay formula to a 7-year final average pay formula. The change in the benefit formula under the Pension Plan affects the benefits provided under the Plan. Accordingly, the Plan is being amended effective January 1, 2012 to reflect these changes.

Section 1. Definitions

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

1.1 “Affiliate” shall mean (a) any organization while it is a member of a controlled group of corporations (as defined in Code Section 414(b)) which includes the Company; or (b) any trades or businesses (whether or not incorporated) while they are under common control (as defined in Code Section 414(c), as modified by Code Section 415(h)) with the Company.

1.2 “Beneficiary” shall mean any person or persons selected by a Participant on a form provided by the Company who may become eligible to receive the benefits provided under this Plan in the event of such Participant’s death.

1.3 “Benefit Commencement Date” shall mean the date on which a Participant’s Supplemental Retirement Benefit shall commence or be paid under this Plan.

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

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

1.6 “CEO” shall mean the Chief Executive Officer of Public Service Enterprise Group Incorporated. If Public Service Enterprise Group Incorporated shall have no designated Chief Executive Officer, “CEO” shall mean the President of Public Service Enterprise Group Incorporated.

1.7 “Change in Control” shall, for the purposes of the Subsection 11.2 of this Plan, mean the occurrence of any of the following events:

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

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

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

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

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

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

1.9 “Committee” or “Employee Benefits Committee” shall mean the Employee Benefits Committee of the Company.

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

1.11 “Compensation” with respect to any Participant shall mean the total remuneration paid for services rendered to the Company, determined without regard to the exclusion of any amounts pursuant to Subsection 1.10(a) of the Pension Plan or Subsection 1.1(m)(1) of the Cash Balance Plan, but excluding:

(a) the Company’s cost for any public or private employee benefit plan other than elective contributions that are made by the Company on behalf of a Participant that are not includable in income under Section 125, 132(f), or 401(k) of the Code; and

(b) all awards to the Participant under the Company’s Long-Term Incentive Compensation Plan.

For purposes of calculating the supplemental retirement benefit payable pursuant to Section 3 of this Plan to a Participant who is a participant in the Cash Balance Plan, Compensation shall include amounts paid in 2006 or later years under the SMICP, the MICP or the ER&T Program. Compensation for any such year shall not exceed 150 percent of the Participant’s annual base salary in effect as of January 1 of that year.

1.12 “Credited Service” shall mean the aggregate of all periods of employment with the Company, an Affiliate or former Affiliate and all periods of additional service credit granted to Participants listed on Schedule A by the Company for which a Participant will be given credit in computing his/her Supplemental Retirement Benefit.

1.13 “Employee” shall mean any individual in the employ of the Company or a Participating Affiliate who is not included within a unit of employees covered by a collective bargaining agreement and who is receiving remuneration for personal services rendered to the Company or Participating Affiliate other than (a) solely as a director of the Company or a Participating Affiliate, (b) as a consultant, (c) as an independent contractor, (d) an individual who is a “leased employee” within the meaning of Code section 414(n), or (e) any other individual engaged by the Company or Participating Affiliate in a relationship that the Company characterizes as other than an employment relationship or who has waived his/her rights to coverage as an employee (regardless of whether a determination is made by the Internal Revenue Service or other governmental agency or court after the individual is engaged to perform such services that the individual is an employee of the Company or Participating Affiliate for the purposes of the Code or otherwise).

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

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

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1.16 “ER&T Program” shall mean the PSEG Power LLC Incentive Compensation Program for PSEG Energy Resources & Trade LLC Employees and each predecessor, successor or replacement plan.

1.17 “Human Resources Department” shall mean the Human Resources Department of the Company’s subsidiary, PSEG Services Corporation.

1.18 “LTIP” shall mean the Public Service Enterprise Group Incorporated 2004 Long-Term Incentive Plan and each predecessor, successor or replacement plan.

1.19 “MICP” shall mean the Public Service Enterprise Group Incorporated Management Incentive Compensation Plan and each predecessor, successor or replacement plan.

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

1.21 “Participant” shall mean any Employee or former Employee who meets the requirements of Subsections 2 or 5 of this Plan.

1.22 “Participating Affiliate” shall mean any Affiliate of the Company which (a) is the sponsor or a Participating Affiliate of the Pension Plan and/or the Cash Balance Plan; (b) adopts this Plan with the approval of the Board of Directors; (c) authorizes the Board of Directors and the Employee Benefits Committee to act for it in all matters arising under or with respect to this Plan; and (d) complies with such other terms and conditions relating to this Plan as may be imposed by the Board of Directors.

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

1.24 “Pension Plan Retirement Benefit” shall mean the aggregate annual benefit payable to a Participant pursuant to the Pension Plan or the Cash Balance Plan, as the case may be, by reason of the Participant’s termination of employment with the Company and all Affiliates for any reason other than death.

1.25 “Pension Plan Surviving Spouse Benefit” shall mean the aggregate annual benefit payable to the Surviving Spouse of a Participant pursuant to the Pension Plan or the Cash Balance Plan, as the case may be, in the event of the death of the Participant at any time prior to commencement of payment of the Participant’s Pension Plan Retirement Benefit.

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

1.27 “Plan Year” shall mean the calendar year.

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1.28 “Retirement” shall mean:

(a) in the case of a Participant who is a participant in the Pension Plan, a Separation from Service either (1) after attaining age 65; or (2) following the date when the sum of the Participant’s age and credited service (as defined in the Pension Plan) equals or exceeds 80.

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

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

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

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

1.32 “Retirement Plans” shall mean all qualified or nonqualified retirement benefits plans maintained by employers other than the Company or any of its Affiliates.

1.33 “SMICP” shall mean the Public Service Enterprise Group Incorporated Senior Management Incentive Compensation Plan and each predecessor, successor or replacement plan.

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

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

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

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

8

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

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

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

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

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

1.36 “Supplemental Retirement Benefit” shall mean the benefit payable to a Participant pursuant to this Plan by reason of the Participant’s Separation from Service with the Company and all Affiliates for any reason other than death.

1.37 “Surviving Spouse” shall mean a person who is married to a Participant or is the domestic partner in a legally recognized same sex civil union under applicable state law of a Participant at the date of the Participant’s death.

1.38 “Supplemental Surviving Spouse Benefit” shall mean the benefit payable to a Surviving Spouse pursuant to this Plan.

1.39 “Voting Stock” shall mean the outstanding stock of a corporation entitled to vote in the election of the directors of that corporation

Section 2. Additional Service Credit Participants

2.1 Each Employee who is selected by the CEO to participate in this Plan and be granted extra service credit shall be listed in Schedule A. Upon selection for participation in the

9

Plan, the CEO shall designate the number of years of additional Credited Service to which such Participant shall be entitled to be credited in calculating his/her Supplemental Retirement Benefit under Section 3 of this Plan. Schedule A shall include the name of each selected Participant and the number of years of additional Credited Service to which each such Participant shall be entitled to be credited.

Each Participant listed on Schedule A that incurs a Separation from Service after becoming vested in his benefits payable under the Pension Plan or the Cash Balance Plan shall be eligible to receive a Supplemental Retirement Benefit pursuant to Section 3 of this Plan. The Surviving Spouse of a Participant described in the preceding sentence who dies prior to commencement of payment of his Reinstatement Plan Retirement Benefit shall be eligible to receive a Supplemental Surviving Spouse Benefit pursuant to Section 4 of this Plan.

Effective January 1, 2011, no Employee shall become a Participant in the Plan with respect to benefits provided in Sections 2 through 4 of the Plan.

Section 3. Additional Service Credit Supplemental Retirement Benefit

3.1 The Additional Service Credit Supplemental Retirement Benefit payable to an eligible Participant under this section shall be equal to the excess of (a) over (b) where:

(a) is the sum of (i) the amount of Pension Plan Retirement Benefit or Cash Balance Pension Plan Retirement Benefit, and (ii) the amount of Reinstatement Plan Supplemental Retirement Benefit to which the Participant would have been entitled as of his/her Normal Retirement Date if such benefits were computed with the additional years of Credited Service provided for in Subsections 5.4(a)(i)(y) and 5.4(b)(i)(y) of this Plan; and

(b) is the sum of: (i) the Pension Plan Retirement Benefit or Cash Balance Pension Plan Retirement Benefit, or (ii) and Reinstatement Plan Retirement Benefit, actually payable to the Participant or payable to a third party on the Participant’s behalf as of his/her Normal Retirement Date.

For Pension Plan Participants who incur a Separation from Service after December 31, 2011, the additional years of Credited Service shall be applied to the 7-year final average pay formula for the Pension Plan Retirement Benefit and Reinstatement Plan Supplemental Retirement Benefit.

The amounts described in (a) and (b) shall be computed as of the date of Separation from Service of the Participant with the Company and all Affiliates in the form of a single life annuity payable over the lifetime of the Participant only commencing on his/her Normal Retirement Date.

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This Additional Service Credit Supplemental Retirement Benefit shall be calculated as a single life annuity commencing on the Participant’s Normal Retirement Date. If payment of a Participant’s Additional Service Credit Supplemental Retirement Benefit commences or is paid before his/her Normal Retirement Date, the benefit amount calculated pursuant to this paragraph (a) shall be reduced for early commencement in accordance with the early retirement reduction factors applicable to calculation of the Participant’s benefit under the Pension Plan or Cash Balance Plan, as applicable.

3.2 The Additional Service Credit Supplemental Retirement Benefit payable to a Participant shall be paid as follows:

(a) If the Participant’s Separation from Service occurs prior to Retirement, the present value of his/her Additional Service Credit Supplemental Retirement Benefit shall be paid in a single lump sum distribution.

(b) Except as provided in Subsection 3.2(e), if the Participant’s Separation from Service occurs on or after his/her Retirement, the Participant may elect to receive his/her Additional Service Credit Supplemental Retirement Benefit in the form of a single life annuity or a joint and survivor annuity.

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

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

(c) A Participant may elect an annuity form of payment pursuant to paragraph (b) at any time before his Benefit Commencement Date, provided that any election shall also apply to any benefits payable to the Participant under the Reinstatement Plan and Section 5 of this Plan. If a Participant fails to make a timely election, his Additional Service Credit Supplemental Retirement Benefit shall be paid in the form of:

(i) a single life annuity, if he/she is not married as of his Benefit Commencement Date; or

(ii) a 50 percent joint and survivor annuity with his/her spouse as Beneficiary, if he/she is married as of his Benefit Commencement Date.

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(d) If a Participant elects a joint and survivor annuity, but his/her Beneficiary dies before the Participant’s Benefit Commencement Date, the Participant’s Additional Service Credit Supplemental Retirement Benefit shall be paid in the form of a single life annuity unless the Participant validly elects a new form of payment pursuant to this subsection.

(e) Notwithstanding paragraphs (b), (c) and (d), if the Participant’s total vested benefit under this Plan, as presently valued at the time of commencement of the payment of such benefit, does not exceed $30,000, his/her benefit shall be paid in a single lump sum distribution.

3.3 Except as otherwise provided in this subsection, payment of a Participant’s Additional Service Credit Supplemental Retirement Benefit shall commence or shall be made as of the last day of the month in which the Participant’s Separation from Service occurs or as soon as administratively practicable after such date, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date.

If the Participant is a Specified Employee, payment of the Participant’s Additional Service Credit Supplemental Retirement Benefit shall commence or shall be made as of the last day of the month coinciding with or next following the six-month anniversary of the Participant’s Separation from Service. In any case where the payment of benefits is delayed pursuant to this paragraph, the Participant’s Additional Service Credit Supplemental Retirement Benefit shall be calculated as of the last day of the month in which the Participant’s Separation from Service occurs. Any annuity payments to which the Participant would be entitled during the first six months after his/her Separation from Service shall be accumulated and paid to the Participant without interest as of the last day of the month coinciding with or next following the six-month anniversary of his Separation from Service. If the Participant’s Additional Service Credit Supplemental Retirement Benefit is payable in the form of a lump sum distribution, the benefit shall be increased with interest at the rate of the first segment rate as determined pursuant to Section 417(e)(3)(C) and (D) of the Code for the second month preceding the first day of the Plan Year in which the Separation from Service occurs.

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

3.4 An Additional Service Credit Supplemental Retirement Benefit which is payable in any form other than a single life annuity shall be the actuarial equivalent of the Additional Service Credit Supplemental Retirement Benefit set forth in Subsection 3.1 above as determined by the same actuarial adjustments as those specified in the Pension Plan or Cash Balance Plan, as applicable, with respect to determination of the amount of retirement benefits payable pursuant

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to the Pension Plan or Cash Balance Plan, as applicable, on the date for commencement of payment hereunder.

3.5 If a Participant earns a further Additional Service Credit Supplemental Retirement Benefit after a Separation from Service, any annuity benefits being paid to the Participant shall be increased to reflect such additional accruals as of the January 1 following the Plan Year in which such additional benefit accrues. If the Participant received a lump sum distribution of his/her Additional Service Credit Supplemental Retirement Benefit as of the earlier Separation from Service, the value of the additional accruals shall be paid to him/her in a lump sum distribution as of the January 1 following the Plan Year in which such additional benefit accrues.

Section 4. Additional Service Credit Supplemental Surviving Spouse Benefit

4.1 If a Participant dies prior to commencement of payment of his/her Pension Plan Retirement Benefit under circumstances in which a Pension Plan Surviving Spouse Benefit is payable to his/her Surviving Spouse, then an Additional Service Credit Supplemental Surviving Spouse Benefit shall be payable to his/her Surviving Spouse as hereinafter provided. This Additional Service Credit Supplemental Surviving Spouse Benefit shall be equal to the excess of (a) over (b) where:

(a) is the sum of: (i) the amount of the Pension Plan Surviving Spouse Benefit or Cash Balance Pension Plan Surviving Spouse Benefit, and (ii) the amount of Reinstatement Plan Surviving Spouse Benefit to which the Surviving Spouse would have been entitled under the Pension Plan and the Reinstatement Plan, as applicable, as of the Participant’s Normal Retirement Date if such benefits were computed with the additional years of Credited Service provided for in Subsections 5.4(a)(i)(y) and 5.4(b)(i)(y); and

(b) is the sum of: (i) the Pension Plan Surviving Spouse Benefit or Cash Balance Pension Plan Surviving Spouse Benefit, and (ii) Reinstatement Plan Surviving Spouse Benefit actually payable to the Surviving Spouse as of the Participant’s Normal Retirement Date.

The Additional Service Credit Supplemental Surviving Spouse Benefit shall be calculated as a single life annuity commencing on the Participant’s Normal Retirement Date. If payment of the Additional Service Credit Supplemental Surviving Spouse Benefit commences or is paid before the Participant’s Normal Retirement Date, the benefit amount calculated pursuant to this subsection shall be reduced for early commencement in accordance with the reduction factors applicable to calculation of a Pension Plan Surviving Spouse Benefit.

4.2 The Additional Service Credit Supplemental Surviving Spouse Benefit shall be paid as follows:

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(a) If the Participant’s death occurs prior to Retirement, the present value of the Additional Service Credit Supplemental Surviving Spouse Benefit shall be paid in a single lump sum distribution.

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

4.3 Payment of the Additional Service Credit Supplemental Surviving Spouse Benefit shall commence or shall be made as of the last day of the month in which the Participant’s death occurs or as soon as administratively practicable after such date, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date.

Section 5. Additional Limited Benefits

5.1 Each Employee nominated by the CEO and designated by the Employee Benefits Policy Committee shall be a Schedule B Participant and shall be eligible to the benefits provided for in this Section 5. The CEO shall nominate such select and key Employees based upon such criteria as he shall deem appropriate due to the Employee’s responsibilities and opportunity to contribute substantially to the financial and operating objectives of the Company. The names of all Participants designated hereunder shall be listed in Schedule B to this Plan.

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

5.3 At Retirement, the Company shall provide each Schedule B Participant with an additional limited retirement benefit calculated as provided in this Section 5.

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

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5.4 The additional limited retirement benefit shall be calculated as follows:

(a) Pension Plan Participants:

(i) The Participant’s Compensation shall be multiplied by an amount equal to one one-hundredth of the sum of (x) the number of the Participant’s years of credited service under the Pension Plan at Retirement (including any additional years of age and service provided to the Participant in accordance with any employment, change in control, or similar arrangement applicable to the Participant so long as the Participant incurs a termination of service from the Company and its Affiliates during the two-year period commencing upon the date of a Change in Control), (y) the number of any additional years of service credit to which the Participant may be entitled from the Company under Section 2 of this Plan or any written arrangement with the Company or an Affiliate (excluding any written arrangement between the Company or an Affiliate and the Participant relating to a Change in Control), and (z) 30; but, in no event, shall the multiple be greater than 0.75.

(ii) The amount determined under subparagraph (i) of this Subsection 5.4(a) shall be reduced by the sum of (x) the amount the Participant would be entitled to at Retirement as an annual pension benefit under the Pension Plan and Section 3 of this Plan and the Reinstatement Plan calculated as a single life annuity payable at the Participant’s Normal Retirement Date (as defined under the Pension Plan) without reduction for any pre-retirement survivor’s option coverage or any reduction for early retirement, (y) 100% of the amount of the unreduced annual Social Security benefit to which the Participant would be entitled at age 65 (or such other age which may be established by the Social Security Administration from time to time as the earliest age at which a Participant may receive an unreduced benefit thereunder), assuming that the Participant has no earnings from the date of Retirement to age 65 (or such other applicable age), or, if greater, any disability benefit under Social Security to which the Participant may be entitled, and (z) the aggregate of the annual benefits to which the Participant is entitled under all Retirement Plans as of the date the Participant is employed by the Company or an Affiliate, such Social Security Benefits and benefits under all Retirement Plans to be calculated as single life annuities without any reductions, under rules, procedures and equivalents determined by the Committee. To determine the amounts referred to under (y) and (z) above, the Participant shall file a declaration of all such amounts with the Human Resources Department in such form as

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the Committee may require from time to time. No benefit shall be paid under the Plan until such a declaration, in satisfactory form, shall be so filed. If a Participant is granted a disability Social Security benefit, he/she shall notify the Company thereof within 30 days thereof, and the Participant’s retirement benefit under this section of the Plan shall be adjusted accordingly. The Company shall be entitled to rely on such statements in making payment, and if any such statement is incorrect or is not furnished, the Company shall be entitled to reimbursement from the Participant, the Beneficiary or their legal representatives for any overpayment and may reduce or suspend future payments to recover any such overpayment. In the event it is established to the satisfaction of the Committee, in its sole discretion, that any such statement was intentionally false or omitted, the Participant or Beneficiary shall be entitled to no further payments under this section of the Plan, and the Company shall be entitled to recover any payments made hereunder.

(iii) For Participants who incur a Separation from Service after December 31, 2011, the number of any additional years of service credited to a Participant under Subsection 5.4(a)(i)(y) of the Plan that a Participant may be entitled from the Company under Section 2 of this Plan or any written arrangement with the Company or an Affiliate shall be applied to the 7-year final average pay formula. The 30 points credited to a Participant under Subsection 5.4(a)(i)(z) of the Plan shall be prorated based on the number of actual years of Credited Service that a Participant has as of December 31, 2011 and has during the period beginning on January 1, 2012 and ending on the date he/she incurs a Separation from Service, without regard to any additional years of service credited to the Participant under Subsection 5.4(a)(i)(y) and without regards to any cap on Credited Service.

(b) Cash Balance Plan Participants:

(i) The Participant’s Compensation shall be multiplied by an amount equal to one one-hundredth of the sum of (x) the number of the Participant’s years of service under the Pension Plan with which such Participant would have been credited at Retirement had the Participant participated in the Pension Plan from his/her date of hire and including any additional years of age and service provided to the participant in accordance with any employment, change in control, or similar arrangement applicable to the Participant so long as the Participant incurs a termination of service from the Company and its Affiliates during the two-year period commencing upon the date of a Change in Control, (y) the number

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of any additional years of service credit to which the Participant may be entitled from the Company under Section 3 of this Plan or any written arrangement with the Company or an Affiliate (excluding any written arrangement between the Company or an Affiliate relating to a Change in Control) and (z) 30; but, in no event, shall the multiple be greater than 0.75.

(ii) The amount determined under subparagraph (i) of this Subsection 8.4(b) shall be reduced by the sum of (x) the amount the Participant would be entitled to at Retirement as an annual pension benefit under the Cash Balance Plan and Section 3 of this Plan and the Reinstatement Plan calculated as a single life annuity payable at the Participant’s Normal Retirement Date (as defined under the Cash Balance Plan), (y) 100% of the amount of the unreduced annual Social Security benefit to which the Participant would be entitled at age 65 (or such other age which may be established by the Social Security Administration from time to time as the earliest age at which a Participant may receive an unreduced benefit thereunder), assuming that the Participant has no earnings from the date of Retirement to age 65 (or such other applicable age), or, if greater, any disability benefit under Social Security to which the Participant may be entitled, and (z) the aggregate of the annual benefits to which the Participant is entitled under all Retirement Plans as of the date the Participant is employed by the Company or an Affiliate, such Social Security Benefits and benefits under all Retirement Plans to be calculated as single life annuities without any reductions, under rules, procedures and equivalents determined by the Committee. To determine the amounts referred to under (y) and (z) above, the Participant shall file a declaration of all such amounts with the Human Resources Department in such form as the Committee may require from time to time. No benefit shall be paid under the Plan until such a declaration, in satisfactory form, shall be filed. If a Participant is granted a disability Social Security benefit, he shall notify the Company thereof within 30 days thereof, and the Participant’s retirement benefit under this Plan shall be adjusted accordingly. The Company shall be entitled to rely on such statements in making payment, and if any such statement is incorrect or is not furnished, the Company shall be entitled to reimbursement from the Participant, the Beneficiary or their legal representatives for any overpayment and may reduce or suspend future payments to recover any such overpayment. In the event it is established to the satisfaction of the Committee, in its sole discretion, that any such statement was intentionally false or omitted, the Participant or Beneficiary shall be entitled to no further payments under this section of the Plan, and the Company shall be entitled to recover any payments made hereunder.

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(iii) For Participants who incur a Separation from Service after December 31, 2011, the number of any additional years of service credited to a Participant under Subsection 5.4(b)(i)(y) of the Plan that a Participant may be entitled from the Company under Section 2 of this Plan or any written arrangement with the Company or an Affiliate shall be applied to the 7-year final average pay formula. The 30 points credited to a Participant under Subsection 5.4(b)(i)(z) of the Plan shall be prorated based on the number of actual years of Credited Service that a Participant has as of December 31, 2011 and has during the period beginning on January 1, 2012 and ending on the date he/she incurs a Separation from Service, without regard to any additional years of service credited to the Participant under Subsection 5.4(b)(i)(y) and without regards to any cap on Credited Service.

(c) The annual amount determined under this Subsection 5.4 shall be paid in the form of a life annuity; either a single life annuity or a joint and survivor annuity, as elected by the Participant.

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

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

Notwithstanding the preceding provisions, if the present value of the Participant’s total vested benefit under this Plan does not exceed $30,000, his/her benefit shall be paid a single lump sum distribution.

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

(i) a single life annuity, if he/she is not married as of his/her benefit commencement date; or

(ii) a 50 percent joint and survivor annuity with his/her spouse as Beneficiary, if he/she is married as of his benefit commencement date.

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(e) Except as otherwise provided in this paragraph (e), payment of a Participant’s additional limited retirement benefit shall commence or shall be made as of the last day of the month in which the Participant’s Retirement occurs or as soon as administratively practicable after such date, but in no event later than the last day permitted under Code Section 409A for treating a delayed payment as having been made on such payment date.

If the Participant is a Specified Employee, payment of the Participant’s additional limited retirement benefit shall commence or shall be made as of the last day of the month coinciding with or next following the six-month anniversary of the Participant’s Retirement date. In any case where the payment of benefits is delayed pursuant to this paragraph, the Participant’s additional limited retirement benefit shall be calculated as of the last day of the month in which the Participant’s Retirement occurs. Any annuity payments to which the Participant would be entitled during the first six months after his Retirement shall be accumulated and paid to the Participant without interest as of the last day of the month coinciding with or next following the six-month anniversary of his Retirement. If the Participant’s additional limited retirement benefit is payable in the form of a lump sum distribution, the benefit shall be increased with interest at the first segment rate as determined pursuant to Code Section 417(e)(3)(C) and (D) for the second month preceding the first day of the Plan Year in which the Retirement occurs.

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

(f) If a Participant earns an additional limited retirement benefit after a Retirement, any annuity benefits being paid to the Participant shall be increased to reflect such additional accruals as of the January 1 following the Plan Year in which such additional limited retirement benefit accrues. If the Participant received a lump sum distribution of his additional limited retirement benefit as of the earlier Retirement, the value of the additional accruals shall be paid to him in a lump sum distribution as of the January 1 following the Plan Year in which such additional benefit accrues.

Notwithstanding the foregoing, if a Participant named in Subsection 5.3 earns an additional retirement benefit after December 31, 2008, the

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additional accruals shall be payable as of the Participant’s Retirement as otherwise provided in this Section 5.

Section 6. Administration of the Plan

6.1 The Committee shall be the named fiduciary of this Plan responsible for the general operation and administration of this Plan and for carrying out the provisions thereof. The Committee shall have discretionary authority to construe the terms of this Plan and shall be the final arbiter of any question that may arise under this Plan.

6.2 The Committee shall adopt such rules and procedures as it deems necessary and advisable to administer this Plan and to transact its business. Subject to the other requirements of this Section 6, the Committee may—

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

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

(c) consult with counsel, who may be counsel to the Company or an Affiliate; and

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

However, any action described in paragraphs (b) or (d) of this Subsection 6.2, and any modification or rescission of any such action, may be effected by the Committee only by a resolution approved by a majority of the Committee. The Committee shall be entitled to rely conclusively upon all tables, valuations, certificates, opinions and reports furnished by any actuary, accountant, controller, counsel or other person employed or engaged by the Committee with respect to this Plan.

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

6.4 In performing their duties, the members of the Committee shall act solely in the interest of the Participants in this Plan and their Beneficiaries and

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

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

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

6.5 In addition to any other duties the Committee may have, the Committee shall review the performance of all persons to whom the Committee shall have delegated or allocated fiduciary duties pursuant to the provisions of this Section 6.

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

6.7 No member of the Committee nor any delegate thereof shall be personally liable by virtue of any contract, agreement or other instrument made or executed by him/her or on his/her behalf in such capacity.

Section 7. Claims Procedure and Status Determination

7.1 Claims for benefits under this Plan and requests for a status determination shall be filed in writing with the Company.

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

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

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

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Section 8. Amendment or Termination

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

8.2 No amendment or termination of this Plan shall directly or indirectly deprive any current or former Participant, Beneficiary or Surviving Spouse of a previously acquired right unless such Participant or Beneficiary or legal representative shall consent to such change. Provided, further, however, that after a Change in Control, this Plan may not be terminated nor the benefit calculation reduced with respect to any Participant in the Plan on the date of such Change in Control unless such Participant or his/her Beneficiary or his/her legal representative shall consent to such change. No right to a death benefit under Subsection 5.2 of this Plan shall accrue until a Schedule B Participant’s death and no right to an additional limited retirement benefit under Subsection 5.3 of this Plan shall accrue until a Schedule B Participant’s Retirement.

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

Section 9. General Provisions

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

9.2 Except as otherwise expressly provided herein, all terms and conditions of the Pension Plan or the Cash Balance Plan, as the case may be, applicable to a Pension Plan Retirement Benefit or a Pension Plan Surviving Spouse Benefit shall also be applicable to a Supplemental Retirement Benefit or a Supplemental Surviving Spouse Benefits payable hereunder. Any Pension Plan Retirement Benefit or Pension Plan Surviving Spouse Benefit, or any other benefit payable under the Pension Plan or the Cash Balance Plan, as the case may be, shall be paid solely in accordance with the terms and conditions of the Pension Plan or the Cash Balance Plan, as the case may be, and nothing in this Plan shall operate or be construed in any way to modify, amend or affect the terms and provisions of the Pension Plan or the Cash Balance Plan, as the case may be.

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

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

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

9.6 No interest of any person or entity in, or right to receive a benefit under, this Plan shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment or other alienation or encumbrance of any kind; nor any such interest or right to receive a benefits be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings.

9.7 This Plan shall be construed and administered under the laws of the United States and the State of New Jersey to the extent not superseded by Federal law. This Plan is specifically intended to comply with the provisions of the American Jobs Creation Act of 2004 (the “AJCA”) and Section 409A of the Code and it shall automatically incorporate all applicable restrictions of the AJCA, the Code and its related regulations, and the Company will amend the Plan to the extent necessary to comply with those requirements. The timing under which a Participant will have a right to receive any payment under this Plan will be deemed to be automatically modified, and a Participant’s rights under the Plan limited to conform to any requirements under, the AJCA or the Code.

9.8 Actuarial assumptions to determine the present value of any benefit hereunder shall be the same as used to determine the present value of benefits under the Pension Plan or the Cash Balance Plan, as the case may be.

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

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

9.11 Any notice to a Participant, a Beneficiary or any legal representative hereunder shall be given in writing, by personal delivery, overnight express service or by United States mail, postage prepaid, addressed to such person’s last known address. Any notice to the Company or the Committee hereunder (including the filing of beneficiary designations) shall be given by delivering it in person or by overnight express service, or depositing it in the United States mail, postage prepaid, to the Secretary of the Employee Benefits Committee, Public Service Enterprise Group Incorporated, 80 Park Plaza, T10B, P.O. Box 1171, Newark, New Jersey, 07101.

9.12 Each Participant shall keep the Company informed of his/her current address and the current address of his/her spouse. The Company shall not be obligated to search for the whereabouts of any person. If the location of a Participant is not made known to the Company within three (3) years after the date on which payment of the Participant’s Supplemental Retirement Benefit may first be made, payment may be made as though the Participant had died at the end of the three-year period. If, within one additional year after such three-year period has elapsed, or, within three years after the actual death of a Participant, the Company is unable to locate any Surviving Spouse of the Participant, then the Company shall have no further obligation to pay any benefit hereunder to such Participant or Surviving Spouse or any other person and such benefit shall be irrevocably forfeited.

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

9.14 The invalidity or unenforceability of any provision hereof shall in no way affect the validity or enforceability of any other provision of this Plan.

9.15 Notwithstanding any of the preceding provisions of this Plan, none of the Company, the Committee or any individual acting as an employee or agent of the Company or the Committee shall be liable to any Participant, former Participant, Surviving Spouse or any other person for any claim, loss, liability or expense incurred in connection with this Plan.

Section 10. Miscellaneous

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

24

MID-CAREER HIRE PLAN

SCHEDULE A

PARTICIPANTS

NAME	TITLE
1. Booth, Brian C.	Director – NOS
2. Bruecks, Michael	Director Security
3. Canziani, Richard M.	Mgr. Maintenance Services
4. Davison, Paul J.	Director NOS
5. Dorsa Caroline	EVP & CFO (PSEG)
6. Izzo, Ralph	Chairman of Board, President & CEO-PSEG
7. Joyce, Thomas P.	President and CNO – Nuclear
8. Knaide, Kenneth M.	Dir. Engineering HC
9. Lopriore, Richard P.	President – Fossil
10. Pendleton, Donald D.	Health & Safety Administrator
11. Sheridan Jr., Ronald P.	CFAM Manager – Maintenance/WM/Projects

Revised – May 7, 2010

25

LIMITED SUPPLEMENTAL BENEFIT PLAN

SCHEDULE B

PARTICIPANTS

NAME	TITLE
1. Bishop, Craig, J.	Director – Business Solutions R
2. Braun, Robert C. (eff. 3/5/12)	SVP – Nuclear Operations
3. Brina, Cora	VP – HR Client Services
4. Brockman, Kenneth E.	Manager – Risk Mgmt.
5. Cardenas, Jorge L.	VP – Gas Delivery
6. Castellano, Raymond C.	Principal
7. Doherty, John F.	Associate Gen. Environ. Counsel
8. Dorsa Caroline (eff. 4/25/14)	EVP & CFO (PSEG)
9. Duddy, Kevin P.	Director Business Ops & HR Strategy
10. Fedak, Edward C.	Associate Gen. Corp Counsel
11. Frese, William E.	General Litigation Counsel
12. Graziano, Joseph	Director – Investments
13. Guida, Arthur S.	Director External Affairs & CMT Dev.
14. Izzo, Ralph	Chairman of Board, President & CEO-PSEG
15. Joyce, Thomas P. (eff. 9/22/11)	President and CNO – Nuclear
16. Krueger, Jr. Robert C.	VP – Assistant Controller – Tax
17. LaRocca, Peter W.	Disability Mgr.
18. LaRossa, Ralph A.	President & COO
19. Leibowitz, Donald S.	Associate Gen. Corp Counsel
20. Levis, William (eff. 1/16/13)	President & COO
21. Leyden, Shawn P.	VP – Commercial
22. Loxley, Colin J.	Distribution Business Team Leader R
23. Lynk, III, Frederick A.	Mgr. Mkt. Strategy & Planning
24. MacDonald, Joan c.	Dir. Portfolio Management
25. MacPhee, John P.	Associate Gen. Enviro Counsel
26. Mack, Ronald J.	Medical Director
27. Mahoney, Hugh	Ethnics Compliance Counsel
28. Mazzeo, Frank	Principal
29. McLaughlin, Patricia R.	VP – Fin – Energy Holdings & Serv. Corp.
30. Mehrberg, Randall E. (eff. 9/8/13)	EVP Strategy & Dev & Pres. PSEG Hold
31. Mnich, Lorraine	Mgr. Corp Capital Invest
32. Morrison, John W.	Technical Specialist
33. Orticelle, Arthur	Division Manager – Electric
34. Oster, Steven B.	Dir. Quantitative Analysis
35. Pego, Margaret M.	SVP – HR & Chief HR Officer
36. Perry, John F. (eff. 3/12/12)	VP – Hope Creek
37. Preston, Bruce	Dir. Environ Projects & Permitting
38. Quinn, Kevin J.	VP – Corporate Strategy

26

39. Scarlata, John P.	VP – Gas Supply
40. Schroeder, Brian H.	Mgr. IT Asset Management R
41. Senkewicz, John W.	Mgr. E&G Bus. Service Marketing
42. Smith, J. Brian	VP – Communications and Advertising.
43. Solowski, Stanley J.	Dir. Projects
44. Sugam, Richard J.	Dir. EH&S Compliance & Planning
45. Svenson, Eric B.	VP – Policy & Environ., Health & Safety
46. Tripodi, Raymond A.	Mgr. Transmission Permitting
47. Tuosto, Michael R.	General Manager Public Affairs
48. Wernsing, Richard W.	RCM Expert
49. Weyant, Donald W.	Regulatory LDR
50. Wohlfarth, David W.	VP – Gas Supply, PSEG ER&T

Revised – May 7, 2010

27

EX-10.2

Exhibit 10.2

RETIREMENT INCOME REINSTATEMENT PLAN

FOR NON-REPRESENTED EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

Amended May 31, 2011

Further amended November 1, 2011

TABLE OF CONTENTS

Section 1.	Definitions	3
Section 2.	Eligibility	9
Section 3.	Supplemental Retirement Benefit	9
Section 4.	Supplemental Surviving Spouse Benefit	12
Section 5.	Administration of the Plan	15
Section 6.	Claims Procedure and Status Determination	16
Section 7.	Amendment or Termination	16
Section 8.	General Provisions	17
Section 9.	Miscellaneous	19

RETIREMENT INCOME REINSTATEMENT PLAN

FOR NON-REPRESENTED EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

Public Service Electric and Gas Company previously established effective January 1, 1995, and currently maintains the Retirement Income Reinstatement Plan for Non-Represented Employees of Public Service Electric and Gas Company and its Affiliates. Effective December 13, 1999, Public Service Electric and Gas Company transferred sponsorship of the plan to the Company and renamed the plan the “Retirement Income Reinstatement Plan for Non-Represented Employees of Public Service Enterprise Group Incorporated and its Affiliates.” The Plan was further amended, effective as of January 1, 2005, as set forth in this document to conform with the requirements of the American Jobs Creation Act of 2004. This Plan was established for the purpose of assisting in attracting and retaining a stable pool of key managerial and professional talent and long-term key employee commitment by providing certain supplemental retirement benefits for certain of their employees who participate in the Pension Plan of Public Service Enterprise Group Incorporated (“Pension Plan”) or the Cash Balance Pension Plan of Public Service Enterprise Group Incorporated. This Plan is intended to constitute an unfunded “excess benefit plan” as defined in Section 3(36) of ERISA, to the extent it provides benefits that would be paid under the Pension Plan of Public Service Enterprise Group Incorporated or the Cash Balance Pension Plan of Public Service Enterprise Group Incorporated but for the limitations of Section 415 of the Code, and an unfunded plan of deferred compensation for a select group of management or highly compensated employees for purposes of Title 1 of ERISA, to the extent it provides other benefits.

The Plan was hereby amended, effective as of January 1, 2009, to provide for lump sum payments of certain benefits, to revise provisions relating to lump sum payments of de minimis benefits, to conform the Plan to certain requirements of Code Section 409A, and to make certain other style and conforming changes. The terms contained herein superseded all prior iterations of the Plan.

The Plan is being amended effective as of January 1, 2012 to reflect the change in the benefit formula under the Pension Plan from a 5-year final average pay formula to a 7-year final average pay formula.

Section 1. Definitions

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

1.1 “Affiliate” shall mean (a) any organization while it is a member of a controlled group of corporations (as defined in Code Section 414(b)) which includes the Company; or (b) any trades or businesses (whether or not incorporated) while they are under common control (as defined in Code Section 414(c)) with the Company.

1.2 “Beneficiary” shall mean any person or persons selected by a Participant on a form provided by the Company who may become eligible to receive the benefits provided under this Plan in the event of such Participant’s death.

1.3 “Benefit Commencement Date” shall mean the date on which a Participant’s Supplemental Retirement Benefit shall commence or be paid under Subsection 3.3.

1.4 “Benefit Limitation” shall mean the maximum annual benefit payable to a Participant under the Pension Plan or the Cash Balance Plan in accordance with Section 415 of the Code.

1.5 “Board of Directors” or “Board” shall mean the Board of Directors of the Company.

1.6 “Cash Balance Plan” shall mean the Cash Balance Pension Plan of Public Service Enterprise Group Incorporated (formerly known as the “Cash Balance Pension Plan of Public Service Electric and Gas Company”) and each successor or replacement plan.

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

1.8 “Company” shall mean Public Service Enterprise Group Incorporated.

1.9 “Compensation” with respect to any Participant shall mean the total remuneration paid for services rendered to the Company, determined without regard to the exclusion of any amounts pursuant to Subsection 1.10(a) of the Pension Plan or Subsection 1.1(m)(1) of the Cash Balance Plan, but excluding:

(a) the Company’s cost for any public or private employee benefit plan other than elective contributions that are made by the Company on behalf of a Participant that are not includable in income under Section 125, 132(f), or 401(k) of the Code; and

(b) all awards to the Participant under the Company’s Long-Term Incentive Compensation Plan.

For purposes of calculating the Supplemental Retirement Benefit payable to a Participant who is a participant in the Cash Balance Plan, Compensation shall include amounts paid in 2006 or later years under the Management Incentive Compensation Plan or the PSEG Power LLC Incentive Compensation Program for PSEG Energy Resources & Trade LLC Employees. Compensation shall also include all amounts paid under the Senior Management Incentive Compensation Plan (including amounts paid under the Senior Management Incentive Compensation Plan prior to January 1, 2011).

Compensation for any such year shall not exceed 150 percent of the Participant’s annual base salary in effect as of January 1 of that year.

4

1.10 “Compensation Limitation” shall mean the maximum amount of annual compensation under Section 401(a)(17) of the Code that may be taken into account in any Plan Year for benefit accrual purposes under the Pension Plan or the Cash Balance Plan.

1.11 “Employee” shall mean any individual in the employ of the Company or a Participating Affiliate who is not included within a unit of employees covered by a collective bargaining agreement. The term “Employee” shall not include a director of the Company or a Participating Affiliate who serves in no capacity other than as a director, a consultant or independent contractor doing work for the Company or a. Participating Affiliate or a person employed by a consultant or independent contractor doing work for the Company or a Participating Affiliate.

1.12 “Employee Benefits Committee” or “Committee” shall mean the Employee Benefits Committee of the Company.

1.13 “Employee Benefits Policy Committee” shall mean the Employee Benefits Policy Committee of Public Service Enterprise Group Incorporated.

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

1.15 “Final Earnings” with respect to a Participant who is entitled to a benefit under the Pension Plan:

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

(1) the Participant’s highest five years of Compensation, excluding any amounts received as an award under the Management Incentive Compensation Plan or the Senior Management Incentive Compensation Plan; and

(2) the five most recent awards paid under the Management Incentive Compensation Plan or the Senior Management Incentive Compensation Plan prior to the Participant’s Separation from Service.

Notwithstanding the foregoing, Final Earnings shall not exceed 150 percent of the average of the Participant’s annual base salary in effect as of January 1 for the five years prior to and including the year in which the Participant’s Separation from Service occurs, provided that, in the case of a Participant who receives an award under the ER&T Program, Final Earnings shall not be less than his Final Earnings determined as of December 31, 2006 in accordance with the preceding paragraph, without applying the 150 percent cap in the preceding sentence.

5

(b) With respect to a Participant who incurs a Separation from Service on or after January 1, 2012 and who is entitled to a benefit under the Pension Plan, Final Earnings shall mean:

(1) With respect to periods of service prior to January 1, 2012, the annual average of the sum, (i) the Participant’s highest five years of Compensation determined as of December 31, 2011, excluding any amounts received as an award under the Management Incentive Compensation Plan or the Senior Management Incentive Compensation Plan, and (ii) the five most recent awards paid under the Management Incentive Compensation Plan or the Senior Management Incentive Compensation Plan on or prior to December 31, 2011. Notwithstanding the foregoing, Final Earnings shall not exceed 150 percent of the average of the Participant’s annual base salary in effect as of January 1 for the five years prior to January 1, 2012, provided that, in the case of a Participant who receives an award under the ER&T Program, Final Earnings shall not be less than his Final Earnings determined as of December 31, 2006 in accordance with the preceding paragraph, without applying the 150 percent cap in the preceding sentence.

(2) With respect to periods of service after December 31, 2011, the annual average of the sum, (i) the Participant’s highest seven years of Compensation beginning after December 31, 2011, excluding any amounts received as an award under the Management Incentive Compensation Plan or the Senior Management Incentive Compensation Plan, and (ii) the seven most recent awards paid under the Management Incentive Compensation Plan or the Senior Management Incentive Compensation Plan prior to the Participant’s Separation from Service.

1.16 “Limited Plan” shall mean the Limited Supplemental Benefits Plan for Certain Employees of Public Service Enterprise Group Incorporated and its Subsidiaries and any successor or replacement plan.

1.17 “Mid-Career Hire Plan” shall mean the Mid-Career Hire Supplemental Retirement Income Plan for Selected Employees of Public Service Enterprise Group Incorporated and its Affiliates and any successor or replacement plan.

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

1.19 “Participant” shall mean any Employee or former Employee of the Company or a Participating Affiliate who meets the requirements of Subsection 2.1 of the Plan.

6

1.20 “Participating Affiliate” shall mean any Affiliate of the Company which (a) is the sponsor or a Participating Affiliate of the Pension Plan and/or the Cash Balance Plan; (b) adopts this Plan with the approval of the Board of Directors; (c) authorizes the Board of Directors and the Employee Benefits Committee to act for it in all matters arising under or with respect to this Plan; and (d) complies with such other terms and conditions relating to this Plan as may be imposed by the Board of Directors.

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

1.22 “Pension Plan Retirement Benefit” shall mean the aggregate annual benefit payable to a Participant pursuant to the Pension Plan or the Cash Balance Plan, as the case may be, by reason of the Participant’s termination of employment with the Company and all Affiliates for any reason other than death.

1.23 “Pension Plan Surviving Spouse Benefit” shall mean the aggregate annual benefit payable to the Surviving Spouse of a Participant pursuant to the Pension Plan or the Cash Balance Plan, as the case may be, in the event of the death of the Participant at any time prior to commencement of payment of the Participant’s Pension Plan Retirement Benefit.

1.24 “Plan” shall mean this Retirement Income Reinstatement Plan for NonRepresented Employees of Public Service Enterprise Group Incorporated and its Affiliates (formerly known as the “Retirement Income Reinstatement Plan for Non-Represented Employees of Public Service Electric and Gas Company and Its Affiliates”).

1.25 “Plan Year” shall mean the calendar year.

1.26 “Retirement” shall be defined as follows:

(a) In the case of a Participant who is a participant in the Pension Plan, Retirement shall mean a Separation from Service either (1) after attaining age 65; or (2) when the sum of the Participant’s age and credited service (as defined in the Pension Plan) equals or exceeds 80.

(b) In the case of a Participant who is a participant in the Cash Balance Plan, Retirement shall mean a Separation from Service after either (1) attaining age 65; or (2) attaining age 55 and completing five or more years of credited service (as defined in the Cash Balance Plan).

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

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

7

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

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

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

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

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

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

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

1.29 “Supplemental Retirement Benefit” shall mean the benefit payable to a Participant pursuant to this Plan by reason of the Participant’s Separation from Service with the Company and all Affiliates for any reason other than death.

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

1.31 “Supplemental Surviving Spouse Benefit” shall mean the benefit payable to a Surviving Spouse pursuant to this Plan.

8

Section 2. Eligibility

2.1 A Participant who incurs a Separation from Service after becoming vested in his Pension Plan Retirement Benefit, the amount of which is reduced by reason of (a) the application of the limitations on benefits imposed by application of any provisions of the Code, as in effect on the date for commencement of the Pension Plan Retirement Benefit or as in effect at any time thereafter, to the Pension Plan or the Cash Balance Plan, as the case may be, or (b) the restrictions of Subsection 1.10(a) of the Pension Plan or Subsection 1.1(m)(1) of the Cash Balance Plan, shall be eligible to receive a Supplemental Retirement Benefit. The Surviving Spouse of a Participant described in the preceding sentence who dies prior to commencement of payment of his Pension Plan Retirement Benefit shall be eligible to receive a Supplemental Surviving Spouse Benefit.

Section 3. Supplemental Retirement Benefit

3.1 The Supplemental Retirement Benefit payable to an eligible Participant shall be determined as follows:

(a) A Participant in the Pension Plan who incurs a Separation from Service prior to January 1, 2012 and who is eligible for a Supplemental Retirement Benefit shall be entitled to receive a benefit as of his Normal Retirement Date equal to the excess of (1) over (2) where:

(1) is the amount of Pension Plan Retirement Benefit under Subsection 3.1(a) of the Pension Plan to which the Participant would have been entitled under the Subsection 3.1(a) of the Pension Plan as of his Normal Retirement Date if such benefit were computed by applying the definition of Final Earnings in Subsection 1.15(a) of the Plan and without regard to (i) the Benefit Limitation or (ii) the Compensation Limitation; and

(2) is the amount of the Pension Plan Retirement Benefit under Subsection 3.1(a) of the Pension Plan actually payable to the Participant or payable to a third party on the Participant’s behalf under the Pension Plan as of his Normal Retirement Date.

(b) A Participant in the Pension Plan who incurs a Separation from Service on or after January 1, 2012 and who is eligible for a Supplemental Retirement Benefit shall be entitled to receive a benefit as of his Normal Retirement Date equal to the excess of (1) over (2) where:

(1) is the amount of Pension Plan Retirement Benefit under Subsection 3.1(b) of the Pension Plan to which the Participant would have been entitled under the Subsection 3.1(b) of the Pension Plan as of his Normal Retirement Date if such benefit were computed by applying the definition of Final Earnings in Subsection 1.15(b) of the Plan and without regard to (i) the Benefit Limitation or (ii) the Compensation Limitation; and

9

(2) is the amount of the Pension Plan Retirement Benefit under Subsection 3.1(b) of the Pension Plan actually payable to the Participant or payable to a third party on the Participant’s behalf under the Pension Plan as of his Normal Retirement Date.

(c) This Supplemental Retirement Benefit shall be calculated as a single life annuity commencing on the Participant’s Normal Retirement Date. If payment of a Participant’s Supplemental Retirement Benefit commences or is paid before his Normal Retirement Date, the benefit amount calculated pursuant to paragraph (a) or paragraph (b) shall be reduced for early commencement in accordance with the early retirement reduction factors applicable to calculation of the Participant’s benefit under the Pension Plan.

(d) Notwithstanding any other provision of this Plan to the contrary, the Supplemental Retirement Benefit payable to Frederick W. Lark and Richard D. Quinn, III, shall be calculated as of December 31, 2008 and shall be paid commencing as of January 31, 2009.

(e) A Participant in the Cash Balance Plan who is eligible for a Supplemental Retirement Benefit shall be entitled to receive a benefit as of his Benefit Commencement Date equal to the excess of (1) over (2) where:

(1) is the amount of the Pension Plan Retirement Benefit to which the Participant would be entitled under the Cash Balance Plan as of his Benefit Commencement Date if such benefit were computed by applying the definition of Compensation in Subsection 1.9 and without regard to (i) the Benefit Limitation or (ii) the Compensation Limitation; and

(2) is the amount of the Pension Plan Retirement Benefit actually payable to the Participant or payable to a third party on the Participant’s behalf under the Cash Balance Plan as of his Benefit Commencement Date.

3.2. The Supplemental Retirement Benefit payable to a Participant shall be paid:

(a) If the Participant’s Separation from Service occurs prior to Retirement, the present value of his Supplemental Retirement Benefit shall be paid in a single lump sum distribution;

(b) Except as otherwise provided in paragraph (d), if the Participant’s Separation from Service occurs on or after his Retirement, the Participant may elect to receive his Supplemental Retirement Benefit in the form of a single life annuity or a joint and survivor annuity.

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

10

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

(c) A Participant may elect an annuity form of payment pursuant to paragraph (b) at any time before his Benefit Commencement Date, provided that any election shall also apply to any benefits payable to the Participant under the Mid-Career Hire Plan and the Limited Plan. If a Participant fails to make a timely election, his Supplemental Retirement Benefit shall be paid in the form of:

(1) a single life annuity, if he is not married as of his Benefit Commencement Date; or

(2) a 50 percent joint and survivor annuity with his spouse as Beneficiary, if he is married as of his Benefit Commencement Date.

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

(d) Notwithstanding paragraphs (b) and (c),if the Participant’s total vested benefit under this Plan the Mid-Career Plan and the Limited Plan, as presently valued at the time of commencement of the payment of such benefit, does not exceed $30,000, his benefit under each of the plans shall be paid in a single lump sum distribution.

3.3 Except as otherwise provided in this subsection, payment of a Participant’s Supplemental Retirement Benefit shall commence or shall be paid as of the last day of the month in which the Participant’s Separation from Service occurs or as soon as administratively practicable after such date, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date.

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

11

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

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

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

3.4 A Supplemental Retirement Benefit which is payable in any form other than a single life annuity, shall be the actuarial equivalent of the Supplemental Retirement Benefit set forth in Subsection 3.1 above as determined by the same actuarial adjustments as those specified in the Pension Plan or the Cash Balance Plan, as the case may be, with respect to determination of the amount of the Pension Plan Retirement Benefit on the date for commencement of payment hereunder.

3.5 If a Participant earns an additional Supplemental Retirement Benefit after a Separation from Service, any annuity benefits being paid to the Participant shall be increased to reflect such additional accruals as of the January 1 following the Plan Year in which such additional benefit accrues. If the Participant received a lump sum distribution of his Supplemental Retirement Benefit as of the earlier Separation from Service, the value of the additional accruals shall be paid to him in a lump sum distribution as of the January 1 following the Plan Year in which such additional benefit accrues.

Notwithstanding the foregoing, if a Participant named in Subsection 3.1(a) earns an additional Supplemental Retirement Benefit after December 31, 2008, the additional accruals shall be payable as of the Participant’s Separation from Service as otherwise provided in this Section 3.

Section 4. Supplemental Surviving Spouse Benefit

4.1 If a Participant dies prior to commencement of payment of his Pension Plan Retirement Benefit under circumstances in which a Pension Plan Surviving Spouse Benefit is payable to his Surviving Spouse, then a Supplemental Surviving Spouse Benefit shall be payable to his Surviving Spouse as hereinafter provided.

12

(a) In the case of a Participant in the Pension Plan, the Supplemental Surviving Spouse Benefit shall be determined as an amount payable as of the Participant’s Normal Retirement Date equal to the excess of (1) over (2) where:

(1) is the amount of Pension Plan Surviving Spouse Benefit to which the Surviving Spouse would have been entitled under the Pension Plan as of the Participant’s Normal Retirement Date if such benefit were computed by applying the definition of Final Earnings in Subsections 1.15(a) and (b) accordingly and without regard to (i) the Benefit Limitation or (ii) the Compensation Limitation; and

(b) is the amount of the Pension Plan Surviving Spouse Benefit actually payable to the Surviving Spouse under the Pension Plan as of the Participant’s Normal Retirement Date.

The Supplemental Surviving Spouse Benefit shall be calculated as a single life annuity commencing on the Participant’s Normal Retirement Date. If payment of the Supplemental Surviving Spouse Benefit commences or is paid before the Participant’s Normal Retirement Date, the benefit amount calculated pursuant to this paragraph (a) shall be reduced for early commencement in accordance with the reduction factors applicable to calculation of a Pension Plan Surviving Spouse Benefit.

(b) In the case of a Participant in the Cash Balance Plan, the Supplemental Surviving Spouse Benefit shall be equal to the amount payable as of the last month of the day coinciding with or next following the Participant’s date of death that is equal to the excess of (1) over (2) where:

(1) is the amount of the Pension Plan Surviving Spouse Benefit to which the Surviving Spouse would be entitled under the Cash Balance Plan as of the Participant’s date of death if such benefit were computed by applying the definition of Compensation in Subsection 1.9 and without regard to (i) the Benefit Limitation or (ii) the Compensation Limitation; and

(2) is the amount of the Pension Plan Surviving Spouse Benefit actually payable to the Surviving Spouse under the Cash Balance Plan as of the Participant’s date of death.

4.2 The Supplemental Surviving Spouse Benefit shall be paid as follows:

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

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(b) If the Participant’s death occurs on or after Retirement, the Supplemental Surviving Spouse Benefit shall be payable over the lifetime of the Surviving Spouse only in monthly installments terminating on the date of the last payment of the Pension Plan Surviving Spouse Benefit made before the Surviving Spouse’s death. Notwithstanding the preceding sentence, if the present value of the total benefit payable to the Surviving Spouse under this Plan and the Mid-Career Hire Plan does not exceed $20,000, the benefit under each of these plans shall be paid in a single lump sum distribution.

4.3 Payment of the Supplemental Surviving Spouse Benefit shall commence or shall be made as of the last day of the month in which the Participant’s death occurs or as soon as administratively practicable after such date, but in no event later than the last day permitted under Section 409A of the Code for treating a delayed payment as having been made on such payment date.

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Section 5. Administration of the Plan

5.1 The Committee shall be the named fiduciary of this Plan responsible for the general operation and administration of this Plan and for carrying out the provisions thereof. The Committee shall have discretionary authority to construe the terms of this Plan.

5.2 The Committee shall adopt such rules and procedures as it deems necessary and advisable to administer this Plan and to transact its business. Subject to the other requirements of this Section 5, the Committee may—

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

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

(c) consult with counsel, who may be counsel to the Company or an Affiliate; and

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

However, any action described in paragraphs (b) or (d) of this subsection 5.2, and any modification or rescission of any such action, may be effected by the Committee only by a resolution approved by a majority of the Committee. The Committee shall be entitled to rely conclusively upon all tables, valuations, certificates, opinions and reports furnished by any actuary, accountant, controller, counsel or other person employed or engaged by the Committee with respect to this Plan.

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

5.4 In performing their duties, the members of the Committee shall act solely in the interest of the Participants in this Plan and their Beneficiaries and

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

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

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

5.5 In addition to any other duties the Committee may have, the Committee shall review the performance of all persons to whom the Committee shall have delegated or allocated fiduciary duties pursuant to the provisions of this Section 5.

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

5.7 No member of the Committee nor any delegate thereof shall be personally liable by virtue of any contract, agreement or other instrument made or executed by him or on his behalf in such capacity.

Section 6. Claims Procedure and Status Determination

6.1 Claims for benefits under this Plan and requests for a status determination shall be filed in writing with the Company.

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

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

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

Section 7. Amendment or Termination

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

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7.2 No amendment or termination of this Plan shall directly or indirectly deprive any current or former Participant, Beneficiary or Surviving Spouse of all or any portion of any Supplemental Retirement Benefit or Supplemental Surviving Spouse Benefit payment which has commenced prior to the effective date of such amendment or termination or the right to which has accrued on such effective date.

7.3 In the event of a Plan termination, Supplemental Retirement Benefits and Supplemental Surviving Spouse Benefits shall be distributed in a single lump sum as soon as practicable after the date the Plan is terminated if such distribution is permitted because the Plan is terminated in accordance with the termination provisions of Section 409A of the Code and related regulations or, in other cases, at the earliest time otherwise permitted under the terms of the Plan in accordance with Section 409A of the Code and related regulations.

Section 8. General Provisions

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

8.2 Except as otherwise expressly provided herein, all terms and conditions of the Pension Plan or the Cash Balance Plan, as the case may be, applicable to a Pension Plan Retirement Benefit or a Pension Plan Surviving Spouse Benefit shall also be applicable to a Supplemental Retirement Benefit or a Supplemental Surviving Spouse Benefits payable hereunder. Any Pension Plan Retirement Benefit or Pension Plan Surviving Spouse Benefit, or any other benefit payable under the Pension Plan or the Cash Balance Plan, as the case may be, shall be paid solely in accordance with the terms and conditions of the Pension Plan or the Cash Balance Plan, as the case may be, and nothing in this Plan shall operate or be construed in any way to modify, amend or affect the terms and provisions of the Pension Plan or the Cash Balance Plan, as the case may be.

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

8.4 No Participant or Surviving Spouse shall have any right to a benefit under this Plan except in accordance with the terms of this Plan. Establishment of this Plan shall not be construed to give any Participant the right to be retained in the service of the Company or any Affiliate.

8.5 No interest of any person or entity in, or right to receive a benefit under, this Plan shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment or other alienation or encumbrance of any kind; nor any such interest or right to receive a benefits

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be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings.

8.6 This Plan shall be construed and administered under the laws of the United States and the State of New Jersey to the extent not superseded by Federal law. This Plan is specifically intended to comply with the provisions of the American Jobs Creation Act of 2004 (the “AJCA”) and Section 409A of the Code and it shall automatically incorporate all applicable restrictions of the AJCA, the Code and its related regulations, and the Company will amend the Plan to the extent necessary to comply with those requirements. The timing under which a Participant will have a right to receive any payment under this Plan will be deemed to be automatically modified, and a Participant’s rights under the Plan limited to conform to any requirements under, the AJCA, the Code and its related regulations.

8.7 Actuarial assumptions to determine the present value of any benefit hereunder shall be the same as used to determine the present value of benefits under the Pension Plan or the Cash Balance Plan, as the case may be.

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

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

8.10 Each Participant shall keep the Company informed of his current address and the current address of his spouse. The Company shall not be obligated to search for the whereabouts of any person. If the location of a Participant is not made known to the Company within three (3) years after the date on which payment of the Participant’s Supplemental Retirement Benefit may first be made, payment may be made as though the Participant had died at the end of the three-year period. If, within one additional year after such three-year period has elapsed, or, within three years after the actual death of a Participant, the Company is unable to locate any. Surviving Spouse of the Participant, then the Company shall have no further obligation to pay any benefit hereunder to such Participant or Surviving Spouse or any other person and such benefit shall be irrevocably forfeited.

8.11 Notwithstanding any of the preceding provisions of this Plan, none of the Company, the Committee or any individual acting as an employee or agent of the Company or the Committee shall be liable to any Participant, former Participant, Surviving Spouse or any other person for any claim, loss, liability or expense incurred in connection with this Plan.

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Section 9. Miscellaneous

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

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EX-10.3

Exhibit 10.3

DEFERRED COMPENSATION PLAN FOR CERTAIN EMPLOYEES

OF PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

AND ITS AFFILIATES

AMENDED JULY 1, 2011,

WITH CERTAIN PROVISIONS EFFECTIVE JANUARY 1, 2012

DEFERRED COMPENSATION PLAN FOR CERTAIN EMPLOYEES OF

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED AND ITS AFFILIATES

AMENDED EFFECTIVE JULY 1, 2011

1. PURPOSE. The purpose of this Plan is to provide a method to certain select and key employees of the Company and its Affiliates to defer compensation as provided herein. This Plan was formerly known as the Deferred Compensation Plan for Certain Employees of Public Service Electric and Gas Company.

2. AMENDMENT. This Plan is being amended and restated effective as of July 1, 2011 (with certain provisions effective January 1, 2012) to provide for in-service distributions and a lump sum payment upon the death of a Participant, to allow Participants to elect distribution of their Accounts on a specified date or a specified event, and certain other administrative changes. This Plan was last amended and restated, effective December 1, 2008, to allow a special one-time election to change certain prior deferral elections and make certain definitional changes related to Section 409A of the Code.

3. DEFINITIONS OF TERMS USED IN THIS PLAN. As used in this Plan, the following words and phrases shall have the meanings indicated:

(a) “Account” - the Deferred Compensation Account described in Paragraph 4 of this Plan.

(b) “Affiliate” - any organization which is a member of a controlled group of corporations (as defined in Code section 414(b), as modified by Code section 415(h)) which includes the Company; or any trades or businesses (whether or not incorporated) which are under common control (as defined in Code section 414(c), as modified by Code section 415(h)) with the Company; or a member of an affiliated service group (as defined in Code section 414(m)) which includes the Company or any other entity required to be aggregated with the Company pursuant to regulations under Code section 414(o). The term affiliate shall also include such entities which shall be specifically designated by the Committee.

(c) “Assets” - all Compensation and interest that have been credited to a Participant’s Account in accordance with Paragraph 5 of this Plan.

(d) “Beneficiary” - the individual(s) and/or entity(ies) designated and defined by the Plan.

(e) “Change in Control” - the occurrence of any of the following events:

(i) any “person” (within the meaning of Section 13(d) of the Securities Exchange Act of 1934, as amended from time to

time (the “Act”)) is or becomes the beneficial owner within the meaning of Rule 13d-3 under the Act (a “Beneficial Owner”), directly or indirectly, of securities of the Company (not including in the securities beneficially owned by such person any securities acquired directly from the Company or its affiliates) representing 25% or more of the combined voting power of the Company’s then outstanding securities, excluding any person who becomes such a Beneficial Owner in connection with a transaction described in clause (A) of subparagraph (iii) below; or

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

(iii) there is consummated a merger or consolidation of the Company or any direct or indirect wholly owned subsidiary of the Company with any other corporation, other than (1) a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of the Company or any subsidiary of the Company, at least 75% of the combined voting power of the securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or (2) a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no person is or becomes the Beneficial Owner, directly or indirectly, of securities of the

Company representing 25% or more of the combined voting power of the Company’s then outstanding securities; or

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

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

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

(g) “Committee” - the Employee Benefits Policy Committee of the Company.

(h) “Company” - Public Service Enterprise Group Incorporated.

(i) “Compensation” - the total remuneration paid to a Participant for services rendered to the Company or a Participating Affiliate, excluding the Company’s or Participating Affiliate’s cost for any public or private employee benefit plan, including this Plan, but including all elective contributions that are made by the Company or Participating Affiliate under Internal Revenue Code Sections 125 or 401(k). Compensation deferrable under this Plan shall specifically include any and all amounts transferred from the deferred compensation accounts of the Company’s Management Incentive Compensation Plan, the Management Incentive Compensation Plan of Public Service Electric and Gas Company and any prior deferred compensation plan of an Affiliate.

(j) “Deferred Compensation” - the amount of Compensation deferred pursuant to Paragraph 4 of this Plan.

(k) “Disability” - a Participant will be considered disabled if he/she meets one of the following requirements: (i) he/she is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of not less than 12 months; or (ii) he/she is, by reason of any medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than 3 months under a Company or Affiliate sponsored plan.

(l) “Employer” - the Company and any Participating Affiliate.

(m) “ERISA” - The Employee Retirement Income Security Act of 1974, as amended. A reference to a section of ERISA shall also refer to any regulations and other guidance issued under that section.

(n) “ERISA Affiliate” - (a) any organization while it is a member of a controlled group of corporations (as defined in Code Section 414(b)) which includes the Company; or (b) any trades or businesses (whether or not incorporated) while they are under common control (as defined in Code Section 414(c)) with the Company.

(o) “Investment Fund” - the fund or funds selected by the Committee from time to time which shall serve as a means of measuring the increase or decrease of each Participant’s Account. The Committee may, in its discretion, add or discontinue any Investment Fund available under the Plan. The Committee shall provide each affected Participant with the opportunity, without limiting or otherwise impairing any other right of such Participant regarding changes in investment directions, to redirect the allocation of his or her Account invested in any discontinued Investment Fund among the other Investment Funds available under the Plan, including any replacement investment vehicle.

(p) “Participant” - each employee of the Company or any Participating Affiliate as may be designated by the Chief Executive Officer of the Company.

(q) “Participating Affiliate” - any Affiliate of the Company which (a) adopts this Plan with the approval of the Company; (b) authorizes the Board of Directors and the Committee to act for it in all matters arising under or

with respect to this Plan; and (c) complies with such other terms and conditions relating to this Plan as may be imposed by the Company.

(r) “Plan” - the Deferred Compensation Plan for Certain Employees of Public Service Enterprise Group Incorporated and its Affiliates (formerly known as the Deferred Compensation Plan for Certain Employees of Public Service Electric and Gas Company).

(s) “Separation from Service” - Subject to paragraphs (i) and (ii), a Participant’s termination from employment with the Company and all ERISA Affiliates, whether by retirement or resignation from or discharge by the Company or an ERISA Affiliate.

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

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

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

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

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

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

If a Participant fails to return to work upon the expiration of any military leave, sick leave, or other bona fide leave of absence where such leave is

for less than six months, the Separation from Service shall occur as of the date of the expiration of such leave.

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

4. ELECTION AS TO THE AMOUNT OF COMPENSATION THAT IS TO BE DEFERRED. A Participant may elect to defer any portion of his/her Compensation otherwise payable for services rendered for his/her Employer.

(a) Timing of Elections - Any election to defer must be made by filing with the Committee or its designee an “Election in Connection with Deferral of Compensation,” the form of which shall be designated and published by the Committee from time-to-time. All elections to defer must be made in the calendar year prior to the year that the services giving rise to the compensation are performed. Provided, however, that elections to defer performance-based compensation may be made up to the date that is six-months before the end of the related performance period, as long as a) the performance period is at least 12 months in length, b) the Participant performed services continuously from the date the performance criteria were established through the date the deferral election is made and c) at the time the deferral election is made, the performance-based compensation is not both i) substantially certain to be paid and ii) readily ascertainable. A Participant may change (using the election form for such purposes), not later than the date than the last date that an election to defer may be made, the amount of Compensation to be deferred by him/her with respect to the next succeeding calendar year or performance period.

In the calendar year that a Participant first becomes eligible to participate in this Plan, such Participant may elect to defer Compensation for part of that calendar year but only if such election is made within thirty (30) days after the Participant first becomes eligible to participate in this Plan or any other plan required under Section 409A of the Code to be aggregated with this Plan. Except as otherwise specifically provided for herein, Compensation may be deferred prospectively only, and the amount of Compensation to be deferred may be changed only with respect to future calendar years.

(b) Special One-Time Election to Rescind 2005 Deferrals - Not later than December 14, 2005, Participants who had elected to defer compensation during 2005 may, by written notice, the form of which shall be designated and published by the Committee, rescind his/her election to defer 2005 compensation and such amounts shall be currently paid to the Participant.

(c) Special One-Time Election to Change Distribution Elections with respect to 2005, 2006, 2007 or 2008 Deferrals - Not later than December 31, 2008, Participants who had elected to defer compensation during 2005, 2006, 2007 or 2008 may, by written notice in a form approved by the Committee, elect to change the distribution elections with respect to any such deferrals.

5. HOW THE ACCOUNT IS TO BE MAINTAINED.

(a) Establishment of Account - The Company shall establish an Account for each Participant who elects to participate in the Plan. Each Participant’s Account shall be credited with an amount equal to the Deferred Compensation which would have otherwise been payable to him/her.

(b) Earnings Credits on Assets in the Account - Each Participant, except Participants whose active employment by an Employer terminated prior to January 1, 2000, may direct investment of his or her Account among the Investment Funds (in the manner established by the Committee) in multiples of one percent; provided, however, that the Committee shall not be obligated to effectuate any such investment direction. In the case of (i) Participants whose active employment by an Employer terminated prior to January 1, 2000 and (ii) a Participant who fails to provide a designation of Investment Funds, such Participants shall be deemed to have designated 100 percent of their Accounts to be invested in the Investment Fund that determines income accrual with reference to the prime commercial lending rate of JPMorgan Chase Bank (formerly, the Chase Manhattan Bank). Effective July 1, 2011, the prime commercial lending rate of JPMorgan Chase Bank shall be capped at 120% applicable federal long-term rate.

A Participant may change his or her investment election daily.

Each Participant’s Account shall be valued daily equal.

(c) Title to and Beneficial Ownership of Assets - The Plan shall be unfunded. The Company shall not be required to segregate any amounts credited to any Participant’s Account, which shall be established merely as an accounting convenience. Title to and beneficial ownership of any Assets,

whether Deferred Compensation or earnings credited to a Participant’s Account pursuant to Subparagraphs 5(a) and (b) hereof, shall at all times remain in the Company, and no Participant nor Beneficiary shall have any interest whatsoever in any specific assets of the Company. All Assets shall at all times remain solely the property of the Company subject to the claims of its general creditors.

6. DISTRIBUTION FROM THE ACCOUNT

(a) Election as to the Commencement and Timing of the Distribution of 2011 and Prior Year Deferrals.

(i) Commencement - By election on the form designated by and filed with the Committee at the same time he/she elects to defer compensation under Paragraph 4, a Participant, may elect to have distribution from his/her account commence (i) on the thirtieth day after the date he/she ceases to be employed by an Employer or, in the alternative, (ii) on January 15^th of any calendar year following Separation from Service elected by the Participant, but in any event no later than the latter of (A) the January of the year following the year of the Participant’s 70th birthday or (B) the January following Separation from Service or (iii) pursuant to the terms of any written employment agreement applicable to the Participant. Notwithstanding the forgoing, however, for any Participant who is a Specified Employee, distribution of his/her account may not occur earlier than six months following his/her Separation from Service.

(ii) Timing - By election on the form designated by and filed with the Committee at the same time he/she elects to defer compensation under Paragraph 4, a Participant may elect to receive the distribution of his/her Account in the form of (A) one lump-sum payment, (B) annual distributions over a five-year period or (C) annual distributions over a 10-year period. A Participant may change such election by filing a subsequent election form, but any such change shall apply only to future deferrals. In the event a lump-sum payment is made under this Plan, the Assets credited to a Participant’s Account, including earnings at the rate provided in Subparagraph 5(b) of this Plan to the date of distribution, shall be paid to the Participant on the date determined under Subparagraph 6(a) of this Plan. In the case of a distribution over a period of years, the Company shall pay to the Participant on the date determined under Subparagraph 6(a) of this Plan and on the yearly anniversaries of such date, annual installments of the unpaid balance of the Assets in the Participant’s Account, including

earnings on the unpaid balance at the rate provided in Subparagraph 5(b) of this Plan to the date of distribution. The amount of each installment shall be determined by multiplying the then unpaid balance, plus accrued earnings, in the Participant’s Account by a fraction, the numerator of which is one and the denominator of which is the number of annual installments remaining to be paid.

(b) Election as to the Commencement and Timing of the Distribution of 2012 and Beyond Deferrals. By election on the form designated by and filed with the Committee, or its designee, at the same time he/she elects to defer compensation under Paragraph 4, a Participant, may elect to have distribution of each year’s deferrals and associated earnings occur on the date or event specified in Subparagraphs (i), (ii) or (iii). A Participant’s distribution election shall apply to future years unless the Participant makes a subsequent election.

(i) For each year, a Participant may elect to have distribution of that year’s deferrals and associated earnings under Subparagraph 5(b), commence six months following Separation from Service. Distribution shall be made or commence within the 30 day period following the date that is the date six months following Separation from Service. A Participant may elect to receive such distribution in the form of (A) one lump-sum payment, or (B) annual installments over a three to fifteen year period. In the case of a distribution over a period of years, the Company shall pay to the Participant on the date determined under this Subparagraph 6(b)(i) and on the yearly anniversaries of such date, annual installments of the unpaid balance of that year’s deferrals, including earnings on the unpaid balance at the rate provided in Subparagraph 5(b) of this Plan to the date of distribution. The amount of each installment shall be determined by multiplying the then unpaid balance of that year’s deferrals, plus accrued earnings, the numerator of which is one and the denominator of which is the number of annual installments remaining to be paid.

(ii) For each year, a Participant may elect to have distribution of that year’s deferrals, and associated earnings under Subparagraph 5(b), paid or commence on a date that is indicated by the Participant as a number of years and/or months following Separation from Service, provided that such specified number of years and/or months is at least six months following Separation from Service. Distribution shall be made or commence within the 30 day period following the date that the Participant elects. A Participant may elect to receive such distribution in the form of (A) one lump-sum payment, or (B)

annual installments over a three to fifteen year period. In the case of a distribution over a period of years, the Company shall pay to the Participant on the date determined under this Subparagraph 6(b)(ii) and on the yearly anniversaries of such date, annual installments of the unpaid balance of that year’s deferrals, including earnings on the unpaid balance, at the rate provided in Subparagraph 5(b) of this Plan to the date of distribution. The amount of each installment shall be determined by multiplying the then unpaid balance of that year’s deferrals, plus accrued earnings, the numerator of which is one and the denominator of which is the number of annual installments remaining to be paid.

(iii) For each year’s deferrals and associated earnings, a Participant may elect to receive distribution of that year’s deferrals on a specified date that is no earlier than three years following the beginning of the year giving rise to the deferrals. The Participant does not have to incur a Separation from Service to receive distribution under this Subparagraph (6)(b)(iii). Distribution shall be made in a lump sum within 30 days following the date elected by the Participant.

In the event that the Participant incurs a Separation from Service prior to the date the elected under this subsection (iii), distribution of those deferrals and associated earnings shall not be made upon Separation from Service, but rather shall be within 30 days following the date elected by the Participant under this subsection (iii).

(c) Changes in Distribution Elections.

(i) Participants may, by notice filed with the Company prior to December 31^st of any year, make changes of distribution elections on a prospective basis.

(ii) Participants may, by notice filed with the Company, make changes of distribution elections with respect to prior deferred compensation as long (A) any such new distribution election is made at least one year prior to the date that the commencement of the distribution would otherwise have occurred and (B) the revised commencement date is at least five years later than the date that the commencement of the distribution would otherwise have occurred. With respect to 2012 and beyond deferrals, installment payments shall be treated as one payment.

(iii) Special One-Time Election - Participants may, by notice filed with the Company prior to December 31, 2005, make a one-time

election to change any distribution election previously made with respect to compensation deferred on or before December 31, 2005.

(iv) Special One-Time Election - Participants may, by notice filed with the Company prior to December 31, 2008, make a one-time election to change any distribution election previously made with respect to compensation deferred during 2005, 2006, 2007 or 2008.

(d) Distribution in Case of Certain Disability - In the event of a Participant’s Disability prior to a calendar year elected by the Participant under Subparagraph 6(a) or Subparagraph (b) of this Plan for distribution to commence, distribution of the Participant’s Account shall commence in the month following the month in which the Participant terminates employment for Disability, in accordance with the Participant’s election under Subparagraph 6(a) or Subparagraph (b) of this Plan as to the form of distribution.

(e) Distribution in Case of Death.

(i) Distribution of 2011 and Prior Years Deferrals. In the event of a Participant’s death, the balance of the Participant’s Account shall be distributed to the Participant’s Beneficiary(ies) over a period of not more than five (5) years, in accordance with the Participant’s election (on the form designated by and filed with the Committee) for distribution in case of death. Any change in the period over which such payments are made shall only apply to future deferrals. Such distribution shall be made in a manner consistent with Subparagraph 6(a) of this Plan and shall commence in the month of January of the year after the year of the Participant’s death, on a date within said month to be determined by the Committee in its sole discretion. Additional annual payments for distributions made over a period of more than one year shall be made on the yearly anniversaries of such date. In the event of a Participant’s death after distribution of his/her Account has commenced, any election under this Subparagraph 6(e)(i) shall not extend the time of payment of his/her Account beyond the time when distribution would have been completed if he/she had lived. A Participant may change Beneficiary designations by filing a subsequent designation with the Committee.

(ii) Distribution of 2012 and Beyond Deferrals. In the event of a Participant’s death prior to the date that the Participant commenced receiving of a specific year’s deferrals and associated earnings, such amount shall be distributed to the Participant’s

Beneficiary(ies) in a lump sum within 90 days following the Participant’s death.

In the event of the Participant’s death after he/she commenced distribution of a year’s deferrals and associated earnings in the form of installments, the balance of such year’s deferrals and associated earnings shall be distributed to the Participant’s Beneficiary(ies) in a lump sum within 90 days following the Participant’s death.

A Participant may change Beneficiary designations by filing a subsequent designation with the Committee or its designee.

(f) Request for Change in Distribution on Account of an Unforeseeable Emergency - A Participant, Beneficiary or a legal representative may request an acceleration of any payments from a Participant’s Account by filing a written request therefore with the Committee. The Committee may, in its sole discretion, grant such request only if the Committee determines that an emergency beyond the control of the Participant, Beneficiary or legal representative exists and which would cause such Participant, beneficiary or legal representative severe financial hardship if the payment of such benefits were not approved. Any such distribution for hardship shall be limited to the amount needed to meet such emergency plus the amount of any tax liability resulting from the distribution. A Participant who makes a hardship withdrawal may not reenter this Plan for 12 months after the date of withdrawal. Any distribution under this Subparagraph 6(f) shall be made on the 15th day after the Committee grants such request for hardship withdrawal.

(g) Employment not Terminated if Transferred to an Affiliate - For the purposes of this Paragraph 6, a Participant shall not be deemed to have experienced a Separation from Service if he/she is transferred to the employ of an employer that is an Affiliate of the Company.

(h) Company may Distribute in Lump-Sum if Distributable Amount Less Than $5,000 - The Company reserves the right to make a lump-sum distribution, notwithstanding any other provision of this Plan, if the total Assets in the Participant’s Account in this Plan and in the Participant’s accounts in all other plans required under the Section 409A of the Code to be aggregated with this Plan, are $5,000 or less at any time after the Participant ceases to be employed by the Company.

(i) Failure to make a Distribution Election.

(i) 2011 and Prior Years Deferrals. If, with respect to any election to defer compensation for 2011 or any prior year, a Participant fails to make a proper election with respect to the distribution of such deferred compensation, such amount will be distributed in a lump sum on the thirtieth day following the Participant’s Separation from Service.

(ii) 2012 and Beyond Deferrals. If, with respect to any election to defer compensation for 2012 or any subsequent year, a Participant fails to make a proper election with respect to the distribution of such deferred compensation, such amount will be distributed in accordance with the prior year’s election (but not any election in place for a year prior to 2012). In the event that no valid election is on file, such amount will be distributed in a lump sum on the date specified in Subparagraph 6(b)(i).

(j) Distribution in Case of Certain Tax Events - If, with respect to any Participant, the Plan fails to meet the requirements of the Code with respect to the deferral of tax liability, the Company may accelerate distribution from a Participant’s Account amounts sufficient to meet such Participant’s resulting Federal, State, Local and/or Foreign tax liability (including any interest and penalties).

7. ASSIGNMENT. No benefit under the Plan shall in any manner or to any extent be assigned, alienated, or transferred by any Participant or Beneficiary under the Plan or subject to attachment, garnishment or other legal process.

8. PLAN DOES NOT CONSTITUTE AN EMPLOYMENT AGREEMENT. This Plan shall not constitute a contract for the continued employment of any Participant by the Company. The Company reserves the right to modify a Participant’s compensation at any time and from time to time as it considers appropriate and to terminate his/her employment for any reason at any time notwithstanding this Plan.

9. AMENDMENT OR TERMINATION OF THE PLAN BY THE COMPANY. The Company may, in its sole discretion and by action of its Board of Directors or Employee Benefit Policy Committee, amend, modify or terminate this Plan at any time, provided, however, that no such amendment, modification or termination shall adversely affect the right of a Participant in respect of Deferred Compensation previously earned by him/her which has not been paid, unless such Participant or his/her legal representative shall consent to such change; and no such amendment, modification or termination shall entitle any Participant to an acceleration of any distributions from this Plan. Provided, further, that notwithstanding any other provision of this Plan, upon the occurrence of a Change in Control, the earnings credit calculated pursuant to Paragraph 5 may not be reduced below the prime commercial lending rate described in Subparagraph 5(b).

10. WHAT CONSTITUTES NOTICE. Any notice to a Participant, Beneficiary or legal representative hereunder shall be given either by delivering it or by depositing it in the United States mail, postage prepaid, addressed to his/her last known address. Any notice to the Company or the Committee hereunder (including the filing of election and designation forms) shall be given either by delivering it, or depositing it in the United States mail, postage prepaid, to the Secretary of the Employee Benefits Policy Committee, Public Service Enterprise Group Incorporated, 80 Park Plaza, P.O. Box 1170, Newark, New Jersey 07102.

11. ADVANCE DISCLAIMER OF ANY WAIVER ON THE PART OF THE COMPANY. Failure by the Company to insist upon strict compliance with any of the terms, covenants or conditions hereof shall not be deemed a waiver of any such term, covenant or condition, nor shall any waiver or relinquishment of any right or power hereunder at any one or more times be deemed a waiver or relinquishment of any such right or power at any other time or times.

12. EFFECT ON INVALIDITY OF ANY PART OF THE PLAN. The invalidity or unenforceability of any provision hereof shall in no way affect the validity or enforceability of any other provision.

13. PLAN BINDING ON ANY SUCCESSOR OWNER. Except as otherwise provided herein, this Plan shall inure to the benefit of and be binding upon the Company, its successors and assigns, including but not limited to any corporation which may acquire all or substantially all of the Company’s assets and business or with or into which the Company may be consolidated or merged.

14. LAWS GOVERNING THIS PLAN. Except to the extent federal law applies, this Plan shall be governed by the laws of the State of New Jersey. This Plan is specifically intended to comply with the provisions of The American Jobs Creation Act of 2004 (the “AJCA”) and Section 409A of the Code and it shall automatically incorporate all applicable restrictions of the AJCA, the Code and its related regulations, and the Company will amend the Plan to the extent necessary to comply with those requirements. The timing under which a Participant will have a right to receive any payment under this Plan will be deemed to be automatically modified, and a Participant’s rights under the Plan limited to conform to any requirements under, the AJCA, the Code and its related regulations.

15. MISCELLANEOUS. The masculine pronoun shall mean the feminine wherever appropriate.

EX-10.4

Exhibit 10.4

THE PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

EQUITY DEFERRAL PLAN

Effective November 1, 2011

THE PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

EQUITY DEFERRAL PLAN

Effective November 1, 2011

Public Service Enterprise Group Incorporated (“Company”) hereby establishes the Public Service Enterprise Group Incorporated Equity Deferral Plan (“Deferral Plan”) effective as of November 1, 2011. The Company maintains the Equity Deferral Plan for a select group of management and highly compensated employees as a means of deferring the receipt of certain equity granted under the Public Service Enterprise Group Incorporated 2004 Long-term Incentive Plan (“LTIP”).

The Deferral Plan is intended to be administered, interpreted and to comply in all respects with Section 409A of the Internal Revenue Code of 1986, as amended (“Section 409A”), and those provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) applicable to an unfunded plan maintained primarily to provide deferred compensation benefits for a select group of management or highly compensated employees.

ARTICLE I

TITLE AND DEFINITIONS

1.1 “Administrator” shall mean the person or persons appointed by the Committee to perform such plan administrative duties as are delegated by the Committee.

1.2 “Board” shall mean the Board of Directors of the Company.

1.3 “Change in Control” shall have the same meaning as such term has under the LTIP.

1.4 “Code” shall mean the Internal Revenue Code of 1986, as amended. Any reference to the Code shall include the regulations issued thereunder.

1.5 “Committee” shall mean the Organization and Compensation Committee of the Board of Directors.

1.6 “Company” shall mean Public Service Enterprise Group Incorporated.

1.7 “Deferral Election” shall mean the forms (including electronic forms) by which an LTIP Participant makes his election to defer the receipt of shares underlying the grant of Restricted Stock Units and Performance Stock Units.

1.8 “Deferral Plan” shall mean the Public Service Enterprise Group Incorporated Equity Deferral Plan.

1.9 “Effective Date” of the Equity Plan is November 1, 2011.

1.10 “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended. Any reference to ERISA shall include the regulations issued thereunder.

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1.11 “LTIP” shall mean the Public Service Enterprise Group Incorporated 2004 Long-Term Incentive Plan.

1.12 “LTIP Participant” shall mean an employee of the Company who is an Officer (as defined by the Company) and who is a participant in the LTIP.

1.13 “Participant” shall mean an LTIP Participant who has made a Deferral Election to defer the receipt of shares underlying Restricted Stock Unit awards or Performance Stock Unit awards granted under the LTIP.

1.14 “Termination of Employment” shall have the same meaning as such term has under the Supplemental Executive Retirement Income Plan for Non-Represented Employees of Public Service Enterprise Group Incorporated and Its Affiliates (“SERP”). Whether a Termination of Employment has occurred shall be based on the facts and circumstances and determined in accordance with Section 409A.

ARTICLE II

PARTICIPATION

An LTIP Participant shall become a Participant in the Deferral Plan by filing a Deferral Election in the manner and the period prescribed by the Administrator.

ARTICLE III

DEFERRAL ELECTIONS

3.1 Election to Defer Shares Underlying Restricted Stock Units.

(a) This Section 3.1 shall apply to Restricted Stock Unit awards granted after the Effective Date of the Deferral Plan.

(b) An LTIP Participant may elect to defer the receipt of all or a portion of the shares attributable to the underlying Restricted Stock Unit awards by completing and submitting a Deferral Election.

(c) An LTIP Participant must make his Deferral Election under this Section 3.1 no later than December 31 of the calendar year prior to the calendar year for which the Restricted Stock Unit award relates (or such earlier date that the Administrator may specify). For example, on December 20, 2011, an LTIP Participant receives a Restricted Stock Unit award attributable to the 2012 Plan Year. The LTIP Participant must make a Deferral Election to defer the receipt of the shares underlying the Restricted Stock award no later than December 31, 2011 (or such earlier date that the Administrator may specify).

(d) Notwithstanding Section 3.1(c), in the case of an Officer who first becomes eligible to participate in the LTIP after the beginning of the Plan Year and receives a Restricted Stock Unit award and who has not been a participant in a nonqualified deferred compensation plan that is required to be aggregated with the Deferral Plan under Section 409A of the Code, such Officer must file a

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Deferral Election within thirty (30) days of the date that the Officer first becomes eligible to participate in the LTIP (for the avoidance of any doubt, the Officer is not eligible to participate in the LTIP until the award is granted).

(e) An LTIP Participant Deferral Election must specify whether he elects to defer all or a portion (and what portion) of the shares underlying the Restricted Stock Unit award. The LTIP Participant’s election must be in whole percentages from 10% to 100%. The percentage of shares that will be deferred is based on the number of shares awarded.

(f) The LTIP Participant must also elect the deferral period, subject to Section 4. An LTIP Participant may elect to defer receipt of all or a portion of the shares underlying the Restricted Stock Unit award:

(i) To a date occurring between the third anniversary and the fifteenth anniversary of the date that the shares otherwise would have been distributed to the Participant if they had not been deferred under the Deferral Plan:

(ii) Upon a Termination of Employment: or

(iii) The earlier of (i) or (ii).

(g) An LTIP Participant’s Deferral Election to defer the receipt of shares underlying the Restricted Stock Unit award is irrevocable for that grant. Such a Deferral Election shall not apply to future grants of Restricted Stock Units.

3.2 Election to Defer Shares Underlying Performance Stock Units.

(a) This Section 3.2 shall apply to Performance Stock Unit awards granted after the Effective Date of the Equity Deferral Plan. Notwithstanding the foregoing, Section 3.2(h) shall apply to Performance Stock Units awards granted before the Effective Date for the 2010 and 2011 Plan Years.

(b) Each LTIP Participant may elect to defer the receipt of all or a portion of the shares attributable to underlying Performance Stock Unit awards by completing and submitting a Deferral Election.

(c) A must make his Deferral Election under this Section 3.2 no later than December 31 of the calendar year prior to the calendar year for which the Performance Stock Unit award relates (or such earlier date that the Administrator may specify). For example, on December 20, 2011, an Employee receives a Performance Stock Unit award attributable to the 2012 Plan Year. The Employee must make a Deferral Election to defer the receipt of the shares underlying the Performance Stock Unit award no later than December 31, 2011 (or such earlier date that the Administrator may specify).

(d) Notwithstanding Section 3.1(c), in the case of an Officer who first becomes eligible to participate in the LTIP after the beginning of the Plan Year and receives a Performance

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Stock Unit award and who has not been a participant in a nonqualified deferred compensation plan that is required to be aggregated with the Deferral Plan under Section 409A of the Code, such Officer must file a Deferral Election within thirty (30) days of the date that the Officer first becomes eligible to participate in the LTIP (for the avoidance of any doubt, the Officer is not eligible until the award is granted under the LTIP).

(e) An LTIP Participant’s Deferral election to defer the receipt of shares underlying the grant of Performance Stock Units is irrevocable for that grant. Such an election shall not apply to future grants of Performance Stock Units.

(f) An LTIP Participant’s Deferral Election must specify whether he elects to defer all or a portion (and what portion) of the shares underlying the Performance Stock Unit award. The LTIP Participant’s election must be in whole percentages from 10% to 100%. The percentage of shares that will be deferred is based on the number of shares awarded.

(g) The LTIP Participant must also elect the deferral period, subject to Section 4. The LTIP Participant must also elect the deferral period, subject to Section 4. An LTIP Participant may elect to defer receipt of the shares underlying the Performance Restricted Stock Unit award:

(i) To a date occurring between the third anniversary and the fifteenth anniversary of the date that the shares otherwise would have been distributed to the Participant if they had not been deferred under the Deferral Plan;

(ii) Upon a Termination of Employment, or

(iii) The earlier of (i) and (ii).

(h) For the 2010 and 2011 Plan Year, an LTIP Participant may elect to defer the receipt of the shares underlying the Performance Stock Unit award by making a Deferral Election no later than December 31, 2011 (or such earlier date that the Administrator may specify). An election under this Section 3.2(h) shall be irrevocable.

(i) An Employee may make a Deferral Election pursuant to Section 3.2(h) provided that such Employee performs services continuously from the later of the beginning of the performance period specified in the Performance Stock Unit award or the date the performance criteria are established through the date a Deferral Election is made, and provided further that in no event may an election to defer the shares under the Performance Stock Unit award be made after such award has become readily ascertainable (as determined in accordance with Section 409A).

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ARTICLE IV

DISTRIBUTION OF SHARES

4.1 Deferral Period. If the Participant elects on the Deferral Election to have the shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award deferred for a specified period, the shares shall be distributed within 30 days of the end of specified period as elected by the Participant. For example, if a Participant elects to have the shares underlying the 2013 grant of Restricted Stock Units which vest on December 31, 2015 deferred for 3 years, the shares shall be distributed within 30 days following December 31, 2018. If the Participant incurs a Termination of Employment prior to the end of the elected deferral period, the shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award shall be distributed within 30 days following the end of the elected deferral period (the Termination of Employment is not a distribution event under this Section 4.1).

4.2 Termination of Employment. In the event that a Participant elects on the Election Form to have his shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award distributed upon Termination of Employment, such shares shall be distributed to the Participant within 30 days of his Termination of Employment. Notwithstanding the foregoing, in the event that the Participant is a Specified Employee (as such term is defined in the SERP), distribution of the shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award shall occur within 30 days following the date that is six after the date of the Participant’s Termination of Employment.

4.3 Earlier of End of Deferral Period or Termination of Employment. If the Participant elects on the Deferral Election to have the shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award deferred until the earlier of the end of a specified period or Termination of Employment, the shares shall be distributed within 30 days of the earlier of the end of specified period or Termination of Employment. Notwithstanding the foregoing, in the event that the Participant is a Specified Employee (as such term is defined in the SERP) and distribution of the shares will be made upon Termination of Employment, distribution shall occur within 30 days following the date that is six after the date of the Participant’s Termination of Employment.

4.4 Death of a Participant. In the event that a Participant dies prior to the date that he elects on the Election Form to have shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award distributed, such shares shall be distributed to the Participant’s estate within 30 days of the date of his death.

4.5 Change in Control. In the event a Change in Control occurs prior to the date that the Participant elects on the Election Form to have shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award distributed, such shares shall be distributed to the Participant within 30 days of the Change in Control provided that the Change in Control constitutes a change in control under Section 409A. If the Change in Control does not constitute a change in control under Section 409A, the shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award shall be distributed in accordance with Sections 4.1 through 4.4 of the Deferral Plan.

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ARTICLE V

VESTING

The Participant’s shares underlying the Restricted Stock Unit award and/or Performance Stock Unit award that are deferred under the Deferral Plan shall be fully vested. For the avoidance of any doubt, if the Participant does not satisfy the vesting requirements under the Restricted Stock Unit award and/or Performance Stock Unit award, no shares shall be deferred under the Deferral Plan.

ARTICLE VI

MISCELLANEOUS

6.1 Deferred Shares. The shares underlying the Participant’s Restricted Stock Unit award and/or Performance Stock Unit award that are deferred under the Deferral Plan shall be issued under the LTIP and held in a rabbi trust until such shares are distributed.

6.2 Dividends and Voting. The dividends attributable to the shares underlying the Participant’s Restricted Stock Unit award and Performance Stock Unit award shall be reinvested in company stock and distributed to the Participant when such shares are paid. A Participant shall direct the trustee of the rabbi trust to vote the shares underlying the Participant’s Restricted Stock Unit award and/or Performance Stock Unit award that are deferred under the Deferral Plan.

6.3 Stock-Splits and Stock Dividends. The number of shares subject to the Deferral Plan and outstanding awards will be adjusted to reflect any change in corporate capitalization, such as a stock-split, stock dividend, corporate transaction and similar events

6.4 Administration. The Deferral Plan shall be administered by the Committee. The Committee may appoint an Administrator to administer the Deferral Plan.

6.5 Amendment or Termination of the Deferral Plan. The Board of Directors may amend the Deferral Plan as it shall deem advisable. The Board of Directors may, in its discretion, terminate the Deferral Plan at any time.

6.6 Unsecured Creditor Status and Assignment Prohibition. No Participant, beneficiary or any other person shall have any interest in any particular assets of the Company by reason of the right to receive the shares that are deferred under the Deferral Plan and any such Participant, beneficiary or other person shall have only the rights of a general unsecured creditor with respect to any deferred shares.

Prior to the distribution date, no interest of any person or entity in, or right to receive the shares underlying the award shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment or other alienation or encumbrance of any kind; nor any such interest or right to receive a benefit be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings

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6.7 Income Taxes. On the distribution date of the deferred shares, the Company shall retain or sell, without notice, a sufficient number of shares to cover the amount needed to fulfill its withholding requirements for Federal, state and local income taxes, and other taxes.

6.8 Successors of the Company. The rights and obligations of the Company under the Deferral Plan shall inure to the benefit of, and shall be binding upon, the successors and assigns of the Company. In addition to any obligations imposed by law upon any successor to the Company, the Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company, to expressly assume and agree to perform the requirements set forth in the Deferral Plan.

6.9 Gender, Singular and Plural. All pronouns and any variations thereof shall be deemed to refer to the masculine, feminine, or neuter, as the identity of the person or persons may require. As the context may require, the singular may be read as the plural and the plural as the singular.

6.10 Governing Law. In the event any provision of, or legal issue relating to, the Deferral Plan is not fully preempted by federal law, such issue or provision shall be governed by the laws of the State of New Jersey without reference to conflicts of law principles.

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EX-10.5

Exhibit 10.5

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

2007 EQUITY COMPENSATION PLAN FOR OUTSIDE DIRECTORS

Amended and Restated Effective July 19, 2011

I. PURPOSE

The purpose of this Public Service Enterprise Group Incorporated 2007 Equity Compensation Plan for Outside Directors (“Plan”) is to advance the interests of the Company and its stockholders by assisting the Company in attracting and retaining individuals of superior talent, ability and achievement to serve on its Board of Directors.

It is intended that the Plan will be interpreted and administered to prevent taxation under Section 409A of the Code. Any provision of or amendment to this Plan that would cause any amount to be taxable under Section 409A with respect to any individual is void and without effect. Any election by any Participant, and any administrative action by the Committee that would cause any amount to be taxable under Section 409A with respect to any individual is void and without effect under the Plan. In the event that a Participant fails to make a Section 409A-compliant payment election, the Plan’s default payment provisions, as set forth in Subsection V.G and Article VIII, shall apply. It is further intended that the Plan will be amended in accordance with present and future guidance issued by the Treasury Department under Section 885 of the American Jobs Creation Act of 2004.

II. DEFINITIONS

The following words and phrases shall have the meanings set forth below unless a different meaning is required by the context:

a) Annual Meeting: The Annual Meeting of Stockholders of the Company.

b) Board: The Board of Directors of the Company.

c) Code: The Internal Revenue Code of 1986, as amended.

d) Committee: Those persons who are members of the Board but who are not Outside Directors.

e) Common Stock: The Common Stock without nominal or par value of the Company.

f) Company: Public Service Enterprise Group Incorporated, a corporation organized and existing under the laws of the State of New Jersey, or its successor or successors.

g) Disability: Any physical or mental condition of a permanent nature which, in sole reasonable judgment of the Committee, renders an Outside Director incapable of performing the duties of a member of the Board.

h) Effective Date: Upon approval by stockholders at the 2007 Annual Meeting of Stockholders.

i) Exchange Act: The Securities and Exchange Act of 1934, as amended, or as it may be amended from time to time.

j) NYSE: The New York Stock Exchange, Inc.

k) Outside Director: A member of the Board on or after the Effective Date who never has been employed by the Company or any of its affiliates.

l) Participant: An Outside Director who receives a Stock Unit Award under this Plan.

m) Plan: This Public Service Enterprise Group Incorporated 2007 Equity Compensation Plan for Outside Directors, as it may be amended from time to time.

n) Securities Act: The Securities Act of 1933, as amended, or as it may be amended from time to time.

o) Service: A Director’s service as a member of the Board.

p) Stock Unit Award: An award, representing the right to receive shares of Common Stock upon termination of service as an Outside Director, subject to the provisions of Article IV hereof

q) Year of Service: The annual period commencing on May 1^st of each year and ending at the earlier of the succeeding April 30^th or the next Annual Meeting of Stockholders. For any person first elected as a member of the Board after May 1^st of any year, his/her first Year of Service shall commence upon his/her election as an Outside Director and shall end at the earlier of the succeeding April 30^th or the next Annual Meeting of Stockholders.

III. SHARES SUBJECT TO THE PLAN

200,000 shares of Common Stock are reserved to satisfy awards of Stock Units pursuant to the terms of this Plan. Such shares may be acquired directly from the Company or, at the discretion of the Company, purchased on the open market by the Company or its agent.

IV. STOCK UNIT AWARDS

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A. Upon the commencement of each Year of Service as a member of the Board, each Outside Director shall be granted an award of Stock Units in an amount as shall be established from time to time by the Board of Directors. The date of grant shall be the first business day of May. With respect to an Outside Director first elected as a director after May 1 of any year, the date of such Outside Director’s initial award grant under this Plan shall be the first business day of the month next following the Outside Director’s initial election as a member of the Board.

B. The number of Stock Units to be awarded on any particular date of grant shall be equal to the amount of the award grant (expressed in dollars) divided by the closing price of the Common Stock on the NYSE on the date of grant as provided in Section IV.A, rounded up to the next whole share.

C. If a Participant fails to complete the Year of Service with respect to which a Stock Unit Award has been granted, other than on account of Disability or death, such Stock Unit Award and any earnings thereon shall be prorated to reflect the portion of the Year of Service actually served by the Participant.

D. No stock certificates shall be issued in connection with any Stock Unit Award and the Stock Unit Awards shall be evidenced by a bookkeeping account in the name of the Participant maintained by the Company. The Company shall not be required to segregate any amounts credited to these Stock Unit Award accounts, which shall be established merely as an accounting convenience. Amounts credited to the Stock Unit Award accounts shall at all times remain solely the property of the Company subject to the claims of its general creditors. Stock Unit Award accounts shall be credited with dividend equivalents at a rate equal to such dividends as may be declared by the Company on the Common Stock. Such dividends equivalents shall be deemed invested as additional Stock Units at a share price equal to closing price of the Common Stock on the NYSE on the date the transaction is credited.

E. Until distribution of shares of Common Stock from the Plan, neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate, alienate or convey the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are expressly declared to be, unassignable and non-transferable. No part of the amounts payable shall, prior to actual payment, be subject to seizure, attachment, garnishment or sequestration for the payment of any debts, judgments, alimony, property settlement or separate maintenance owed by a Participant or any other person, or be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency.

Provided, however, that, in the event that a domestic relations order of any State is received by the Plan and thereafter determined to be a Qualified Domestic Relations Order (QDRO) within the meaning of Code section 414(p), the portion of the Account of the Participant to which such QDRO is directed shall be

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apportioned as specified in such QDRO, valued as of the business day preceding the date specified in such QDRO. Upon notice to the Committee that a QDRO is being sought with respect to a Participant’s Account, no distribution shall be made to a Participant until such time as the status of the QDRO is determined. The alternate payee of the Participant’s Account shall thereafter participate in the Plan in accordance with its terms, except such person shall not have the rights or benefits provided in Subsection IV.A If a QDRO is issued and the amount awarded the alternate payee exceeds the value of the Participant’s Account, the amount apportioned shall be limited to the amount then in the account. If a QDRO so provides, benefits may be paid to an alternate payee before they would otherwise be distributable under the Plan, and no such distribution to an alternate payee shall be treated as a distribution to the Participant for purposes of Article V.

F. No Participant shall have any of the rights of a stockholder (including the right to vote and to receive dividends and other distributions (except as set forth in Section IV(D) and (G)) with respect to Stock Units unless and until shares of Common Stock are actually issued in his/her name.

G. In the event of any stock dividend, stock split, combination or exchange of shares, merger, consolidation, spin-off or other distribution (other than normal cash dividends) of Company assets to shareholders, or any other change affecting the Common Stock, such adjustments, if any, as are appropriate to reflect such change shall be made with respect to outstanding Stock Unit Awards.

H. Upon a Change in Control of the Company all outstanding Stock Unit Awards shall be considered as having met the requirements of Section IV.C. For the purposes of this Plan, “Change in Control” shall mean the occurrence of any of the following events:

a) any “person” (within the meaning of Section 13(d) of the Exchange Act is or becomes the beneficial owner within the meaning of Rule 13d-3 under the Exchange Act (a “Beneficial Owner”), directly or indirectly, of securities of the Company (not including in the securities beneficially owned by such person any securities acquired directly from the Company or its affiliates) representing 25% or more of the combined voting power of the Company’s then outstanding securities, excluding any person who becomes such a Beneficial Owner in connection with a transaction described in clause (1) of paragraph (c) below; or

b) the following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, on December 15, 1998, constitute the Board of Directors and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including but not limited to a consent solicitation. relating to the election of directors of the Company) whose appointment or election by the Board of Directors or nomination for

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election by the Company’s stockholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors on April 17, 2007 or whose appointment, election or nomination for election was previously so approved or recommended: or

c) there is consummated a merger or consolidation of the Company or any direct or indirect wholly owned subsidiary of the Company with any other corporation other than (1) a merger or consolidation which would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of the Company or any subsidiary of the Company, at least 75% of the combined voting power of the securities of the Company or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or (2) a merger or consolidation effected to implement a recapitalization of the Company (or similar transaction) in which no person is or becomes the Beneficial Owner, directly or indirectly, of securities of the Company representing 25% or more of the combined voting power of the Company’s then outstanding securities; or

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

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

V. DISTRIBUTIONS

A. Upon the termination of a Participant’s service as an Outside Director, or as of such later date as is elected by the Participant under Section V.B., the Company shall issue to the Participant certificates for shares of Common Stock equal to the number of whole Stock Units in his/her account without any legend or restriction

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of any kind in accordance with such Participant’s distribution elections hereunder. Any remaining fractional Stock Units shall be paid in cash based upon the closing price of the Common Stock on the NYSE on the day prior to the date of distribution.

B. By written notice to the Plan filed with the Company’s Secretary, a Participant may elect to have distribution of his/her Stock Unit Award account commence: (1) on the 30^th day following the date of termination of the Participant’s Service, (2) on the 15^th day of January next following the date of termination of the Participant’s Service or (3) on the 15^th day of January of any calendar year following termination of the Participant’s Service, but not later than the January following the Participant’s 72^nd birthday, unless the Participant is still a Director at such time, in which case distribution shall commence on the 30^th day following the date the Participant ceases to be a Director. Any such election, or any change in such election (by written notice to the Secretary of the Company), shall apply only to future awards. In the event no election is made as to the commencement of distribution, such distribution shall commence on the 30^th day following the date the Participant ceases to be a Director of the Company.

This paragraph shall apply to Stock Unit Awards granted on and after January 1, 2012. By written notice to the Plan filed with the Company’s Secretary prior to December 31 of the year prior to the year a Stock Unit Award is granted, a Participant may elect to have distribution of his/her Stock Unit Award account commence: (1) within 30 days following the date of termination of the Participant’s Service, or on a date indicated by the Participant as a specified number of years and/or months following termination of the Participant’s Service. Distribution shall commence within 30 days following the date that the Participant elects. If a Participant does not make an election respect to a Stock Unit Award, such Stock Unit Award shall be distributed to the Participant within 30 days following the date of termination of the Participant’s Service.

C. By written notice to the Plan filed with the Company’s Secretary, a Participant may elect to receive the distribution of his/her Stock Unit Award account in the form of (1) one lump-sum payment, or (2) annual distributions over a period selected by the Participant of up to ten years. In the event a lump-sum payment is made under the Plan, the amount then standing to the Participant’s credit in his/ her Stock Unit Award account shall be paid to the Participant on the date determined under Section V.B. In the case of a distribution over a period of years, the Company shall pay to the Participant, commencing on the date determined under Section V.B, annual installments from the amount then standing to his or her credit in his or her Stock Unit Award account, including earnings credits on the unpaid balance to the date of distribution. The amount of each installment shall be determined by dividing the then unpaid balance, plus earnings credits, in the Participant’s Stock Unit Award account by the number of installments remaining to be paid. If a Participant does not make an election as to

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the manner of distribution of his or her Stock Unit Award account, such distribution shall be made in the form of a lump sum.

This paragraph shall apply to Stock Unit Awards granted on and after January 1, 2012. By written notice to the Plan filed with the Company’s Secretary prior to December 31 of the year prior to the year a Stock Unit Award is granted, a Participant may elect to receive the distribution of his/her Stock Unit Award account in the form of (1) one lump-sum payment, or (2) annual distributions over a period of three to fifteen years as selected by the Participant. In the event a lump-sum payment is made under the Plan, the amount then standing to the Participant’s credit in his/ her Stock Unit Award account shall be paid to the Participant on the date determined under Section V.B. In the case of a distribution over a period of years, the Company shall pay to the Participant, commencing on the date determined under Section V.B, annual installments from the amount then standing to his or her credit in his or her Stock Unit Award account. The amount of each installment shall be determined by dividing the then unpaid balance in the Participant’s Stock Unit Award account by the number of installments remaining to be paid. If a Participant does not make an election as to the manner of distribution of his or her Stock Unit Award account, such distribution shall be made in the form of a lump sum.

D. In the event of a Participant’s death, the balance of the Participant’s Stock Unit Award account shall be distributed to the Participant’s Beneficiary(ies) in a lump-sum payment within 30 days following the Participant’s death. A Participant may change Beneficiary designations by filing a subsequent notice with the Secretary of the Company. If a Participant does not make a Beneficiary designation, or if the Beneficiary has predeceased the Participant, such distribution shall be made as a lump-sum to his/her estate.

E. Participants may, (i) by notice filed with the Company prior to December 31^st of any year, make changes of distribution elections on a prospective basis with respect to future grants of Stock Unit Awards; and (ii) by notice filed with the Company, make changes of distribution elections with respect to prior deferred compensation as long as (A) any such new distribution election is made at least one year prior to the date that the commencement of the distribution would otherwise have occurred and (B) the revised commencement date is at least five years later than the date that the commencement of the distribution would otherwise have occurred (and with respect to Stock Unit Awards granted before January 1, 2012, such an election may not defer payment beyond the later of the January following the Participant’s 72^nd birthday or the Participant’s termination of service as a director). For the purposes of this subsection V.E, with respect to Stock Unit Awards granted before January 1, 2012, if a Participant has elected a distribution in installments, each installment shall be deemed a separate election. With respect to Stock Unit Awards granted on and after January 1, 2012, if a Participant has elected a distribution in installments, installment payments shall be treated as one payment.

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F. Notwithstanding any other provision of the Plan, if the Board, by vote of the Outside Directors, other than the Participant making the claim, shall determine in its sole discretion that the time of payment of a Participant’s Stock Unit Award account should be advanced because of protracted illness or other undue hardship, then the Board may advance the time or times of payment (whether before or after the date of Participant’s termination of service as a Director) of an amount or amounts needed to meet the emergency in accordance with the requirements of Section 409A and the regulations promulgated thereunder.

G. Distribution in Case of Certain Tax Events – If, with respect to any Participant, the Plan fails to meet the requirements of the Code with respect to the deferral of tax liability, the Company may accelerate distribution from a Participant’s Account amounts sufficient to meet such Participant’s resulting Federal, State, Local and/or Foreign tax liability (including any interest and penalties).

VI. FURTHER CONDITIONS

A. Unless the shares of Common Stock to be distributed pursuant to the Plan have been registered with the Securities and Exchange Commission under the Securities Act prior to issuance, the Participant receiving such shares must represent in writing to the Company that such shares of Common Stock are being acquired for investment purposes only and not with a view towards the further resale or distribution thereof and must supply to the Company such other documentation as may be required by the Company, unless in the opinion of counsel to the Company such representation, agreement or documentation is not necessary to comply with the Securities Act.

B. The Company shall not be obligated to deliver any shares of Common Stock until they have been listed on each securities exchange on which the shares of Common Stock may then be listed or until there has been qualification under or compliance with such state or federal laws, rules or regulations as the Company may deem applicable. The Company shall use reasonable efforts to obtain such listing, qualification and compliance.

C. The Committee may make such provisions and take such steps as it may deem necessary or appropriate for the withholding of any taxes that the Company is required by any law or regulation of any governmental authority, whether federal, state or local, domestic or foreign, to withhold in connection with the award of Stock Units or the distribution of any Common Stock, including, but not limited to (i) the withholding of delivery of certificates for shares of Common Stock until the Participant reimburses the Company for the amount the Company is required to withhold with respect to such taxes, (ii) the canceling of any number of shares of Common Stock issuable in an amount sufficient to reimburse the Company for the amount it is required to so withhold or (iii) withholding the amount due from any such Participant’s other compensation.

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VII. ADMINISTRATION

The Plan shall be administered by the Committee, which shall establish rules and regulations regarding the administration and operation of the Plan.

VIII. TERMINATION, MODIFICATION AND AMENDMENT

Although the Company anticipates that it will continue the Plan for an indefinite period of time, there is no guarantee that the Company will continue the Plan or will not terminate the Plan at any time in the future. Accordingly, the Company, by the Board of Directors, reserves the right to discontinue its sponsorship of the Plan or to terminate the Plan (or both), at any time, by the action of the Board of Directors. In general, upon the termination of the Plan, the affected Participants shall receive payment of their benefits in accordance with the terms of Article V. However, the Company may, in its discretion, terminate the entire Plan and pay each Participant a single lump-sum distribution of his or her entire Account Balance, in the event that the Company satisfies any of the following:

(a) such distributions are made between 12 and 24 months following the termination of the Plan, and the Company does not adopt a new plan which would be aggregated with this Plan under IRS guidance under Code Section 409A at any time within the five years following the Plan termination.

(b) the Plan is terminated within the 30 days preceding or the 12 months following a Change in Control, all payments are made within 12 months of the date of termination, and all substantially similar arrangements sponsored by the Company are terminated as well.

(c) the Plan is terminated within 12 months of a corporate dissolution, as defined in IRS guidance under Code Section 409A, and lump sum payments are made in the latest of (i) the year of the termination, (ii) the year in which amounts are no longer subject to a substantial risk of forfeiture; or (iii) the first year in which payment is administratively practicable.

The termination of the Plan shall not adversely affect any Participant or Beneficiary who has become entitled to the payment of any benefits under the Plan as of the date of termination.

IX. NOT A CONTRACT FOR CONTINUED SERVICE

Nothing contained in the Plan or in any stock unit agreement executed pursuant hereto shall be deemed to confer upon any Outside Director to whom Stock Unit Awards are or may be awarded hereunder any right to remain a member of the Board or in any way limit the right of the Board or the Stockholders to terminate or fail to renominate or reelect any such Outside Director as a member of the Board.

X. MISCELLANEOUS

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A. The costs and expenses of administering the Plan shall be borne by the Company and shall not be charged against any award or to any Outside Director receiving an award.

B. This Plan and actions taken in connection herewith shall be governed and construed in accordance with the laws of the State of New Jersey.

C. The captions and section numbers appearing in this Plan are inserted only as a matter of convenience. They do not define, limit or describe the scope or intent of the provisions of this Plan. In this Plan, words in the singular number include the plural and in the plural include the singular; and words of the masculine gender include the feminine and the neuter, and when the sense so indicates, words of the neuter gender may refer to any gender.

D. Whenever the time for payment or performance hereunder shall fall on a weekend or public holiday, such payment or performance shall be deemed to be timely if made on the next succeeding business day.

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EX-10.6

Exhibit 10.6

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

DEFERRED COMPENSATION PLAN FOR DIRECTORS

Amended July 19, 2011

With Certain Provisions Effective January 1, 2012

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

DEFERRED COMPENSATION PLAN FOR DIRECTORS

Amended Effective July 19, 2011

1 PURPOSE. The Plan is designed to provide a method of deferring payment to non-employee Directors of their fees and annual retainers, as fixed from time to time by the Board of Directors, until termination of their services on the Board.

2. PLAN PERIODS. The first Plan Period shall commence upon the election of Directors at the 1987 Annual Stockholders’ Meeting and terminate upon the election of Directors at the 1988 Annual Stockholders’ Meeting. Subsequent Plan Periods shall relate to successive similar periods between Annual Stockholders Meetings. Effective January 1, 2002, Plan Periods shall be calendar year periods.

3. ADMINISTRATION. The Plan shall be administered by a Committee consisting of the Chief Executive Officer of the Company and two other officers appointed by him. The Committee shall have the power to interpret the Plan and, subject to its provisions, to make all determinations necessary or desirable for the Plan’s administration.

4. PARTICIPATION.

(a) An individual who serves as a Director and is not otherwise employed by the Company or any of its subsidiaries shall be eligible to participate in the Plan if he or she elects to have payment of his or her annual retainer, his or her fees or his or her annual retainer and fees in respect of a Plan Period deferred as provided herein.

(b) All elections to defer must be made in the calendar year prior to the year that the services giving rise to the compensation are performed. The election shall be made by written notice to the Plan filed with the Company’s Secretary prior to the first day of such Plan Period or, in the case of a Director who first becomes eligible during a Plan Period, not later than 30 days after he or she first becomes eligible. Except as otherwise provided herein, each such election shall be irrevocable.

(c) Special One-Time Election to Rescind 2005 Deferrals – Not later than December 30, 2005, Participants who had elected to defer compensation during 2005 may, by written notice, the form of which shall be designated and published by the Committee, rescind his/her election to defer 2005 compensation and such amounts shall be currently paid to the Participant.

(d) Special One-Time Election to Change Distribution Elections with respect to 2005, 2006, 2007 or 2008 Deferrals – Not later than December 31, 2008, Participants who had elected to defer compensation during 2005, 2006, 2007 or 2008 may, by

written notice in a form approved by the Committee, elect to change the distribution elections with respect to any such deferrals.

5. DEFERRED COMPENSATION ACCOUNTS.

(a) An account shall be established for each eligible electing Director (a “Participant”) which shall be designated as his or her Deferred Compensation Account. If a Participant elects to have payment deferred of his or her annual retainer, the amount of the annual retainer payable to him or her with respect to a Plan Period shall be credited, in four equal installments on or about the last day of March , June, September and December in the Plan Period to which such retainer relates, to his or her Deferred Compensation Account, subject to the provisions of Section 5(c). If a Participant elects to have payment deferred of his or her fees, the amount of each fee payable to him or her for attendance at a meeting during a Plan Period shall be credited to his or her Deferred Compensation Account on or about the first business day following such meeting. The Company shall not be required to segregate any amounts credited to the Deferred Compensation Accounts, which shall be established merely as an accounting convenience. Amounts credited to the Deferred Compensation Accounts shall at all times remain solely the property of the Company subject to the claims of its general creditors.

(b) A Director, except a Director not actively serving on the Board on April 1, 2000, may direct investment of his or her Account among the Investment Funds (hereinafter defined) (in the manner established by the Committee) in multiples of one percent; provided, however, that the Committee shall not be obligated to effectuate any such investment direction. The amounts credited to a Deferred Compensation Account shall accrue earnings credits as determined by the Investment Fund(s) selected by the Director. In the case of (i) Director not actively serving on the Board on April 1, 2000 and (ii) a Director who fails to provide a designation of Investment Funds, each such Director shall be deemed to have designated 100 percent of his or her Account to be invested in the Investment Fund that determines income accrual with reference to the prime commercial lending rate of JPMorgan Chase Bank (formerly, the Chase Manhattan Bank). Except with respect to an investment election related to (a) an election made within 30 days of April 1, 2000 and (b) any Investment Fund which is discontinued during a Plan Year, each of which shall be effective immediately. Effective July 1, 2011, the prime commercial lending rate of JPMorgan Chase Bank shall be capped at 120% applicable federal long-term rate.

A Director’s investment election may be changed daily.

Each Director’s Account shall be valued daily.

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(c) ‘Investment Fund’ - the fund or funds selected by the Committee from time to time and included in Schedule C of the Plan which shall serve as a means of measuring the increase or decrease of each Director’s Account. The Committee may, in its discretion, add or discontinue any Investment Fund available under the Plan. The Committee shall provide each affected Director with the opportunity, without limiting or otherwise impairing any other right of such Director regarding changes in investment directions, to redirect the allocation of his or her Account invested in any discontinued Investment Fund among the other Investment Funds available under the Plan, including any replacement investment vehicle.

(d) If, prior to the end of a Plan Period, a Participant becomes an employee of the Company or one of its subsidiaries or dies or ceases for any reason to be a Director, or if the effective date of participation by a Participant for any Plan Period shall be other than the first day thereof, he or she will be entitled to be credited with that proportion of the annual retainer for the full Plan Period which the number of days of his or her participation in the Plan during such Plan Period bears to the total number of days in such Plan Period.

6. PAYMENT.

(a) Following termination of a Participant’s service on the Board, the Company shall distribute his or her Deferred Compensation Account.

(b) For 2011 and Prior Years Deferrals.

(i) By written notice to the Plan filed with the Company’s Secretary, a Participant may elect to have distribution of his or her Deferred Compensation Account commence either (1) on the 30th day following the date of termination of the Participant’s service on the Board, (2) on the 15^th day of January next following the date of termination of the Participant’s service on the Board or (3) on the 15^th day of January of any calendar year following termination of the Participant’s service on the Board, but not later than the January following the Participant’s 71st birthday, unless the Participant is still a Director at such time, in which case distribution shall commence on the 30^th day following the date the Participant ceases to be a Director. Any such election, or any change in such election (by such subsequent written notice to the Secretary of the Company), shall apply only to future deferrals. In the event no election is made as to the commencement of distribution, such distribution shall commence on the 30th day following the date the Participant ceases to be a Director of the Company.

(ii) By written notice to the Plan filed with the Company’s Secretary, a Participant may elect to receive the distribution of his or her Deferred Compensation Account in the form of (1) one lump-sum payment, or (2)

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annual distributions over a period selected by the Participant of up to ten years. In the event a lump-sum payment is made under the Plan, the amount then standing to the Participant’s credit in his or her Deferred Compensation Account, including earnings credits provided in Section 5(b) to the date of distribution, shall be paid to the Participant on the date determined under Section 6(b)(i). In the case of a distribution over a period of years, the Company shall pay to the Participant, commencing on the date determined under Section 6(b)(i), annual installments from the amount then standing to his or her credit in his or her Deferred Compensation Account, including earnings credits on the unpaid balance at the rate provided in Section 5(b) to the date of distribution. The amount of each installment shall be determined by dividing the then unpaid balance, plus earnings credits, in the Participant’s Deferred Compensation Account by the number of installments remaining to be paid. If a Participant does not make an election as to the manner of distribution of his or her Deferred Compensation Account, such distribution shall be made in the form of annual installments paid over a five-year period.

(c) For 2012 and Beyond Deferrals. By written notice to the Plan filed with the Company’s Secretary, a Participant may elect to have distribution of each year’s deferrals and associated earnings occur on the date or event specified in subsections (i) or (ii). A Participant’s distribution election shall apply to future years unless the Participant makes a subsequent election.

(i) For each year, a Participant, may elect to have distribution of that year’s deferrals, and associated earnings, made or commence within the 30-day period following the Participant’s termination of service on the Board. A Participant may elect to receive such distribution in the form of (A) one lump-sum payment, or (B) annual installments over a three to fifteen year period. In the case of a distribution over a period of years, the Company shall pay to the Participant on the date determined under this Section 6(c)(i) and on the yearly anniversaries of such date, annual installments of the unpaid balance of that year’s deferrals, including earnings on the unpaid balance at the rate provided in Section 5(b) of this Plan to the date of distribution. The amount of each installment shall be determined by multiplying the then unpaid balance of that year’s deferrals, plus accrued earnings, the numerator of which is one and the denominator of which is the number of annual installments remaining to be paid.

(ii) For each year, a Participant, may elect to have distribution of that year’s deferrals and associated earnings be paid or commence on a date that is indicated by the Participant as a specified number of years and/or months following termination of service on the Board. Distribution shall be made or commence within the 30 day period following the date that the Participant elects. A Participant may elect to receive such distribution in

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the form of (A) one lump-sum payment, or (B) annual installments over a three to fifteen year period. In the case of a distribution over a period of years, the Company shall pay to the Participant on the date determined under this Section 6(c)(ii) and on the yearly anniversaries of such date, annual installments of the unpaid balance of that year’s deferrals, including earnings on the unpaid balance at the rate provided in Section 5(b) of this Plan to the date of distribution. The amount of each installment shall be determined by multiplying the then unpaid balance of that year’s deferrals, plus accrued earnings, the numerator of which is one and the denominator of which is the number of annual installments remaining to be paid.

(iii) If, with respect to any election to defer compensation for 2012 or any subsequent year, a Participant fails to make a proper election with respect to the distribution of such deferred compensation, such amount will be distributed in accordance with the prior year’s election (but not any election in place for a year prior to 2012). In the event that no valid election is on file, such amount will be distributed in a lump sum on the date specified in Section 6(c)(i).

(d) The payment of all distributions shall be made in money by check, except that the portion of a Participant’s Deferred Compensation Account that is allocated to the Investment Fund based upon the performance of this Corporation’s common stock may elect to receive distributions with respect to that portion of his/her Deferred Compensation Account in shares of common stock. Any amounts related to fractional shares shall be paid in money by check.

(e) Distribution upon Death.

(i) For 2011 and Prior Years Deferrals. In the event of a Participant’s death, the balance of the Participant’s Deferred Compensation Account shall be distributed to the Participant’s Beneficiary(ies) in annual installments over a period of not more than five years, in accordance with the Participant’s election on Schedule B to the Plan filed with the Secretary of the Company. Any change in the period over which such payments are made shall only apply to future deferrals. Such distribution shall be made in a manner consistent with Section 6(c) of the Plan and shall commence on the 30th day following the Participant’s death. Additional annual payments for distributions made over a period of more than one year shall be made on the yearly anniversaries of such date. In the event of a Participant’s death after distribution of this Deferred Compensation Account has commenced, any election under this Section 6(d) shall not extend the time of payment of his or her Deferred Compensation Account beyond the time when distribution would have been completed if the Participant had lived. A Participant may change Beneficiary designations by filing a subsequent

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Schedule B with the Secretary of the Company. If a Participant does not make an election as to the manner of distribution of his or her Deferred Compensation Account in the event of his or her death, any such distribution shall be made as a lump-sum payment to his or her estate on the 30th day following the Participant’s death.

(ii) For 2012 and Beyond Deferrals. In the event of a Participant’s death prior to the date that the Participant commences payment of a year’s deferrals and associated earnings, such amount shall be distributed to the Participant’s Beneficiary(ies) in a lump sum within 90 days following the Participant’s death.

In the event of the Participant’s death after he/she commenced distribution of a year’s deferrals and associated earnings in the form of installments, the balance of such year’s deferrals and associated earnings shall be distributed to the Participant’s Beneficiary(ies) in a lump sum within 90 days following the Participant’s death.

A Participant’s Beneficiary designation shall apply to all 2012 and beyond deferrals. A Participant cannot designate a different Beneficiary for each year’s deferrals. A Participant may change Beneficiary designations by filing a subsequent designation with the Secretary of the Company.

(f) Participants may:

(i) By notice filed with the Company prior to December 31^st of any year, make changes of distribution elections on a prospective basis;

(ii) By notice filed with the Company, make changes of distribution elections with respect to prior deferred compensation as long (A) any such new distribution election is made at least one year prior to the date that the commencement of the distribution would otherwise have occurred and (B) the revised commencement date is at least five years later than the date that the commencement of the distribution would otherwise have occurred (with respect to 2012 and beyond deferrals, installment payments shall be treated as one payment);

(iii) Special One-Time Election - by notice filed with the Company prior to December 31, 2005, make a one-time election to change any distribution election previously made with respect to compensation deferred on or before December 31, 2005; or

(iv) Special One-Time Election - Participants may, by notice filed with the

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Company prior to December 31, 2008, make a one-time election to change any distribution election previously made with respect to compensation deferred during 2005, 2006, 2007 or 2008.

(g) Notwithstanding any other provision of the Plan, if the Committee shall determine in its sole discretion that the time of payment of a Participant’s Deferred Compensation Account should be advanced because of protracted illness or other undue hardship, then the Committee may advance the time or times of payment (whether before or after the Retirement Date) only if the Committee determines that an emergency beyond the control of the Participant exists and which would cause such Participant severe financial hardship if the payment of such benefits were not approved. Any such distribution for hardship shall be limited to the amount needed to meet such emergency (plus the amount of any tax liability resulting from the distribution). A Participant who receives a hardship distribution may not reenter the Plan for twelve months after the date of such distribution. Any distribution for hardship under this Section 6(f) shall commence on the 15^th day following the date the Committee determines to make such hardship distribution.

(h) Distribution in Case of Certain Tax Events – If, with respect to any Participant, the Plan fails to meet the requirements of the Internal Revenue Code with respect to the deferral of tax liability, the Company may accelerate distribution from a Participant’s Account amounts sufficient to meet such Participant’s resulting Federal, State, Local and/or Foreign tax liability (including any interest and penalties).

7. ASSIGNMENT. No benefit under the Plan shall in any manner or to any extent be assigned, alienated, or transferred by any Participant or Beneficiary or subject to attachment, garnishment or other legal process.

8. TERMINATION AND AMENDMENT.

(a) The Board may terminate the Plan at any time so that no further amounts shall be credited to Deferred Compensation Accounts or may, from time to time, amend the Plan, without the consent of Participants or Beneficiaries; provided, however, that no such amendment or termination shall impair any rights, including rights to income credits pursuant to Section 5(b) hereof, which have accrued under the Plan without the consent of the Participant or Beneficiary, or the legal representative of such person, so affected.

(b) Notwithstanding any other provision of this Plan, upon the occurrence of a Change in Control (as defined below), the income credit calculated pursuant to Section 5(b) hereof may not be reduced below the prime commercial lending rate described therein.

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For purposes of this Plan, “Change in Control” shall mean the occurrence of any of the following events:

(i) any “person” (within the meaning of Section 13(d) of the Securities Exchange Act of 1934, as amended from time to time (the “Act”)) is or becomes the beneficial owner within the meaning of Rule l3d-3 under the Act (a “Beneficial Owner”), directly or indirectly, of securities of the Corporation (not including in the securities beneficially owned by such person any securities acquired directly from the Corporation or its affiliates) representing 25% or more of the combined voting power of the Corporation’s then outstanding securities, excluding any person who becomes such a Beneficial Owner in connection with a transaction described in clause (1) of paragraph (iii) below; or

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

(iii) there is consummated a merger or consolidation of the Corporation or any direct or indirect wholly owned subsidiary of the Corporation with any other corporation, other than (1) a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or any subsidiary of the Corporation, at least 75% of the combined voting power of the securities of the Corporation or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or (2) a merger or consolidation effected to implement a recapitalization of the Corporation (or similar transaction) in which no person is or becomes the Beneficial Owner, directly or indirectly, of securities of the Corporation representing 25% or more of the combined voting power of the Corporation’s then outstanding securities; or

8

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

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

9. WHAT CONSTITUTES NOTICE.

Any notice to an Participant, Beneficiary or legal representative hereunder shall be given either by delivering it or by depositing it in the United States mail, postage prepaid, addressed to his/her last known address. Any notice to the Company or the Committee hereunder (including the filing of election and designation forms) shall be given either by delivering it, or depositing it in the United States mail, postage prepaid, to the Secretary of the Employee Benefits Policy Committee, Public Service Enterprise Group Incorporated, 80 Park Plaza, P. 0. Box 1171, Newark, New Jersey 07102.

10. ADVANCE DISCLAIMER OF ANY WAIVER ON THE PART OF THE COMPANY. Failure by the Company to insist upon strict compliance with any of the terms, covenants or conditions hereof shall not be deemed a waiver of any such term, covenant or condition, nor shall any waiver or relinquishment of any right or power hereunder at any one or more times be deemed a waiver or relinquishment of any such right or power at any other time or times.

11. EFFECT ON INVALIDITY OF ANY PART OF THE PLAN. The invalidity or unenforceability of any provision hereof shall in no way affect the validity or enforceability of any other provision.

12. PLAN BINDING ON ANY SUCCESSOR OWNER. Except as otherwise provided herein, this Plan shall inure to the benefit of and be binding upon the Company, its successors and assigns, including but not limited to any corporation which may acquire all or substantially all of the Company’s assets and business or with or into which the Company may be consolidated or merged.

9

13. LAWS GOVERNING THIS PLAN. Except to the extent federal law applies, this Plan shall be governed by the laws of the State of New Jersey. This Plan is specifically intended to comply with the provisions of the American Jobs Creation Act of 2004 (the “AJCA”) and Section 409A of the Code and it shall automatically incorporate all applicable restrictions of the AJCA, the Code and its related regulations, and the Company will amend the Plan to the extent necessary to comply with those requirements. The timing under which a Participant will have a right to receive any payment under this Plan will be deemed to be automatically modified, and a Participant’s rights under the Plan limited to conform to any requirements under, the AJCA, the Code and its related regulations.

14. MISCELLANEOUS. The masculine pronoun shall mean the feminine wherever appropriate.

10

EX-12

EXHIBIT 12

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	For the Nine Months Ended September 30,						For the Years Ended December 31,
	2011			2010			2010			2009			2008			2007			2006
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	1,804		$	2,123		$	2,616		$	2,636		$	1,806		$	2,303		$	1,000
(Income) Loss from Equity Investees, net of Distributions		(7	)		(17	)		(19	)		(25	)		(5	)		(10	)		(33	)
Fixed Charges		394			429			571			600			633			755			821
Capitalized Interest		(7	)		(49	)		(68	)		(45	)		(37	)		(26	)		(32	)
Preferred Securities Dividend Requirements of Subsidiaries		0			(2	)		(2	)		(6	)		(6	)		(6	)		(6	)
Total Earnings	$	2,184		$	2,484		$	3,098		$	3,160		$	2,391		$	3,016		$	1,750
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	384		$	417		$	555		$	581		$	615		$	737		$	803
Interest Factor in Rentals		10			10			14			13			12			12			12
Preferred Securities Dividend Requirements of Subsidiaries		0			2			2			6			6			6			6
Total Fixed Charges	$	394		$	429		$	571		$	600		$	633		$	755		$	821
Ratio of Earnings to Fixed Charges		5.54			5.79			5.43			5.27			3.78			3.99			2.13

(A) The term “earnings” shall be defined as pre-tax Income from Continuing Operations before income or loss from equity investees plus distributed income from equity investees. Add to pre-tax income the amount of fixed charges adjusted to exclude (a) the amount of any interest capitalized during the period and (b) the actual amount of any preferred securities dividend requirements of majority-owned subsidiaries stated on a pre-tax level.

(B) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount, premium and expense, (c) an estimate of interest implicit in rentals and (d) preferred securities dividend requirements of majority-owned subsidiaries stated on a pre-tax level.

EX-12.1

EXHIBIT 12.1

PSEG POWER LLC

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	For the Nine Months Ended September 30,						For the Years Ended December 31,
	2011			2010			2010			2009			2008			2007			2006
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	1,314		$	1,569		$	1,914		$	1,958		$	1,711		$	1,590		$	878
Fixed Charges		157			180			238			221			210			193			190
Capitalized Interest		(6	)		(46	)		(63	)		(43	)		(31	)		(23	)		(30	)
Total Earnings	$	1,465		$	1,703		$	2,089		$	2,136		$	1,890		$	1,760		$	1,038
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	155		$	177		$	235		$	219		$	208		$	192		$	189
Interest Factor in Rentals		2			3			3			2			2			1			1
Total Fixed Charges	$	157		$	180		$	238		$	221		$	210		$	193		$	190
Ratio of Earnings to Fixed Charges		9.33			9.46			8.78			9.67			9.00			9.12			5.46

(A) The term “earnings” shall be defined as pre-tax Income from Continuing Operations. Add to pre-tax income the amount of fixed charges adjusted to exclude the amount of any interest capitalized during the period.

(B) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount, premium and expense and (c) an estimate of interest implicit in rentals.

EX-12.2

EXHIBIT 12.2

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	For the Nine Months Ended September 30,						For the Years Ended December 31,
	2011			2010			2010			2009			2008		2007		2006
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	709		$	448		$	591		$	551		$	592	$	637	$	448
Fixed Charges		240			243			325			317			325		332		346
Capitalized Interest		(2	)		(1	)		(2	)		(1	)		0		0		0
Total Earnings	$	947		$	690		$	914		$	867		$	917	$	969	$	794
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	236		$	240		$	320		$	313		$	325	$	332	$	346
Interest Factor in Rentals		4			3			5			4			0		0		0
Total Fixed Charges	$	240		$	243		$	325		$	317		$	325	$	332	$	346
Ratio of Earnings to Fixed Charges		3.95			2.84			2.81			2.74			2.82		2.92		2.29

(A) The term “earnings” shall be defined as pretax income from continuing operations. Add to pretax income the amount of fixed charges adjusted to exclude the amount of any interest capitalized during the period.

(B) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount, premium and expense and (c) an estimate of interest implicit in rentals.

EX-12.3

EXHIBIT 12.3

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

Plus Preferred Security Dividend Requirements

	For the Nine Months Ended September 30,						For the Years Ended December 31,
	2011			2010			2010			2009			2008			2007			2006
	(Millions, except ratios)
Earnings as Defined in Regulation S-K (A):
Pre-tax Income from Continuing Operations	$	709		$	448		$	591		$	551		$	592		$	637		$	448
Fixed Charges		240			245			327			323			332			339			353
Capitalized Interest		(2	)		(1	)		(2	)		(1	)		0			0			0
Preferred Securities Dividend Requirements of Subsidiaries		0			(2	)		(2	)		(6	)		(6	)		(6	)		(6	)
Total Earnings	$	947		$	690		$	914		$	867		$	918		$	970		$	795
Fixed Charges as Defined in Regulation S-K (B)
Interest Expense	$	236		$	240		$	320		$	313		$	325		$	332		$	346
Interest Factor in Rentals		4			3			5			4			0			0			0
Preferred Securities Dividends		0			1			1			4			4			4			4
Adjustments to state Preferred Securities Dividends on a pre-income tax basis		0			1			1			2			2			2			2
Total Fixed Charges	$	240		$	245		$	327		$	323		$	331		$	338		$	352
Ratio of Earnings to Fixed Charges		3.95			2.82			2.80			2.68			2.77			2.87			2.26

(A) The term “earnings” shall be defined as pretax income from continuing operations. Add to pretax income the amount of fixed charges adjusted to exclude (a) the amount of any interest capitalized during the period (b) the actual amount of any preferred securities dividend requirements of majority owned subsidiaries (c) preferred stock dividends which were included in such fixed charges amount but not deducted in the determination of pre-tax income.

(B) Fixed Charges represent (a) interest, whether expensed or capitalized, (b) amortization of debt discount and premium expense (c) an estimate of interest implicit in rentals and (d) preferred securities dividend requirements of majority owned subsidiaries and preferred stock dividends, increased to reflect the pre-tax earnings requirement for PSE&G.

EX-31

EXHIBIT 31

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Ralph Izzo, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Enterprise Group Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 1, 2011	/s/ Ralph Izzo
		Ralph Izzo Public Service Enterprise Group Incorporated Chief Executive Officer

EX-31.1

EXHIBIT 31.1

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Caroline Dorsa, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Enterprise Group Incorporated;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 1, 2011	/s/ Caroline Dorsa
		Caroline Dorsa Public Service Enterprise Group Incorporated Chief Financial Officer

EX-31.2

EXHIBIT 31.2

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Ralph Izzo, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PSEG Power LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 1, 2011	/s/ Ralph Izzo
		Ralph Izzo PSEG Power LLC Chief Executive Officer

EX-31.3

EXHIBIT 31.3

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Caroline Dorsa, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of PSEG Power LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 1, 2011	/s/ Caroline Dorsa
		Caroline Dorsa PSEG Power LLC Chief Financial Officer

EX-31.4

EXHIBIT 31.4

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Ralph Izzo, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Electric and Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 1, 2011	/s/ Ralph Izzo
	Ralph Izzo
	Public Service Electric and Gas Company
	Chief Executive Officer

EX-31.5

EXHIBIT 31.5

Certification Pursuant to Rules 13a-14 and 15d-14

of the 1934 Securities Exchange Act

I, Caroline Dorsa, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Public Service Electric and Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 1, 2011	/s/ Caroline Dorsa
	Caroline Dorsa
	Public Service Electric and Gas Company
	Chief Financial Officer

EX-32

EXHIBIT 32

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Ralph Izzo, Chief Executive Officer of Public Service Enterprise Group Incorporated, to the best of my knowledge, certify that (i) the Quarterly Report of Public Service Enterprise Group Incorporated on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Public Service Enterprise Group Incorporated.

/s/ Ralph Izzo

Ralph Izzo

Public Service Enterprise Group Incorporated

Chief Executive Officer

November 1, 2011

EX-32.1

EXHIBIT 32.1

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Caroline Dorsa, Chief Financial Officer of Public Service Enterprise Group Incorporated, to the best of my knowledge, certify that (i) the Quarterly Report of Public Service Enterprise Group Incorporated on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Public Service Enterprise Group Incorporated.

/s/ Caroline Dorsa

Caroline Dorsa

Public Service Enterprise Group Incorporated

Chief Financial Officer

November 1, 2011

EX-32.2

EXHIBIT 32.2

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Ralph Izzo, Chief Executive Officer of PSEG Power LLC, to the best of my knowledge, certify that (i) the Quarterly Report of PSEG Power LLC on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of PSEG Power LLC.

/s/ Ralph Izzo

Ralph Izzo

PSEG Power LLC

Chief Executive Officer

November 1, 2011

EX-32.3

EXHIBIT 32.3

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Caroline Dorsa, Chief Financial Officer of PSEG Power LLC, to the best of my knowledge, certify that (i) the Quarterly Report of PSEG Power LLC on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of PSEG Power LLC.

/s/ Caroline Dorsa

Caroline Dorsa

PSEG Power LLC

Chief Financial Officer

November 1, 2011

EX-32.4

EXHIBIT 32.4

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Ralph Izzo, Chief Executive Officer of Public Service Electric and Gas Company, to the best of my knowledge, certify that (i) the Quarterly Report of Public Service Electric and Gas Company on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Public Service Electric and Gas Company.

/s/ Ralph Izzo

Ralph Izzo

Public Service Electric and Gas Company

Chief Executive Officer

November 1, 2011

EX-32.5

EXHIBIT 32.5

Certification Pursuant to Section 1350 of Chapter 63 of Title 18

of the United States Code

I, Caroline Dorsa, Chief Financial Officer of Public Service Electric and Gas Company, to the best of my knowledge, certify that (i) the Quarterly Report of Public Service Electric and Gas Company on Form 10-Q for the quarter ended September 30, 2011 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Public Service Electric and Gas Company.

/s/ Caroline Dorsa

Caroline Dorsa

Public Service Electric and Gas Company

Chief Financial Officer

November 1, 2011

XML

Income Taxes (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended	12 Months Ended		15 Months Ended
	Dec. 31, 2010	Mar. 31, 2010	Sep. 30, 2011	Dec. 31, 2012	Dec. 31, 2010	Dec. 31, 2011
Component of Other Income, Nonoperating [Line Items]
Reduction in unrecognized tax benefits					97
Deferred tax recorded related to health care reform		$ 9
Bonus depreciation for tax purposes	50.00%			50.00%		100.00%
Unrecognized tax benefit increase on settlement with IRS			205
Unrecognized tax benefit decrease on settlement with IRS			297
Increase in unrecognized tax benefits reasonably likely to increase or decrease within one year	19				19
PSE&G [Member] | Offset To Deferred Tax Related To Health Care Reform [Member]
Component of Other Income, Nonoperating [Line Items]
Regulatory assets			78
PSE&G [Member]
Component of Other Income, Nonoperating [Line Items]
Reduction in unrecognized tax benefits					43
Increases in unrecognized tax benefits			53
Investment tax credit			$ 32

XML

Available-For-Sale Securities (Fair Values And Gross Unrealized Gains And Losses For The Securities Held In The NDT Funds) (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Power [Member] | Nuclear Decommissioning Trust (NDT) Funds [Member] | Total Available-For-Sale Securities Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 1,216	$ 1,143
Gross Unrealized Gains	123	229
Gross Unrealized Losses	(59)	(9)
Estimated Fair Value	1,280	1,363
Power [Member] | Nuclear Decommissioning Trust (NDT) Funds [Member] | Debt Securities Total [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	613	548
Gross Unrealized Gains	30	16
Gross Unrealized Losses	(4)	(6)
Estimated Fair Value	639	558
Power [Member] | Nuclear Decommissioning Trust (NDT) Funds [Member] | Other Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	273	247
Gross Unrealized Gains	14	10
Gross Unrealized Losses	(3)	(2)
Estimated Fair Value	284	255
Power [Member] | Nuclear Decommissioning Trust (NDT) Funds [Member] | US States And Political Subdivisions Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	340	301
Gross Unrealized Gains	16	6
Gross Unrealized Losses	(1)	(4)
Estimated Fair Value	355	303
Power [Member] | Nuclear Decommissioning Trust (NDT) Funds [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	537	525
Gross Unrealized Gains	93	213
Gross Unrealized Losses	(55)	(3)
Estimated Fair Value	575	735
Power [Member] | Nuclear Decommissioning Trust (NDT) Funds [Member] | Other Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	66	70
Gross Unrealized Gains	0	0
Gross Unrealized Losses	0	0
Estimated Fair Value	66	70
Total Available-For-Sale Securities Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	163	158
Gross Unrealized Gains	7	2
Gross Unrealized Losses	0	0
Estimated Fair Value	170	160
Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	16	16
Gross Unrealized Gains	2	2
Gross Unrealized Losses	0	0
Estimated Fair Value	$ 18	$ 18

XML

Condensed Consolidated Statements Of Operations (Parenthetical) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income (Loss) from Discontinued Operations, tax (expense) benefit	$ (15)	$ (11)	$ (51)	$ (10)
Power [Member]
Income (Loss) from Discontinued Operations, tax (expense) benefit	$ (15)	$ (11)	$ (51)	$ (10)

XML

Condensed Consolidated Balance Sheets (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
CURRENT ASSETS
Cash and Cash Equivalents	$ 1,242		$ 280
Accounts Receivable	1,164		1,387
Tax Receivable	377		689
Unbilled Revenues	251		400
Fuel	740		666
Materials and Supplies, net	365		359
Prepayments	416		204
Derivative Contracts	113		182
Assets of Discontinued Operations	0		564
Deferred Income Taxes	96		43
Regulatory Assets	86		155
Other	120		122
Total Current Assets	4,970		5,051
PROPERTY, PLANT AND EQUIPMENT	24,618		23,272
Less: Accumulated Depreciation and Amortization	(7,336)		(6,882)
Net Property, Plant and Equipment	17,282		16,390
NONCURRENT ASSETS
Regulatory Assets	3,354		3,736
Regulatory Assets of Variable Interest Entities (VIEs)	968		1,128
Long-Term Investments	1,406		1,623
Nuclear Decommissioning Trust (NDT) Funds	1,280		1,363
Other Special Funds	170		160
Goodwill	16		16
Other Intangibles	164		136
Derivative Contracts	75		79
Restricted Cash of VIEs	22		21
Other	204		206
Total Noncurrent Assets	7,659		8,468
TOTAL ASSETS	29,911		29,909
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	1,275		915
Securitization Debt of VIEs Due Within One Year	214		206
Commercial Paper and Loans	0		64
Accounts Payable	1,144		1,176
Derivative Contracts	94		103
Accrued Interest	131		108
Accrued Taxes	30		49
Clean Energy Program	224		195
Obligation to Return Cash Collateral	107		104
Regulatory Liabilities	161		174
Liabilities of Discontinued Operations	0		72
Other	312		319
Total Current Liabilities	3,692		3,485
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	5,652		5,129
Regulatory Liabilities	235		285
Regulatory Liabilities of VIEs	9		8
Asset Retirement Obligations	482		461
Other Postretirement Benefit (OPEB) Costs	948		967
Accrued Pension Costs	189		788
Clean Energy Program	70		235
Environmental Costs	651		669
Derivative Contracts	31		22
Long-Term Accrued Taxes	234		248
Other	77		152
Total Noncurrent Liabilities	8,578		8,964
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT
Long-Term Debt	6,651		6,834
Securitization Debt of VIEs	784		939
Project Level, Non-Recourse Debt	45		46
Total Long-Term Debt	7,480		7,819
STOCKHOLDERS' EQUITY
Common Stock	4,818		4,807
Treasury Stock, at cost, 2011-27,651,927 shares; 2010-27,582,437 shares	(601)		(593)
Retained Earnings	6,198		5,575
Accumulated Other Comprehensive Loss	(256)		(156)	[1]
Total Common Stockholders' Equity	10,159		9,633
Noncontrolling Interest	2		8
Total Stockholders' Equity	10,161		9,641
Total Capitalization	17,641		17,460
TOTAL LIABILITIES AND CAPITALIZATION	29,911		29,909
Power [Member]
CURRENT ASSETS
Cash and Cash Equivalents	14		11
Accounts Receivable	432		511
Accounts Receivable - Affiliated Companies, net	127		782
Short-Term Loan to Affiliate	1,574		398
Fuel	740		666
Materials and Supplies, net	273		269
Prepayments	42		80
Derivative Contracts	95		163
Assets of Discontinued Operations	0		564
Total Current Assets	3,297		3,444
PROPERTY, PLANT AND EQUIPMENT	9,118		8,643
Less: Accumulated Depreciation and Amortization	(2,552)		(2,301)
Net Property, Plant and Equipment	6,566		6,342
NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds	1,280		1,363
Other Special Funds	33		32
Goodwill	16		16
Other Intangibles	164		130
Derivative Contracts	24		42
Long-Term Accrued Taxes	19		16
Other	85		67
Total Noncurrent Assets	1,621		1,666
TOTAL ASSETS	11,484		11,452
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	710		650
Accounts Payable	635		643
Derivative Contracts	79		91
Deferred Income Taxes	8		64
Accrued Interest	63		40
Liabilities of Discontinued Operations	0		72
Other	111		91
Total Current Liabilities	1,606		1,651
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	1,211		1,146
Asset Retirement Obligations	255		242
Other Postretirement Benefit (OPEB) Costs	158		151
Accrued Pension Costs	75		253
Environmental Costs	51		51
Derivative Contracts	17		22
Other	34		104
Total Noncurrent Liabilities	1,801		1,969
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT
Total Long-Term Debt	2,640		2,805
STOCKHOLDERS' EQUITY
Contributed Capital	2,028		2,028
Basis Adjustment	(986)		(986)
Retained Earnings	4,602		4,080
Accumulated Other Comprehensive Loss	(207)		(95)
Total Stockholders' Equity	5,437		5,027
TOTAL LIABILITIES AND CAPITALIZATION	11,484		11,452
PSE&G [Member]
CURRENT ASSETS
Cash and Cash Equivalents	242		245
Accounts Receivable	720		832
Accounts Receivable - Affiliated Companies, net	304		0
Tax Receivable	21		0
Unbilled Revenues	251		400
Materials and Supplies, net	91		90
Prepayments	320		117
Regulatory Assets	86		155
Other	35		19
Total Current Assets	2,070		1,858
PROPERTY, PLANT AND EQUIPMENT	14,917		14,068
Less: Accumulated Depreciation and Amortization	(4,500)		(4,326)
Net Property, Plant and Equipment	10,417		9,742
NONCURRENT ASSETS
Regulatory Assets	3,354		3,736
Regulatory Assets of Variable Interest Entities (VIEs)	968		1,128
Long-Term Investments	258		230
Other Special Funds	57		54
Derivative Contracts	0		17
Restricted Cash of VIEs	22		21
Other	89		87
Total Noncurrent Assets	4,748		5,273
TOTAL ASSETS	17,235		16,873
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	564		264
Securitization Debt of VIEs Due Within One Year	214		206
Accounts Payable	396		406
Accounts Payable - Affiliated Companies, net	0		85
Derivative Contracts	15		12
Deferred Income Taxes	21		19
Accrued Interest	66		65
Clean Energy Program	224		195
Obligation to Return Cash Collateral	107		104
Regulatory Liabilities	161		174
Other	190		229
Total Current Liabilities	1,958		1,759
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	3,690		3,127
Regulatory Liabilities	235		285
Regulatory Liabilities of VIEs	9		8
Asset Retirement Obligations	223		216
Other Postretirement Benefit (OPEB) Costs	743		770
Accrued Pension Costs	18		377
Clean Energy Program	70		235
Environmental Costs	600		617
Derivative Contracts	11		0
Long-Term Accrued Taxes	54	[2]	74	[2]
Other	21		23
Total Noncurrent Liabilities	5,674		5,732
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT
Long-Term Debt	3,971		4,019
Securitization Debt of VIEs	784		939
Total Long-Term Debt	4,755		4,958
STOCKHOLDERS' EQUITY
Common Stock	892		892
Contributed Capital	420		420
Basis Adjustment	986		986
Retained Earnings	2,548		2,126
Accumulated Other Comprehensive Loss	2	[3]	0
Total Stockholders' Equity	4,848		4,424
Total Capitalization	9,603		9,382
TOTAL LIABILITIES AND CAPITALIZATION	$ 17,235		$ 16,873

[1] Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $54 million, $(31) million and $78 million, respectively for the nine months ended September 30, 2011. Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $1 million, $(12) million and $1 million, respectively for the nine months ended September 30, 2010.

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

[3] Net of tax of $(7) million for the nine months ended September 30, 2011 and $2 million for the nine months ended September 30, 2010.

XML

Financial Risk Management Activities (Schedule Of Derivative Instruments Designated As Cash Flow Hedges) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011		Sep. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges reclassified from AOCI into Operating Revenue (effective portion)			$ 182
PSEG [Member] | Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges reclassified from AOCI into Operating Revenue (effective portion)	60	60	152	[1]	178	[1]
Amount of gain (loss) attributed to cash flow hedges recognized in income (ineffective portion)	0	0	1	[1]	(3)	[1]
PSEG [Member] | Energy Costs [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges reclassified from AOCI into Energy Costs (effective portion)	0	0	2	[1]	(2)	[1]
PSEG [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges reclassified from AOCI into Earnings (effective portion)	0	0	(1)	[1]	(1)	[1]
PSEG [Member] | Interest Expense [Member] | Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges recognized in income (ineffective portion)	0	0
PSEG [Member] | Energy-Related Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges recognized in AOCI, effective portion	21	62	18	[1]	171	[1]
PSEG [Member] | Energy-Related Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges recognized in AOCI, effective portion	0	0	1	[1]	1	[1]
Amount of gain (loss) attributed to cash flow hedges recognized in income (ineffective portion)	0	0	0	[1]	0	[1]
PSEG [Member] | Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges recognized in AOCI, effective portion	0	0	0	[1]	0	[1]
Amount of gain (loss) attributed to cash flow hedges recognized in income (ineffective portion)			0	[1]	0	[1]
PSEG [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) attributed to cash flow hedges recognized in AOCI, effective portion	21	62	19	[1]	172	[1]
Amount of gain (loss) attributed to cash flow hedges reclassified from AOCI into Earnings (effective portion)	60	60	153	[1]	175	[1]
Amount of gain (loss) attributed to cash flow hedges recognized in income (ineffective portion)	$ 0	$ 0	$ 1	[1]	$ (3)	[1]

[1] Includes amounts for PSEG parent.

XML

Available-For-Sale Securities (Proceeds From The Sales Of And The Net Realized Gains On Securities In The NDT Funds And Rabbit Trusts) (Details) (USD $) In Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Aug. 31, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Schedule of Available-for-sale Securities [Line Items]
Proceeds from Sales		$ 431	$ 302	$ 1,088	$ 728
Gross Realized Gains		26	26	121	86
Gross Realized Losses		(10)	(8)	(28)	(31)
Net Realized Gains		16	18	93	55
Rabbi Trusts [Member]
Schedule of Available-for-sale Securities [Line Items]
Proceeds from Sales		0	158	0	158
Gross Realized Gains	31	0	31	0	31
Gross Realized Losses		0	0	0	0
Net Realized Gains		$ 0	$ 31	$ 0	$ 31

XML

Comprehensive Income, Net Of Tax (Comprehensive Income) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Net Income	$ 294		$ 567		$ 1,143		$ 1,282
Other Comprehensive Income (Loss)	(77)		28		(100)		5
Comprehensive Income	217		595		1,043		1,287
Power [Member]
Net Income	302		384		871		952
Other Comprehensive Income (Loss)	(80)		38		(112)		13
Comprehensive Income	222		422		759		965
PSE&G [Member]
Net Income	154		155		422		276
Other Comprehensive Income (Loss)	1		(6)		2		(5)
Comprehensive Income	155		149		424		271
Other [Member]
Net Income	(162)	[1]	28	[1]	(150)	[1]	54	[1]
Other Comprehensive Income (Loss)	2	[1]	(4)	[1]	10	[1]	(3)	[1]
Comprehensive Income	$ (160)	[1]	$ 24	[1]	$ (140)	[1]	$ 51	[1]

[1] Other consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations.

XML

Related-Party Transactions (Schedule Of Related Party Transactions, Revenue) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Power [Member]
Related Party Transaction [Line Items]
Billings to PSE&G through BGSS	$ 91	[1]	$ 118	[1]	$ 958	[1]	$ 1,102	[1]
Billings to PSE&G through BGS	272	[1]	345	[1]	734	[1]	904	[1]
Total Revenue from Affiliates	363		463		1,692		2,006
Administrative Billings from Services	(37)	[2]	(34)	[2]	(109)	[2]	(106)	[2]
Total Expense Billings from Affiliates	(37)		(34)		(109)		(106)
PSE&G [Member]
Related Party Transaction [Line Items]
Billings from Power through BGSS	(91)	[1]	(118)	[1]	(958)	[1]	(1,102)	[1]
Billings from Power through BGS	(272)	[1]	(345)	[1]	(734)	[1]	(904)	[1]
Administrative Billings from Services	(53)	[2]	(47)	[2]	(154)	[2]	(151)	[2]
Total Expense Billings from Affiliates	$ (416)		$ (510)		$ (1,846)		$ (2,157)

[1] PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G's BGSS and other contractual requirements through March 31, 2012 and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.

[2] 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.

XML

Related-Party Transactions

9 Months Ended

Sep. 30, 2011

Related-Party Transactions

Note 17. 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 September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)	$	91		$	118		$	958		$	1,102
Billings to PSE&G through BGS (A)		272			345			734			904
Total Revenue from Affiliates	$	363		$	463		$	1,692		$	2,006
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(37	)	$	(34	)	$	(109	)	$	(106	)
Total Expense Billings from Affiliates	$	(37	)	$	(34	)	$	(109	)	$	(106	)

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	110		$	372
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)		64			58
Payable to Services (B)		(23	)		(26	)
Tax Sharing Receivable from (Payable to) PSEG (C)		(18	)		380
Current Unrecognized Tax Receivable from (Payable to) PSEG (C)		(5	)		1
Payable to PSEG		(1	)		(3	)
Accounts Receivable—Affiliated Companies, net	$	127		$	782
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)	$	1,574		$	398
Working Capital Advances to Services (E)	$	17		$	17
Long-Term Accrued Taxes Receivable (C)	$	19		$	16

PSE&G

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)	$	(91	)	$	(118	)	$	(958	)	$	(1,102	)
Billings from Power through BGS (A)		(272	)		(345	)		(734	)		(904	)
Administrative Billings from Services (B)		(53	)		(47	)		(154	)		(151	)
Total Expense Billings from Affiliates	$	(416	)	$	(510	)	$	(1,846	)	$	(2,157	)

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Payable to Power through BGS and BGSS (A)	$	(110	)	$	(372	)
Payable to Power Related to Gas Supply Hedges for BGSS (A)		(64	)		(58	)
Payable to Power for SREC Liability (F)		(7	)		(7	)
Payable to Services (B)		(42	)		(48	)
Tax Sharing Receivable from PSEG (C)		467			321
Current Unrecognized Tax Receivable from PSEG (C)		59			73
Receivable from PSEG		1			6
Accounts Receivable (Payable)—Affiliated Companies, net	$	304		$	(85	)
Working Capital Advances to Services (E)	$	33		$	33
Long-Term Accrued Taxes Payable (C)	$	(54	)	$	(74	)

(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 through March 31, 2012 and year-to-year thereafter. 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) In 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU's 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court's ruling. PSE&G, along with other New Jersey utilities and Power participated at the hearing and filed comments. The BPU has not yet issued a decision. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of September 30, 2011 and December 31, 2010, including approximately $7 million for Power's share which is included in PSE&G's Accounts Payable—Affiliated Companies as of December 31, 2010. Under current guidance, Power is unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G's liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG's Condensed Consolidated Balance Sheet as of September 30, 2011 and December 31, 2010.

Power [Member]

Related-Party Transactions

Note 17. 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 September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)	$	91		$	118		$	958		$	1,102
Billings to PSE&G through BGS (A)		272			345			734			904
Total Revenue from Affiliates	$	363		$	463		$	1,692		$	2,006
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(37	)	$	(34	)	$	(109	)	$	(106	)
Total Expense Billings from Affiliates	$	(37	)	$	(34	)	$	(109	)	$	(106	)

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	110		$	372
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)		64			58
Payable to Services (B)		(23	)		(26	)
Tax Sharing Receivable from (Payable to) PSEG (C)		(18	)		380
Current Unrecognized Tax Receivable from (Payable to) PSEG (C)		(5	)		1
Payable to PSEG		(1	)		(3	)
Accounts Receivable—Affiliated Companies, net	$	127		$	782
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)	$	1,574		$	398
Working Capital Advances to Services (E)	$	17		$	17
Long-Term Accrued Taxes Receivable (C)	$	19		$	16

PSE&G

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)	$	(91	)	$	(118	)	$	(958	)	$	(1,102	)
Billings from Power through BGS (A)		(272	)		(345	)		(734	)		(904	)
Administrative Billings from Services (B)		(53	)		(47	)		(154	)		(151	)
Total Expense Billings from Affiliates	$	(416	)	$	(510	)	$	(1,846	)	$	(2,157	)

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Payable to Power through BGS and BGSS (A)	$	(110	)	$	(372	)
Payable to Power Related to Gas Supply Hedges for BGSS (A)		(64	)		(58	)
Payable to Power for SREC Liability (F)		(7	)		(7	)
Payable to Services (B)		(42	)		(48	)
Tax Sharing Receivable from PSEG (C)		467			321
Current Unrecognized Tax Receivable from PSEG (C)		59			73
Receivable from PSEG		1			6
Accounts Receivable (Payable)—Affiliated Companies, net	$	304		$	(85	)
Working Capital Advances to Services (E)	$	33		$	33
Long-Term Accrued Taxes Payable (C)	$	(54	)	$	(74	)

(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 through March 31, 2012 and year-to-year thereafter. 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) In 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU's 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court's ruling. PSE&G, along with other New Jersey utilities and Power participated at the hearing and filed comments. The BPU has not yet issued a decision. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of September 30, 2011 and December 31, 2010, including approximately $7 million for Power's share which is included in PSE&G's Accounts Payable—Affiliated Companies as of December 31, 2010. Under current guidance, Power is unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G's liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG's Condensed Consolidated Balance Sheet as of September 30, 2011 and December 31, 2010.

PSE&G [Member]

Related-Party Transactions

Note 17. 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 September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)	$	91		$	118		$	958		$	1,102
Billings to PSE&G through BGS (A)		272			345			734			904
Total Revenue from Affiliates	$	363		$	463		$	1,692		$	2,006
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(37	)	$	(34	)	$	(109	)	$	(106	)
Total Expense Billings from Affiliates	$	(37	)	$	(34	)	$	(109	)	$	(106	)

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	110		$	372
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)		64			58
Payable to Services (B)		(23	)		(26	)
Tax Sharing Receivable from (Payable to) PSEG (C)		(18	)		380
Current Unrecognized Tax Receivable from (Payable to) PSEG (C)		(5	)		1
Payable to PSEG		(1	)		(3	)
Accounts Receivable—Affiliated Companies, net	$	127		$	782
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)	$	1,574		$	398
Working Capital Advances to Services (E)	$	17		$	17
Long-Term Accrued Taxes Receivable (C)	$	19		$	16

PSE&G

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

	Three Months Ended September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)	$	(91	)	$	(118	)	$	(958	)	$	(1,102	)
Billings from Power through BGS (A)		(272	)		(345	)		(734	)		(904	)
Administrative Billings from Services (B)		(53	)		(47	)		(154	)		(151	)
Total Expense Billings from Affiliates	$	(416	)	$	(510	)	$	(1,846	)	$	(2,157	)

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Payable to Power through BGS and BGSS (A)	$	(110	)	$	(372	)
Payable to Power Related to Gas Supply Hedges for BGSS (A)		(64	)		(58	)
Payable to Power for SREC Liability (F)		(7	)		(7	)
Payable to Services (B)		(42	)		(48	)
Tax Sharing Receivable from PSEG (C)		467			321
Current Unrecognized Tax Receivable from PSEG (C)		59			73
Receivable from PSEG		1			6
Accounts Receivable (Payable)—Affiliated Companies, net	$	304		$	(85	)
Working Capital Advances to Services (E)	$	33		$	33
Long-Term Accrued Taxes Payable (C)	$	(54	)	$	(74	)

(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 through March 31, 2012 and year-to-year thereafter. 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) In 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU's 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court's ruling. PSE&G, along with other New Jersey utilities and Power participated at the hearing and filed comments. The BPU has not yet issued a decision. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of September 30, 2011 and December 31, 2010, including approximately $7 million for Power's share which is included in PSE&G's Accounts Payable—Affiliated Companies as of December 31, 2010. Under current guidance, Power is unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G's liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG's Condensed Consolidated Balance Sheet as of September 30, 2011 and December 31, 2010.

XML

Other Income And Deductions (Schedule Of Other Income) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Component of Other Income, Nonoperating [Line Items]
NDT Funds Gains, Interest, Dividend and Other Income	$ 36		$ 35		$ 153		$ 115
Realized Gains from Rabbi Trust			31				31
Other	9		9		23		19
Total Other Income	45		75		176		165
PSE&G [Member]
Component of Other Income, Nonoperating [Line Items]
NDT Funds Gains, Interest, Dividend and Other Income	0		0		0		0
Realized Gains from Rabbi Trust			11				11
Other	7		3		16		11
Total Other Income	7		14		16		22
Power [Member]
Component of Other Income, Nonoperating [Line Items]
NDT Funds Gains, Interest, Dividend and Other Income	36		35		153		115
Realized Gains from Rabbi Trust			7				7
Other	1		2		3		4
Total Other Income	37		44		156		126
Other Segments [Member]
Component of Other Income, Nonoperating [Line Items]
NDT Funds Gains, Interest, Dividend and Other Income	0	[1]	0	[1]	0	[1]	0	[1]
Realized Gains from Rabbi Trust			13	[1]			13	[1]
Other	1	[1]	4	[1]	4	[1]	4	[1]
Total Other Income	$ 1	[1]	$ 17	[1]	$ 4	[1]	$ 17	[1]

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

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2011	Oct. 14, 2011
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Entity Registrant Name	PUBLIC SERVICE ENTERPRISE GROUP INC
Entity Central Index Key	0000788784
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Power [Member]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Entity Registrant Name	PSEG POWER LLC
Entity Central Index Key	0001158659
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
PSE&G [Member]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Entity Registrant Name	PUBLIC SERVICE ELECTRIC & GAS CO
Entity Central Index Key	0000081033
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		132,450,344
PSEG [Member]
Entity Common Stock, Shares Outstanding		505,904,850

XML

Financing Receivables (Lease Assets And Locations) (Details) (Energy Holdings [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2011 mW
Powerton Station Units 5 And 6 [Member]
Property, Plant and Equipment [Line Items]
Lease Receivable, Asset Location	IL
Lease Receivable, Gross Investment	$ 135
Lease Receivable, Percent Owned	64.00%
Lease Receivable, Total, MW's	1,538
Lease Receivable, Asset, Fuel Type	Coal
Lease Receivable, Counterparties' S&P Credit Rating	B-
Lease Receivable, Counterparty	Edison Mission Energy
Joliet Station Units 7 And 8 [Member]
Property, Plant and Equipment [Line Items]
Lease Receivable, Asset Location	IL
Lease Receivable, Gross Investment	84
Lease Receivable, Percent Owned	64.00%
Lease Receivable, Total, MW's	1,044
Lease Receivable, Asset, Fuel Type	Coal
Lease Receivable, Counterparties' S&P Credit Rating	B-
Lease Receivable, Counterparty	Edison Mission Energy
Keystone Station Units 1 And 2 [Member]
Property, Plant and Equipment [Line Items]
Lease Receivable, Asset Location	PA
Lease Receivable, Gross Investment	112
Lease Receivable, Percent Owned	17.00%
Lease Receivable, Total, MW's	1,711
Lease Receivable, Asset, Fuel Type	Coal
Lease Receivable, Counterparties' S&P Credit Rating	B
Lease Receivable, Counterparty	GenOn REMA, LLC
Conemaugh Station Units 1 And 2 [Member]
Property, Plant and Equipment [Line Items]
Lease Receivable, Asset Location	PA
Lease Receivable, Gross Investment	112
Lease Receivable, Percent Owned	17.00%
Lease Receivable, Total, MW's	1,711
Lease Receivable, Asset, Fuel Type	Coal
Lease Receivable, Counterparties' S&P Credit Rating	B
Lease Receivable, Counterparty	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 And 4 [Member]
Property, Plant and Equipment [Line Items]
Lease Receivable, Asset Location	PA
Lease Receivable, Gross Investment	$ 107
Lease Receivable, Percent Owned	100.00%
Lease Receivable, Total, MW's	603
Lease Receivable, Asset, Fuel Type	Coal
Lease Receivable, Counterparties' S&P Credit Rating	B
Lease Receivable, Counterparty	GenOn REMA, LLC

XML

Discontinued Operations And Dispositions (Tables)

9 Months Ended

Sep. 30, 2011

Leveraged Leases [Member] | Energy Holdings [Member]

Discontinued Operations And Dispositions [Line Items]

International Leveraged Lease To Disallow Certain Tax Deductions

	Three Months Ended September 30,		Nine Months Ended September 30,
	2010		2010
	Millions
Proceeds from Sales	$	204	$	365
Gains on Sales, after-tax	$	15	$	27

PSEG Texas [Member]

Discontinued Operations And Dispositions [Line Items]

Operating Results Reclassified To Discontinued Operations

	Three Months Ended, September 30,				Nine Months Ended, September 30,
	2011		2010		2011		2010
	Millions
Operating Revenues	$	20	$	140	$	112	$	341
Income (Loss ) Before Income Taxes	$	6	$	31	$	26	$	25
Net Income (Loss)	$	4	$	20	$	17	$	15

Summary Of Carrying Amounts Of Assets And Liabilities

	As of December 31,
	2010
	Millions
Current Assets	$	28
Noncurrent Assets		536
Total Assets of Discontinued Operations	$	564
Current Liabilities	$	28
Noncurrent Liabilities		44
Total Liabilities of Discontinued Operations	$	72

XML

Financing Receivables (Schedule Of Counterparties' Credit Rating) (Details) (Energy Holdings [Member], USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Guarantor Obligations [Line Items]
Lease Receivables (net of Non-Recourse Debt)	$ 763	$ 896
Standard & Poor's Not Rated [Member]
Guarantor Obligations [Line Items]
Lease Receivables (net of Non-Recourse Debt)	16	17
Standard & Poor's, B - B - Rating [Member]
Guarantor Obligations [Line Items]
Lease Receivables (net of Non-Recourse Debt)	300	430
Standard & Poor's, BBB-BB Rating [Member]
Guarantor Obligations [Line Items]
Lease Receivables (net of Non-Recourse Debt)	316	316
Standard & Poor's, A Rating [Member]
Guarantor Obligations [Line Items]
Lease Receivables (net of Non-Recourse Debt)	110	112
Standard & Poor's, AAA-AA Rating [Member]
Guarantor Obligations [Line Items]
Lease Receivables (net of Non-Recourse Debt)	$ 21	$ 21

XML

Fair Value Measurements (PSEG's, Power's And PSE&G's Respective Assets And (Liabilities) Measured At Fair Value On A Recurring Basis) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	$ 188		$ 261
Total Mark-to-Market Derivative Liabilities	125		125
Other Debt Securities [Member] | Total Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	284	[1]	255	[1]
US States And Political Subdivisions Debt Securities [Member] | Total Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	355	[1]	303	[1]
Equity Securities [Member] | Total Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	575	[1]	735	[1]
Other Securities [Member] | Total Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	66	[1]	70	[1]
Total Estimate Of Fair Value [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	119	[2]	222	[2]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	(122)	[2]	(125)	[2]
Total Estimate Of Fair Value [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	69	[3]	39	[3]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	(3)	[3]
Total Estimate Of Fair Value [Member] | Rabbi Trusts Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	170	[1]	160	[1]
Total Estimate Of Fair Value [Member] | Other Derivative Long Term Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments			2	[4]
Other Debt Securities [Member] | Cash Collateral Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1],[5]	0	[1],[5]
US States And Political Subdivisions Debt Securities [Member] | Cash Collateral Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1],[5]	0	[1],[5]
Equity Securities [Member] | Cash Collateral Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1],[5]	0	[1],[5]
Other Securities [Member] | Cash Collateral Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1],[5]	0	[1],[5]
Cash Collateral Netting [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	(10)	[2],[5]	(135)	[2],[5]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	[2],[5]	74	[2],[5]
Cash Collateral Netting [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	0	[3],[5]	0	[3],[5]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	[3],[5]
Cash Collateral Netting [Member] | Rabbi Trusts Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1],[5]	0	[1],[5]
Cash Collateral Netting [Member] | Other Derivative Long Term Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments			0	[4],[5]
Other Debt Securities [Member] | Quoted Market Prices For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1]	0	[1]
US States And Political Subdivisions Debt Securities [Member] | Quoted Market Prices For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1]	0	[1]
Equity Securities [Member] | Quoted Market Prices For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	575	[1]	735	[1]
Other Securities [Member] | Quoted Market Prices For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	1	[1]	0	[1]
Quoted Market Prices For Identical Assets (Level 1) [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	0	[2]	0	[2]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	[2]	0	[2]
Quoted Market Prices For Identical Assets (Level 1) [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	0	[3]	0	[3]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	[3]
Quoted Market Prices For Identical Assets (Level 1) [Member] | Rabbi Trusts Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	17	[1]	18	[1]
Quoted Market Prices For Identical Assets (Level 1) [Member] | Other Derivative Long Term Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments			2	[4]
Other Debt Securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	284	[1]	255	[1]
US States And Political Subdivisions Debt Securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	355	[1]	303	[1]
Equity Securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1]	0	[1]
Other Securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	65	[1]	62	[1]
Significant Other Observable Inputs (Level 2) [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	99	[2]	228	[2]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	(88)	[2]	(117)	[2]
Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	69	[3]	39	[3]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	(3)	[3]
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trusts Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	153	[1]	142	[1]
Significant Other Observable Inputs (Level 2) [Member] | Other Derivative Long Term Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments			0	[4]
Other Debt Securities [Member] | Pension And OPEB Plans' Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1]	0	[1]
US States And Political Subdivisions Debt Securities [Member] | Pension And OPEB Plans' Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1]	0	[1]
Equity Securities [Member] | Pension And OPEB Plans' Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1]	0	[1]
Other Securities [Member] | Pension And OPEB Plans' Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1]	8	[1]
Pension And OPEB Plans' Level 3 [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	30	[2]	129	[2]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	(34)	[2]	(82)	[2]
Pension And OPEB Plans' Level 3 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	0	[3]	0	[3]
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	[3]
Pension And OPEB Plans' Level 3 [Member] | Rabbi Trusts Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	0	[1]	0	[1]
Pension And OPEB Plans' Level 3 [Member] | Other Derivative Long Term Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments			$ 0	[4]

[1] Power's NDT funds maintain investments in various equity and fixed income securities classified as "available for sale." These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the NDT funds 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). Power's NDT investments in fixed income securities are primarily with investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities (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). The Rabbi Trust mutual funds are mainly invested in a United States bond index fund, an S&P 500 index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

[2] Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs. Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.

[3] 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.

[4] Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices.

[5] 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.

XML

Available-For-Sale Securities

9 Months Ended

Sep. 30, 2011

Available-For-Sale Securities

Note 6. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Funds

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 two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisors who operate under investment guidelines developed by Power.

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

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	537	$	93	$	(55	)	$	575
Debt Securities
Government Obligations		340		16		(1	)		355
Other Debt Securities		273		14		(3	)		284
Total Debt Securities		613		30		(4	)		639
Other Securities		66		0		0			66
Total Available-for-Sale Securities	$	1,216	$	123	$	(59	)	$	1,280

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	525	$	213	$	(3	)	$	735
Debt Securities
Government Obligations		301		6		(4	)		303
Other Debt Securities		247		10		(2	)		255
Total Debt Securities		548		16		(6	)		558
Other Securities		70		0		0			70
Total Available-for-Sale Securities	$	1,143	$	229	$	(9	)	$	1,363

These amounts 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 September 30,		As of December 31,
	2011		2010
	Millions
Accounts Receivable	$	100	$	35
Accounts Payable	$	95	$	60

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

	As of September 30, 2011										As of December 31, 2010
	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)	$	252	$	(55	)	$	0	$	0		$	55	$	(3	)	$	0	$	0
Debt Securities
Government Obligations (B)		72		(1	)		2		0			106		(4	)		1		0
Other Debt Securities (C)		65		(2	)		6		(1	)		65		(1	)		8		(1	)
Total Debt Securities		137		(3	)		8		(1	)		171		(5	)		9		(1	)
Other Securities		1		0			0		0			0		0			0		0
Total Available-for-Sale Securities	$	390	$	(58	)	$	8	$	(1	)	$	226	$	(8	)	$	9	$	(1	)

(A) Equity Securities—Investments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(B) Debt Securities (Government)—Unrealized losses on Power's NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(C) Debt Securities (Corporate)—Power's investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2011.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	Millions						Millions
Proceeds from Sales	$	431		$	302		$	1,088		$	728
Net Realized Gains (Losses)
Gross Realized Gains	$	26		$	26		$	121		$	86
Gross Realized Losses		(10	)		(8	)		(28	)		(31	)
Net Realized Gains	$	16		$	18		$	93		$	55

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEG's and Power's Condensed Consolidated Statements of Operations. Net unrealized gains of $32 million (after-tax) were recognized in Accumulated Other Comprehensive Income (OCI) on Power's Condensed Consolidated Balance Sheet as of September 30, 2011. The available-for-sale debt securities held as of September 30, 2011 had the following maturities:

Time Frame	Fair Value
	Millions
Less than 1 Year	$	11
1 - 5 Years		141
6 - 10 Years		172
11 - 15 Years		43
16 - 20 Years		18
Over 20 Years		254
	$	639

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 OCI. In 2011, other-than-temporary impairments of $10 million were recognized on securities in the NDT funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is 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 detail of the securities.

Rabbi Trusts

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 grantor trusts commonly known as "Rabbi Trusts." In August 2010, PSEG revised the asset structure of the Rabbi Trust and realized gains of $31 million as the investments were transitioned to a new asset allocation and investment manager. The new structure resulted in lower investment management fees.

PSEG classifies investments in the Rabbi Trusts 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 Trusts.

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		147		5		0		152
Total PSEG Available-for-Sale Securities	$	163	$	7	$	0	$	170

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		142		0		0		142
Total PSEG Available-for-Sale Securities	$	158	$	2	$	0	$	160

The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, 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 the nine months ended September 30, 2011, other-than-temporary impairments of $3 million were recognized on the bond portfolio of the Rabbi Trusts.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	Millions				Millions
Proceeds from Sales	$	0	$	158	$	0	$	158
Net Realized Gains (Losses)
Gross Realized Gains	$	0	$	31	$	0	$	31
Gross Realized Losses		0		0		0		0
Net Realized Gains (Losses)	$	0	$	31	$	0	$	31

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

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

	As of September 30, 2011		As of December 31, 2010
	Millions
Power	$	33	$	32
PSE&G		57		54
Other		80		74
Total PSEG Available-for-Sale Securities	$	170	$	160

Power [Member]

Available-For-Sale Securities

Note 6. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Funds

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 two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisors who operate under investment guidelines developed by Power.

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

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	537	$	93	$	(55	)	$	575
Debt Securities
Government Obligations		340		16		(1	)		355
Other Debt Securities		273		14		(3	)		284
Total Debt Securities		613		30		(4	)		639
Other Securities		66		0		0			66
Total Available-for-Sale Securities	$	1,216	$	123	$	(59	)	$	1,280

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	525	$	213	$	(3	)	$	735
Debt Securities
Government Obligations		301		6		(4	)		303
Other Debt Securities		247		10		(2	)		255
Total Debt Securities		548		16		(6	)		558
Other Securities		70		0		0			70
Total Available-for-Sale Securities	$	1,143	$	229	$	(9	)	$	1,363

These amounts 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 September 30,		As of December 31,
	2011		2010
	Millions
Accounts Receivable	$	100	$	35
Accounts Payable	$	95	$	60

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

	As of September 30, 2011										As of December 31, 2010
	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)	$	252	$	(55	)	$	0	$	0		$	55	$	(3	)	$	0	$	0
Debt Securities
Government Obligations (B)		72		(1	)		2		0			106		(4	)		1		0
Other Debt Securities (C)		65		(2	)		6		(1	)		65		(1	)		8		(1	)
Total Debt Securities		137		(3	)		8		(1	)		171		(5	)		9		(1	)
Other Securities		1		0			0		0			0		0			0		0
Total Available-for-Sale Securities	$	390	$	(58	)	$	8	$	(1	)	$	226	$	(8	)	$	9	$	(1	)

(A) Equity Securities—Investments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(B) Debt Securities (Government)—Unrealized losses on Power's NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(C) Debt Securities (Corporate)—Power's investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2011.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	Millions						Millions
Proceeds from Sales	$	431		$	302		$	1,088		$	728
Net Realized Gains (Losses)
Gross Realized Gains	$	26		$	26		$	121		$	86
Gross Realized Losses		(10	)		(8	)		(28	)		(31	)
Net Realized Gains	$	16		$	18		$	93		$	55

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEG's and Power's Condensed Consolidated Statements of Operations. Net unrealized gains of $32 million (after-tax) were recognized in Accumulated Other Comprehensive Income (OCI) on Power's Condensed Consolidated Balance Sheet as of September 30, 2011. The available-for-sale debt securities held as of September 30, 2011 had the following maturities:

Time Frame	Fair Value
	Millions
Less than 1 Year	$	11
1 - 5 Years		141
6 - 10 Years		172
11 - 15 Years		43
16 - 20 Years		18
Over 20 Years		254
	$	639

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 OCI. In 2011, other-than-temporary impairments of $10 million were recognized on securities in the NDT funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is 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 detail of the securities.

Rabbi Trusts

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 grantor trusts commonly known as "Rabbi Trusts." In August 2010, PSEG revised the asset structure of the Rabbi Trust and realized gains of $31 million as the investments were transitioned to a new asset allocation and investment manager. The new structure resulted in lower investment management fees.

PSEG classifies investments in the Rabbi Trusts 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 Trusts.

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		147		5		0		152
Total PSEG Available-for-Sale Securities	$	163	$	7	$	0	$	170

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		142		0		0		142
Total PSEG Available-for-Sale Securities	$	158	$	2	$	0	$	160

The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, 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 the nine months ended September 30, 2011, other-than-temporary impairments of $3 million were recognized on the bond portfolio of the Rabbi Trusts.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	Millions				Millions
Proceeds from Sales	$	0	$	158	$	0	$	158
Net Realized Gains (Losses)
Gross Realized Gains	$	0	$	31	$	0	$	31
Gross Realized Losses		0		0		0		0
Net Realized Gains (Losses)	$	0	$	31	$	0	$	31

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

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

	As of September 30, 2011		As of December 31, 2010
	Millions
Power	$	33	$	32
PSE&G		57		54
Other		80		74
Total PSEG Available-for-Sale Securities	$	170	$	160

PSE&G [Member]

Available-For-Sale Securities

Note 6. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Funds

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 two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisors who operate under investment guidelines developed by Power.

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

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	537	$	93	$	(55	)	$	575
Debt Securities
Government Obligations		340		16		(1	)		355
Other Debt Securities		273		14		(3	)		284
Total Debt Securities		613		30		(4	)		639
Other Securities		66		0		0			66
Total Available-for-Sale Securities	$	1,216	$	123	$	(59	)	$	1,280

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	525	$	213	$	(3	)	$	735
Debt Securities
Government Obligations		301		6		(4	)		303
Other Debt Securities		247		10		(2	)		255
Total Debt Securities		548		16		(6	)		558
Other Securities		70		0		0			70
Total Available-for-Sale Securities	$	1,143	$	229	$	(9	)	$	1,363

These amounts 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 September 30,		As of December 31,
	2011		2010
	Millions
Accounts Receivable	$	100	$	35
Accounts Payable	$	95	$	60

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

	As of September 30, 2011										As of December 31, 2010
	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)	$	252	$	(55	)	$	0	$	0		$	55	$	(3	)	$	0	$	0
Debt Securities
Government Obligations (B)		72		(1	)		2		0			106		(4	)		1		0
Other Debt Securities (C)		65		(2	)		6		(1	)		65		(1	)		8		(1	)
Total Debt Securities		137		(3	)		8		(1	)		171		(5	)		9		(1	)
Other Securities		1		0			0		0			0		0			0		0
Total Available-for-Sale Securities	$	390	$	(58	)	$	8	$	(1	)	$	226	$	(8	)	$	9	$	(1	)

(A) Equity Securities—Investments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(B) Debt Securities (Government)—Unrealized losses on Power's NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(C) Debt Securities (Corporate)—Power's investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2011.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	Millions						Millions
Proceeds from Sales	$	431		$	302		$	1,088		$	728
Net Realized Gains (Losses)
Gross Realized Gains	$	26		$	26		$	121		$	86
Gross Realized Losses		(10	)		(8	)		(28	)		(31	)
Net Realized Gains	$	16		$	18		$	93		$	55

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEG's and Power's Condensed Consolidated Statements of Operations. Net unrealized gains of $32 million (after-tax) were recognized in Accumulated Other Comprehensive Income (OCI) on Power's Condensed Consolidated Balance Sheet as of September 30, 2011. The available-for-sale debt securities held as of September 30, 2011 had the following maturities:

Time Frame	Fair Value
	Millions
Less than 1 Year	$	11
1 - 5 Years		141
6 - 10 Years		172
11 - 15 Years		43
16 - 20 Years		18
Over 20 Years		254
	$	639

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 OCI. In 2011, other-than-temporary impairments of $10 million were recognized on securities in the NDT funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is 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 detail of the securities.

Rabbi Trusts

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 grantor trusts commonly known as "Rabbi Trusts." In August 2010, PSEG revised the asset structure of the Rabbi Trust and realized gains of $31 million as the investments were transitioned to a new asset allocation and investment manager. The new structure resulted in lower investment management fees.

PSEG classifies investments in the Rabbi Trusts 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 Trusts.

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		147		5		0		152
Total PSEG Available-for-Sale Securities	$	163	$	7	$	0	$	170

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		142		0		0		142
Total PSEG Available-for-Sale Securities	$	158	$	2	$	0	$	160

The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, 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 the nine months ended September 30, 2011, other-than-temporary impairments of $3 million were recognized on the bond portfolio of the Rabbi Trusts.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	Millions				Millions
Proceeds from Sales	$	0	$	158	$	0	$	158
Net Realized Gains (Losses)
Gross Realized Gains	$	0	$	31	$	0	$	31
Gross Realized Losses		0		0		0		0
Net Realized Gains (Losses)	$	0	$	31	$	0	$	31

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

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

	As of September 30, 2011		As of December 31, 2010
	Millions
Power	$	33	$	32
PSE&G		57		54
Other		80		74
Total PSEG Available-for-Sale Securities	$	170	$	160

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Financing Receivables (Tables)

9 Months Ended

Sep. 30, 2011

Schedule Of Net Investment In Leveraged Leases

	As of September 30,			As of December 31,
	2011			2010
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	763		$	896
Estimated Residual Value of Leased Assets		684			905
		1,447			1,801
Unearned and Deferred Income		(450	)		(546	)
Gross Investments in Leases		997			1,255
Deferred Tax Liabilities		(804	)		(899	)
Net Investment in Leases	$	193		$	356

PSE&G [Member]

Schedule Of Credit Risk Profile Based On Payment Activity

Credit Risk Profile Based on Payment Activity	As of		As of
	September 30,		December 31,
Consumer Loans	2011		2010
	Millions
Commercial/Industrial	$	86	$	62
Residential		7		4
	$	93	$	66

Energy Holdings [Member]

Schedule Of Lease Receivables, Net Of Nonrecourse Debt, Associated With Leveraged Lease Portfolio Based On Counterparty Credit Rating

	Lease Receivables, net of Non-Recourse Debt
	As of September 30,		As of December 31,
Counterparties' Credit Rating (S&P)	2011		2010
	Millions
AAA - AA	$	21	$	21
A		110		112
BBB - BB		316		316
B - B-		300		430
Not Rated		16		17
	$	763	$	896

Schedule Of Assets Under Lease Receivables

Asset	Location		Gross Investment		% Owned		Total		Fuel Type	Counterparties' S&P Credit Rating	Counterparty
			Millions				MW
Powerton Station Units 5 and 6		IL	$	135		64%		1,538	Coal	B-	Edison Mission Energy
Joliet Station Units 7 and 8		IL	$	84		64%		1,044	Coal	B-	Edison Mission Energy
Keystone Station Units 1 and 2		PA	$	112		17%		1,711	Coal	B	GenOn REMA, LLC
Conemaugh Station Units 1 and 2		PA	$	112		17%		1,711	Coal	B	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 and 4		PA	$	107		100%		603	Coal	B	GenOn REMA, LLC

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Discontinued Operations And Dispositions (International Leveraged Lease To Disallow Certain Tax Deductions) (Details) (Leveraged Leases [Member], Energy Holdings [Member], USD $) In Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2010
Leveraged Leases [Member] | Energy Holdings [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sales	$ 204	$ 365
Gain on Sales, after-tax	$ 15	$ 27

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Related-Party Transactions (Tables)

9 Months Ended

Sep. 30, 2011

Power [Member]

Schedule Of Related Party Transactions, Revenue

	Three Months Ended September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)	$	91		$	118		$	958		$	1,102
Billings to PSE&G through BGS (A)		272			345			734			904
Total Revenue from Affiliates	$	363		$	463		$	1,692		$	2,006
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(37	)	$	(34	)	$	(109	)	$	(106	)
Total Expense Billings from Affiliates	$	(37	)	$	(34	)	$	(109	)	$	(106	)

Schedule Of Related Party Transactions, Receivables

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	110		$	372
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)		64			58
Payable to Services (B)		(23	)		(26	)
Tax Sharing Receivable from (Payable to) PSEG (C)		(18	)		380
Current Unrecognized Tax Receivable from (Payable to) PSEG (C)		(5	)		1
Payable to PSEG		(1	)		(3	)
Accounts Receivable—Affiliated Companies, net	$	127		$	782
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)	$	1,574		$	398
Working Capital Advances to Services (E)	$	17		$	17
Long-Term Accrued Taxes Receivable (C)	$	19		$	16

PSE&G [Member]

Schedule Of Related Party Transactions, Revenue

	Three Months Ended September 30,						Nine Months Ended September 30,
Related Party Transactions	2011			2010			2011			2010
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)	$	(91	)	$	(118	)	$	(958	)	$	(1,102	)
Billings from Power through BGS (A)		(272	)		(345	)		(734	)		(904	)
Administrative Billings from Services (B)		(53	)		(47	)		(154	)		(151	)
Total Expense Billings from Affiliates	$	(416	)	$	(510	)	$	(1,846	)	$	(2,157	)

Schedule Of Related Party Transactions, Payables

Related Party Transactions	As of September 30, 2011			As of December 31, 2010
	Millions
Payable to Power through BGS and BGSS (A)	$	(110	)	$	(372	)
Payable to Power Related to Gas Supply Hedges for BGSS (A)		(64	)		(58	)
Payable to Power for SREC Liability (F)		(7	)		(7	)
Payable to Services (B)		(42	)		(48	)
Tax Sharing Receivable from PSEG (C)		467			321
Current Unrecognized Tax Receivable from PSEG (C)		59			73
Receivable from PSEG		1			6
Accounts Receivable (Payable)—Affiliated Companies, net	$	304		$	(85	)
Working Capital Advances to Services (E)	$	33		$	33
Long-Term Accrued Taxes Payable (C)	$	(54	)	$	(74	)

(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 through March 31, 2012 and year-to-year thereafter. 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) In 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU's 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court's ruling. PSE&G, along with other New Jersey utilities and Power participated at the hearing and filed comments. The BPU has not yet issued a decision. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of September 30, 2011 and December 31, 2010, including approximately $7 million for Power's share which is included in PSE&G's Accounts Payable—Affiliated Companies as of December 31, 2010. Under current guidance, Power is unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G's liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG's Condensed Consolidated Balance Sheet as of September 30, 2011 and December 31, 2010.

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Organization And Basis Of Presentation (Policy)

9 Months Ended

Sep. 30, 2011

Organization And Basis Of Presentation [Abstract]

Basis Of Presentation

Basis of Presentation

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to 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, 2010 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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. 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, 2010.

During 2011, Power sold its two generating facilities located in Texas that were owned and operated by its subsidiary, PSEG Texas. As a result, amounts related to these plants were reclassified as Discontinued Operations in the financial statements. See Note 4. Discontinued Operations and Dispositions for additional information.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Fair Value Measurements

Note 11. Fair Value Measurements

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

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, 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. These consist mainly of various FTRs, certain full requirements contracts and other longer term capacity and transportation 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, 2011 and December 31, 2010, 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.

	Recurring Fair Value Measurements as of September 30, 2011
Description	Total			Cash Collateral Netting (E)			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)	$	119		$	(10	)	$	0	$	99		$	30
Interest Rate Swaps (B)	$	69		$	0		$	0	$	69		$	0
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	170		$	0		$	17	$	153		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(122	)	$	0		$	0	$	(88	)	$	(34	)
Interest Rate Swaps (B)	$	(3	)	$	0		$	0	$	(3	)	$	0
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	119		$	(10	)	$	0	$	99		$	30
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	33		$	0		$	3	$	30		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(96	)	$	0		$	0	$	(88	)	$	(8	)
PSE&G
Assets:
Rabbi Trust—Mutual Funds (C)	$	57		$	0		$	6	$	51		$	0
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(26	)	$	0		$	0	$	0		$	(26	)

	Recurring Fair Value Measurements as of December 31, 2010
Description	Total			Cash Collateral Netting (E)			Quoted Market Prices of Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	222		$	(135	)	$	0	$	228		$	129
Interest Rate Swaps (B)	$	39		$	0		$	0	$	39		$	0
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	160		$	0		$	18	$	142		$	0
Other Long-Term Investments (D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(125	)	$	74		$	0	$	(117	)	$	(82	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	205		$	(135	)	$	0	$	228		$	112
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	32		$	0		$	4	$	28		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(113	)	$	74		$	0	$	(117	)	$	(70	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	17		$	0		$	0	$	0		$	17
Rabbi Trusts—Mutual Funds (C)	$	54		$	0		$	6	$	48		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(12	)	$	0		$	0	$	0		$	(12	)

(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.   Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.

(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) Power's NDT funds maintain investments in various equity and fixed income securities classified as "available for sale." These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the NDT funds 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).   Power's NDT investments in fixed income securities are primarily with investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities (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).   The Rabbi Trust mutual funds are mainly invested in a United States bond index fund, an S&P 500 index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

(D) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices.

(E) 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.

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, 2011 follows:

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

for the Three Months Ended September 30, 2011

				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1,    2011			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)		Transfers In (Out)		Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(3	)	$	13	$	(27	)	$	10	$	3	$	0	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	(4	)	$	13	$	0		$	10	$	3	$	0	$	22
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	0	$	(27	)	$	0	$	0	$	0	$	(26	)

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

for the Nine Months Ended September 30, 2011

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2011		Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)			Transfers In (Out)			Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	47	$	(27	)	$	(31	)	$	29	$	(22	)	$	0		$	(4	)
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
Power
Net Derivative Assets	$	42	$	(27	)	$	0		$	29	$	(22	)	$	0		$	22
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
PSE&G
Net Derivative Assets (Liabilities)	$	5	$	0		$	(31	)	$	0	$	0		$	0		$	(26	)

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, 2010 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2010		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	168	$	33	$	(11	)	$	(2	)	$	188
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	16	$	0	$	0		$	(16	)	$	0
Power
Net Derivative Assets	$	117	$	33	$	0		$	(2	)	$	148
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	3	$	0	$	0		$	(3	)	$	0
PSE&G
Net Derivative Assets	$	51	$	0	$	(11	)	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0		$	(5	)	$	0

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

for the Nine Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2010		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)		Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	105	$	61	$	34	$	(12	)	$	188
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	14	$	0	$	0	$	(14	)	$	0
Power
Net Derivative Assets	$	99	$	61	$	0	$	(12	)	$	148
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	3	$	0	$	0	$	(3	)	$	0
PSE&G
Net Derivative Assets	$	6	$	0	$	34	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0	$	(5	)	$	0

(A) PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $12 million and $17 million are included in Operating Income, $1 million and $14 million are included in OCI, and less than $1 million and $2 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $12 million in Operating Income in 2011, $31 million is unrealized and $(19) million is realized. Of the $17 million in Operating Income in 2010, $32 million is unrealized and $(15) million is realized.

(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 $10 million in purchases for the three months ended September 30, 2011. Includes $65 million in purchases and $(36) million in sales for the nine months ended September 30, 2011.

(D) Includes $(5) million in issuances and $8 million in settlements for the three months ended September 30, 2011. Includes $(25) million in issuances and $3 million in settlements for the nine months ended September 30, 2011.

(E) PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(28) million and $8 million are included in Operating Income, $(2) million and $28 million are included in OCI, and $3 million and $25 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $(28) million in Operating Income in 2011, $(25) million is unrealized and $(3) million is realized. Of the $8 million in Operating Income in 2010, $9 million is unrealized and $(1) million is realized.

As of September 30, 2011, PSEG carried $1.5 billion of net assets that are measured at fair value on a recurring basis, of which $4 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG's total assets. During the nine months ended September 30, 2011, $8 million of assets in the NDT fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. As per PSEG's policy, this transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred).

As of September 30, 2010, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $197 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG's total assets and there were no transfers among levels during the three months and nine months ended September 30, 2010.

Non-recurring Fair Value Measurements

In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset's carrying amount may not be recoverable. There were no material impairments recorded during 2011.

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, 2011 and December 31, 2010.

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value (A)		Carrying Amount		Fair Value (A)
	Millions
Long-Term Debt:
PSEG (Parent)	$	40	$	66	$	10	$	39
Power -Recourse Debt		3,350		3,710		3,455		3,831
PSE&G		4,535		5,099		4,283		4,615
Transition Funding (PSE&G)		948		1,080		1,090		1,245
Transition Funding II (PSE&G)		50		54		55		59
Energy Holdings:
Project Level, Non-Recourse Debt		46		46		47		47
Total Long-Term Debt	$	8,969	$	10,055	$	8,940	$	9,836

(A) Fair value excludes unamortized discounts, including amounts related to the Debt Exchange between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company.

Power [Member]

Fair Value Measurements

Note 11. Fair Value Measurements

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

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, 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. These consist mainly of various FTRs, certain full requirements contracts and other longer term capacity and transportation 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, 2011 and December 31, 2010, 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.

	Recurring Fair Value Measurements as of September 30, 2011
Description	Total			Cash Collateral Netting (E)			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)	$	119		$	(10	)	$	0	$	99		$	30
Interest Rate Swaps (B)	$	69		$	0		$	0	$	69		$	0
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	170		$	0		$	17	$	153		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(122	)	$	0		$	0	$	(88	)	$	(34	)
Interest Rate Swaps (B)	$	(3	)	$	0		$	0	$	(3	)	$	0
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	119		$	(10	)	$	0	$	99		$	30
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	33		$	0		$	3	$	30		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(96	)	$	0		$	0	$	(88	)	$	(8	)
PSE&G
Assets:
Rabbi Trust—Mutual Funds (C)	$	57		$	0		$	6	$	51		$	0
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(26	)	$	0		$	0	$	0		$	(26	)

	Recurring Fair Value Measurements as of December 31, 2010
Description	Total			Cash Collateral Netting (E)			Quoted Market Prices of Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	222		$	(135	)	$	0	$	228		$	129
Interest Rate Swaps (B)	$	39		$	0		$	0	$	39		$	0
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	160		$	0		$	18	$	142		$	0
Other Long-Term Investments (D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(125	)	$	74		$	0	$	(117	)	$	(82	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	205		$	(135	)	$	0	$	228		$	112
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	32		$	0		$	4	$	28		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(113	)	$	74		$	0	$	(117	)	$	(70	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	17		$	0		$	0	$	0		$	17
Rabbi Trusts—Mutual Funds (C)	$	54		$	0		$	6	$	48		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(12	)	$	0		$	0	$	0		$	(12	)

(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.

Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.

(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) Power's NDT funds maintain investments in various equity and fixed income securities classified as "available for sale." These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the NDT funds 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).

Power's NDT investments in fixed income securities are primarily with investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities (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).

The Rabbi Trust mutual funds are mainly invested in a United States bond index fund, an S&P 500 index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

(D) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices.

(E) 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.

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, 2011 follows:

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

for the Three Months Ended September 30, 2011

				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1,    2011			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)		Transfers In (Out)		Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(3	)	$	13	$	(27	)	$	10	$	3	$	0	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	(4	)	$	13	$	0		$	10	$	3	$	0	$	22
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	0	$	(27	)	$	0	$	0	$	0	$	(26	)

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

for the Nine Months Ended September 30, 2011

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2011		Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)			Transfers In (Out)			Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	47	$	(27	)	$	(31	)	$	29	$	(22	)	$	0		$	(4	)
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
Power
Net Derivative Assets	$	42	$	(27	)	$	0		$	29	$	(22	)	$	0		$	22
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
PSE&G
Net Derivative Assets (Liabilities)	$	5	$	0		$	(31	)	$	0	$	0		$	0		$	(26	)

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, 2010 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2010		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	168	$	33	$	(11	)	$	(2	)	$	188
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	16	$	0	$	0		$	(16	)	$	0
Power
Net Derivative Assets	$	117	$	33	$	0		$	(2	)	$	148
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	3	$	0	$	0		$	(3	)	$	0
PSE&G
Net Derivative Assets	$	51	$	0	$	(11	)	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0		$	(5	)	$	0

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

for the Nine Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2010		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)		Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	105	$	61	$	34	$	(12	)	$	188
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	14	$	0	$	0	$	(14	)	$	0
Power
Net Derivative Assets	$	99	$	61	$	0	$	(12	)	$	148
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	3	$	0	$	0	$	(3	)	$	0
PSE&G
Net Derivative Assets	$	6	$	0	$	34	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0	$	(5	)	$	0

(A) PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $12 million and $17 million are included in Operating Income, $1 million and $14 million are included in OCI, and less than $1 million and $2 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $12 million in Operating Income in 2011, $31 million is unrealized and $(19) million is realized. Of the $17 million in Operating Income in 2010, $32 million is unrealized and $(15) million is realized.

(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 $10 million in purchases for the three months ended September 30, 2011. Includes $65 million in purchases and $(36) million in sales for the nine months ended September 30, 2011.

(D) Includes $(5) million in issuances and $8 million in settlements for the three months ended September 30, 2011. Includes $(25) million in issuances and $3 million in settlements for the nine months ended September 30, 2011.

(E) PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(28) million and $8 million are included in Operating Income, $(2) million and $28 million are included in OCI, and $3 million and $25 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $(28) million in Operating Income in 2011, $(25) million is unrealized and $(3) million is realized. Of the $8 million in Operating Income in 2010, $9 million is unrealized and $(1) million is realized.

As of September 30, 2011, PSEG carried $1.5 billion of net assets that are measured at fair value on a recurring basis, of which $4 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG's total assets. During the nine months ended September 30, 2011, $8 million of assets in the NDT fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. As per PSEG's policy, this transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred).

As of September 30, 2010, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $197 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG's total assets and there were no transfers among levels during the three months and nine months ended September 30, 2010.

Non-recurring Fair Value Measurements

In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset's carrying amount may not be recoverable. There were no material impairments recorded during 2011.

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, 2011 and December 31, 2010.

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value (A)		Carrying Amount		Fair Value (A)
	Millions
Long-Term Debt:
PSEG (Parent)	$	40	$	66	$	10	$	39
Power -Recourse Debt		3,350		3,710		3,455		3,831
PSE&G		4,535		5,099		4,283		4,615
Transition Funding (PSE&G)		948		1,080		1,090		1,245
Transition Funding II (PSE&G)		50		54		55		59
Energy Holdings:
Project Level, Non-Recourse Debt		46		46		47		47
Total Long-Term Debt	$	8,969	$	10,055	$	8,940	$	9,836

(A) Fair value excludes unamortized discounts, including amounts related to the Debt Exchange between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company.

PSE&G [Member]

Fair Value Measurements

Note 11. Fair Value Measurements

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

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, 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. These consist mainly of various FTRs, certain full requirements contracts and other longer term capacity and transportation 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, 2011 and December 31, 2010, 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.

	Recurring Fair Value Measurements as of September 30, 2011
Description	Total			Cash Collateral Netting (E)			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)	$	119		$	(10	)	$	0	$	99		$	30
Interest Rate Swaps (B)	$	69		$	0		$	0	$	69		$	0
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	170		$	0		$	17	$	153		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(122	)	$	0		$	0	$	(88	)	$	(34	)
Interest Rate Swaps (B)	$	(3	)	$	0		$	0	$	(3	)	$	0
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	119		$	(10	)	$	0	$	99		$	30
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	33		$	0		$	3	$	30		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(96	)	$	0		$	0	$	(88	)	$	(8	)
PSE&G
Assets:
Rabbi Trust—Mutual Funds (C)	$	57		$	0		$	6	$	51		$	0
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(26	)	$	0		$	0	$	0		$	(26	)

	Recurring Fair Value Measurements as of December 31, 2010
Description	Total			Cash Collateral Netting (E)			Quoted Market Prices of Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	222		$	(135	)	$	0	$	228		$	129
Interest Rate Swaps (B)	$	39		$	0		$	0	$	39		$	0
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	160		$	0		$	18	$	142		$	0
Other Long-Term Investments (D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(125	)	$	74		$	0	$	(117	)	$	(82	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	205		$	(135	)	$	0	$	228		$	112
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	32		$	0		$	4	$	28		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(113	)	$	74		$	0	$	(117	)	$	(70	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	17		$	0		$	0	$	0		$	17
Rabbi Trusts—Mutual Funds (C)	$	54		$	0		$	6	$	48		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(12	)	$	0		$	0	$	0		$	(12	)

(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.

Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.

(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) Power's NDT funds maintain investments in various equity and fixed income securities classified as "available for sale." These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the NDT funds 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).

Power's NDT investments in fixed income securities are primarily with investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities (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).

The Rabbi Trust mutual funds are mainly invested in a United States bond index fund, an S&P 500 index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

(D) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices.

(E) 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.

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, 2011 follows:

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

for the Three Months Ended September 30, 2011

				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1,    2011			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)		Transfers In (Out)		Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(3	)	$	13	$	(27	)	$	10	$	3	$	0	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	(4	)	$	13	$	0		$	10	$	3	$	0	$	22
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	0	$	(27	)	$	0	$	0	$	0	$	(26	)

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

for the Nine Months Ended September 30, 2011

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2011		Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)			Transfers In (Out)			Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	47	$	(27	)	$	(31	)	$	29	$	(22	)	$	0		$	(4	)
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
Power
Net Derivative Assets	$	42	$	(27	)	$	0		$	29	$	(22	)	$	0		$	22
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
PSE&G
Net Derivative Assets (Liabilities)	$	5	$	0		$	(31	)	$	0	$	0		$	0		$	(26	)

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, 2010 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2010		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	168	$	33	$	(11	)	$	(2	)	$	188
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	16	$	0	$	0		$	(16	)	$	0
Power
Net Derivative Assets	$	117	$	33	$	0		$	(2	)	$	148
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	3	$	0	$	0		$	(3	)	$	0
PSE&G
Net Derivative Assets	$	51	$	0	$	(11	)	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0		$	(5	)	$	0

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

for the Nine Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2010		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)		Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	105	$	61	$	34	$	(12	)	$	188
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	14	$	0	$	0	$	(14	)	$	0
Power
Net Derivative Assets	$	99	$	61	$	0	$	(12	)	$	148
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	3	$	0	$	0	$	(3	)	$	0
PSE&G
Net Derivative Assets	$	6	$	0	$	34	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0	$	(5	)	$	0

(A) PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $12 million and $17 million are included in Operating Income, $1 million and $14 million are included in OCI, and less than $1 million and $2 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $12 million in Operating Income in 2011, $31 million is unrealized and $(19) million is realized. Of the $17 million in Operating Income in 2010, $32 million is unrealized and $(15) million is realized.

(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 $10 million in purchases for the three months ended September 30, 2011. Includes $65 million in purchases and $(36) million in sales for the nine months ended September 30, 2011.

(D) Includes $(5) million in issuances and $8 million in settlements for the three months ended September 30, 2011. Includes $(25) million in issuances and $3 million in settlements for the nine months ended September 30, 2011.

(E) PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(28) million and $8 million are included in Operating Income, $(2) million and $28 million are included in OCI, and $3 million and $25 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $(28) million in Operating Income in 2011, $(25) million is unrealized and $(3) million is realized. Of the $8 million in Operating Income in 2010, $9 million is unrealized and $(1) million is realized.

As of September 30, 2011, PSEG carried $1.5 billion of net assets that are measured at fair value on a recurring basis, of which $4 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG's total assets. During the nine months ended September 30, 2011, $8 million of assets in the NDT fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. As per PSEG's policy, this transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred).

As of September 30, 2010, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $197 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG's total assets and there were no transfers among levels during the three months and nine months ended September 30, 2010.

Non-recurring Fair Value Measurements

In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset's carrying amount may not be recoverable. There were no material impairments recorded during 2011.

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, 2011 and December 31, 2010.

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value (A)		Carrying Amount		Fair Value (A)
	Millions
Long-Term Debt:
PSEG (Parent)	$	40	$	66	$	10	$	39
Power -Recourse Debt		3,350		3,710		3,455		3,831
PSE&G		4,535		5,099		4,283		4,615
Transition Funding (PSE&G)		948		1,080		1,090		1,245
Transition Funding II (PSE&G)		50		54		55		59
Energy Holdings:
Project Level, Non-Recourse Debt		46		46		47		47
Total Long-Term Debt	$	8,969	$	10,055	$	8,940	$	9,836

(A) Fair value excludes unamortized discounts, including amounts related to the Debt Exchange between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company.

XML

Recent Accounting Standards

9 Months Ended

Sep. 30, 2011

Recent Accounting Standards

Note 2. Recent Accounting Standards

New Standard Adopted during 2011

Revenue Arrangements with Multiple Deliverables

• amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist,

• establishes a selling price hierarchy, such as, "vendor-specific objective evidence," "third-party evidence" and "estimated selling price" for determining the selling price of a deliverable, and

• provides guidance for allocating and recognizing revenue based on separate deliverables.

We adopted this standard, prospectively, effective January 1, 2011, for new and significantly modified revenue arrangements. Upon adoption, there was no material impact on our financial statements and we do not anticipate any changes to the pattern or general timing of revenue recognition for our significant units of account in future periods.

New Accounting Standards Issued But Not Yet Adopted

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)

This accounting standard was issued to update guidance related to fair value measurements and disclosures as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• clarifies intent about application of existing fair value measurements and disclosures,

• changes some requirements for fair value measurements, and

• requires expanded disclosures.

This guidance is effective for interim and annual periods beginning after December 15, 2011. We believe our adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows; however, it will result in expanded disclosures.

Presentation of Comprehensive Income

This accounting standard was issued on the presentation of comprehensive income as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and

• eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.

This guidance is effective for fiscal years and interim periods beginning after December 15, 2011. We believe that the adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows, but will change the presentation of the components of other comprehensive income.

Testing Goodwill for Impairment

This accounting standard was issued to simplify testing for goodwill impairment. The updated guidance allows an entity to first perform a qualitative assessment to determine if it is more likely than not that the fair value of the reporting unit is less than its carrying value. Only if it is concluded that this is the case is it necessary to perform the two-step goodwill impairment test.

The guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Earlier adoption is permitted. We believe that if we adopt the new optional guidance, it will not have a material impact on our consolidated financial position, results of operations or cash flows.

Power [Member]

Recent Accounting Standards

Note 2. Recent Accounting Standards

New Standard Adopted during 2011

Revenue Arrangements with Multiple Deliverables

• amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist,

• establishes a selling price hierarchy, such as, "vendor-specific objective evidence," "third-party evidence" and "estimated selling price" for determining the selling price of a deliverable, and

• provides guidance for allocating and recognizing revenue based on separate deliverables.

We adopted this standard, prospectively, effective January 1, 2011, for new and significantly modified revenue arrangements. Upon adoption, there was no material impact on our financial statements and we do not anticipate any changes to the pattern or general timing of revenue recognition for our significant units of account in future periods.

New Accounting Standards Issued But Not Yet Adopted

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)

This accounting standard was issued to update guidance related to fair value measurements and disclosures as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• clarifies intent about application of existing fair value measurements and disclosures,

• changes some requirements for fair value measurements, and

• requires expanded disclosures.

This guidance is effective for interim and annual periods beginning after December 15, 2011. We believe our adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows; however, it will result in expanded disclosures.

Presentation of Comprehensive Income

This accounting standard was issued on the presentation of comprehensive income as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and

• eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.

This guidance is effective for fiscal years and interim periods beginning after December 15, 2011. We believe that the adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows, but will change the presentation of the components of other comprehensive income.

Testing Goodwill for Impairment

This accounting standard was issued to simplify testing for goodwill impairment. The updated guidance allows an entity to first perform a qualitative assessment to determine if it is more likely than not that the fair value of the reporting unit is less than its carrying value. Only if it is concluded that this is the case is it necessary to perform the two-step goodwill impairment test.

The guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Earlier adoption is permitted. We believe that if we adopt the new optional guidance, it will not have a material impact on our consolidated financial position, results of operations or cash flows.

PSE&G [Member]

Recent Accounting Standards

Note 2. Recent Accounting Standards

New Standard Adopted during 2011

Revenue Arrangements with Multiple Deliverables

• amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist,

• establishes a selling price hierarchy, such as, "vendor-specific objective evidence," "third-party evidence" and "estimated selling price" for determining the selling price of a deliverable, and

• provides guidance for allocating and recognizing revenue based on separate deliverables.

We adopted this standard, prospectively, effective January 1, 2011, for new and significantly modified revenue arrangements. Upon adoption, there was no material impact on our financial statements and we do not anticipate any changes to the pattern or general timing of revenue recognition for our significant units of account in future periods.

New Accounting Standards Issued But Not Yet Adopted

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)

This accounting standard was issued to update guidance related to fair value measurements and disclosures as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• clarifies intent about application of existing fair value measurements and disclosures,

• changes some requirements for fair value measurements, and

• requires expanded disclosures.

This guidance is effective for interim and annual periods beginning after December 15, 2011. We believe our adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows; however, it will result in expanded disclosures.

Presentation of Comprehensive Income

This accounting standard was issued on the presentation of comprehensive income as a step towards achieving convergence between GAAP and IFRS. The updated guidance

• allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and

• eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.

This guidance is effective for fiscal years and interim periods beginning after December 15, 2011. We believe that the adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows, but will change the presentation of the components of other comprehensive income.

Testing Goodwill for Impairment

This accounting standard was issued to simplify testing for goodwill impairment. The updated guidance allows an entity to first perform a qualitative assessment to determine if it is more likely than not that the fair value of the reporting unit is less than its carrying value. Only if it is concluded that this is the case is it necessary to perform the two-step goodwill impairment test.

The guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Earlier adoption is permitted. We believe that if we adopt the new optional guidance, it will not have a material impact on our consolidated financial position, results of operations or cash flows.

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Comprehensive Income, Net Of Tax (Tables)

9 Months Ended

Sep. 30, 2011

Comprehensive Income, Net Of Tax [Abstract]

Comprehensive Income

Comprehensive Income	Power			PSE&G			Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Net Income	$	302		$	154		$	(162	)	$	294
Other Comprehensive Income (Loss)		(80	)		1			2			(77	)
Comprehensive Income	$	222		$	155		$	(160	)	$	217
Three Months Ended September 30, 2010
Net Income	$	384		$	155		$	28		$	567
Other Comprehensive Income (Loss)		38			(6	)		(4	)		28
Comprehensive Income	$	422		$	149		$	24		$	595
Nine Months Ended September 30, 2011
Net Income	$	871		$	422		$	(150	)	$	1,143
Other Comprehensive Income (Loss)		(112	)		2			10			(100	)
Comprehensive Income	$	759		$	424		$	(140	)	$	1,043
Nine Months Ended September 30, 2010
Net Income	$	952		$	276		$	54		$	1,282
Other Comprehensive Income (Loss)		13			(5	)		(3	)		5
Comprehensive Income	$	965		$	271		$	51		$	1,287

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

Accumulated Other Comprehensive Income (Loss)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2010			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2011							Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2011
				Power (A)			PSE&G (B)		Other (C)
	Millions
Derivative Contracts	$	111		$	(80	)	$	0	$	0	$	31
Pension and OPEB Plans		(377	)		45			0		8		(324	)
NDT Funds		109			(77	)		0		0		32
Other		1			0			2		2		5
Accumulated Other Comprehensive Income (Loss)	$	(156	)	$	(112	)	$	2		10	$	(256	)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2009			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2010									Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2010
				Power (A)			PSE&G (B)			Other (C)
	Millions
Derivative Contracts	$	180		$	(2	)	$	0		$	0		$	178
Pension and OPEB Plans		(400	)		18			0			1			(381	)
NDT Funds		91			0			0			0			91
Other		13			(3	)		(5	)		(4	)		1
Accumulated Other Comprehensive Income (Loss)	$	(116	)	$	13		$	(5	)	$	(3	)	$	(111	)

(A) Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $54 million, $(31) million and $78 million, respectively for the nine months ended September 30, 2011. Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $1 million, $(12) million and $1 million, respectively for the nine months ended September 30, 2010.

(B) Net of tax of $(1) million for the nine months ended September 30, 2011 and $3 million for the nine months ended September 30, 2010.

(C) Net of tax of $(7) million for the nine months ended September 30, 2011 and $2 million for the nine months ended September 30, 2010.

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Commitments And Contingent Liabilities

9 Months Ended

Sep. 30, 2011

Commitments And Contingent Liabilities

Note 8. Commitments and Contingent Liabilities

Guaranteed ObligationsPSEG and Power

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.

The face value of outstanding guarantees, current exposure and margin positions as of September 30, 2011 and December 31, 2010 are shown below:

	As of September 30, 2011			As of December 31, 2010
	Millions
Face Value of Outstanding Guarantees	$	1,758		$	1,936
Exposure under Current Guarantees	$	283		$	330
Letters of Credit Margin Posted	$	135		$	137
Letters of Credit Margin Received	$	53		$	109
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	1		$	0
Counterparty Cash Margin Received		(5	)		(2	)
Net Broker Balance Deposited (Received)		37			(28	)
In the Event Power Were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	765		$	828
Liquidity Available under PSEG's and Power's Credit Facilities to Post Collateral	$	3,466		$	2,750
Additional Amounts Posted
Other Letters of Credit	$	99		$	98

Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Receivable.

In the event of a deterioration of Power's credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

In addition, during 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. Power will carefully monitor these new rules as they are developed to analyze the potential impact on its swap and derivatives transactions, including any potential increase to collateral requirements.

In April 2011, PSEG and Power entered into new 5-year credit agreements resulting in an increase of $650 million in Power's total credit capacity.

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 United States Environmental Protection Agency (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, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G's former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. The total cost of the study is now estimated at approximately $86 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 71 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G's former MGP sites and approximately one percent to Power's generating stations. Power has provided notice to insurers concerning this potential claim.

In 2007, the EPA released a draft "Focused Feasibility Study" that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study may be released as early as the second quarter of 2012.

In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to these 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 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 February 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 they allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaint in June 2010. A special master for discovery has been appointed by the court and document production has commenced. 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. 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. PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study 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 is participating in and partially funding 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 next 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.

During the third quarter of 2011, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $643 million and $741 million from September 30, 2011 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $643 million on its Condensed Consolidated Balance Sheet as of September 30, 2011. Of this amount, $53 million was recorded in Other Current Liabilities and $590 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $643 million Regulatory Asset with respect to these costs.

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

The PSD/NSR regulations, promulgated under the Clean Air Act, 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 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Power's generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at the Hudson and Mercer facilities designed to meet targeted reductions in emissions of sulfur dioxide (SO₂), nitrogen oxide (NO_x ), particulate matter and mercury. Power completed the construction of all plant modifications by the end of 2010 at a cost of $1.3 billion. Performance testing to validate the agreed-upon emission reductions was completed in the second quarter of 2011 and all performance metrics were met.

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 Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act 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 court ruling, the EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which is expected to be finalized by December 2011. This regulation prescribes reduced levels of mercury and other hazardous air pollutants pursuant to the Clean Air Act. Until the final rule is adopted, the impact cannot be determined; however, if the rule is adopted as proposed, Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rule's requirements. Some additional controls could be necessary at Power's Connecticut facilities and some of its other New Jersey facilities, pending engineering evaluation. The impact to Power's jointly owned coal fired generating facilities in Pennsylvania is under evaluation.

New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.

With newly installed controls at its plants in New Jersey, Power expects to achieve the required mercury reductions that are part of Power's multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

NO_x Regulation

In April 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel fired electric generating units. The rule has a significant impact on Power's generation fleet, as it imposes NO_x emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW) by April 30, 2015. Power is unable to estimate the possible loss or range of loss related to this matter.

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.

Cross-State Air Pollution Rule (CSAPR)

On July 6, 2011, the EPA issued the CSAPR. CSAPR limits power plant emissions in 27 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions will be governed by this rule beginning on January 1, 2012 for SO₂ and "annual NO_x" and May 1, 2012 for "Ozone season NO_x". Certain states will be required to make additional SO₂ reductions in 2014.

PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. As Power has made major capital investments over the past several years to lower the SO₂ and NO_X emissions of its fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania), Power does not foresee the need to make significant additional expenditures to its generation fleet to comply with the regulation. As such, Power believes this rule will not have a material impact to its capital investment program or units' operations.

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In 1999, in anticipation of the transfer of PSE&G's generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability related to these obligations, which was included in Environmental Costs on Power's and PSEG's Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NJPDES) 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.

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 February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.

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 April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established impingement and entrainment mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power's electric generating stations would be affected. 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 or results of operations. 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.

In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies may ultimately impact the EPA's rulemaking.

In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that company's nuclear generating station located in New Jersey. In December 2010, the NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit will be issued in substitution for the draft NJPDES permit issued in January 2010. Power cannot predict at this time the final outcome of the NJDEP decision and the impact, if any, such a decision would have on any of Power's once-through cooled generating stations.

New Generation and Development

Nuclear

Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed on schedule in October 2011. Unit 2 upgrades are expected to result in an increase of Power's share of nominal capacity by approximately 18 MW in 2012. Total expenditures through September 30, 2011 were $94 million and are expected to continue through 2012. The actual increase in nominal capacity is under evaluation.

Power has begun expenditures in pursuit of additional output through an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power's share of the increased capacity is expected to be approximately 133 MW with an anticipated cost of approximately $400 million. Total expenditures through September 30, 2011 were $28 million and are expected to continue through 2016.

Connecticut

Power was selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $140 million to $150 million. Total capitalized expenditures through September 30, 2011 were $99 million, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power. The initial filing is expected to be made in the fourth quarter of 2011. Costs for this project will be recovered subject to regulatory review and approval.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. Construction began in the second quarter of 2011. The projects are expected to be in service by June 2012. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Capacity in the amount of 267 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 and 2014-2015 periods. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through September 30, 2011 were $148 million which are included in Property, Plant and Equipment on Power's and PSEG's Condensed Consolidated Balance Sheets.

PSE&GSolar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&G's commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units PSE&G estimates the total cost of this project to be $264 million. Approximately 23 MW have been installed as of September 30, 2011. PSE&G's cumulative investments for these solar units were approximately $164 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available. to

Another aspect of the Solar 4 All program is the installation of 40 MW of solar systems on land and buildings owned by PSE&G and third parties. PSE&G estimates the total cost of this phase of the program to be $189 million. Through September 30, 2011, 23 MW representing 15 projects were placed into service with an investment of approximately $116 million.

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. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.

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

Auction Year
	2008		2009		2010		2011
36-Month Terms Ending		May 2011		May 2012		May 2013		May 2014	(A)
Load (MW)		2,800		2,900		2,800		2,800
$ per kWh		0.11150		0.10372		0.09577		0.09430

(A) Prices set in the 2011 BGS auction became effective on June 1, 2011 when the 2008 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. The contract extends through March 31, 2012, and year-to-year thereafter. 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. For additional information, see Note 17. Related-Party Transactions. 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.

Minimum Fuel Purchase Requirements

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

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.

Power's strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below 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 2013 and a portion for 2014 through 2015 at Salem, Hope Creek and Peach Bottom.

As of September 30, 2011, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Commitments through 2015 Power's Share
	Millions
Nuclear Fuel
Uranium	$	493
Enrichment	$	383
Fabrication	$	130
Natural Gas	$	903
Coal/Oil	$	896

Included in the $896 million commitment for coal is $647 million related to a certain coal contract under which Power can cancel future contractual deliveries at no cost. In 2011, Power has not cancelled any related coal deliveries.

Regulatory Proceedings

Electric Discount and Energy Competition Act (Competition Act)

In 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G's electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

Also in 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In October 2007, the Court granted PSE&G's motion to dismiss the amended Complaint and in November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court (Appellate Division). In February 2009, the Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division's decision.

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G's recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G's motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. In June 2011, the plaintiff/petitioner filed a notice of appeal of the BPU action with the Appellate Division. A briefing schedule has been established.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey EDC applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&G's share is $705 million. PSE&G has recorded a discounted liability of $294 million as of September 30, 2011. Of this amount, $224 million was recorded as a current liability and $70 million as a noncurrent liability. 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 expected to be recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. It has no impact on current SBC assessments.

Long-Term Capacity Agreement Pilot Program (LCAPP)

In January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of approximately 1,949 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, executed standard offer capacity agreements (SOCA) with each of the three selected generators in compliance with the BPU's directive, but did so under protest preserving its respective legal rights. The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The LCAPP Act and the BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. PSE&G will not make or receive payments under the three contracts unless (1) the plant successfully bids into and clears the capacity auction, and (2) the proposed plant is constructed. In April 2011, the BPU approved the executed contracts. Both PSE&G and Power joined other parties, including the EDCs, and appealed the BPU's implementation of the LCAPP Act to the Appellate Division. The Division of Rate Counsel filed a motion to dismiss the EDCs' appeal, which was denied by the Appellate Division.

Leveraged Lease Investments

The IRS has issued reports with respect to its audits of PSEG's consolidated federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.

PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, six cases have been decided at the trial court level, five of which were decided in favor of the government. The appeals of three of these decisions were affirmed, each in favor of the government. The sixth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer.

In order to reduce the cash tax exposure related to these leases, Energy Holdings pursued opportunities to terminate international leases with lessees that were willing to meet certain economic thresholds. As of December 31, 2010, Energy Holdings had terminated all of these leasing transactions and reduced the related cash tax exposure by $1.1 billion. PSEG has completely eliminated its gross investment in such transactions.

Cash Impact

As of September 30, 2011, an aggregate of approximately $266 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, eliminating its cash exposure completely. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. Penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure will grow at an average rate of $2 million per quarter during 2011. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $20 million to $40 million of tax would be due for tax positions through September 30, 2011.

Unless this matter is resolved with the IRS, PSEG currently anticipates that it may be required to pay between $110 million and $300 million in tax, interest and penalties for the tax years 1997-2000 during 2011 and subsequently commence litigation to recover those amounts. It is possible that an additional payment of between $220 million and $560 million could be required during 2011 for tax years 2001-2003 followed by further litigation to recover those amounts. The amounts that may be required to litigate differ from the potential net cash exposure noted above, as the former amounts include all potential deficiencies for only contested tax years 1997 through 2003. These litigation amounts also include penalties which are not included in the computation of potential net cash exposure as PSEG believes it has strong defenses. These amounts also exclude an offset for taxes paid on lease terminations, which is netted in the potential net cash exposure as PSEG would be entitled to a refund of such amounts under a loss scenario. Any potential claims PSEG would make to recover such amounts would include the deposit noted above.

Earnings Impact

PSEG's current reserve position represents its view of the earnings impact that could result from a settlement related to these transactions, although a total loss, consistent with the broad settlement offer previously proposed by the IRS, would result in an additional earnings charge of $120 million to $140 million.

Power [Member]

Commitments And Contingent Liabilities

Note 8. Commitments and Contingent Liabilities

Guaranteed ObligationsPSEG and Power

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.

The face value of outstanding guarantees, current exposure and margin positions as of September 30, 2011 and December 31, 2010 are shown below:

	As of September 30, 2011			As of December 31, 2010
	Millions
Face Value of Outstanding Guarantees	$	1,758		$	1,936
Exposure under Current Guarantees	$	283		$	330
Letters of Credit Margin Posted	$	135		$	137
Letters of Credit Margin Received	$	53		$	109
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	1		$	0
Counterparty Cash Margin Received		(5	)		(2	)
Net Broker Balance Deposited (Received)		37			(28	)
In the Event Power Were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	765		$	828
Liquidity Available under PSEG's and Power's Credit Facilities to Post Collateral	$	3,466		$	2,750
Additional Amounts Posted
Other Letters of Credit	$	99		$	98

Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Receivable.

In the event of a deterioration of Power's credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

In addition, during 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. Power will carefully monitor these new rules as they are developed to analyze the potential impact on its swap and derivatives transactions, including any potential increase to collateral requirements.

In April 2011, PSEG and Power entered into new 5-year credit agreements resulting in an increase of $650 million in Power's total credit capacity.

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 United States Environmental Protection Agency (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, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G's former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. The total cost of the study is now estimated at approximately $86 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 71 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G's former MGP sites and approximately one percent to Power's generating stations. Power has provided notice to insurers concerning this potential claim.

In 2007, the EPA released a draft "Focused Feasibility Study" that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study may be released as early as the second quarter of 2012.

In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to these 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 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 February 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 they allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaint in June 2010. A special master for discovery has been appointed by the court and document production has commenced. 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. 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. PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study 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 is participating in and partially funding 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 next 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.

During the third quarter of 2011, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $643 million and $741 million from September 30, 2011 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $643 million on its Condensed Consolidated Balance Sheet as of September 30, 2011. Of this amount, $53 million was recorded in Other Current Liabilities and $590 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $643 million Regulatory Asset with respect to these costs.

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

The PSD/NSR regulations, promulgated under the Clean Air Act, 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 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Power's generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at the Hudson and Mercer facilities designed to meet targeted reductions in emissions of sulfur dioxide (SO₂), nitrogen oxide (NO_x ), particulate matter and mercury. Power completed the construction of all plant modifications by the end of 2010 at a cost of $1.3 billion. Performance testing to validate the agreed-upon emission reductions was completed in the second quarter of 2011 and all performance metrics were met.

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 Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act 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 court ruling, the EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which is expected to be finalized by December 2011. This regulation prescribes reduced levels of mercury and other hazardous air pollutants pursuant to the Clean Air Act. Until the final rule is adopted, the impact cannot be determined; however, if the rule is adopted as proposed, Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rule's requirements. Some additional controls could be necessary at Power's Connecticut facilities and some of its other New Jersey facilities, pending engineering evaluation. The impact to Power's jointly owned coal fired generating facilities in Pennsylvania is under evaluation.

New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.

With newly installed controls at its plants in New Jersey, Power expects to achieve the required mercury reductions that are part of Power's multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

NO_x Regulation

In April 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel fired electric generating units. The rule has a significant impact on Power's generation fleet, as it imposes NO_x emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW) by April 30, 2015. Power is unable to estimate the possible loss or range of loss related to this matter.

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.

Cross-State Air Pollution Rule (CSAPR)

On July 6, 2011, the EPA issued the CSAPR. CSAPR limits power plant emissions in 27 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions will be governed by this rule beginning on January 1, 2012 for SO₂ and "annual NO_x" and May 1, 2012 for "Ozone season NO_x". Certain states will be required to make additional SO₂ reductions in 2014.

PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. As Power has made major capital investments over the past several years to lower the SO₂ and NO_X emissions of its fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania), Power does not foresee the need to make significant additional expenditures to its generation fleet to comply with the regulation. As such, Power believes this rule will not have a material impact to its capital investment program or units' operations.

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In 1999, in anticipation of the transfer of PSE&G's generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability related to these obligations, which was included in Environmental Costs on Power's and PSEG's Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NJPDES) 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.

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 February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.

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 April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established impingement and entrainment mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power's electric generating stations would be affected. 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 or results of operations. 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.

In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies may ultimately impact the EPA's rulemaking.

In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that company's nuclear generating station located in New Jersey. In December 2010, the NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit will be issued in substitution for the draft NJPDES permit issued in January 2010. Power cannot predict at this time the final outcome of the NJDEP decision and the impact, if any, such a decision would have on any of Power's once-through cooled generating stations.

New Generation and Development

Nuclear

Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed on schedule in October 2011. Unit 2 upgrades are expected to result in an increase of Power's share of nominal capacity by approximately 18 MW in 2012. Total expenditures through September 30, 2011 were $94 million and are expected to continue through 2012. The actual increase in nominal capacity is under evaluation.

Power has begun expenditures in pursuit of additional output through an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power's share of the increased capacity is expected to be approximately 133 MW with an anticipated cost of approximately $400 million. Total expenditures through September 30, 2011 were $28 million and are expected to continue through 2016.

Connecticut

Power was selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $140 million to $150 million. Total capitalized expenditures through September 30, 2011 were $99 million, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power. The initial filing is expected to be made in the fourth quarter of 2011. Costs for this project will be recovered subject to regulatory review and approval.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. Construction began in the second quarter of 2011. The projects are expected to be in service by June 2012. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Capacity in the amount of 267 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 and 2014-2015 periods. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through September 30, 2011 were $148 million which are included in Property, Plant and Equipment on Power's and PSEG's Condensed Consolidated Balance Sheets.

PSE&GSolar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&G's commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units PSE&G estimates the total cost of this project to be $264 million. Approximately 23 MW have been installed as of September 30, 2011. PSE&G's cumulative investments for these solar units were approximately $164 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available.

Another aspect of the Solar 4 All program is the installation of 40 MW of solar systems on land and buildings owned by PSE&G and third parties. PSE&G estimates the total cost of this phase of the program to be $189 million. Through September 30, 2011, 23 MW representing 15 projects were placed into service with an investment of approximately $116 million.

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. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.

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

Auction Year
	2008		2009		2010		2011
36-Month Terms Ending		May 2011		May 2012		May 2013		May 2014	(A)
Load (MW)		2,800		2,900		2,800		2,800
$ per kWh		0.11150		0.10372		0.09577		0.09430

(A) Prices set in the 2011 BGS auction became effective on June 1, 2011 when the 2008 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. The contract extends through March 31, 2012, and year-to-year thereafter. 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. For additional information, see Note 17. Related-Party Transactions. 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.

Minimum Fuel Purchase Requirements

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

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.

Power's strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below 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 2013 and a portion for 2014 through 2015 at Salem, Hope Creek and Peach Bottom.

As of September 30, 2011, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Commitments through 2015 Power's Share
	Millions
Nuclear Fuel
Uranium	$	493
Enrichment	$	383
Fabrication	$	130
Natural Gas	$	903
Coal/Oil	$	896

Included in the $896 million commitment for coal is $647 million related to a certain coal contract under which Power can cancel future contractual deliveries at no cost. In 2011, Power has not cancelled any related coal deliveries.

Regulatory Proceedings

Electric Discount and Energy Competition Act (Competition Act)

In 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G's electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

Also in 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In October 2007, the Court granted PSE&G's motion to dismiss the amended Complaint and in November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court (Appellate Division). In February 2009, the Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division's decision.

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G's recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G's motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. In June 2011, the plaintiff/petitioner filed a notice of appeal of the BPU action with the Appellate Division. A briefing schedule has been established.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey EDC applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&G's share is $705 million. PSE&G has recorded a discounted liability of $294 million as of September 30, 2011. Of this amount, $224 million was recorded as a current liability and $70 million as a noncurrent liability. 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 expected to be recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. It has no impact on current SBC assessments.

Long-Term Capacity Agreement Pilot Program (LCAPP)

In January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of approximately 1,949 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, executed standard offer capacity agreements (SOCA) with each of the three selected generators in compliance with the BPU's directive, but did so under protest preserving its respective legal rights.  The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The LCAPP Act and the BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. PSE&G will not make or receive payments under the three contracts unless (1) the plant successfully bids into and clears the capacity auction, and (2) the proposed plant is constructed. In April 2011, the BPU approved the executed contracts. Both PSE&G and Power joined other parties, including the EDCs, and appealed the BPU's implementation of the LCAPP Act to the Appellate Division. The Division of Rate Counsel filed a motion to dismiss the EDCs' appeal, which was denied by the Appellate Division.

Leveraged Lease Investments

The IRS has issued reports with respect to its audits of PSEG's consolidated federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.

PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, six cases have been decided at the trial court level, five of which were decided in favor of the government. The appeals of three of these decisions were affirmed, each in favor of the government. The sixth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer.

In order to reduce the cash tax exposure related to these leases, Energy Holdings pursued opportunities to terminate international leases with lessees that were willing to meet certain economic thresholds. As of December 31, 2010, Energy Holdings had terminated all of these leasing transactions and reduced the related cash tax exposure by $1.1 billion. PSEG has completely eliminated its gross investment in such transactions.

Cash Impact

As of September 30, 2011, an aggregate of approximately $266 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, eliminating its cash exposure completely. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. Penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure will grow at an average rate of $2 million per quarter during 2011. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $20 million to $40 million of tax would be due for tax positions through September 30, 2011.

Unless this matter is resolved with the IRS, PSEG currently anticipates that it may be required to pay between $110 million and $300 million in tax, interest and penalties for the tax years 1997-2000 during 2011 and subsequently commence litigation to recover those amounts. It is possible that an additional payment of between $220 million and $560 million could be required during 2011 for tax years 2001-2003 followed by further litigation to recover those amounts. The amounts that may be required to litigate differ from the potential net cash exposure noted above, as the former amounts include all potential deficiencies for only contested tax years 1997 through 2003. These litigation amounts also include penalties which are not included in the computation of potential net cash exposure as PSEG believes it has strong defenses. These amounts also exclude an offset for taxes paid on lease terminations, which is netted in the potential net cash exposure as PSEG would be entitled to a refund of such amounts under a loss scenario. Any potential claims PSEG would make to recover such amounts would include the deposit noted above.

Earnings Impact

PSEG's current reserve position represents its view of the earnings impact that could result from a settlement related to these transactions, although a total loss, consistent with the broad settlement offer previously proposed by the IRS, would result in an additional earnings charge of $120 million to $140 million.

PSE&G [Member]

Commitments And Contingent Liabilities

Note 8. Commitments and Contingent Liabilities

Guaranteed ObligationsPSEG and Power

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.

The face value of outstanding guarantees, current exposure and margin positions as of September 30, 2011 and December 31, 2010 are shown below:

	As of September 30, 2011			As of December 31, 2010
	Millions
Face Value of Outstanding Guarantees	$	1,758		$	1,936
Exposure under Current Guarantees	$	283		$	330
Letters of Credit Margin Posted	$	135		$	137
Letters of Credit Margin Received	$	53		$	109
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	1		$	0
Counterparty Cash Margin Received		(5	)		(2	)
Net Broker Balance Deposited (Received)		37			(28	)
In the Event Power Were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	765		$	828
Liquidity Available under PSEG's and Power's Credit Facilities to Post Collateral	$	3,466		$	2,750
Additional Amounts Posted
Other Letters of Credit	$	99		$	98

Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Receivable.

In the event of a deterioration of Power's credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

In addition, during 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. Power will carefully monitor these new rules as they are developed to analyze the potential impact on its swap and derivatives transactions, including any potential increase to collateral requirements.

In April 2011, PSEG and Power entered into new 5-year credit agreements resulting in an increase of $650 million in Power's total credit capacity.

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 United States Environmental Protection Agency (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, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G's former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. The total cost of the study is now estimated at approximately $86 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 71 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G's former MGP sites and approximately one percent to Power's generating stations. Power has provided notice to insurers concerning this potential claim.

In 2007, the EPA released a draft "Focused Feasibility Study" that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study may be released as early as the second quarter of 2012.

In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to these 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 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 February 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 they allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaint in June 2010. A special master for discovery has been appointed by the court and document production has commenced. 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. 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. PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study 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 is participating in and partially funding 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 next 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.

During the third quarter of 2011, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $643 million and $741 million from September 30, 2011 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $643 million on its Condensed Consolidated Balance Sheet as of September 30, 2011. Of this amount, $53 million was recorded in Other Current Liabilities and $590 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $643 million Regulatory Asset with respect to these costs.

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

The PSD/NSR regulations, promulgated under the Clean Air Act, 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 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Power's generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at the Hudson and Mercer facilities designed to meet targeted reductions in emissions of sulfur dioxide (SO₂), nitrogen oxide (NO_x ), particulate matter and mercury. Power completed the construction of all plant modifications by the end of 2010 at a cost of $1.3 billion. Performance testing to validate the agreed-upon emission reductions was completed in the second quarter of 2011 and all performance metrics were met.

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 Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act 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 court ruling, the EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which is expected to be finalized by December 2011. This regulation prescribes reduced levels of mercury and other hazardous air pollutants pursuant to the Clean Air Act. Until the final rule is adopted, the impact cannot be determined; however, if the rule is adopted as proposed, Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rule's requirements. Some additional controls could be necessary at Power's Connecticut facilities and some of its other New Jersey facilities, pending engineering evaluation. The impact to Power's jointly owned coal fired generating facilities in Pennsylvania is under evaluation.

New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.

With newly installed controls at its plants in New Jersey, Power expects to achieve the required mercury reductions that are part of Power's multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

NO_x Regulation

In April 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel fired electric generating units. The rule has a significant impact on Power's generation fleet, as it imposes NO_x emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW) by April 30, 2015. Power is unable to estimate the possible loss or range of loss related to this matter.

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.

Cross-State Air Pollution Rule (CSAPR)

On July 6, 2011, the EPA issued the CSAPR. CSAPR limits power plant emissions in 27 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions will be governed by this rule beginning on January 1, 2012 for SO₂ and "annual NO_x" and May 1, 2012 for "Ozone season NO_x". Certain states will be required to make additional SO₂ reductions in 2014.

PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. As Power has made major capital investments over the past several years to lower the SO₂ and NO_X emissions of its fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania), Power does not foresee the need to make significant additional expenditures to its generation fleet to comply with the regulation. As such, Power believes this rule will not have a material impact to its capital investment program or units' operations.

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In 1999, in anticipation of the transfer of PSE&G's generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability related to these obligations, which was included in Environmental Costs on Power's and PSEG's Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NJPDES) 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.

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 February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.

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 April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established impingement and entrainment mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power's electric generating stations would be affected. 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 or results of operations. 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.

In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies may ultimately impact the EPA's rulemaking.

In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that company's nuclear generating station located in New Jersey. In December 2010, the NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit will be issued in substitution for the draft NJPDES permit issued in January 2010. Power cannot predict at this time the final outcome of the NJDEP decision and the impact, if any, such a decision would have on any of Power's once-through cooled generating stations.

New Generation and Development

Nuclear

Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed on schedule in October 2011. Unit 2 upgrades are expected to result in an increase of Power's share of nominal capacity by approximately 18 MW in 2012. Total expenditures through September 30, 2011 were $94 million and are expected to continue through 2012. The actual increase in nominal capacity is under evaluation.

Power has begun expenditures in pursuit of additional output through an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power's share of the increased capacity is expected to be approximately 133 MW with an anticipated cost of approximately $400 million. Total expenditures through September 30, 2011 were $28 million and are expected to continue through 2016.

Connecticut

Power was selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $140 million to $150 million. Total capitalized expenditures through September 30, 2011 were $99 million, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power. The initial filing is expected to be made in the fourth quarter of 2011. Costs for this project will be recovered subject to regulatory review and approval.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. Construction began in the second quarter of 2011. The projects are expected to be in service by June 2012. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Capacity in the amount of 267 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 and 2014-2015 periods. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through September 30, 2011 were $148 million which are included in Property, Plant and Equipment on Power's and PSEG's Condensed Consolidated Balance Sheets.

PSE&GSolar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&G's commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units PSE&G estimates the total cost of this project to be $264 million. Approximately 23 MW have been installed as of September 30, 2011. PSE&G's cumulative investments for these solar units were approximately $164 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available.

Another aspect of the Solar 4 All program is the installation of 40 MW of solar systems on land and buildings owned by PSE&G and third parties. PSE&G estimates the total cost of this phase of the program to be $189 million. Through September 30, 2011, 23 MW representing 15 projects were placed into service with an investment of approximately $116 million.

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. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.

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

Auction Year
	2008		2009		2010		2011
36-Month Terms Ending		May 2011		May 2012		May 2013		May 2014	(A)
Load (MW)		2,800		2,900		2,800		2,800
$ per kWh		0.11150		0.10372		0.09577		0.09430

(A) Prices set in the 2011 BGS auction became effective on June 1, 2011 when the 2008 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. The contract extends through March 31, 2012, and year-to-year thereafter. 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. For additional information, see Note 17. Related-Party Transactions. 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.

Minimum Fuel Purchase Requirements

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

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.

Power's strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below 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 2013 and a portion for 2014 through 2015 at Salem, Hope Creek and Peach Bottom.

As of September 30, 2011, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Commitments through 2015 Power's Share
	Millions
Nuclear Fuel
Uranium	$	493
Enrichment	$	383
Fabrication	$	130
Natural Gas	$	903
Coal/Oil	$	896

Included in the $896 million commitment for coal is $647 million related to a certain coal contract under which Power can cancel future contractual deliveries at no cost. In 2011, Power has not cancelled any related coal deliveries.

Regulatory Proceedings

Electric Discount and Energy Competition Act (Competition Act)

In 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G's electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

Also in 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In October 2007, the Court granted PSE&G's motion to dismiss the amended Complaint and in November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court (Appellate Division). In February 2009, the Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division's decision.

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G's recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G's motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. In June 2011, the plaintiff/petitioner filed a notice of appeal of the BPU action with the Appellate Division. A briefing schedule has been established.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey EDC applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&G's share is $705 million. PSE&G has recorded a discounted liability of $294 million as of September 30, 2011. Of this amount, $224 million was recorded as a current liability and $70 million as a noncurrent liability. 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 expected to be recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. It has no impact on current SBC assessments.

Long-Term Capacity Agreement Pilot Program (LCAPP)

In January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of approximately 1,949 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, executed standard offer capacity agreements (SOCA) with each of the three selected generators in compliance with the BPU's directive, but did so under protest preserving its respective legal rights.  The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The LCAPP Act and the BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. PSE&G will not make or receive payments under the three contracts unless (1) the plant successfully bids into and clears the capacity auction, and (2) the proposed plant is constructed. In April 2011, the BPU approved the executed contracts. Both PSE&G and Power joined other parties, including the EDCs, and appealed the BPU's implementation of the LCAPP Act to the Appellate Division. The Division of Rate Counsel filed a motion to dismiss the EDCs' appeal, which was denied by the Appellate Division.

Leveraged Lease Investments

The IRS has issued reports with respect to its audits of PSEG's consolidated federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.

PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, six cases have been decided at the trial court level, five of which were decided in favor of the government. The appeals of three of these decisions were affirmed, each in favor of the government. The sixth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer.

In order to reduce the cash tax exposure related to these leases, Energy Holdings pursued opportunities to terminate international leases with lessees that were willing to meet certain economic thresholds. As of December 31, 2010, Energy Holdings had terminated all of these leasing transactions and reduced the related cash tax exposure by $1.1 billion. PSEG has completely eliminated its gross investment in such transactions.

Cash Impact

As of September 30, 2011, an aggregate of approximately $266 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, eliminating its cash exposure completely. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. Penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure will grow at an average rate of $2 million per quarter during 2011. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $20 million to $40 million of tax would be due for tax positions through September 30, 2011.

Unless this matter is resolved with the IRS, PSEG currently anticipates that it may be required to pay between $110 million and $300 million in tax, interest and penalties for the tax years 1997-2000 during 2011 and subsequently commence litigation to recover those amounts. It is possible that an additional payment of between $220 million and $560 million could be required during 2011 for tax years 2001-2003 followed by further litigation to recover those amounts. The amounts that may be required to litigate differ from the potential net cash exposure noted above, as the former amounts include all potential deficiencies for only contested tax years 1997 through 2003. These litigation amounts also include penalties which are not included in the computation of potential net cash exposure as PSEG believes it has strong defenses. These amounts also exclude an offset for taxes paid on lease terminations, which is netted in the potential net cash exposure as PSEG would be entitled to a refund of such amounts under a loss scenario. Any potential claims PSEG would make to recover such amounts would include the deposit noted above.

Earnings Impact

PSEG's current reserve position represents its view of the earnings impact that could result from a settlement related to these transactions, although a total loss, consistent with the broad settlement offer previously proposed by the IRS, would result in an additional earnings charge of $120 million to $140 million.

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Income Taxes

9 Months Ended

Sep. 30, 2011

Income Taxes

Note 13. Income Taxes

PSEG's, Power's and PSE&G's effective tax rates for the three months and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
PSEG		43.1	%		40.4	%		42.0	%		40.3	%
Power		40.7	%		39.6	%		41.0	%		40.3	%
PSE&G		40.1	%		39.5	%		40.5	%		38.4	%

For the three months ended September 30, 2011, the increase in PSEG's effective tax rate was due primarily to Energy Holdings' 2011 charge against earnings applicable to the Dynegy leases. (See Note 5. Financing Receivables) and a lower manufacturer's deduction under the American Job Creation Act of 2004 as compared to the same period in 2010. There was no material change in the effective tax rate for Power and PSE&G.

For the nine months ended September 30, 2011, the increase in PSEG's effective tax rate was due primarily to Energy Holdings' 2011 charge against earnings applicable to the Dynegy leases and a lower manufacturer's deduction as compared to the same period in 2010. PSE&G's effective tax rate was lower in 2010, primarily due to tax benefits from uncollectible accounts and plant-related adjustments. There was no material change in the effective tax rate for Power.

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 include various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. As a result, in the first quarter of 2010, PSEG recorded noncash after-tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&G's income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.

Two other tax provisions enacted during 2010 will have a significant impact on PSEG's cash position. The Small Business Jobs Act of 2010, enacted in September 2010, extended the tax deduction for 50% bonus depreciation through 2010 for qualified property. The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, enacted in December 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 will be eligible for 50% bonus depreciation for tax purposes. These provisions will generate cash for PSEG through tax benefits related to the accelerated depreciation, most of which is anticipated to be realized in 2011. Also, for the third quarter of 2011, Power and PSE&G completed an analysis of industry specific tax accounting method changes resulting in current tax benefits. These tax benefits would have otherwise been received over the longer lives of the related depreciable property.

PSE&G has accrued $32 million of Investment Tax Credits (ITC) associated with alternative energy projects in the first nine months of 2011. Because the law provides an option to claim either a grant or the ITC, the ITC has been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense.

PSEG's unrecognized tax benefits increased by approximately $53 million in the first nine months of 2011, attributable to PSE&G. This increase is due to a position raised by the IRS during its examination of the tax years 2004 to 2006 and a position taken for tax years 2004 to 2011 related to casualty loss deductions. Since December 31, 2010, the balance of unrecognized tax benefits that are reasonably likely to increase or decrease within the next 12 months changed by $19 million related to the positions discussed above.

PSEG made tax deposits with the IRS to defray interest costs associated with disputed tax assessments associated with certain lease investments. The deposits are fully refundable and are recorded as a reduction to Current Accrued Taxes on PSEG's Condensed Consolidated Balance Sheets, but are not reflected in the unrecognized tax benefits.

As a result of a change in accounting method for the capitalization of indirect costs, PSEG reduced the net amount of its uncertain tax positions (including interest) by $97 million, approximately $43 million of which related to PSE&G. It is reasonably possible that PSE&G's claim related to this matter will be settled with the IRS in the next 12 months, resulting in an increase in the uncertain tax positions.

It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 8. Commitments and Contingent Liabilities, will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase by as much as $205 million or decrease by as much as $297 million. It is not possible to predict the magnitude, timing or direction of any such change.

Power [Member]

Income Taxes

Note 13. Income Taxes

PSEG's, Power's and PSE&G's effective tax rates for the three months and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
PSEG		43.1	%		40.4	%		42.0	%		40.3	%
Power		40.7	%		39.6	%		41.0	%		40.3	%
PSE&G		40.1	%		39.5	%		40.5	%		38.4	%

For the three months ended September 30, 2011, the increase in PSEG's effective tax rate was due primarily to Energy Holdings' 2011 charge against earnings applicable to the Dynegy leases. (See Note 5. Financing Receivables) and a lower manufacturer's deduction under the American Job Creation Act of 2004 as compared to the same period in 2010. There was no material change in the effective tax rate for Power and PSE&G.

For the nine months ended September 30, 2011, the increase in PSEG's effective tax rate was due primarily to Energy Holdings' 2011 charge against earnings applicable to the Dynegy leases and a lower manufacturer's deduction as compared to the same period in 2010. PSE&G's effective tax rate was lower in 2010, primarily due to tax benefits from uncollectible accounts and plant-related adjustments. There was no material change in the effective tax rate for Power.

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 include various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. As a result, in the first quarter of 2010, PSEG recorded noncash after-tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&G's income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.

Two other tax provisions enacted during 2010 will have a significant impact on PSEG's cash position. The Small Business Jobs Act of 2010, enacted in September 2010, extended the tax deduction for 50% bonus depreciation through 2010 for qualified property. The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, enacted in December 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 will be eligible for 50% bonus depreciation for tax purposes. These provisions will generate cash for PSEG through tax benefits related to the accelerated depreciation, most of which is anticipated to be realized in 2011. Also, for the third quarter of 2011, Power and PSE&G completed an analysis of industry specific tax accounting method changes resulting in current tax benefits. These tax benefits would have otherwise been received over the longer lives of the related depreciable property.

PSE&G has accrued $32 million of Investment Tax Credits (ITC) associated with alternative energy projects in the first nine months of 2011. Because the law provides an option to claim either a grant or the ITC, the ITC has been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense.

PSEG's unrecognized tax benefits increased by approximately $53 million in the first nine months of 2011, attributable to PSE&G. This increase is due to a position raised by the IRS during its examination of the tax years 2004 to 2006 and a position taken for tax years 2004 to 2009 related to casualty loss deductions. Since December 31, 2010, the balance of unrecognized tax benefits that are reasonably likely to increase or decrease within the next 12 months changed by $19 million related to the positions discussed above.

PSEG made tax deposits with the IRS to defray interest costs associated with disputed tax assessments associated with certain lease investments. The deposits are fully refundable and are recorded as a reduction to Current Accrued Taxes on PSEG's Condensed Consolidated Balance Sheets, but are not reflected in the unrecognized tax benefits.

As a result of a change in accounting method for the capitalization of indirect costs, PSEG reduced the net amount of its uncertain tax positions (including interest) by $97 million, approximately $43 million of which related to PSE&G. It is reasonably possible that PSE&G's claim related to this matter will be settled with the IRS in the next 12 months, resulting in an increase in the uncertain tax positions.

It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 8. Commitments and Contingent Liabilities, will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase by as much as $205 million or decrease by as much as $297 million. It is not possible to predict the magnitude, timing or direction of any such change.

PSE&G [Member]

Income Taxes

Note 13. Income Taxes

PSEG's, Power's and PSE&G's effective tax rates for the three months and nine months ended September 30, 2011 and 2010 were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
PSEG		43.1	%		40.4	%		42.0	%		40.3	%
Power		40.7	%		39.6	%		41.0	%		40.3	%
PSE&G		40.1	%		39.5	%		40.5	%		38.4	%

For the three months ended September 30, 2011, the increase in PSEG's effective tax rate was due primarily to Energy Holdings' 2011 charge against earnings applicable to the Dynegy leases. (See Note 5. Financing Receivables) and a lower manufacturer's deduction under the American Job Creation Act of 2004 as compared to the same period in 2010. There was no material change in the effective tax rate for Power and PSE&G.

For the nine months ended September 30, 2011, the increase in PSEG's effective tax rate was due primarily to Energy Holdings' 2011 charge against earnings applicable to the Dynegy leases and a lower manufacturer's deduction as compared to the same period in 2010. PSE&G's effective tax rate was lower in 2010, primarily due to tax benefits from uncollectible accounts and plant-related adjustments. There was no material change in the effective tax rate for Power.

The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 include various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. As a result, in the first quarter of 2010, PSEG recorded noncash after-tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&G's income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.

Two other tax provisions enacted during 2010 will have a significant impact on PSEG's cash position. The Small Business Jobs Act of 2010, enacted in September 2010, extended the tax deduction for 50% bonus depreciation through 2010 for qualified property. The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, enacted in December 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 will be eligible for 50% bonus depreciation for tax purposes. These provisions will generate cash for PSEG through tax benefits related to the accelerated depreciation, most of which is anticipated to be realized in 2011. Also, for the third quarter of 2011, Power and PSE&G completed an analysis of industry specific tax accounting method changes resulting in current tax benefits. These tax benefits would have otherwise been received over the longer lives of the related depreciable property.

PSE&G has accrued $32 million of Investment Tax Credits (ITC) associated with alternative energy projects in the first nine months of 2011. Because the law provides an option to claim either a grant or the ITC, the ITC has been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense.

PSEG's unrecognized tax benefits increased by approximately $53 million in the first nine months of 2011, attributable to PSE&G. This increase is due to a position raised by the IRS during its examination of the tax years 2004 to 2006 and a position taken for tax years 2004 to 2009 related to casualty loss deductions. Since December 31, 2010, the balance of unrecognized tax benefits that are reasonably likely to increase or decrease within the next 12 months changed by $19 million related to the positions discussed above.

PSEG made tax deposits with the IRS to defray interest costs associated with disputed tax assessments associated with certain lease investments. The deposits are fully refundable and are recorded as a reduction to Current Accrued Taxes on PSEG's Condensed Consolidated Balance Sheets, but are not reflected in the unrecognized tax benefits.

As a result of a change in accounting method for the capitalization of indirect costs, PSEG reduced the net amount of its uncertain tax positions (including interest) by $97 million, approximately $43 million of which related to PSE&G. It is reasonably possible that PSE&G's claim related to this matter will be settled with the IRS in the next 12 months, resulting in an increase in the uncertain tax positions.

It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 8. Commitments and Contingent Liabilities, will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase by as much as $205 million or decrease by as much as $297 million. It is not possible to predict the magnitude, timing or direction of any such change.

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Financial Risk Management Activities (Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Their Impact On Condensed Consolidated Statements Of Operations) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized on derivatives not designated as hedging instruments	$ 13	$ (6)	$ (28)	$ (5)
Operating Revenues [Member] | Energy-Related Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized on derivatives not designated as hedging instruments	24	(6)	(18)	3
Energy Costs [Member] | Energy-Related Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized on derivatives not designated as hedging instruments	$ (11)	$ 0	$ (10)	$ (8)

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Changes In Capitalization

9 Months Ended

Sep. 30, 2011

Changes In Capitalization

Note 9. Changes in Capitalization

The following capital transactions occurred in the first nine months of 2011:

Power

• issued $250 million of 2.75% Senior Notes due September 2016 in September,

• issued $250 million of 4.15% Senior Notes due September 2021 in September,

• paid $606 million of 7.75% Senior Notes at maturity in April, and

• paid cash dividends of $350 million to PSEG.

PSE&G

• issued $250 million of 0.85% Medium Term Notes due August 2014 in August, and

• paid $142 million of Transition Funding's securitization debt, and

• paid $5 million of Transition Funding II's securitization debt.

Energy Holdings

• paid $1 million of nonrecourse project debt.

PSE&G

In addition, $164 million of tax-exempt bonds of the Pollution Control Financing Authority of Salem County (Authority Bonds), which are serviced and secured by PSE&G's first mortgage bonds of like tenor, are subject to a mandatory put in November 2011. PSE&G intends to buy the Authority Bonds in on their mandatory put date. The Authority Bonds had an initial term rate of 0.95%.

Also, $100 million of tax-exempt bonds of the New Jersey Economic Development Authority (EDA Bonds), which are serviced and secured by PSE&G's first mortgage bonds of like tenor, are subject to a mandatory put in December 2011. PSE&G intends to buy the EDA Bonds in on their mandatory put date. The EDA Bonds had an initial term rate of 1.20%.

Power [Member]

Changes In Capitalization

Note 9. Changes in Capitalization

The following capital transactions occurred in the first nine months of 2011:

Power

• issued $250 million of 2.75% Senior Notes due September 2016 in September,

• issued $250 million of 4.15% Senior Notes due September 2021 in September,

• paid $606 million of 7.75% Senior Notes at maturity in April, and

• paid cash dividends of $350 million to PSEG.

PSE&G

• issued $250 million of 0.85% Medium Term Notes due August 2014 in August, and

• paid $142 million of Transition Funding's securitization debt, and

• paid $5 million of Transition Funding II's securitization debt.

Energy Holdings

• paid $1 million of nonrecourse project debt.

PSE&G

In addition, $164 million of tax-exempt bonds of the Pollution Control Financing Authority of Salem County (Authority Bonds), which are serviced and secured by PSE&G's first mortgage bonds of like tenor, are subject to a mandatory put in November 2011. PSE&G intends to buy the Authority Bonds in on their mandatory put date. The Authority Bonds had an initial term rate of 0.95%.

Also, $100 million of tax-exempt bonds of the New Jersey Economic Development Authority (EDA Bonds), which are serviced and secured by PSE&G's first mortgage bonds of like tenor, are subject to a mandatory put in December 2011. PSE&G intends to buy the EDA Bonds in on their mandatory put date. The EDA Bonds had an initial term rate of 1.20%.

PSE&G [Member]

Changes In Capitalization

Note 9. Changes in Capitalization

The following capital transactions occurred in the first nine months of 2011:

Power

• issued $250 million of 2.75% Senior Notes due September 2016 in September,

• issued $250 million of 4.15% Senior Notes due September 2021 in September,

• paid $606 million of 7.75% Senior Notes at maturity in April, and

• paid cash dividends of $350 million to PSEG.

PSE&G

• issued $250 million of 0.85% Medium Term Notes due August 2014 in August, and

• paid $142 million of Transition Funding's securitization debt, and

• paid $5 million of Transition Funding II's securitization debt.

Energy Holdings

• paid $1 million of nonrecourse project debt.

PSE&G

In addition, $164 million of tax-exempt bonds of the Pollution Control Financing Authority of Salem County (Authority Bonds), which are serviced and secured by PSE&G's first mortgage bonds of like tenor, are subject to a mandatory put in November 2011. PSE&G intends to buy the Authority Bonds in on their mandatory put date. The Authority Bonds had an initial term rate of 0.95%.

Also, $100 million of tax-exempt bonds of the New Jersey Economic Development Authority (EDA Bonds), which are serviced and secured by PSE&G's first mortgage bonds of like tenor, are subject to a mandatory put in December 2011. PSE&G intends to buy the EDA Bonds in on their mandatory put date. The EDA Bonds had an initial term rate of 1.20%.

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Financial Information By Business Segments (Financial Information By Business Segments) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010		Dec. 31, 2010
Segment Reporting Information [Line Items]
Net Income (Loss)	$ 294		$ 567		$ 1,143		$ 1,282
Total Assets	29,911				29,911				29,909
Power [Member]
Segment Reporting Information [Line Items]
Total Operating Revenues	1,398		1,523		4,650		4,983
Income (Loss) from Continuing Operations	273		364		775		937
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax	29		20		96		15
Net Income (Loss)	302		384		871		952
Preferred Securities Dividends							0
Segments Earnings (Loss)	302		384		871		952
Gross Additions to Long-Lived Assets	207		251		530		579
Total Assets	11,484				11,484				11,452
Investments in Equity Method Subsidiaries	30				30				25
PSE&G [Member]
Segment Reporting Information [Line Items]
Total Operating Revenues	1,841		2,007		5,718		5,987
Income (Loss) from Continuing Operations	154		155		422		276
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax	0		0		0		0
Net Income (Loss)	154		155		422		276
Preferred Securities Dividends							(1)
Segments Earnings (Loss)	154		155		422		275
Gross Additions to Long-Lived Assets	265		341		939		871
Total Assets	17,235				17,235				16,873
Investments in Equity Method Subsidiaries	0				0				0
Energy Holdings [Member]
Segment Reporting Information [Line Items]
Total Operating Revenues	(247)		58		(206)		114
Income (Loss) from Continuing Operations	(166)		24		(164)		43
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax	0		0		0		0
Net Income (Loss)	(166)		24		(164)		43
Preferred Securities Dividends							0
Segments Earnings (Loss)	(166)		24		(164)		43
Gross Additions to Long-Lived Assets	1		12		2		61
Total Assets	1,959				1,959				2,234
Investments in Equity Method Subsidiaries	113				113				105
PSEG Other [Member]
Segment Reporting Information [Line Items]
Total Operating Revenues	(372)	[1]	(474)	[1]	(1,719)	[1]	(2,036)	[1]
Income (Loss) from Continuing Operations	4	[1]	4	[1]	14	[1]	11	[1]
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax	0	[1]	0	[1]	0	[1]	0	[1]
Net Income (Loss)	4	[1]	4	[1]	14	[1]	11	[1]
Preferred Securities Dividends							1	[1]
Segments Earnings (Loss)	4	[1]	4	[1]	14	[1]	12	[1]
Gross Additions to Long-Lived Assets	4	[1]	2	[1]	8	[1]	6	[1]
Total Assets	(767)	[1]			(767)	[1]			(650)	[1]
Investments in Equity Method Subsidiaries	0	[1]			0	[1]			0	[1]
Consolidated [Member]
Segment Reporting Information [Line Items]
Total Operating Revenues	2,620		3,114		8,443		9,048
Income (Loss) from Continuing Operations	265		547		1,047		1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax	29		20		96		15
Net Income (Loss)	294		567		1,143		1,282
Preferred Securities Dividends							0
Segments Earnings (Loss)	294		567		1,143		1,282
Gross Additions to Long-Lived Assets	477		606		1,479		1,517
Total Assets	29,911				29,911				29,909
Investments in Equity Method Subsidiaries	$ 143				$ 143				$ 130

[1] 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 at cost 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 17. Related-Party Transactions.

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Comprehensive Income, Net Of Tax (Accumulated Other Comprehensive Income (Loss)) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010		Sep. 30, 2010		Dec. 31, 2009
Derivative Contracts	$ 31		$ 111	[1]	$ 178		$ 180	[1]
Pension and OPEB Plans	(324)		(377)	[1]	(381)		(400)	[1]
NDT Funds	32		109	[1]	91		91	[1]
Other	5		1	[1]	1		13	[1]
Accumulated Other Comprehensive Income (Loss)	(256)		(156)	[1]	(111)		(116)	[1]
Power [Member] | Accumulated Other Comprehensive Income (Loss) [Member]
Derivative Contracts	(80)	[2]			(2)	[2]
Pension and OPEB Plans	45	[2]			18	[2]
NDT Funds	(77)	[2]			0	[2]
Other	0	[2]			(3)	[2]
Accumulated Other Comprehensive Income (Loss)	(112)	[2]			13	[2]
Power [Member]
Accumulated Other Comprehensive Income (Loss)	(207)		(95)
Accumulated other comprehensive income loss derivative contracts net of tax	54				1
Accumulated other comprehensive income loss pension and other postretirement plans net of tax	(31)				(12)
Accumulated other comprehensive income loss other net of tax	78				1
PSE&G [Member]
Derivative Contracts	0	[3]			0	[3]
Pension and OPEB Plans	0	[3]			0	[3]
NDT Funds	0	[3]			0	[3]
Other	2	[3]			(5)	[3]
Accumulated Other Comprehensive Income (Loss)	2	[3]	0		(5)	[3]
Accumulated other comprehensive income loss other net of tax	(1)				3
Other [Member]
Derivative Contracts	0				0
Pension and OPEB Plans	8				1
NDT Funds	0				0
Other	2				(4)
Accumulated Other Comprehensive Income (Loss)	10				(3)
Accumulated other comprehensive income loss other net of tax	$ (7)				$ 2

[1] Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $54 million, $(31) million and $78 million, respectively for the nine months ended September 30, 2011. Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $1 million, $(12) million and $1 million, respectively for the nine months ended September 30, 2010.

[2] Net of tax of $(1) million for the nine months ended September 30, 2011 and $3 million for the nine months ended September 30, 2010.

[3] Net of tax of $(7) million for the nine months ended September 30, 2011 and $2 million for the nine months ended September 30, 2010.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Fair Value Measurements [Abstract]

PSEG's, Power's And PSE&G's Respective Assets And (Liabilities) Measured At Fair Value On A Recurring Basis

	Recurring Fair Value Measurements as of September 30, 2011
Description	Total			Cash Collateral Netting (E)			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)	$	119		$	(10	)	$	0	$	99		$	30
Interest Rate Swaps (B)	$	69		$	0		$	0	$	69		$	0
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	170		$	0		$	17	$	153		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(122	)	$	0		$	0	$	(88	)	$	(34	)
Interest Rate Swaps (B)	$	(3	)	$	0		$	0	$	(3	)	$	0
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	119		$	(10	)	$	0	$	99		$	30
NDT Funds: (C)
Equity Securities	$	575		$	0		$	575	$	0		$	0
Debt Securities—Govt Obligations	$	355		$	0		$	0	$	355		$	0
Debt Securities—Other	$	284		$	0		$	0	$	284		$	0
Other Securities	$	66		$	0		$	1	$	65		$	0
Rabbi Trusts—Mutual Funds (C)	$	33		$	0		$	3	$	30		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(96	)	$	0		$	0	$	(88	)	$	(8	)
PSE&G
Assets:
Rabbi Trust—Mutual Funds (C)	$	57		$	0		$	6	$	51		$	0
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(26	)	$	0		$	0	$	0		$	(26	)

	Recurring Fair Value Measurements as of December 31, 2010
Description	Total			Cash Collateral Netting (E)			Quoted Market Prices of Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	222		$	(135	)	$	0	$	228		$	129
Interest Rate Swaps (B)	$	39		$	0		$	0	$	39		$	0
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	160		$	0		$	18	$	142		$	0
Other Long-Term Investments (D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(125	)	$	74		$	0	$	(117	)	$	(82	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	205		$	(135	)	$	0	$	228		$	112
NDT Funds: (C)
Equity Securities	$	735		$	0		$	735	$	0		$	0
Debt Securities-Govt Obligations	$	303		$	0		$	0	$	303		$	0
Debt Securities-Other	$	255		$	0		$	0	$	255		$	0
Other Securities	$	70		$	0		$	0	$	62		$	8
Rabbi Trusts—Mutual Funds (C)	$	32		$	0		$	4	$	28		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(113	)	$	74		$	0	$	(117	)	$	(70	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	17		$	0		$	0	$	0		$	17
Rabbi Trusts—Mutual Funds (C)	$	54		$	0		$	6	$	48		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(12	)	$	0		$	0	$	0		$	(12	)

(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.   Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.

(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) Power's NDT funds maintain investments in various equity and fixed income securities classified as "available for sale." These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the NDT funds 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).   Power's NDT investments in fixed income securities are primarily with investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities (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).   The Rabbi Trust mutual funds are mainly invested in a United States bond index fund, an S&P 500 index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

(D) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices.

(E) 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.

A Reconciliation Of The Beginning And Ending Balances Of Level 3 Derivative Contracts And Securities

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

for the Three Months Ended September 30, 2011

				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1,    2011			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)		Transfers In (Out)		Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(3	)	$	13	$	(27	)	$	10	$	3	$	0	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	(4	)	$	13	$	0		$	10	$	3	$	0	$	22
PSE&G
Net Derivative Assets (Liabilities)	$	1		$	0	$	(27	)	$	0	$	0	$	0	$	(26	)

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

for the Nine Months Ended September 30, 2011

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2011		Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		(Issuances) Settlements (D)			Transfers In (Out)			Balance as of September 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	47	$	(27	)	$	(31	)	$	29	$	(22	)	$	0		$	(4	)
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
Power
Net Derivative Assets	$	42	$	(27	)	$	0		$	29	$	(22	)	$	0		$	22
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
PSE&G
Net Derivative Assets (Liabilities)	$	5	$	0		$	(31	)	$	0	$	0		$	0		$	(26	)

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, 2010 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2010		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	168	$	33	$	(11	)	$	(2	)	$	188
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	16	$	0	$	0		$	(16	)	$	0
Power
Net Derivative Assets	$	117	$	33	$	0		$	(2	)	$	148
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	3	$	0	$	0		$	(3	)	$	0
PSE&G
Net Derivative Assets	$	51	$	0	$	(11	)	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0		$	(5	)	$	0

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

for the Nine Months Ended September 30, 2010

			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2010		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)		Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	105	$	61	$	34	$	(12	)	$	188
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	14	$	0	$	0	$	(14	)	$	0
Power
Net Derivative Assets	$	99	$	61	$	0	$	(12	)	$	148
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	3	$	0	$	0	$	(3	)	$	0
PSE&G
Net Derivative Assets	$	6	$	0	$	34	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0	$	(5	)	$	0

(A) PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $12 million and $17 million are included in Operating Income, $1 million and $14 million are included in OCI, and less than $1 million and $2 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $12 million in Operating Income in 2011, $31 million is unrealized and $(19) million is realized. Of the $17 million in Operating Income in 2010, $32 million is unrealized and $(15) million is realized.

(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 $10 million in purchases for the three months ended September 30, 2011. Includes $65 million in purchases and $(36) million in sales for the nine months ended September 30, 2011.

(D) Includes $(5) million in issuances and $8 million in settlements for the three months ended September 30, 2011. Includes $(25) million in issuances and $3 million in settlements for the nine months ended September 30, 2011.

(E) PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(28) million and $8 million are included in Operating Income, $(2) million and $28 million are included in OCI, and $3 million and $25 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $(28) million in Operating Income in 2011, $(25) million is unrealized and $(3) million is realized. Of the $8 million in Operating Income in 2010, $9 million is unrealized and $(1) million is realized.

Fair Value Of Debt

	September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value (A)		Carrying Amount		Fair Value (A)
	Millions
Long-Term Debt:
PSEG (Parent)	$	40	$	66	$	10	$	39
Power -Recourse Debt		3,350		3,710		3,455		3,831
PSE&G		4,535		5,099		4,283		4,615
Transition Funding (PSE&G)		948		1,080		1,090		1,245
Transition Funding II (PSE&G)		50		54		55		59
Energy Holdings:
Project Level, Non-Recourse Debt		46		46		47		47
Total Long-Term Debt	$	8,969	$	10,055	$	8,940	$	9,836

(A) Fair value excludes unamortized discounts, including amounts related to the Debt Exchange between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company.

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Pension And OPEB

9 Months Ended

Sep. 30, 2011

Pension And OPEB

Note 7. Pension and 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. In early June 2011, PSEG amended certain provisions of its pension and OPEB plans, including revisions to the benefit formulas for certain participants of PSEG's qualified and nonqualified pension and OPEB plans. The weighted average discount rate for the pension plans decreased from 5.51% to 5.31% while the discount rate for the OPEB plans decreased from 5.50% to 5.30%. The expected long-term rate of return on plan assets remained at 8.50%. The pension benefit and OPEB obligations, as well as the asset values, were re-measured as of May 31, 2011 (the closest month-end date to the time the revisions were made). As a result, the annual net periodic pension benefit cost for 2011 will decrease by $32 million and the 2011 annual net OPEB cost will decrease by $6 million compared to costs that would have been expensed in 2011 if PSEG did not re-measure. The re-measured pension projected benefit obligations and accumulated OPEB obligation as of May 31, 2011 were $4.3 billion and $1.2 billion, respectively. The year-to-date rate of return on plan assets through the May 31 remeasurement date was 6.70%.

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. The costs for January through May 2011 are calculated under the prior plans' assumptions. The costs for June 2011 and subsequent months are being calculated under the revised plan provisions. OPEB costs are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. New federal health care legislation enacted in March 2010 eliminates the tax deductibility of retiree health care costs beginning in 2013, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. See Note 13. Income Taxes for additional information.

Pension and OPEB costs for PSEG are detailed as follows:

	Pension Benefits Three Months Ended September 30,						OPEB Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	22		$	21		$	3		$	4		$	69		$	65		$	10		$	12
Interest Cost		56			58			15			18			172			173			45			54
Expected Return on Plan Assets		(85	)		(67	)		(5	)		(4	)		(248	)		(200	)		(13	)		(11	)
Amortization of Net
Transition Obligation		0			0			1			6			0			0			4			20
Prior Service Cost (Credit)		(4	)		0			(4	)		4			(6	)		0			(10	)		10
Actuarial Loss		29			31			4			2			89			92			11			6
Net Periodic Benefit Cost		18			43			14			30			76			130			47			91
Effect of Regulatory Asset		0			0			5			5			0			0			15			15
Total Benefit Costs, Including Effect of Regulatory Asset	$	18		$	43		$	19		$	35		$	76		$	130		$	62		$	106

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

	Pension Benefits Three Months Ended September 30,				OPEB Three Months Ended September 30,				Pension Benefits Nine Months Ended September 30,				OPEB Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
	Millions
Power	$	6	$	13	$	3	$	4	$	24	$	40	$	9	$	13
PSE&G		9		24		16		30		41		72		51		90
Other		3		6		0		1		11		18		2		3
Total Benefit Costs	$	18	$	43	$	19	$	35	$	76	$	130	$	62	$	106

During the three months ended March 31, 2011, PSEG contributed its entire planned contributions for the year 2011 of $415 million and $11 million into its pension and postretirement healthcare plans, respectively.

Power [Member]

Pension And OPEB

Note 7. Pension and 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. In early June 2011, PSEG amended certain provisions of its pension and OPEB plans, including revisions to the benefit formulas for certain participants of PSEG's qualified and nonqualified pension and OPEB plans. The weighted average discount rate for the pension plans decreased from 5.51% to 5.31% while the discount rate for the OPEB plans decreased from 5.50% to 5.30%. The expected long-term rate of return on plan assets remained at 8.50%. The pension benefit and OPEB obligations, as well as the asset values, were re-measured as of May 31, 2011 (the closest month-end date to the time the revisions were made). As a result, the annual net periodic pension benefit cost for 2011 will decrease by $32 million and the 2011 annual net OPEB cost will decrease by $6 million compared to costs that would have been expensed in 2011 if PSEG did not re-measure. The re-measured pension projected benefit obligations and accumulated OPEB obligation as of May 31, 2011 were $4.3 billion and $1.2 billion, respectively. The year-to-date rate of return on plan assets through the May 31 remeasurement date was 6.70%.

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. The costs for January through May 2011 are calculated under the prior plans' assumptions. The costs for June 2011 and subsequent months are being calculated under the revised plan provisions. OPEB costs are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. New federal health care legislation enacted in March 2010 eliminates the tax deductibility of retiree health care costs beginning in 2013, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. See Note 13. Income Taxes for additional information.

Pension and OPEB costs for PSEG are detailed as follows:

	Pension Benefits Three Months Ended September 30,						OPEB Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	22		$	21		$	3		$	4		$	69		$	65		$	10		$	12
Interest Cost		56			58			15			18			172			173			45			54
Expected Return on Plan Assets		(85	)		(67	)		(5	)		(4	)		(248	)		(200	)		(13	)		(11	)
Amortization of Net
Transition Obligation		0			0			1			6			0			0			4			20
Prior Service Cost (Credit)		(4	)		0			(4	)		4			(6	)		0			(10	)		10
Actuarial Loss		29			31			4			2			89			92			11			6
Net Periodic Benefit Cost		18			43			14			30			76			130			47			91
Effect of Regulatory Asset		0			0			5			5			0			0			15			15
Total Benefit Costs, Including Effect of Regulatory Asset	$	18		$	43		$	19		$	35		$	76		$	130		$	62		$	106

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

	Pension Benefits Three Months Ended September 30,				OPEB Three Months Ended September 30,				Pension Benefits Nine Months Ended September 30,				OPEB Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
	Millions
Power	$	6	$	13	$	3	$	4	$	24	$	40	$	9	$	13
PSE&G		9		24		16		30		41		72		51		90
Other		3		6		0		1		11		18		2		3
Total Benefit Costs	$	18	$	43	$	19	$	35	$	76	$	130	$	62	$	106

During the three months ended March 31, 2011, PSEG contributed its entire planned contributions for the year 2011 of $415 million and $11 million into its pension and postretirement healthcare plans, respectively.

PSE&G [Member]

Pension And OPEB

Note 7. Pension and 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. In early June 2011, PSEG amended certain provisions of its pension and OPEB plans, including revisions to the benefit formulas for certain participants of PSEG's qualified and nonqualified pension and OPEB plans. The weighted average discount rate for the pension plans decreased from 5.51% to 5.31% while the discount rate for the OPEB plans decreased from 5.50% to 5.30%. The expected long-term rate of return on plan assets remained at 8.50%. The pension benefit and OPEB obligations, as well as the asset values, were re-measured as of May 31, 2011 (the closest month-end date to the time the revisions were made). As a result, the annual net periodic pension benefit cost for 2011 will decrease by $32 million and the 2011 annual net OPEB cost will decrease by $6 million compared to costs that would have been expensed in 2011 if PSEG did not re-measure. The re-measured pension projected benefit obligations and accumulated OPEB obligation as of May 31, 2011 were $4.3 billion and $1.2 billion, respectively. The year-to-date rate of return on plan assets through the May 31 remeasurement date was 6.70%.

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. The costs for January through May 2011 are calculated under the prior plans' assumptions. The costs for June 2011 and subsequent months are being calculated under the revised plan provisions. OPEB costs are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. New federal health care legislation enacted in March 2010 eliminates the tax deductibility of retiree health care costs beginning in 2013, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. See Note 13. Income Taxes for additional information.

Pension and OPEB costs for PSEG are detailed as follows:

	Pension Benefits Three Months Ended September 30,						OPEB Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	22		$	21		$	3		$	4		$	69		$	65		$	10		$	12
Interest Cost		56			58			15			18			172			173			45			54
Expected Return on Plan Assets		(85	)		(67	)		(5	)		(4	)		(248	)		(200	)		(13	)		(11	)
Amortization of Net
Transition Obligation		0			0			1			6			0			0			4			20
Prior Service Cost (Credit)		(4	)		0			(4	)		4			(6	)		0			(10	)		10
Actuarial Loss		29			31			4			2			89			92			11			6
Net Periodic Benefit Cost		18			43			14			30			76			130			47			91
Effect of Regulatory Asset		0			0			5			5			0			0			15			15
Total Benefit Costs, Including Effect of Regulatory Asset	$	18		$	43		$	19		$	35		$	76		$	130		$	62		$	106

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

	Pension Benefits Three Months Ended September 30,				OPEB Three Months Ended September 30,				Pension Benefits Nine Months Ended September 30,				OPEB Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
	Millions
Power	$	6	$	13	$	3	$	4	$	24	$	40	$	9	$	13
PSE&G		9		24		16		30		41		72		51		90
Other		3		6		0		1		11		18		2		3
Total Benefit Costs	$	18	$	43	$	19	$	35	$	76	$	130	$	62	$	106

During the three months ended March 31, 2011, PSEG contributed its entire planned contributions for the year 2011 of $415 million and $11 million into its pension and postretirement healthcare plans, respectively.

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Available-For-Sale Securities (Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Unrealized Loss Position Greater Than 12 Months [Member] | Total Available-For-Sale Securities Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	$ 8		$ 9
Gross Unrealized Losses	(1)		(1)
Unrealized Loss Position Greater Than 12 Months [Member] | Debt Securities Total [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	8		9
Gross Unrealized Losses	(1)		(1)
Unrealized Loss Position Greater Than 12 Months [Member] | Other Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	6	[1]	8	[1]
Gross Unrealized Losses	(1)	[1]	(1)	[1]
Unrealized Loss Position Greater Than 12 Months [Member] | US States And Political Subdivisions Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	2	[2]	1	[2]
Gross Unrealized Losses	0	[2]	0	[2]
Unrealized Loss Position Greater Than 12 Months [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	0	[3]	0	[3]
Gross Unrealized Losses	0	[3]	0	[3]
Unrealized Loss Position Greater Than 12 Months [Member] | Other Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	0		0
Gross Unrealized Losses	0		0
Unrealized Loss Position Less Than 12 Months [Member] | Total Available-For-Sale Securities Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	390		226
Gross Unrealized Losses	(58)		(8)
Unrealized Loss Position Less Than 12 Months [Member] | Debt Securities Total [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	137		171
Gross Unrealized Losses	(3)		(5)
Unrealized Loss Position Less Than 12 Months [Member] | Other Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	65	[1]	65	[1]
Gross Unrealized Losses	(2)	[1]	(1)	[1]
Unrealized Loss Position Less Than 12 Months [Member] | US States And Political Subdivisions Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	72	[2]	106	[2]
Gross Unrealized Losses	(1)	[2]	(4)	[2]
Unrealized Loss Position Less Than 12 Months [Member] | Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	252	[3]	55	[3]
Gross Unrealized Losses	(55)	[3]	(3)	[3]
Unrealized Loss Position Less Than 12 Months [Member] | Other Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	1		0
Gross Unrealized Losses	0		0
Total Available-For-Sale Securities Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	170		160
Gross Unrealized Losses	0		0
Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	152		142
Gross Unrealized Losses	0		0
Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Estimated Fair Value	18		18
Gross Unrealized Losses	$ 0		$ 0

[1] Debt Securities (Corporate)—Power's investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2011.

[2] Debt Securities (Government)—Unrealized losses on Power's NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

[3] Equity Securities—Investments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

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Condensed Consolidated Statements Of Cash Flows (USD $) In Millions	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$ 1,143	$ 1,282
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations	(122)	0
Depreciation and Amortization	745	730
Amortization of Nuclear Fuel	114	102
Provision for Deferred Income Taxes (Other than Leases) and ITC	629	205
Non-Cash Employee Benefit Plan Costs	138	236
Net (Gain) Loss on Lease Investments	0	(51)
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(16)	(391)
Leveraged Lease Reserve, net of tax	170	0
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(14)	(42)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs	100	35
Over (Under) Recovery of Societal Benefits Charge (SBC)	(26)	(55)
Market Transition Charge Refund	(47)	98
Cost of Removal	(43)	(47)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds	(110)	(73)
Realized Gains from Rabbi Trusts	(5)	(31)
Net Change in Tax Receivable	312	0
Net Change in Certain Current Assets and Liabilities	(44)	(237)
Net Change in Certain Current Assets and Liabilities:
Employee Benefit Plan Funding and Related Payments	(486)	(483)
Other	(29)	61
Net Cash Provided By (Used In) Operating Activities	2,409	1,339
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,479)	(1,517)
Proceeds from Sale of Discontinued Operations	687	0
Proceeds from the Sale of Capital Leases and Investments	0	427
Proceeds from Sales of Available-for-Sale Securities	1,088	886
Investments in Available-for-Sale Securities	(1,110)	(905)
Other	(13)	13
Net Cash Provided By (Used In) Investing Activities	(827)	(1,096)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(64)	(530)
Issuance of Long-Term Debt	750	1,608
Redemption of Long-Term Debt	(606)	(548)
Repayment of Non-Recourse Debt	(1)	(3)
Redemption of Securitization Debt	(147)	(140)
Cash Dividends Paid on Common Stock	(520)	(520)
Redemption of Preferred Securities	0	(80)
Other	(32)	(48)
Net Cash Provided By (Used In) Financing Activities	(620)	(261)
Net Increase (Decrease) in Cash and Cash Equivalents	962	(18)
Cash and Cash Equivalents at Beginning of Period	280	350
Cash and Cash Equivalents at End of Period	1,242	332
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	60	1,080
Interest Paid, Net of Amounts Capitalized	341	299
Power [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	871	952
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations	(122)	0
Depreciation and Amortization	173	144
Amortization of Nuclear Fuel	114	102
Provision for Deferred Income Taxes (Other than Leases) and ITC	74	145
Non-Cash Employee Benefit Plan Costs	33	53
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(14)	(42)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds	(110)	(73)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	(82)	(2)
Margin Deposit	(63)	(26)
Accounts Receivable	157	16
Accounts Payable	(103)	(99)
Accounts Receivable/Payable-Affiliated Companies, net	650	186
Accrued Interest Payable	23	41
Other Current Assets and Liabilities	48	(42)
Employee Benefit Plan Funding and Related Payments	(127)	(131)
Other	(35)	32
Net Cash Provided By (Used In) Operating Activities	1,487	1,256
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(530)	(579)
Proceeds from Sale of Discontinued Operations	687	0
Proceeds from Sales of Available-for-Sale Securities	1,088	759
Investments in Available-for-Sale Securities	(1,106)	(778)
Short-Term Loan - Affiliated Company, net	(1,176)	(309)
Other	19	28
Net Cash Provided By (Used In) Investing Activities	(1,018)	(879)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	500	594
Redemption of Long-Term Debt	(606)	(248)
Cash Dividends Paid on Common Stock	(350)	(550)
Short-Term Loan - Affiliated Company, net	0	(194)
Other	(10)	(17)
Net Cash Provided By (Used In) Financing Activities	(466)	(415)
Net Increase (Decrease) in Cash and Cash Equivalents	3	(38)
Cash and Cash Equivalents at Beginning of Period	11	64
Cash and Cash Equivalents at End of Period	14	26
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	110	558
Interest Paid, Net of Amounts Capitalized	111	85
PSE&G [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	422	276
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	548	563
Provision for Deferred Income Taxes (Other than Leases) and ITC	563	41
Non-Cash Employee Benefit Plan Costs	92	162
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs	100	35
Over (Under) Recovery of Societal Benefits Charge (SBC)	(26)	(55)
Market Transition Charge Refund	(47)	98
Cost of Removal	(43)	(47)
Net Change in Tax Receivable	(21)	0
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	261	117
Fuel, Materials and Supplies	(1)	(17)
Prepayments	(203)	(126)
Accounts Receivable/Payable-Affiliated Companies, net	(381)	(318)
Other Current Assets and Liabilities	(66)	19
Employee Benefit Plan Funding and Related Payments	(311)	(305)
Other	(15)	(16)
Net Cash Provided By (Used In) Operating Activities	872	427
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(939)	(871)
Solar Loan Investments	(34)	(11)
Proceeds from Sales of Available-for-Sale Securities	0	54
Investments in Available-for-Sale Securities	0	(54)
Other	(1)	(4)
Net Cash Provided By (Used In) Investing Activities	(974)	(886)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	250	1,014
Redemption of Long-Term Debt	0	(300)
Redemption of Securitization Debt	(147)	(140)
Cash Dividends Paid on Common Stock	0	(150)
Redemption of Preferred Securities	0	(80)
Other	(4)	(10)
Net Cash Provided By (Used In) Financing Activities	99	334
Net Increase (Decrease) in Cash and Cash Equivalents	(3)	(125)
Cash and Cash Equivalents at Beginning of Period	245	240
Cash and Cash Equivalents at End of Period	242	115
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	(44)	182
Interest Paid, Net of Amounts Capitalized	$ 225	$ 213

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Income Taxes (Schedule Of Effective Tax Rates) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
PSEG (Parent) [Member]
Effective tax rate	43.10%	40.40%	42.00%	40.30%
Power [Member]
Effective tax rate	40.70%	39.60%	41.00%	40.30%
PSE&G [Member]
Effective tax rate	40.10%	39.50%	40.50%	38.40%

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Variable Interest Entities

9 Months Ended

Sep. 30, 2011

Variable Interest Entities

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, 2011 and December 31, 2010. 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 2011 or in 2010. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.

PSE&G [Member]

Variable Interest Entities

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, 2011 and December 31, 2010. 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 2011 or in 2010. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.

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Discontinued Operations And Dispositions (Narrative) (Details) (Power [Member], USD $) In Millions, unless otherwise specified	1 Months Ended
	Jul. 31, 2011	Mar. 31, 2011
Power [Member]
Sale of gas fired generation facilities	1,000	1,000
Aggregate amount for plant sale	$ 335	$ 352
Gain on disposal of discontinued operations	$ 25	$ 54

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Financial Risk Management Activities (Tables)

9 Months Ended

Sep. 30, 2011

Financial Risk Management Activities [Abstract]

Schedule Of Derivative Transactions Designated And Effective As Cash Flow Hedges

	As of September 30, 2011		As of December 31, 2010
	Millions
Fair Value of Cash Flow Hedges	$	79	$	196
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	34	$	114

Schedule Of Derivative Instruments Fair Value In Balance Sheet

	As of September 30, 2011
	Power												PSE&G			PSEG			Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	76		$	232		$	(213	)	$	95		$	0		$	18		$	113
Noncurrent Assets		7			44			(27	)		24			0			51			75
Total Mark-to-Market Derivative Assets	$	83		$	276		$	(240	)	$	119		$	0		$	69		$	188
Derivative Contracts
Current Liabilities	$	(2	)	$	(281	)	$	204		$	(79	)	$	(15	)	$	0		$	(94	)
Noncurrent Liabilities		(2	)		(41	)		26			(17	)		(11	)		(3	)		(31	)
Total Mark-to-Market Derivative (Liabilities)	$	(4	)	$	(322	)	$	230		$	(96	)	$	(26	)	$	(3	)	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	79		$	(46	)	$	(10	)	$	23		$	(26	)	$	66		$	63

	As of December 31, 2010
	Power												PSE&G			PSEG		Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			FairValue Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	204		$	403		$	(444	)	$	163		$	0		$	19	$	182
Noncurrent Assets		3			80			(41	)		42			17			20		79
Total Mark-to-Market Derivative Assets	$	207		$	483		$	(485	)	$	205		$	17		$	39	$	261
Derivative Contracts
Current Liabilities	$	(11	)	$	(454	)	$	374		$	(91	)	$	(12	)	$	0	$	(103	)
Noncurrent Liabilities		0			(72	)		50			(22	)		0			0		(22	)
Total Mark-to-Market Derivative (Liabilities)	$	(11	)	$	(526	)	$	424		$	(113	)	$	(12	)	$	0	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	196		$	(43	)	$	(61	)	$	92		$	5		$	39	$	136

(A) Represents the netting of fair value balances with the same counterparty and the application of collateral. As of September 30, 2011 and December 31, 2010, net cash collateral received of $10 million and $61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $10 million as of September 30, 2011, cash collateral of $(9) million and $(1) million were netted against current assets and noncurrent assets, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively.

Schedule Of Derivative Instruments Designated As Cash Flow Hedges

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 September 30,					Three Months Ended September 30,					Three Months Ended September 30,
	2011		2010			2011		2010			2011		2010
	Millions
PSEG
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Interest Rate Swaps		0		0	Interest Expense		0		0			0		0
Total PSEG	$	21	$	62		$	60	$	60		$	0	$	0
Power
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Total Power	$	21	$	62		$	60	$	60		$	0	$	0

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, 2011 and 2010:

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 September 30,					Nine Months Ended September 30,							Nine Months Ended September 30,
	2011		2010			2011			2010				2011		2010
	Millions
PSEG (A)
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Interest Rate Swaps		0		0	Interest Expense		(1	)		(1	)			0		0
Total PSEG	$	19	$	172		$	153		$	175			$	1	$	(3	)
Power
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Total Power	$	19	$	172		$	154		$	176			$	1	$	(3	)

(A) Includes amounts for PSEG parent.

Schedule Of Reconciliation For Derivative Activity Included In Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Income	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2010	$	188		$	111
Loss Recognized in AOCI (Effective Portion)		(2	)		(1	)
Less: Gain Reclassified into Income (Effective Portion)		(93	)		(56	)
Balance as of June 30, 2011	$	93		$	54
Gain Recognized in AOCI (Effective Portion)		21			12
Less: Gain Reclassified into Income (Effective Portion)		(60	)		(35	)
Balance as of September 30, 2011	$	54		$	31

Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Impact On Results Of Operations

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 September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
		Millions						Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	24		$	(6	)	$	(18	)	$	3
Energy-Related Contracts	Energy Costs		(11	)		0			(10	)		(8	)
Total PSEG and Power		$	13		$	(6	)	$	(28	)	$	(5	)

Schedule Of Gross Volume On Absolute Value Basis For Derivative Contracts

Type	Notional	Total		PSEG		Power		PSE&G
	Millions
As of September 30, 2011
Natural Gas	Dth		593		0		350		243
Electricity	MWh		145		0		145		0
Financial Transmission Rights (FTRs)	MWh		20		0		20		0
Interest Rate Swaps	US Dollars		1,400		1,400		0		0
As of December 31, 2010
Natural Gas	Dth		704		0		424		280
Electricity	MWh		154		0		154		0
Capacity	MW days		1		0		1		0
FTRs	MWh		23		0		23		0
Interest Rate Swaps	US Dollars		1,150		1,150		0		0

Schedule Providing Credit Risk From Others, Net Of Collateral

Rating	Current Exposure		Securities held as Collateral		Net Exposure		Number of Counterparties         >10%		Net Exposure of Counterparties         >10%
			Millions						Millions
Investment Grade—External Rating	$	396	$	46	$	392		3	$	242	(A)
Non-Investment Grade—External Rating		11		0		11		0		0
Investment Grade—No External Rating		9		0		9		0		0
Non-Investment Grade—No External Rating		9		0		9		0		0
Total Credit Risk	$	425	$	46	$	421		3	$	242

(A) Includes net exposure of $129 million with PSE&G. The remaining net exposure of $113 million is with two nonaffiliated power purchasers which are regulated investment grade counterparties.

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Pension And OPEB (Schedule Of Components Of Net Periodic Benefit Cost) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 22	$ 21	$ 69	$ 65
Interest Cost	56	58	172	173
Expected Return on Plan Assets	(85)	(67)	(248)	(200)
Amortization of Net Transition Obligation	0	0	0	0
Amortization of Net Prior Service Cost (Credit)	(4)	0	(6)	0
Amortization of Net Actuarial Loss	29	31	89	92
Net Periodic Benefit Cost	18	43	76	130
Effect of Regulatory Asset	0	0	0	0
Total Benefit Costs, Including Effect of Regulatory Asset	18	43	76	130
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	3	4	10	12
Interest Cost	15	18	45	54
Expected Return on Plan Assets	(5)	(4)	(13)	(11)
Amortization of Net Transition Obligation	1	6	4	20
Amortization of Net Prior Service Cost (Credit)	(4)	4	(10)	10
Amortization of Net Actuarial Loss	4	2	11	6
Net Periodic Benefit Cost	14	30	47	91
Effect of Regulatory Asset	5	5	15	15
Total Benefit Costs, Including Effect of Regulatory Asset	$ 19	$ 35	$ 62	$ 106

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Commitments And Contingent Liabilities (Face Value Of Outstanding Guarantees, Current Exposure and Margin Positions) (Details) (USD $) In Millions, unless otherwise specified			1 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Apr. 30, 2011 Power [Member]	Apr. 30, 2011 PSEG And Power [Member]
Face Value of Outstanding Guarantees	$ 1,758	$ 1,936
Exposure under Current Guarantees	283	330
Letters of Credit Margin Posted	135	137
Letters of Credit Margin Received	53	109
Counterparty Cash Margin Deposited	1	0
Counterparty Cash Margin Received	(5)	(2)
Net Broker Balance Deposited (Received)	37	(28)
Additional collateral that could be Required if Power Loses Investment Grade Rating	765	828
Liquidity Available under PSEG's and Power's Credit Facilities to Post Collateral	3,466	2,750
Additional Amounts Posted Other Letters of Credit	99	98
Increase total credit capacity, due to credit agreements			$ 650
Length of time for credit agreement, years				5

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Available-For-Sale Securities (Accounts Receivable And Accounts Payable To NDT Fund) (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Schedule of Available-for-sale Securities [Line Items]
Accounts Receivable	$ 1,164	$ 1,387
Accounts Payable	1,144	1,176
Nuclear Decommissioning Trust (NDT) Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Accounts Receivable	100	35
Accounts Payable	$ 95	$ 60

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Commitments And Contingent Liabilities (Minimum Fuel Purchase Requirements) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	$ 896
Power [Member] | Commitments Through 2015 [Member] | Nuclear Fuel Uranium [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	493
Power [Member] | Commitments Through 2015 [Member] | Nuclear Fuel Enrichment [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	383
Power [Member] | Commitments Through 2015 [Member] | Nuclear Fuel Fabrication [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	130
Power [Member] | Commitments Through 2015 [Member] | Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	903
Power [Member] | Commitments Through 2015 [Member] | Coal/Oil [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	896
Power [Member]
Long-term Purchase Commitment [Line Items]
Coverage percentage of nuclear fuel commitments of uranium, enrichment, and fabrication requirements	100.00%
Amount of coal / oil commitments Power can cancel at no cost	$ 647

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Discontinued Operations And Dispositions

9 Months Ended

Sep. 30, 2011

Discontinued Operations And Dispositions

Note 4. Discontinued Operations and Dispositions

Discontinued Operations

Power

In March 2011, Power completed the sale of its 1,000 MW gas-fired Guadalupe generating facility for a total purchase price of $352 million, resulting in an after-tax gain of $54 million.

In July 2011, Power completed the sale of its 1,000 MW gas-fired Odessa generating facility for a total purchase price of $335 million, resulting in an after-tax gain of $25 million. The closing of the Odessa sale completed the Texas asset sale process announced by Power in early 2011.

PSEG Texas' operating results for the three months and nine months ended September 30, 2011 and 2010, which were reclassified to Discontinued Operations, are summarized below:

	Three Months Ended, September 30,				Nine Months Ended, September 30,
	2011		2010		2011		2010
	Millions
Operating Revenues	$	20	$	140	$	112	$	341
Income (Loss ) Before Income Taxes	$	6	$	31	$	26	$	25
Net Income (Loss)	$	4	$	20	$	17	$	15

The carrying amounts of PSEG Texas' assets and liabilities as of December 31, 2010 are summarized in the following table:

	As of December 31,
	2010
	Millions
Current Assets	$	28
Noncurrent Assets		536
Total Assets of Discontinued Operations	$	564
Current Liabilities	$	28
Noncurrent Liabilities		44
Total Liabilities of Discontinued Operations	$	72

Dispositions

Leveraged Leases

During the first nine months of 2010, Energy Holdings sold its interest in five leveraged leases, including four international leases for which the IRS has indicated its intention to disallow certain tax deductions taken in prior years.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2010		2010
	Millions
Proceeds from Sales	$	204	$	365
Gains on Sales, after-tax	$	15	$	27

Proceeds from the sales of the international leases were used to reduce the tax exposure related to these lease investments. For additional information see Note 8. Commitments and Contingent Liabilities.

Power [Member]

Discontinued Operations And Dispositions

Note 4. Discontinued Operations and Dispositions

Discontinued Operations

Power

In March 2011, Power completed the sale of its 1,000 MW gas-fired Guadalupe generating facility for a total purchase price of $352 million, resulting in an after-tax gain of $54 million.

In July 2011, Power completed the sale of its 1,000 MW gas-fired Odessa generating facility for a total purchase price of $335 million, resulting in an after-tax gain of $25 million. The closing of the Odessa sale completed the Texas asset sale process announced by Power in early 2011.

PSEG Texas' operating results for the three months and nine months ended September 30, 2011 and 2010, which were reclassified to Discontinued Operations, are summarized below:

	Three Months Ended, September 30,				Nine Months Ended, September 30,
	2011		2010		2011		2010
	Millions
Operating Revenues	$	20	$	140	$	112	$	341
Income (Loss ) Before Income Taxes	$	6	$	31	$	26	$	25
Net Income (Loss)	$	4	$	20	$	17	$	15

The carrying amounts of PSEG Texas' assets and liabilities as of December 31, 2010 are summarized in the following table:

	As of December 31,
	2010
	Millions
Current Assets	$	28
Noncurrent Assets		536
Total Assets of Discontinued Operations	$	564
Current Liabilities	$	28
Noncurrent Liabilities		44
Total Liabilities of Discontinued Operations	$	72

Dispositions

Leveraged Leases

During the first nine months of 2010, Energy Holdings sold its interest in five leveraged leases, including four international leases for which the IRS has indicated its intention to disallow certain tax deductions taken in prior years.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2010		2010
	Millions
Proceeds from Sales	$	204	$	365
Gains on Sales, after-tax	$	15	$	27

Proceeds from the sales of the international leases were used to reduce the tax exposure related to these lease investments. For additional information see Note 8. Commitments and Contingent Liabilities.

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Fair Value Measurements (Narrative) (Details) (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Fair Value Measurements [Abstract]
Net assets measured at fair value on a recurring basis	$ 1,500,000,000	$ 1,700,000,000
Net assets measured at fair value on a recurring basis measured using unobservable inputs	4,000,000	197,000,000
Level 3 net assets as a percentage of total assets	1.00%
Assets transferred from Level 3 to Level 2	$ 8,000,000

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Discontinued Operations And Dispositions (Summary Of Carrying Amount Of Assets And Liabilities) (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total Assets of Discontinued Operations	$ 0	$ 564
Total Liabilities of Discontinued Operations	0	72
Power [Member] | PSEG Texas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current Assets		28
Noncurrent Assets		536
Total Assets of Discontinued Operations		564
Current Liabilities		28
Noncurrent Liabilities		44
Total Liabilities of Discontinued Operations		72
Power [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total Assets of Discontinued Operations	0	564
Total Liabilities of Discontinued Operations	$ 0	$ 72

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Available-For-Sale Securities (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2011

Dec. 31, 2010

Available For Sale Securities [Line Items]

Fair Values And Gross Unrealized Gains And Losses For The Securities Held In The NDT Funds

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	537	$	93	$	(55	)	$	575
Debt Securities
Government Obligations		340		16		(1	)		355
Other Debt Securities		273		14		(3	)		284
Total Debt Securities		613		30		(4	)		639
Other Securities		66		0		0			66
Total Available-for-Sale Securities	$	1,216	$	123	$	(59	)	$	1,280

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	525	$	213	$	(3	)	$	735
Debt Securities
Government Obligations		301		6		(4	)		303
Other Debt Securities		247		10		(2	)		255
Total Debt Securities		548		16		(6	)		558
Other Securities		70		0		0			70
Total Available-for-Sale Securities	$	1,143	$	229	$	(9	)	$	1,363

Accounts Receivable And Accounts Payable Related To NDT Fund

	As of September 30,		As of December 31,
	2011		2010
	Millions
Accounts Receivable	$	100	$	35
Accounts Payable	$	95	$	60

Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months

	As of September 30, 2011										As of December 31, 2010
	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)	$	252	$	(55	)	$	0	$	0		$	55	$	(3	)	$	0	$	0
Debt Securities
Government Obligations (B)		72		(1	)		2		0			106		(4	)		1		0
Other Debt Securities (C)		65		(2	)		6		(1	)		65		(1	)		8		(1	)
Total Debt Securities		137		(3	)		8		(1	)		171		(5	)		9		(1	)
Other Securities		1		0			0		0			0		0			0		0
Total Available-for-Sale Securities	$	390	$	(58	)	$	8	$	(1	)	$	226	$	(8	)	$	9	$	(1	)

(A) Equity Securities—Investments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(B) Debt Securities (Government)—Unrealized losses on Power's NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(C) Debt Securities (Corporate)—Power's investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2011.

Proceeds From The Sales Of And The Net Realized Gains On Securities In The NDT Funds

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	Millions						Millions
Proceeds from Sales	$	431		$	302		$	1,088		$	728
Net Realized Gains (Losses)
Gross Realized Gains	$	26		$	26		$	121		$	86
Gross Realized Losses		(10	)		(8	)		(28	)		(31	)
Net Realized Gains	$	16		$	18		$	93		$	55

Amount Of Available-For-Sale Debt Securities By Maturity Periods

Time Frame	Fair Value
	Millions
Less than 1 Year	$	11
1 - 5 Years		141
6 - 10 Years		172
11 - 15 Years		43
16 - 20 Years		18
Over 20 Years		254
	$	639

Securities Held In The Rabbi Trusts

	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		147		5		0		152
Total PSEG Available-for-Sale Securities	$	163	$	7	$	0	$	170

	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		142		0		0		142
Total PSEG Available-for-Sale Securities	$	158	$	2	$	0	$	160

Rabbi Trusts [Member]

Available For Sale Securities [Line Items]

Proceeds From The Sales Of And The Net Realized Gains On Securities In The NDT Funds

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	Millions				Millions
Proceeds from Sales	$	0	$	158	$	0	$	158
Net Realized Gains (Losses)
Gross Realized Gains	$	0	$	31	$	0	$	31
Gross Realized Losses		0		0		0		0
Net Realized Gains (Losses)	$	0	$	31	$	0	$	31

Fair Value Of The Rabbi Trusts

	As of September 30, 2011		As of December 31, 2010
	Millions
Power	$	33	$	32
PSE&G		57		54
Other		80		74
Total PSEG Available-for-Sale Securities	$	170	$	160

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Commitments And Contingent Liabilities (Leveraged Lease Investments) (Details) (USD $)	9 Months Ended	12 Months Ended		12 Months Ended
	Sep. 30, 2011	Dec. 31, 2011	Sep. 30, 2011 Leveraged Lease Investments [Member]	Dec. 31, 2010 Energy Holdings [Member]
Site Contingency [Line Items]
Penalty percentage proposed for substantial understatement of tax liability			20.00%
Reduction in tax exposure				$ 1,100,000,000
Aggregate tax currently payable	266,000,000
Amount deposited with IRS to defray potential interest costs	320,000,000
Penalties from leverage lease investment tax examination	150,000,000
Rate of interest and penalty growth per quarter during 2011	2,000,000
Additional tax potentially due-low estimate	20,000,000
Additional tax potentially due-high estimate	40,000,000
Estimate of tax, interest and penalties potentially payable in 2011 for 1997 to 2000 tax years-low estimate		110,000,000
Estimate of tax, interest and penalties potentially payable in 2011 for 1997 to 2000 tax years-high estimate		300,000,000
Estimate of tax, interest and penalties potentially payable in 2011 for 2001 to 2003 tax years-low estimate		220,000,000
Estimate of tax, interest and penalties potentially payable in 2011 for 2001 to 2003 tax years-high estimate		560,000,000
Earnings impact consistent with broad settlement offer proposed by IRS-low estimate	120,000,000
Earnings impact consistent with broad settlement offer proposed by IRS-high estimate	$ 140,000,000
Income tax examination, description	To date, six cases have been decided at the trial court level, five of which were decided in favor of the government. The appeals of three of these decisions were affirmed, each in favor of the government. The sixth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer.

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Earnings Per Share (EPS) (Dividend Payments On Common Stock) (Details) (USD $) In Millions, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Earnings Per Share (EPS) [Abstract]
Dividend Payments on Common Stock, Per Share	$ 0.3425	$ 0.3425	$ 1.0275	$ 1.0275
Cash Dividends Paid on Common Stock	$ 173	$ 173	$ 520	$ 520

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Fair Value Measurements (A Reconciliation Of The Beginning And Ending Balances Of Level 3 Derivative Contracts And Securities) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Closing Balance	$ 0				$ 0
Gains and losses attributable to changes in net derivative assets and liabilities, included in Operating Income					(28)		8
Gains and losses attributable to changes in net derivative assets and liabilities included in OCI	1				(2)		28
Gains and losses attributable to changes in net derivative assets and liabilities included in Income from Discontinued Operations	1				3		25
Gains and losses attributable to changes in net derivative assets and liabilities, unrealized	31		32		(25)		9
Gains and losses attributable to changes in net derivative assets and liabilities, realized					(3)		(1)
Purchases	10				65
Sales	(36)
Issuances	(5)				(25)
Settlements	8				3
PSEG (Parent) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains and losses attributable to changes in net derivative assets and liabilities, included in Operating Income	12
Power [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains and losses attributable to changes in net derivative assets and liabilities, included in Operating Income			17
Gains and losses attributable to changes in net derivative assets and liabilities included in OCI			14
Gains and losses attributable to changes in net derivative assets and liabilities included in Income from Discontinued Operations			2
Gains and losses attributable to changes in net derivative assets and liabilities, realized	(19)		(15)
Net Derivative Assets [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Opening Balance	(3)		168		47		105
Included in Income	13	[1]	33	[1]	(27)	[2]	61	[2]
Included in Regulatory Assets/Liabilities	(27)	[3]	(11)	[3]	(31)	[3]	34	[3]
Purchases, (Sales)	10	[4]			29	[4]
(Issuances) (Settlements)	3	[5]			(22)	[5]
Purchases, (Sales) and Settlements			(2)				(12)
Transfers In (Out)	0				0
Closing Balance	(4)		188		(4)		188
NDT Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Opening Balance			6		8		9
Included in Income			0	[1]	0	[2]	0	[2]
Included in Regulatory Assets/Liabilities			0	[3]	0	[3]	0	[3]
Purchases, (Sales)					0	[4]
(Issuances) (Settlements)					0	[5]
Purchases, (Sales) and Settlements			3				0
Transfers In (Out)					(8)
Closing Balance	0		9		0		9
Rabbi Trust Funds [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Opening Balance			16				14
Included in Income			0	[1]			0	[2]
Included in Regulatory Assets/Liabilities			0	[3]			0	[3]
Purchases, (Sales) and Settlements			(16)				(14)
Closing Balance			$ 0				$ 0

[1] PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $12 million and $17 million are included in Operating Income, $1 million and $14 million are included in OCI, and less than $1 million and $2 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $12 million in Operating Income in 2011, $31 million is unrealized and $(19) million is realized. Of the $17 million in Operating Income in 2010, $32 million is unrealized and $(15) million is realized.

[2] PSEG's and Power's gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(28) million and $8 million are included in Operating Income, $(2) million and $28 million are included in OCI, and $3 million and $25 million are included in Income from Discontinued Operations in 2011 and 2010, respectively. Of the $(28) million in Operating Income in 2011, $(25) million is unrealized and $(3) million is realized. Of the $8 million in Operating Income in 2010, $9 million is unrealized and $(1) million is realized.

[3] 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.

[4] Represents $10 million in purchases for the three months ended September 30, 2011. Includes $65 million in purchases and $(36) million in sales for the nine months ended September 30, 2011.

[5] Includes $(5) million in issuances and $8 million in settlements for the three months ended September 30, 2011. Includes $(25) million in issuances and $3 million in settlements for the nine months ended September 30, 2011.

XML

Commitments And Contingent Liabilities (New Generation And Development) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended		12 Months Ended			9 Months Ended					9 Months Ended	12 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2011 mW	Sep. 30, 2011 Power [Member] Period 2012-2013 [Member] Kearny Site [Member] PJM Interconnection Capital Additions [Member] mW	Sep. 30, 2011 Power [Member] Period 2013-2015 [Member] PJM Interconnection Capital Additions [Member] mW	Sep. 30, 2011 Power [Member] Peach Bottom Units [Member] Nuclear Up Rate Capital Additions [Member] mW	Sep. 30, 2011 PSE&G [Member] Solar Capital Additions [Member]	Sep. 30, 2011 Power [Member] PJM Interconnection Capital Additions [Member]	Sep. 30, 2011 Power [Member] Connecticut Capital Additions [Member]	Mar. 31, 2011 Power [Member] Connecticut Capital Additions [Member] mW	Sep. 30, 2011 Power [Member] Nuclear Steam Path Capital Additions [Member]	Dec. 31, 2011 Power [Member] Nuclear Steam Path Capital Additions [Member] mW	Sep. 30, 2011 Power [Member]	Sep. 30, 2010 Power [Member]	Sep. 30, 2011 PSE&G [Member] mW cubicFeet	Sep. 30, 2010 PSE&G [Member]
Long-term Purchase Commitment [Line Items]
Approximate amount committed	$ 896					$ 400					$ 192
Increase of MW nominal capacity after completion of upgrades						133						18
Total expenditures to date	1,479	1,517				28	164	148	99		94		530	579	939	871
Number of MW of gas fired peaking capacity to be built				178	267					130
Number of MW of solar generation on existing utility poles being installed															40
Number of MW of installation of solar generation on land and building															40
Approximately amount of MW's already installed															23
Estimated solar project cost, total	264
Estimated total cost of land and buildings owned phase	189
Number of MW of solar capacity placed into service			23
Long term purchase commitment amount low range								250	140
Approximate amount committed-high end of range								300	150
Investment in projects, amount							$ 116

XML

Other Income And Deductions (Tables)

9 Months Ended

Sep. 30, 2011

Other Income And Deductions [Abstract]

Schedule Of Other Income

Other Income	Power		PSE&G		Other (A)		Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	36	$	0	$	0	$	36
Other		1		7		1		9
Total Other Income	$	37	$	7	$	1	$	45
Three Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	35	$	0	$	0	$	35
Realized Gains from Rabbi Trust		7		11		13		31
Other		2		3		4		9
Total Other Income	$	44	$	14	$	17	$	75
Nine Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	153	$	0	$	0	$	153
Other		3		16		4		23
Total Other Income	$	156	$	16	$	4	$	176
Nine Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	115	$	0	$	0	$	115
Realized Gains from Rabbi Trust		7		11		13		31
Other		4		11		4		19
Total Other Income	$	126	$	22	$	17	$	165

Schedule Of Other Deductions

Other Deductions	Power		PSE&G		Other (A)			Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	10	$	0	$	0		$	10
Other		0		1		0			1
Total Other Deductions	$	10	$	1	$	0		$	11
Three Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	9	$	0	$	0		$	9
Other		0		1		(1	)		0
Total Other Deductions	$	9	$	1	$	(1	)	$	9
Nine Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	32	$	0	$	0		$	32
Other		5		2		0			7
Total Other Deductions	$	37	$	2	$	0		$	39
Nine Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	35	$	0	$	0		$	35
Other		1		2		(1	)		2
Total Other Deductions	$	36	$	2	$	(1	)	$	37

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

XML

Discontinued Operations And Dispositions (Operating Results Reclassified To Discontinued Operations) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net Income (Loss)	$ 29	$ 20	$ 96	$ 15
Power [Member] | PSEG Texas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues	20	140	112	341
Income (Loss ) Before Income Taxes	6	31	26	25
Net Income (Loss)	4	20	17	15
Power [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net Income (Loss)	$ 29	$ 20	$ 96	$ 15

XML

Commitments And Contingent Liabilities (Tables)

9 Months Ended

Sep. 30, 2011

Commitments And Contingent Liabilities [Abstract]

Face Value Of Outstanding Guarantees, Current Exposure And Margin Positions

	As of September 30, 2011			As of December 31, 2010
	Millions
Face Value of Outstanding Guarantees	$	1,758		$	1,936
Exposure under Current Guarantees	$	283		$	330
Letters of Credit Margin Posted	$	135		$	137
Letters of Credit Margin Received	$	53		$	109
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	1		$	0
Counterparty Cash Margin Received		(5	)		(2	)
Net Broker Balance Deposited (Received)		37			(28	)
In the Event Power Were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	765		$	828
Liquidity Available under PSEG's and Power's Credit Facilities to Post Collateral	$	3,466		$	2,750
Additional Amounts Posted
Other Letters of Credit	$	99		$	98

Contract For Anticipated BGS-Fixed Price Eligible Load

Auction Year
	2008		2009		2010		2011
36-Month Terms Ending		May 2011		May 2012		May 2013		May 2014	(A)
Load (MW)		2,800		2,900		2,800		2,800
$ per kWh		0.11150		0.10372		0.09577		0.09430

(A) Prices set in the 2011 BGS auction became effective on June 1, 2011 when the 2008 BGS auction agreements expired.

Total Minimum Purchase Commitments

Fuel Type	Commitments through 2015 Power's Share
	Millions
Nuclear Fuel
Uranium	$	493
Enrichment	$	383
Fabrication	$	130
Natural Gas	$	903
Coal/Oil	$	896

XML

Other Income And Deductions

9 Months Ended

Sep. 30, 2011

Other Income And Deductions

Note 12. Other Income and Deductions

Other Income	Power		PSE&G		Other (A)		Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	36	$	0	$	0	$	36
Other		1		7		1		9
Total Other Income	$	37	$	7	$	1	$	45
Three Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	35	$	0	$	0	$	35
Realized Gains from Rabbi Trust		7		11		13		31
Other		2		3		4		9
Total Other Income	$	44	$	14	$	17	$	75
Nine Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	153	$	0	$	0	$	153
Other		3		16		4		23
Total Other Income	$	156	$	16	$	4	$	176
Nine Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	115	$	0	$	0	$	115
Realized Gains from Rabbi Trust		7		11		13		31
Other		4		11		4		19
Total Other Income	$	126	$	22	$	17	$	165

Other Deductions	Power		PSE&G		Other (A)			Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	10	$	0	$	0		$	10
Other		0		1		0			1
Total Other Deductions	$	10	$	1	$	0		$	11
Three Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	9	$	0	$	0		$	9
Other		0		1		(1	)		0
Total Other Deductions	$	9	$	1	$	(1	)	$	9
Nine Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	32	$	0	$	0		$	32
Other		5		2		0			7
Total Other Deductions	$	37	$	2	$	0		$	39
Nine Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	35	$	0	$	0		$	35
Other		1		2		(1	)		2
Total Other Deductions	$	36	$	2	$	(1	)	$	37

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

Power [Member]

Other Income And Deductions

Note 12. Other Income and Deductions

Other Income	Power		PSE&G		Other (A)		Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	36	$	0	$	0	$	36
Other		1		7		1		9
Total Other Income	$	37	$	7	$	1	$	45
Three Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	35	$	0	$	0	$	35
Realized Gains from Rabbi Trust		7		11		13		31
Other		2		3		4		9
Total Other Income	$	44	$	14	$	17	$	75
Nine Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	153	$	0	$	0	$	153
Other		3		16		4		23
Total Other Income	$	156	$	16	$	4	$	176
Nine Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	115	$	0	$	0	$	115
Realized Gains from Rabbi Trust		7		11		13		31
Other		4		11		4		19
Total Other Income	$	126	$	22	$	17	$	165

Other Deductions	Power		PSE&G		Other (A)			Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	10	$	0	$	0		$	10
Other		0		1		0			1
Total Other Deductions	$	10	$	1	$	0		$	11
Three Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	9	$	0	$	0		$	9
Other		0		1		(1	)		0
Total Other Deductions	$	9	$	1	$	(1	)	$	9
Nine Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	32	$	0	$	0		$	32
Other		5		2		0			7
Total Other Deductions	$	37	$	2	$	0		$	39
Nine Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	35	$	0	$	0		$	35
Other		1		2		(1	)		2
Total Other Deductions	$	36	$	2	$	(1	)	$	37

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

PSE&G [Member]

Other Income And Deductions

Note 12. Other Income and Deductions

Other Income	Power		PSE&G		Other (A)		Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	36	$	0	$	0	$	36
Other		1		7		1		9
Total Other Income	$	37	$	7	$	1	$	45
Three Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	35	$	0	$	0	$	35
Realized Gains from Rabbi Trust		7		11		13		31
Other		2		3		4		9
Total Other Income	$	44	$	14	$	17	$	75
Nine Months Ended September 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	153	$	0	$	0	$	153
Other		3		16		4		23
Total Other Income	$	156	$	16	$	4	$	176
Nine Months Ended September 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	115	$	0	$	0	$	115
Realized Gains from Rabbi Trust		7		11		13		31
Other		4		11		4		19
Total Other Income	$	126	$	22	$	17	$	165

Other Deductions	Power		PSE&G		Other (A)			Consolidated Total
	Millions
Three Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	10	$	0	$	0		$	10
Other		0		1		0			1
Total Other Deductions	$	10	$	1	$	0		$	11
Three Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	9	$	0	$	0		$	9
Other		0		1		(1	)		0
Total Other Deductions	$	9	$	1	$	(1	)	$	9
Nine Months Ended September 30, 2011
NDT Fund Realized Losses and Expenses	$	32	$	0	$	0		$	32
Other		5		2		0			7
Total Other Deductions	$	37	$	2	$	0		$	39
Nine Months Ended September 30, 2010
NDT Fund Realized Losses and Expenses	$	35	$	0	$	0		$	35
Other		1		2		(1	)		2
Total Other Deductions	$	36	$	2	$	(1	)	$	37

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

XML

Available-For-Sale Securities (Fair Value Of Rabbi Trusts) (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Total Available-for-Sale Securities	$ 170	$ 160
Power [Member]
Total Available-for-Sale Securities	33	32
PSE&G [Member]
Total Available-for-Sale Securities	57	54
Others [Member]
Total Available-for-Sale Securities	$ 80	$ 74

XML

Other Income And Deductions (Schedule Of Other Deductions) (Details) (USD $) In Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Component of Other Income, Nonoperating [Line Items]
NDT Fund Realized Losses and Expenses	$ 10		$ 9		$ 32		$ 35
Other	1		0		7		2
Total Other Deductions	11		9		39		37
Power [Member]
Component of Other Income, Nonoperating [Line Items]
NDT Fund Realized Losses and Expenses	10		9		32		35
Other	0		0		5		1
Total Other Deductions	10		9		37		36
PSE&G [Member]
Component of Other Income, Nonoperating [Line Items]
NDT Fund Realized Losses and Expenses	0		0		0		0
Other	1		1		2		2
Total Other Deductions	1		1		2		2
Other Segments [Member]
Component of Other Income, Nonoperating [Line Items]
NDT Fund Realized Losses and Expenses	0	[1]	0	[1]	0	[1]	0	[1]
Other	0	[1]	(1)	[1]	0	[1]	(1)	[1]
Total Other Deductions	$ 0	[1]	$ (1)	[1]	$ 0	[1]	$ (1)	[1]

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

XML

Financial Risk Management Activities (Schedule Of Gross Volume On Absolute Basis For Derivative Contracts) (Details)	Sep. 30, 2011	Dec. 31, 2010
Natural Gas Dth [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	593,000,000	704,000,000
Electricity MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	145,000,000	154,000,000
Capacity MW Days [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis		1,000,000
FTRs MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	20,000,000	23,000,000
Interest Rate Swaps [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	1,400,000,000	1,150,000,000
Power [Member] | Natural Gas Dth In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	350,000,000	424,000,000
PSE&G [Member] | Natural Gas Dth In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	243,000,000	280,000,000
PSEG [Member] | Natural Gas Dth In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
Power [Member] | Electricity MWh In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	145,000,000	154,000,000
PSE&G [Member] | Electricity MWh In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
PSEG [Member] | Electricity MWh In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
Power [Member] | Capacity MW Days In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis		1,000,000
PSE&G [Member] | Capacity MW Days In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis		0
PSEG [Member] | Capacity MW Days In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis		0
Power [Member] | FTRs MWh In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	20,000,000	23,000,000
PSE&G [Member] | FTRs MWh In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
PSEG [Member] | FTRs MWh In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
Power [Member] | Interest Rate Swaps USD In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
PSE&G [Member] | Interest Rate Swaps USD In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
PSEG [Member] | Interest Rate Swaps USD In Millions [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	1,400,000,000	1,150,000,000

XML

Related-Party Transactions (Schedule Of Related Party Transactions, Receivables) (Details) (Power [Member], USD $) In Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Power [Member]
Related Party Transaction [Line Items]
Receivables from PSE&G through BGS and BGSS Contracts	$ 110	[1]	$ 372	[1]
Receivables from PSE&G Related to Gas Supply Hedges for BGSS	64	[1]	58	[1]
Payable to Services	(23)	[2]	(26)	[2]
Tax Sharing Receivables from (Payable to) PSEG	(18)	[3]	380	[3]
Current Unrecognized Tax Receivable from Parent	(5)	[3]	1	[3]
Payable to PSEG	(1)		(3)
Accounts Receivable-Affiliated Companies, net	127		782
Short-Term Loan to Affiliate (Demand Note to PSEG)	1,574	[4]	398	[4]
Working Capital Advances to Services	17	[5]	17	[5]
Long-Term Accrued Taxes Receivable	$ 19	[3]	$ 16	[3]

[1] PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G's BGSS and other contractual requirements through March 31, 2012 and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.

[2] 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.

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

[4] Power's short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

[5] 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.

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Commitments And Contingent Liabilities (Environmental Matters) (Details) (USD $)	9 Months Ended									3 Months Ended										12 Months Ended				12 Months Ended
	Sep. 30, 2011 gal mW	Dec. 31, 2010	Apr. 30, 2009 mW	Dec. 15, 2007	Aug. 31, 2006	Sep. 30, 2011 Power [Member] NJ Industrial Site Recovery Act Site Contingency [Member]	Dec. 31, 2010 NJ Industrial Site Recovery Act Site Contingency [Member]	Sep. 30, 2011 Power [Member] PSD NSR Regulations Site Contingency [Member]	Feb. 28, 2009 PSE&G [Member] Power [Member] Passaic River Site Contingency [Member]	Jun. 30, 2008 Passaic River Site Contingency [Member]	Sep. 30, 2011 Passaic River Site Contingency [Member]	Dec. 31, 2007 Passaic River Site Contingency [Member]	Dec. 31, 2003 Passaic River Site Contingency [Member]	Sep. 30, 2011 Passaic River Site Contingency [Member] PSE&G [Member]	Sep. 30, 2011 Passaic River Site Contingency [Member] Transferred To Power From PSE&G [Member]	Sep. 30, 2011 PSE&G [Member] MGP Remediation Site Contingency [Member]	Sep. 30, 2011 MGP Remediation Site Contingency [Member] PSE&G [Member]	Dec. 31, 2006 Power [Member] PSE&G's Former MGP Sites [Member]	Sep. 30, 2011 PSE&G's Former MGP Sites [Member]	Dec. 31, 2006 PSE&G's Former MGP Sites [Member] PSE&G [Member]	Sep. 30, 2011 PSE&G's Former MGP Sites [Member] PSE&G [Member]	Sep. 30, 2011 PSE&G [Member]	Dec. 31, 2010 PSE&G [Member]	Dec. 31, 2010 Power [Member]	Sep. 30, 2011 Power [Member]
Site Contingency [Line Items]
Number of miles related to the Passaic River constituting a facility as determined by the US Environmental Protection Agency	8
Number of miles on Passaic River tidal reach required to be studied as determined by the US Environmental Protection Agency	17
Number of operating electric generating station (Essex Site)															1
Number of former generating electric station														1
Number of former Manufactured Gas Plant (MGP) sites														4
Number of former MGP locations (Harrison Site) which EPA believes that hazardous substances were released																					1
Original estimated cost of feasibility study																				$ 20,000,000
Estimated, total cost of the study																				86,000,000
Number of potentially responsible parties ("PRPs") in connection with environmental liabilities for operations conducted near Passaic River																				73
Number of current potentially responsible parties ("PRPs") in connection with environmental liabilities for operations conducted near Passaic River																				71
Percentage of cost attributable to potentially responsible party																		1.00%		5.00%
Number of miles of Passaic River which EPA released a draft (Focused Feasibility Study) that proposes six options to address the contamination cleanup												8
Estimated cleanup costs-low estimate											1,300,000,000
Estimated cleanup costs-high estimate											3,700,000,000
Estimated cleanup costs agreed to by two potentially responsible parties										80,000,000
Aggregate number of defendants including registrant entities Power and PSE&G included in NJDEP complaint filed February 2009									320
Aggregate number of PRPs directed by the NJDEP to arrange for natural resource damage assessment and interim compensatory restoration along the lower Passaic River													56
Estimated cost of interim natural resource injury restoration											950,000,000
Number of legal entities contacted by EPA in conjunction with Newark Bay study area contamination					11
Number of operating electric generating stations located on Hackensack River	2
Number of former MGP contamination sites located on Hackensack river in conjunction with Newark Bay study area contamination	1
Number of MGP sites identified by registrant and the NJDEP requiring some level of remedial action																			38
Estimated expenditures, low end of range																	643,000,000
Estimated expenditures, high end of range																	741,000,000
Accrued environmental costs	651,000,000	669,000,000				50,000,000	50,000,000										643,000,000					600,000,000	617,000,000	51,000,000	51,000,000
Remediation liability recorded as other current liabilities																	53,000,000
Remediation liability recorded as environmental costs in noncurrent liabilities																	590,000,000
Regulatory assets																643,000,000
Penalty per day from date of violation-minimum								25,000
Penalty per day from date of violation-maximum								37,500
Amount spent on Mercer and Hudson up to date																								1,300,000,000
Ownership percentage of Keystone Coal fired plant in Pennsylvania																									23.00%
Percentage of reduction required by New Jersey regulations on coal fired electric generating units				90.00%
Number of combustion turbines required to be retired to meet NOx emission reduction requirements			102
Number of MW required to be retired to meet NOx emission reduction requirements			2,000
Number of steam electric generation units requiring significant capital investment for additional controls or retirement as determined by NJDEP			5
Number of MW requiring significant capital investment for additional controls or retirement as determined by NJDEP			800
Total production capacity	2,000,000
New Salem facility cooling towers estimated cost total	$ 1,000,000,000																								$ 575,000,000

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Financing Receivables

9 Months Ended

Sep. 30, 2011

Financing Receivables

Note 5. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout our electric service area. The loans are generally paid back with Solar Renewable Energy Certificates (SRECS) generated from the installed solar electric systems. The following table reflects the outstanding short and long-term loans by class of customer, none of which would be considered "non-performing."

Credit Risk Profile Based on Payment Activity	As of		As of
	September 30,		December 31,
Consumer Loans	2011		2010
	Millions
Commercial/Industrial	$	86	$	62
Residential		7		4
	$	93	$	66

Energy Holdings

Energy Holdings has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG's Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings' investments in the leases are comprised of the total expected lease receivables on its investments over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG's Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG's Condensed Consolidated Balance Sheets. The table below shows Energy Holdings' gross and net lease investment as of September 30, 2011 and December 31, 2010, respectively.

	As of September 30,			As of December 31,
	2011			2010
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	763		$	896
Estimated Residual Value of Leased Assets		684			905
		1,447			1,801
Unearned and Deferred Income		(450	)		(546	)
Gross Investments in Leases		997			1,255
Deferred Tax Liabilities		(804	)		(899	)
Net Investment in Leases	$	193		$	356

Note: The above table does not include $264 million of Gross Investment in Leases to subsidiaries of Dynegy Incorporated (Dynegy) as of September 30, 2011 as we have fully reserved our Gross Investment in the Dynegy leases.

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 relate to investments in leases of commercial real estate properties.

	Lease Receivables, net of Non-Recourse Debt
	As of September 30,		As of December 31,
Counterparties' Credit Rating (S&P)	2011		2010
	Millions
AAA - AA	$	21	$	21
A		110		112
BBB - BB		316		316
B - B-		300		430
Not Rated		16		17
	$	763	$	896

Note: The above table does not include $121 million of lease receivables as of September 30, 2011 related to subsidiaries of Dynegy as we fully reserved our Gross Investments in the Dynegy leases.

The "B" and "B-" ratings above represent lease receivables underlying coal fired assets in Illinois and Pennsylvania. As of September 30, 2011, the gross investment in the leases of such assets, net of non-recourse debt, was $550 million ($54 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the table below.

Asset	Location		Gross Investment		% Owned		Total		Fuel Type	Counterparties' S&P Credit Rating	Counterparty
			Millions				MW
Powerton Station Units 5 and 6		IL	$	135		64%		1,538	Coal	B-	Edison Mission Energy
Joliet Station Units 7 and 8		IL	$	84		64%		1,044	Coal	B-	Edison Mission Energy
Keystone Station Units 1 and 2		PA	$	112		17%		1,711	Coal	B	GenOn REMA, LLC
Conemaugh Station Units 1 and 2		PA	$	112		17%		1,711	Coal	B	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 and 4		PA	$	107		100%		603	Coal	B	GenOn REMA, LLC

Although all payments of equity rent, debt service and other fees are current, no assurances can be given that all payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flow 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 and electricity, overall financial condition of lease counterparties and the quality and condition of assets under lease.

The credit exposure to the lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverage ratios are not met and similar cash flow restrictions if ratings are not maintained at stated levels. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased assets. In the event of a default in any of the lease transactions, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. 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.

Energy Holdings' collateral related to the lease to two affiliates (the Dynegy lessees) of Dynegy Incorporated (Dynegy), includes a guarantee from Dynegy Holdings LLC (DH), a subsidiary of Dynegy. In early August 2011, Dynegy reorganized the legal entity structure for its generation assets. It transferred substantially all of its coal and natural gas-fired generation assets, other than the Dynegy lessees that lease the Roseton Station Units 1 and 2 and Danskammer Station Units 3 and 4, to new subsidiaries which Dynegy termed as "bankruptcy remote". This resulted in a lowering of certain credit ratings of Dynegy and DH. Dynegy's credit is currently rated "CC" by S&P and "Caa3" by Moody's. On July 22, 2011, subsidiaries of Energy Holdings that hold the lessor interests filed a lawsuit in Delaware Chancery Court to halt the proposed transfer of assets to the new subsidiaries alleging that the proposed transfers would violate DH's obligations under its Roseton and Danskammer guarantees. The request for a temporary restraining order was denied on July 29, 2011 and on August 5, 2011, the Delaware Supreme Court denied Energy Holdings' application for certification of an interlocutory appeal and motions to expedite and for injunctive relief. Thereafter on August 8, 2011, Energy Holdings voluntarily dismissed this lawsuit without prejudice.

In September 2011, Dynegy continued its corporate reorganization, transferring DH's interests in its newly formed coal generation subsidiary directly to the parent company, Dynegy, in exchange for an undertaking. It also launched an exchange offer for a substantial portion of DH's debt in exchange for Dynegy debt at various discounts. Dynegy has indicated that in the absence of a debt restructuring and/or refinancing, it may not have sufficient resources to pay its indebtedness under the lease. The consummation of these transactions triggered the filing of two separate lawsuits, one by a group of corporate unsecured bondholders of DH and a second on behalf of a majority of the holders of certain debt certificates related to the Dynegy lessee facilities; these lawsuits asserted fraudulent conveyance claims among several other causes of action. In addition to claims asserted against DH, one of the suits included claims against several members of DH's Board of Directors.

As a result of the above actions, Energy Holdings has evaluated its likely recovery under the lease arrangements for the Roseton and Danskammer facilities leased to subsidiaries of DH, considering the overall value of the underlying assets subject to lease, and has fully reserved its $264 million gross investment. This gross charge is reflected as a reduction to Operating Revenues and resulted in an after-tax charge of approximately $170 million. In the absence of a negotiated resolution of the disputes with Dynegy, Energy Holdings intends to assert claims against DH, its directors and various Dynegy affiliates relative to the reorganization activities which have diminished the value of assets available to satisfy DH's lease guarantee obligations. In addition, Energy Holdings has a tax indemnity agreement, which is designed to protect it from adverse tax consequences should the lease structure not be maintained. Should there be adverse consequences, Energy Holdings intends to assert its claims under this agreement, notwithstanding any attempt by Dynegy in contravention of current case law to limit such claims in a bankruptcy proceeding of DH. In the event of a bankruptcy filing or the failure of DH to honor its obligations under the lease guarantee, it is possible that the lease certificate holders could foreclose on the underlying facilities in partial satisfaction of their indebtedness. Should this occur, Energy Holdings could be required to pay approximately $100 million to satisfy income tax obligations, an amount for which it would seek reimbursement from DH under the tax indemnity agreement. This potential cash tax obligation is fully reflected in the overall estimate of the aggregate after-tax charge.

PSE&G [Member]

Financing Receivables

Note 5. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout our electric service area. The loans are generally paid back with Solar Renewable Energy Certificates (SRECS) generated from the installed solar electric systems. The following table reflects the outstanding short and long-term loans by class of customer, none of which would be considered "non-performing."

Credit Risk Profile Based on Payment Activity	As of		As of
	September 30,		December 31,
Consumer Loans	2011		2010
	Millions
Commercial/Industrial	$	86	$	62
Residential		7		4
	$	93	$	66

Energy Holdings

Energy Holdings has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG's Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings' investments in the leases are comprised of the total expected lease receivables on its investments over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG's Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG's Condensed Consolidated Balance Sheets. The table below shows Energy Holdings' gross and net lease investment as of September 30, 2011 and December 31, 2010, respectively.

	As of September 30,			As of December 31,
	2011			2010
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	763		$	896
Estimated Residual Value of Leased Assets		684			905
		1,447			1,801
Unearned and Deferred Income		(450	)		(546	)
Gross Investments in Leases		997			1,255
Deferred Tax Liabilities		(804	)		(899	)
Net Investment in Leases	$	193		$	356

Note: The above table does not include $264 million of Gross Investment in Leases to subsidiaries of Dynegy Incorporated (Dynegy) as of September 30, 2011 as we have fully reserved our Gross Investment in the Dynegy leases.

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 relate to investments in leases of commercial real estate properties.

	Lease Receivables, net of Non-Recourse Debt
	As of September 30,		As of December 31,
Counterparties' Credit Rating (S&P)	2011		2010
	Millions
AAA - AA	$	21	$	21
A		110		112
BBB - BB		316		316
B - B-		300		430
Not Rated		16		17
	$	763	$	896

Note: The above table does not include $121 million of lease receivables as of September 30, 2011 related to subsidiaries of Dynegy as we fully reserved our Gross Investments in the Dynegy leases.

The "B" and "B-" ratings above represent lease receivables underlying coal fired assets in Illinois and Pennsylvania. As of September 30, 2011, the gross investment in the leases of such assets, net of non-recourse debt, was $550 million ($54 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the table below.

Asset	Location		Gross Investment		% Owned		Total		Fuel Type	Counterparties' S&P Credit Rating	Counterparty
			Millions				MW
Powerton Station Units 5 and 6		IL	$	135		64%		1,538	Coal	B-	Edison Mission Energy
Joliet Station Units 7 and 8		IL	$	84		64%		1,044	Coal	B-	Edison Mission Energy
Keystone Station Units 1 and 2		PA	$	112		17%		1,711	Coal	B	GenOn REMA, LLC
Conemaugh Station Units 1 and 2		PA	$	112		17%		1,711	Coal	B	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 and 4		PA	$	107		100%		603	Coal	B	GenOn REMA, LLC

Although all payments of equity rent, debt service and other fees are current, no assurances can be given that all payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flow 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 and electricity, overall financial condition of lease counterparties and the quality and condition of assets under lease.

The credit exposure to the lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverage ratios are not met and similar cash flow restrictions if ratings are not maintained at stated levels. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased assets. In the event of a default in any of the lease transactions, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. 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.

Energy Holdings' collateral related to the lease to two affiliates (the Dynegy lessees) of Dynegy Incorporated (Dynegy), includes a guarantee from Dynegy Holdings LLC (DH), a subsidiary of Dynegy. In early August 2011, Dynegy reorganized the legal entity structure for its generation assets. It transferred substantially all of its coal and natural gas-fired generation assets, other than the Dynegy lessees that lease the Roseton Station Units 1 and 2 and Danskammer Station Units 3 and 4, to new subsidiaries which Dynegy termed as "bankruptcy remote". This resulted in a lowering of certain credit ratings of Dynegy and DH. Dynegy's credit is currently rated "CC" by S&P and "Caa3" by Moody's. On July 22, 2011, subsidiaries of Energy Holdings that hold the lessor interests filed a lawsuit in Delaware Chancery Court to halt the proposed transfer of assets to the new subsidiaries alleging that the proposed transfers would violate DH's obligations under its Roseton and Danskammer guarantees. The request for a temporary restraining order was denied on July 29, 2011 and on August 5, 2011, the Delaware Supreme Court denied Energy Holdings' application for certification of an interlocutory appeal and motions to expedite and for injunctive relief. Thereafter on August 8, 2011, Energy Holdings voluntarily dismissed this lawsuit without prejudice.

In September 2011, Dynegy continued its corporate reorganization, transferring DH's interests in its newly formed coal generation subsidiary directly to the parent company, Dynegy, in exchange for an undertaking. It also launched an exchange offer for a substantial portion of DH's debt in exchange for Dynegy debt at various discounts. Dynegy has indicated that in the absence of a debt restructuring and/or refinancing, it may not have sufficient resources to pay its indebtedness under the lease. The consummation of these transactions triggered the filing of two separate lawsuits, one by a group of corporate unsecured bondholders of DH and a second on behalf of a majority of the holders of certain debt certificates related to the Dynegy lessee facilities; these lawsuits asserted fraudulent conveyance claims among several other causes of action. In addition to claims asserted against DH, one of the suits included claims against several members of DH's Board of Directors.

As a result of the above actions, Energy Holdings has evaluated its likely recovery under the lease arrangements for the Roseton and Danskammer facilities leased to subsidiaries of DH, considering the overall value of the underlying assets subject to lease, and has fully reserved its $264 million gross investment. This gross charge is reflected as a reduction to Operating Revenues and resulted in an after-tax charge of approximately $170 million. In the absence of a negotiated resolution of the disputes with Dynegy, Energy Holdings intends to assert claims against DH, its directors and various Dynegy affiliates relative to the reorganization activities which have diminished the value of assets available to satisfy DH's lease guarantee obligations. In addition, Energy Holdings has a tax indemnity agreement, which is designed to protect it from adverse tax consequences should the lease structure not be maintained. Should there be adverse consequences, Energy Holdings intends to assert its claims under this agreement, notwithstanding any attempt by Dynegy in contravention of current case law to limit such claims in a bankruptcy proceeding of DH. In the event of a bankruptcy filing or the failure of DH to honor its obligations under the lease guarantee, it is possible that the lease certificate holders could foreclose on the underlying facilities in partial satisfaction of their indebtedness. Should this occur, Energy Holdings could be required to pay approximately $100 million to satisfy income tax obligations, an amount for which it would seek reimbursement from DH under the tax indemnity agreement. This potential cash tax obligation is fully reflected in the overall estimate of the aggregate after-tax charge.

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Earnings Per Share (EPS) (Basic And Diluted Earnings Per Share Computation) (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Schedule of Earnings Per Share, Basic and Diluted, by Common Class [Line Items]
Net income from continuing operations	$ 265	$ 547	$ 1,047	$ 1,267
Discontinued Operations	29	20	96	15
NET INCOME	$ 294	$ 567	$ 1,143	$ 1,282
Weighted Average Common Shares Outstanding	505,909	505,945	505,959	506,001
Total Shares, Basic	505,909	505,945	505,959	506,001
Total Shares, Diluted	506,999	506,968	506,963	507,068
INCOME FROM CONTINUING OPERATIONS, BASIC	$ 0.52	$ 1.08	$ 2.07	$ 2.50
Earnings Per Share, Discontinued Operations, Basic	$ 0.06	$ 0.04	$ 0.19	$ 0.03
INCOME FROM CONTINUING OPERATIONS, DILUTED	$ 0.52	$ 1.08	$ 2.06	$ 2.50
Earnings Per Share, Discontinued Operations, Diluted	$ 0.06	$ 0.04	$ 0.19	$ 0.03
Earnings Per Share, Basic, Total	$ 0.58	$ 1.12	$ 2.26	$ 2.53
Earnings Per Share, Diluted, Total	$ 0.58	$ 1.12	$ 2.25	$ 2.53
Stock Options [Member]
Schedule of Earnings Per Share, Basic and Diluted, by Common Class [Line Items]
Incremental common shares attributable to share based payment arrangements, Basic	0	0	0	0
Incremental common shares attributable to share based payment arrangements, diluted	193	165	172	148
Performance Share [Member]
Schedule of Earnings Per Share, Basic and Diluted, by Common Class [Line Items]
Incremental common shares attributable to share based payment arrangements, Basic	0	0	0	0
Incremental common shares attributable to share based payment arrangements, diluted	599	662	607	785
Restricted Stock Units [Member]
Schedule of Earnings Per Share, Basic and Diluted, by Common Class [Line Items]
Incremental common shares attributable to share based payment arrangements, Basic	0	0	0	0
Incremental common shares attributable to share based payment arrangements, diluted	298	196	225	134

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Earnings Per Share (EPS)

9 Months Ended

Sep. 30, 2011

Earnings Per Share (EPS) [Abstract]

Earnings Per Share (EPS)

Note 15. Earnings Per Share (EPS)

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2011				2010
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Continuing Operations	$	265	$	265	$	547	$	547	$	1,047	$	1,047	$	1,267	$	1,267
Discontinued Operations		29		29		20		20		96		96		15		15
Net Income	$	294	$	294	$	567	$	567	$	1,143	$	1,143	$	1,282	$	1,282
EPS Denominator (Thousands)
Weighted Average Common Shares Outstanding		505,909		505,909		505,945		505,945		505,959		505,959		506,001		506,001
Effect of Stock Options		0		193		0		165		0		172		0		148
Effect of Stock Performance Share Units		0		599		0		662		0		607		0		785
Effect of Restricted Stock Units		0		298		0		196		0		225		0		134
Total Shares		505,909		506,999		505,945		506,968		505,959		506,963		506,001		507,068
EPS:
Continuing Operations	$	0.52	$	0.52	$	1.08	$	1.08	$	2.07	$	2.06	$	2.50	$	2.50
Discontinued Operations		0.06		0.06		0.04		0.04		0.19		0.19		0.03		0.03
Net Income	$	0.58	$	0.58	$	1.12	$	1.12	$	2.26	$	2.25	$	2.53	$	2.53

	Three Months Ended September 30,				Nine Months Ended September 30,
Dividend Payments on Common Stock	2011		2010		2011		2010
Per Share	$	0.3425	$	0.3425	$	1.0275	$	1.0275
in Millions	$	173	$	173	$	520	$	520

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Commitments And Contingent Liabilities (Regulatory Proceedings) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2011 mW	Mar. 31, 2011 mW
Loss Contingencies [Line Items]
New combined cycle generating facilities to be built under LCAPP		1,949
Mid-merit electric power generation capacity to be built under LCAPP	2,000
PSE&G [Member] | New Jersey Clean Energy Program Unfavorable Regulatory Action [Member]
Loss Contingencies [Line Items]
Aggregate funding for New Jersey Clean Energy Program	$ 705
Discounted liability recorded-total	294
Discounted liability recorded-current	224
Discounted liability recorded-noncurrent	70
New Jersey Clean Energy Program Unfavorable Regulatory Action [Member]
Loss Contingencies [Line Items]
Aggregate funding for New Jersey Clean Energy Program	$ 1,200

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Commitments And Contingent Liabilities (Basic Generation Service (BGS) And Basic Gas Supply Service (BGSS)) (Details) (PSE&G [Member])	Sep. 30, 2011 mW cubicFeet
PSE&G [Member]
Long-term Purchase Commitment [Line Items]
Number of cubic feet in gas hedging permitted to be recovered by BPU	115,000,000,000
Percentage of residential gas supply permitted to be recovered in gas hedging by BPU	80.00%
Number of cubic feet to be hedged	70,000,000,000
Percentage of annual residential gas supply requirements to be hedged	50.00%

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Variable Interest Entities (Details) (PSE&G [Member], USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
PSE&G [Member]
Maximum exposure to loss	$ 16	$ 16

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Financial Risk Management Activities (Schedule Of Derivative Instruments Fair Value In Balance Sheet) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Derivative Assets, Current	$ 113		$ 182
Derivative Assets, Noncurrent	75		79
Derivative Assets	188		261
Derivative Liabilities, Current	(94)		(103)
Derivative Liabilities, Noncurrent	(31)		(22)
Derivative Liabilities	(125)		(125)
Net mark-to-market derivative assets (liabilities)	63		136
Net cash collateral received in connection with net derivative contracts	10		61
Power [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current assets	76		204
Fair value amount of derivative contracts that do not qualify for cash flow hedge accounting	232		403
Amount of fair value netting attributed to same counterparty and application of collateral received	(213)	[1]	(444)	[1]
Derivative Assets, Current	95		163
PSE&G [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value amount of derivative contracts that do not qualify for cash flow hedge accounting	0		0
PSEG [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current assets	18		19
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets, Current	113		182
Net cash collateral received in connection with net derivative contracts	(9)		(132)
Power [Member] | Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current assets	7		3
Fair value amount of derivative contracts that do not qualify for cash flow hedge accounting	44		80
Amount of fair value netting attributed to same counterparty and application of collateral received	(27)	[1]	(41)	[1]
Derivative Assets, Noncurrent	24		42
PSE&G [Member] | Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value amount of derivative contracts that do not qualify for cash flow hedge accounting	0		17
PSEG [Member] | Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current assets	51		20
Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets, Noncurrent	75		79
Net cash collateral received in connection with net derivative contracts	(1)		(3)
Power [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current liabilities	(2)		(11)
Fair value of derivatives not designated as hedges, current liabilities	(281)		(454)
Amount of fair value netting attributed to same counterparty and application of collateral received, attributed to current liabilities	204	[1]	374	[1]
Derivative Liabilities, Current	(79)		(91)
PSE&G [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives not designated as hedges, current liabilities	(15)		(12)
PSEG [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current liabilities	0		0
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Current	(94)		(103)
Net cash collateral received in connection with net derivative contracts			62
Power [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current liabilities	(2)		0
Fair value of derivatives not designated as hedges, current liabilities	(41)		(72)
Amount of fair value netting attributed to same counterparty and application of collateral received, attributed to current liabilities	26	[1]	50	[1]
Derivative Liabilities, Noncurrent	(17)		(22)
PSE&G [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives not designated as hedges, current liabilities	(11)		0
PSEG [Member] | Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current liabilities	(3)		0
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Noncurrent	(31)		(22)
Net cash collateral received in connection with net derivative contracts			12
Power [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current assets	83		207
Fair value amount of derivative contracts that do not qualify for cash flow hedge accounting	276		483
Amount of fair value netting attributed to same counterparty and application of collateral received	(240)	[1]	(485)	[1]
Derivative Assets, Current	95		163
Derivative Assets, Noncurrent	24		42
Derivative Assets	119		205
Fair value of derivatives designated cash flow hedges, current liabilities	(4)		(11)
Fair value of derivatives not designated as hedges, current liabilities	(322)		(526)
Amount of fair value netting attributed to same counterparty and application of collateral received, attributed to current liabilities	230	[1]	424	[1]
Derivative Liabilities, Current	(79)		(91)
Derivative Liabilities, Noncurrent	(17)		(22)
Derivative Liabilities	(96)		(113)
Net mark-to-market derivative assets (liabilities) attributed to cash flow hedges	79		196
Net mark-to-market derivative assets (liabilities) attributed to non cash flow hedges	(46)		(43)
Amount of fair value netting attributed to same counterparty and application of collateral received, attributed to net mark-to-market derivative assets (liabilities)	(10)	[1]	(61)	[1]
Net mark-to-market derivative assets (liabilities)	23		92
PSE&G [Member]
Derivatives, Fair Value [Line Items]
Fair value amount of derivative contracts that do not qualify for cash flow hedge accounting	0		17
Derivative Assets, Noncurrent	0		17
Fair value of derivatives not designated as hedges, current liabilities	(26)		(12)
Derivative Liabilities, Current	(15)		(12)
Derivative Liabilities, Noncurrent	(11)		0
Net mark-to-market derivative assets (liabilities) attributed to non cash flow hedges	(26)		5
PSEG [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives designated cash flow hedges, current assets	69		39
Fair value of derivatives designated cash flow hedges, current liabilities	(3)		0
Net mark-to-market derivative assets (liabilities)	$ 66		$ 39

[1] Represents the netting of fair value balances with the same counterparty and the application of collateral. As of September 30, 2011 and December 31, 2010, net cash collateral received of $10 million and $61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $10 million as of September 30, 2011, cash collateral of $(9) million and $(1) million were netted against current assets and noncurrent assets, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively.

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Pension And OPEB (Tables)

9 Months Ended

Sep. 30, 2011

Pension And OPEB [Abstract]

Schedule Of Components Of Net Periodic Benefit Cost

	Pension Benefits Three Months Ended September 30,						OPEB Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	22		$	21		$	3		$	4		$	69		$	65		$	10		$	12
Interest Cost		56			58			15			18			172			173			45			54
Expected Return on Plan Assets		(85	)		(67	)		(5	)		(4	)		(248	)		(200	)		(13	)		(11	)
Amortization of Net
Transition Obligation		0			0			1			6			0			0			4			20
Prior Service Cost (Credit)		(4	)		0			(4	)		4			(6	)		0			(10	)		10
Actuarial Loss		29			31			4			2			89			92			11			6
Net Periodic Benefit Cost		18			43			14			30			76			130			47			91
Effect of Regulatory Asset		0			0			5			5			0			0			15			15
Total Benefit Costs, Including Effect of Regulatory Asset	$	18		$	43		$	19		$	35		$	76		$	130		$	62		$	106

Schedule Of Pension And OPEB Costs

	Pension Benefits Three Months Ended September 30,				OPEB Three Months Ended September 30,				Pension Benefits Nine Months Ended September 30,				OPEB Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
	Millions
Power	$	6	$	13	$	3	$	4	$	24	$	40	$	9	$	13
PSE&G		9		24		16		30		41		72		51		90
Other		3		6		0		1		11		18		2		3
Total Benefit Costs	$	18	$	43	$	19	$	35	$	76	$	130	$	62	$	106

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data	Sep. 30, 2011	Dec. 31, 2010
Accounts Receivable, allowances	$ 64	$ 68
Common Stock, no par value
Common Stock, authorized	1,000,000,000	1,000,000,000
Common Stock, issued	533,556,660	533,556,660
Treasury Stock, shares	27,651,927	27,582,437
PSE&G [Member]
Accounts Receivable, allowances	$ 64	$ 67
Common Stock, authorized	150,000,000	150,000,000
Common Stock, issued	132,450,344	132,450,344
Common Stock, outstanding	132,450,344	132,450,344

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Financial Information By Business Segments

9 Months Ended

Sep. 30, 2011

Financial Information By Business Segments

Note 16. Financial Information by Business Segments

	Power		PSE&G			Energy Holdings			Other(A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Total Operating Revenues	$	1,398	$	1,841		$	(247	)	$	(372	)	$	2,620
Income (Loss) From Continuing Operations		273		154			(166	)		4			265
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		29		0			0			0			29
Net Income (Loss)		302		154			(166	)		4			294
Segment Earnings (Loss)		302		154			(166	)		4			294
Gross Additions to Long-Lived Assets		207		265			1			4			477
Three Months Ended September 30, 2010
Total Operating Revenues	$	1,523	$	2,007		$	58		$	(474	)	$	3,114
Income (Loss) From Continuing Operations		364		155			24			4			547
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		20		0			0			0			20
Net Income (Loss)		384		155			24			4			567
Segment Earnings (Loss)		384		155			24			4			567
Gross Additions to Long-Lived Assets		251		341			12			2			606
Nine Month Ended September 30, 2011
Total Operating Revenues	$	4,650	$	5,718		$	(206	)	$	(1,719	)	$	8,443
Income (Loss) From Continuing Operations		775		422			(164	)		14			1,047
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		96		0			0			0			96
Net Income (Loss)		871		422			(164	)		14			1,143
Segment Earnings (Loss)		871		422			(164	)		14			1,143
Gross Additions to Long-Lived Assets		530		939			2			8			1,479
Nine Months Ended September 30, 2010
Total Operating Revenues	$	4,983	$	5,987		$	114		$	(2,036	)	$	9,048
Income (Loss) From Continuing Operations		937		276			43			11			1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		15		0			0			0			15
Net Income (Loss)		952		276			43			11			1,282
Preferred Securities Dividends		0		(1	)		0			1			0
Segment Earnings (Loss)		952		275			43			12			1,282
Gross Additions to Long-Lived Assets		579		871			61			6			1,517
As of September 30, 2011
Total Assets	$	11,484	$	17,235		$	1,959		$	(767	)	$	29,911
Investments in Equity Method Subsidiaries	$	30	$	0		$	113		$	0		$	143
As of December 31, 2010
Total Assets	$	11,452	$	16,873		$	2,234		$	(650	)	$	29,909
Investments in Equity Method Subsidiaries	$	25	$	0		$	105		$	0		$	130

(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 at cost 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 17. Related-Party Transactions.

Power [Member]

Financial Information By Business Segments

Note 16. Financial Information by Business Segments

	Power		PSE&G			Energy Holdings			Other(A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Total Operating Revenues	$	1,398	$	1,841		$	(247	)	$	(372	)	$	2,620
Income (Loss) From Continuing Operations		273		154			(166	)		4			265
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		29		0			0			0			29
Net Income (Loss)		302		154			(166	)		4			294
Segment Earnings (Loss)		302		154			(166	)		4			294
Gross Additions to Long-Lived Assets		207		265			1			4			477
Three Months Ended September 30, 2010
Total Operating Revenues	$	1,523	$	2,007		$	58		$	(474	)	$	3,114
Income (Loss) From Continuing Operations		364		155			24			4			547
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		20		0			0			0			20
Net Income (Loss)		384		155			24			4			567
Segment Earnings (Loss)		384		155			24			4			567
Gross Additions to Long-Lived Assets		251		341			12			2			606
Nine Month Ended September 30, 2011
Total Operating Revenues	$	4,650	$	5,718		$	(206	)	$	(1,719	)	$	8,443
Income (Loss) From Continuing Operations		775		422			(164	)		14			1,047
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		96		0			0			0			96
Net Income (Loss)		871		422			(164	)		14			1,143
Segment Earnings (Loss)		871		422			(164	)		14			1,143
Gross Additions to Long-Lived Assets		530		939			2			8			1,479
Nine Months Ended September 30, 2010
Total Operating Revenues	$	4,983	$	5,987		$	114		$	(2,036	)	$	9,048
Income (Loss) From Continuing Operations		937		276			43			11			1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		15		0			0			0			15
Net Income (Loss)		952		276			43			11			1,282
Preferred Securities Dividends		0		(1	)		0			1			0
Segment Earnings (Loss)		952		275			43			12			1,282
Gross Additions to Long-Lived Assets		579		871			61			6			1,517
As of September 30, 2011
Total Assets	$	11,484	$	17,235		$	1,959		$	(767	)	$	29,911
Investments in Equity Method Subsidiaries	$	30	$	0		$	113		$	0		$	143
As of December 31, 2010
Total Assets	$	11,452	$	16,873		$	2,234		$	(650	)	$	29,909
Investments in Equity Method Subsidiaries	$	25	$	0		$	105		$	0		$	130

(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 at cost 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 17. Related-Party Transactions.

PSE&G [Member]

Financial Information By Business Segments

Note 16. Financial Information by Business Segments

	Power		PSE&G			Energy Holdings			Other(A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Total Operating Revenues	$	1,398	$	1,841		$	(247	)	$	(372	)	$	2,620
Income (Loss) From Continuing Operations		273		154			(166	)		4			265
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		29		0			0			0			29
Net Income (Loss)		302		154			(166	)		4			294
Segment Earnings (Loss)		302		154			(166	)		4			294
Gross Additions to Long-Lived Assets		207		265			1			4			477
Three Months Ended September 30, 2010
Total Operating Revenues	$	1,523	$	2,007		$	58		$	(474	)	$	3,114
Income (Loss) From Continuing Operations		364		155			24			4			547
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		20		0			0			0			20
Net Income (Loss)		384		155			24			4			567
Segment Earnings (Loss)		384		155			24			4			567
Gross Additions to Long-Lived Assets		251		341			12			2			606
Nine Month Ended September 30, 2011
Total Operating Revenues	$	4,650	$	5,718		$	(206	)	$	(1,719	)	$	8,443
Income (Loss) From Continuing Operations		775		422			(164	)		14			1,047
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		96		0			0			0			96
Net Income (Loss)		871		422			(164	)		14			1,143
Segment Earnings (Loss)		871		422			(164	)		14			1,143
Gross Additions to Long-Lived Assets		530		939			2			8			1,479
Nine Months Ended September 30, 2010
Total Operating Revenues	$	4,983	$	5,987		$	114		$	(2,036	)	$	9,048
Income (Loss) From Continuing Operations		937		276			43			11			1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		15		0			0			0			15
Net Income (Loss)		952		276			43			11			1,282
Preferred Securities Dividends		0		(1	)		0			1			0
Segment Earnings (Loss)		952		275			43			12			1,282
Gross Additions to Long-Lived Assets		579		871			61			6			1,517
As of September 30, 2011
Total Assets	$	11,484	$	17,235		$	1,959		$	(767	)	$	29,911
Investments in Equity Method Subsidiaries	$	30	$	0		$	113		$	0		$	143
As of December 31, 2010
Total Assets	$	11,452	$	16,873		$	2,234		$	(650	)	$	29,909
Investments in Equity Method Subsidiaries	$	25	$	0		$	105		$	0		$	130

(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 at cost 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 17. Related-Party Transactions.

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Financing Receivables (Narrative) (Details) (USD $) In Millions	Sep. 30, 2011
Energy Holdings [Member]
Lease investment with non-investment grade counterparties, gross	$ 550
Lease investment with non-investment grade counterparties, net of deferred taxes	54
DHI [Member]
Lease investments, gross	264
Lease receivables	121
Lease investment aggregate tax charges, minimum	170
PSEG (Parent) [Member]
Lease investment income tax obligations	$ 100

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Guarantees Of Debt

9 Months Ended

Sep. 30, 2011

Guarantees Of Debt

Note 18. Guarantees of Debt

Each series of Power's Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). 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, 2011
Operating Revenues	$	0		$	1,725		$	29		$	(356	)	$	1,398
Operating Expenses		1			1,241			29			(356	)		915
Operating Income (Loss)		(1	)		484			0			0			483
Equity Earnings (Losses) of Subsidiaries		315			29			0			(344	)		0
Other Income		9			38			0			(10	)		37
Other Deductions		(1	)		(8	)		0			(1	)		(10	)
Other-Than-Temporary Impairments		1			(9	)		0			0			(8	)
Interest Expense		(33	)		(17	)		(3	)		11			(42	)
Income Tax Benefit (Expense)		12			(200	)		1			0			(187	)
Income (Loss) from Discontinued Operations, net of tax		0			0			29			0			29
Net Income (Loss)	$	302		$	317			27		$	(344	)	$	302
Three Months Ended September 30, 2010
Operating Revenues	$	0		$	1,817		$	30		$	(324	)	$	1,523
Operating Expenses		0			1,207			34			(325	)		916
Operating Income (Loss)		0			610			(4	)		1			607
Equity Earnings (Losses) of Subsidiaries		378			14			0			(392	)		0
Other Income		18			39			1			(14	)		44
Other Deductions		0			(9	)		0			0			(9	)
Other-Than-Temporary Impairments		0			(2	)		0			0			(2	)
Interest Expense		(26	)		(19	)		(5	)		13			(37	)
Income Tax Benefit (Expense)		14			(255	)		2			0			(239	)
Income (Loss) from Discontinued Operations, net of tax		0			0			20			0			20
Net Income (Loss)	$	384		$	378		$	14		$	(392	)	$	384

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Nine Months Ended September 30, 2011
Operating Revenues	$	0		$	5,622		$	106		$	(1,078	)	$	4,650
Operating Expenses		2			4,278			109			(1,078	)		3,311
Operating Income (Loss)		(2	)		1,344			(3	)		0			1,339
Equity Earnings (Losses) of Subsidiaries		917			88			0			(1,005	)		0
Other Income		28			159			0			(31	)		156
Other Deductions		(4	)		(32	)		0			(1	)		(37	)
Other-Than-Temporary Impairments		0			(10	)		0			0			(10	)
Interest Expense		(115	)		(38	)		(13	)		32			(134	)
Income Tax Benefit (Expense)		47			(592	)		6			0			(539	)
Income (Loss) from Discontinued Operations, net of tax		0			0			96			0			96
Net Income (Loss)	$	871		$	919		$	86		$	(1,005	)	$	871
Nine Months Ended September 30, 2011
Net Cash Provided By (Used In) Operating Activities	$	370		$	2,029		$	(319	)	$	(593	)	$	1,487
Net Cash Provided By (Used In) Investing Activities	$	86		$	(935	)	$	652		$	(821	)	($	1,018	)
Net Cash Provided By (Used In) Financing Activities	$	(456	)	$	(1,091	)	$	(332	)	$	1,413		$	(466	)
Nine Months Ended September 30, 2010
Operating Revenues	$	0		$	5,853		$	95		$	(965	)	$	4,983
Operating Expenses		0			4,236			107			(966	)		3,377
Operating Income (Loss)		0			1,617			(12	)		1			1,606
Equity Earnings (Losses) of Subsidiaries		968			(4	)		0			(964	)		0
Other Income		36			124			1			(35	)		126
Other Deductions		(1	)		(35	)		0			0			(36	)
Other-Than-Temporary Impairments		0			(8	)		0			0			(8	)
Interest Expense		(91	)		(45	)		(17	)		34			(119	)
Income Tax Benefit (Expense)		40			(681	)		9			0			(632	)
Income (Loss) from Discontinued Operations, net of tax		0			0			15			0			15
Net Income (Loss)	$	952		$	968		$	(4	)	$	(964	)	$	952
Nine Months Ended September 30, 2010
Net Cash Provided By (Used In) Operating Activities	$	239		$	1,979		$	(3	)	$	(959	)	$	1,256
Net Cash Provided By (Used In) Investing Activities	$	(18	)	$	(1,522	)	$	0		$	661		$	(879	)
Net Cash Provided By (Used In) Financing Activities	$	(216	)	$	(453	)	$	(43	)	$	297		$	(415	)

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated
	Millions
As of September 30, 2011
Current Assets	$	4,746	$	7,343	$	909	$	(9,701	)	$	3,297
Property, Plant and Equipment, net		58		5,576		932		0			6,566
Investment in Subsidiaries		4,194		800		0		(4,994	)		0
Noncurrent Assets		157		1,496		47		(79	)		1,621
Total Assets	$	9,155	$	15,215	$	1,888	$	(14,774	)	$	11,484
Current Liabilities	$	828	$	9,534	$	944	$	(9,700	)	$	1,606
Noncurrent Liabilities		250		1,488		143		(80	)		1,801
Long-Term Debt		2,640		0		0		0			2,640
Member's Equity		5,437		4,193		801		(4,994	)		5,437
Total Liabilities and Member's Equity	$	9,155	$	15,215	$	1,888	$	(14,774	)	$	11,484
As of December 31, 2010
Current Assets	$	3,988	$	6,807	$	1,117	$	(8,468	)	$	3,444
Property, Plant and Equipment, net		55		5,385		902		0			6,342
Investment in Subsidiaries		4,794		1,079		0		(5,873	)		0
Noncurrent Assets		170		1,549		41		(94	)		1,666
Total Assets	$	9,007	$	14,820	$	2,060	$	(14,435	)	$	11,452
Current Liabilities	$	751	$	8,519	$	849	$	(8,468	)	$	1,651
Noncurrent Liabilities		423		1,510		129		(93	)		1,969
Long-Term Debt		2,805		0		0		0			2,805
Member's Equity		5,028		4,791		1,082		(5,874	)		5,027
Total Liabilities and Member's Equity	$	9,007	$	14,820	$	2,060	$	(14,435	)	$	11,452

Power [Member]

Guarantees Of Debt

Note 18. Guarantees of Debt

Each series of Power's Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). 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, 2011
Operating Revenues	$	0		$	1,725		$	29		$	(356	)	$	1,398
Operating Expenses		1			1,241			29			(356	)		915
Operating Income (Loss)		(1	)		484			0			0			483
Equity Earnings (Losses) of Subsidiaries		315			29			0			(344	)		0
Other Income		9			38			0			(10	)		37
Other Deductions		(1	)		(8	)		0			(1	)		(10	)
Other-Than-Temporary Impairments		1			(9	)		0			0			(8	)
Interest Expense		(33	)		(17	)		(3	)		11			(42	)
Income Tax Benefit (Expense)		12			(200	)		1			0			(187	)
Income (Loss) from Discontinued Operations, net of tax		0			0			29			0			29
Net Income (Loss)	$	302		$	317			27		$	(344	)	$	302
Three Months Ended September 30, 2010
Operating Revenues	$	0		$	1,817		$	30		$	(324	)	$	1,523
Operating Expenses		0			1,207			34			(325	)		916
Operating Income (Loss)		0			610			(4	)		1			607
Equity Earnings (Losses) of Subsidiaries		378			14			0			(392	)		0
Other Income		18			39			1			(14	)		44
Other Deductions		0			(9	)		0			0			(9	)
Other-Than-Temporary Impairments		0			(2	)		0			0			(2	)
Interest Expense		(26	)		(19	)		(5	)		13			(37	)
Income Tax Benefit (Expense)		14			(255	)		2			0			(239	)
Income (Loss) from Discontinued Operations, net of tax		0			0			20			0			20
Net Income (Loss)	$	384		$	378		$	14		$	(392	)	$	384

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Nine Months Ended September 30, 2011
Operating Revenues	$	0		$	5,622		$	106		$	(1,078	)	$	4,650
Operating Expenses		2			4,278			109			(1,078	)		3,311
Operating Income (Loss)		(2	)		1,344			(3	)		0			1,339
Equity Earnings (Losses) of Subsidiaries		917			88			0			(1,005	)		0
Other Income		28			159			0			(31	)		156
Other Deductions		(4	)		(32	)		0			(1	)		(37	)
Other-Than-Temporary Impairments		0			(10	)		0			0			(10	)
Interest Expense		(115	)		(38	)		(13	)		32			(134	)
Income Tax Benefit (Expense)		47			(592	)		6			0			(539	)
Income (Loss) from Discontinued Operations, net of tax		0			0			96			0			96
Net Income (Loss)	$	871		$	919		$	86		$	(1,005	)	$	871
Nine Months Ended September 30, 2011
Net Cash Provided By (Used In) Operating Activities	$	370		$	2,029		$	(319	)	$	(593	)	$	1,487
Net Cash Provided By (Used In) Investing Activities	$	86		$	(935	)	$	652		$	(821	)	($	1,018	)
Net Cash Provided By (Used In) Financing Activities	$	(456	)	$	(1,091	)	$	(332	)	$	1,413		$	(466	)
Nine Months Ended September 30, 2010
Operating Revenues	$	0		$	5,853		$	95		$	(965	)	$	4,983
Operating Expenses		0			4,236			107			(966	)		3,377
Operating Income (Loss)		0			1,617			(12	)		1			1,606
Equity Earnings (Losses) of Subsidiaries		968			(4	)		0			(964	)		0
Other Income		36			124			1			(35	)		126
Other Deductions		(1	)		(35	)		0			0			(36	)
Other-Than-Temporary Impairments		0			(8	)		0			0			(8	)
Interest Expense		(91	)		(45	)		(17	)		34			(119	)
Income Tax Benefit (Expense)		40			(681	)		9			0			(632	)
Income (Loss) from Discontinued Operations, net of tax		0			0			15			0			15
Net Income (Loss)	$	952		$	968		$	(4	)	$	(964	)	$	952
Nine Months Ended September 30, 2010
Net Cash Provided By (Used In) Operating Activities	$	239		$	1,979		$	(3	)	$	(959	)	$	1,256
Net Cash Provided By (Used In) Investing Activities	$	(18	)	$	(1,522	)	$	0		$	661		$	(879	)
Net Cash Provided By (Used In) Financing Activities	$	(216	)	$	(453	)	$	(43	)	$	297		$	(415	)

	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated
	Millions
As of September 30, 2011
Current Assets	$	4,746	$	7,343	$	909	$	(9,701	)	$	3,297
Property, Plant and Equipment, net		58		5,576		932		0			6,566
Investment in Subsidiaries		4,194		800		0		(4,994	)		0
Noncurrent Assets		157		1,496		47		(79	)		1,621
Total Assets	$	9,155	$	15,215	$	1,888	$	(14,774	)	$	11,484
Current Liabilities	$	828	$	9,534	$	944	$	(9,700	)	$	1,606
Noncurrent Liabilities		250		1,488		143		(80	)		1,801
Long-Term Debt		2,640		0		0		0			2,640
Member's Equity		5,437		4,193		801		(4,994	)		5,437
Total Liabilities and Member's Equity	$	9,155	$	15,215	$	1,888	$	(14,774	)	$	11,484
As of December 31, 2010
Current Assets	$	3,988	$	6,807	$	1,117	$	(8,468	)	$	3,444
Property, Plant and Equipment, net		55		5,385		902		0			6,342
Investment in Subsidiaries		4,794		1,079		0		(5,873	)		0
Noncurrent Assets		170		1,549		41		(94	)		1,666
Total Assets	$	9,007	$	14,820	$	2,060	$	(14,435	)	$	11,452
Current Liabilities	$	751	$	8,519	$	849	$	(8,468	)	$	1,651
Noncurrent Liabilities		423		1,510		129		(93	)		1,969
Long-Term Debt		2,805		0		0		0			2,805
Member's Equity		5,028		4,791		1,082		(5,874	)		5,027
Total Liabilities and Member's Equity	$	9,007	$	14,820	$	2,060	$	(14,435	)	$	11,452

XML

Financial Risk Management Activities (Schedule Of Reconciliation For Derivative Activity Included In Accumulated Other Comprehensive Loss) (Details) (USD $) In Millions	6 Months Ended	9 Months Ended
	Jun. 30, 2011	Sep. 30, 2011
Financial Risk Management Activities [Abstract]
Balance in AOCI, Beginning of Period, Pre-Tax	$ 188	$ 188
Loss Recognized in AOCI (Effective Portion)	21	(2)
Less: Gain Reclassified into Income (Effective Portion), Pre-Tax	(93)	(60)
Balance in AOCI, End of Period, Pre-Tax	93	54
Balance in AOCI, Beginning of Period, After-Tax	111	111
Gain Recognized in AOCI (Effective Portion), After-Tax	12	(1)
Less: Gain Reclassified into Income (Effective Portion), After-Tax	(56)	(35)
Balance in AOCI, End of Period, After-Tax	$ 54	$ 31

XML

Financial Risk Management Activities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended						9 Months Ended			3 Months Ended		9 Months Ended
	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Power [Member] Senior Notes 6.95% Due June 2012 [Member]	Sep. 30, 2011 Senior Notes 5% Due April 2014 [Member]	Sep. 30, 2011 Power [Member] Senior Notes 5.5% Due 2015 [Member]	Sep. 30, 2011 Power [Member] Senior Notes 5.32% Due September 2016 [Member]	Sep. 30, 2011 Power [Member] Senior Notes 2.75% Due September 2016 [Member]	Sep. 30, 2011 Power [Member]	Sep. 30, 2012 Power [Member]	Dec. 31, 2010 Power [Member]	Sep. 30, 2011 PSEG [Member]	Sep. 30, 2010 PSEG [Member]	Sep. 30, 2011 PSEG [Member]	Sep. 30, 2010 PSEG [Member]
Derivatives, Fair Value [Line Items]
Amount of unrealized gains on derivatives designated and effective as cash flow hedges expected to be reclassified to earnings during the 12 months following period end									$ 33
Cash flow hedge ineffectiveness								3
Percent of gross margin	1
Fair value of other derivatives								19		(4)
Aggregate amount of series of interest rate swaps converting to variable-rate debt	1,400		300			300
Power's senior notes converted into variable rate debt			600	250	300	303	250
Fair value of interest rate swaps designated as fair value hedges	66	39
Aggregate amount of accumulated other comprehensive loss attributed to interest rate derivatives designated as cash flow hedges	(3)	(3)
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral	182
Additional collateral aggregate fair value	765
Amount of reduction in interest expense attributed to interest rate swaps designated as fair value hedges											$ 6	$ 6	$ 19	$ 18
Credit exposure, percentage	95.00%
Number of active counterparties on credit risk derivatives								190

XML

Organization And Basis Of Presentation

9 Months Ended

Sep. 30, 2011

Organization And Basis Of Presentation

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, energy trading and marketing and risk management 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 an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC. PSE&G is also investing in the development of solar generation projects and energy efficiency programs, which are regulated by the BPU.

• PSEG Energy Holdings L.L.C. (Energy Holdings)—which has invested in leveraged leases and owns and operates primarily domestic projects engaged in the generation of energy through its direct wholly owned subsidiaries. Certain Energy Holdings' subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings has also invested in solar generation projects and is exploring opportunities for other investments in renewable generation.

• PSEG Services Corporation (Services)—which provides management and 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, 2010 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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. 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, 2010.

During 2011, Power sold its two generating facilities located in Texas that were owned and operated by its subsidiary, PSEG Texas. As a result, amounts related to these plants were reclassified as Discontinued Operations in the financial statements. See Note 4. Discontinued Operations and Dispositions for additional information.

Power [Member]

Organization And Basis Of Presentation

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:

Powerwhich is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management 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&Gwhich is an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC. PSE&G is also investing in the development of solar generation projects and energy efficiency programs, which are regulated by the BPU.

PSEG Energy Holdings L.L.C. (Energy Holdings)which has invested in leveraged leases and owns and operates primarily domestic projects engaged in the generation of energy through its direct wholly owned subsidiaries. Certain Energy Holdings' subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings has also invested in solar generation projects and is exploring opportunities for other investments in renewable generation.

PSEG Services Corporation (Services)which provides management and 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, 2010 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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. 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, 2010.

During 2011, Power sold its two generating facilities located in Texas that were owned and operated by its subsidiary, PSEG Texas. As a result, amounts related to these plants were reclassified as Discontinued Operations in the financial statements. See Note 4. Discontinued Operations and Dispositions for additional information.

PSE&G [Member]

Organization And Basis Of Presentation

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:

Powerwhich is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management 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&Gwhich is an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC. PSE&G is also investing in the development of solar generation projects and energy efficiency programs, which are regulated by the BPU.

PSEG Energy Holdings L.L.C. (Energy Holdings)which has invested in leveraged leases and owns and operates primarily domestic projects engaged in the generation of energy through its direct wholly owned subsidiaries. Certain Energy Holdings' subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings has also invested in solar generation projects and is exploring opportunities for other investments in renewable generation.

PSEG Services Corporation (Services)which provides management and 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, 2010 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

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. 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, 2010.

During 2011, Power sold its two generating facilities located in Texas that were owned and operated by its subsidiary, PSEG Texas. As a result, amounts related to these plants were reclassified as Discontinued Operations in the financial statements. See Note 4. Discontinued Operations and Dispositions for additional information.

XML

Financial Risk Management Activities

9 Months Ended

Sep. 30, 2011

Financial Risk Management Activities

Note 10. Financial Risk Management Activities

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

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

• the price of fuel to meet its fuel purchase requirements.

These derivative transactions are designated and effective as cash flow hedges. As of September 30, 2011 and December 31, 2010, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:

	As of September 30, 2011		As of December 31, 2010
	Millions
Fair Value of Cash Flow Hedges	$	79	$	196
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	34	$	114

The expiration date of the longest-dated cash flow hedge at Power is in 2013. Power's after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $33 million. There was ineffectiveness of $3 million associated with these hedges as of September 30, 2011.

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 we serve. 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 are marked to market through the income statement and represented less than one percent of gross margin (revenues less energy costs) on an annual basis. Effective July 2011, Power anticipates that it will only enter into transactions that are associated with the output or fuel purchase requirements of its facilities.

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These asset backed transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of our expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of September 30, 2011 and December 31, 2010 was $19 million and $(4) million, respectively.

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, we 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. Since 2009, PSEG has entered into eleven interest rate swaps totaling $1.4 billion. These swaps convert $300 million of Power's $600 million of 6.95% Senior Notes due June 2012, Power's $250 million of 5% Senior Notes due April 2014, 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 debt. As of September 30, 2011 and December 31, 2010, the fair value of all the underlying hedges was $66 million and $39 million, respectively.

Cash Flow Hedges

PSEG and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of September 30, 2011, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of September 30, 2011 and December 31, 2010. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(3) million and $(3) million as of September 30, 2011 and December 31, 2010, respectively.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets:

	As of September 30, 2011
	Power												PSE&G			PSEG			Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	76		$	232		$	(213	)	$	95		$	0		$	18		$	113
Noncurrent Assets		7			44			(27	)		24			0			51			75
Total Mark-to-Market Derivative Assets	$	83		$	276		$	(240	)	$	119		$	0		$	69		$	188
Derivative Contracts
Current Liabilities	$	(2	)	$	(281	)	$	204		$	(79	)	$	(15	)	$	0		$	(94	)
Noncurrent Liabilities		(2	)		(41	)		26			(17	)		(11	)		(3	)		(31	)
Total Mark-to-Market Derivative (Liabilities)	$	(4	)	$	(322	)	$	230		$	(96	)	$	(26	)	$	(3	)	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	79		$	(46	)	$	(10	)	$	23		$	(26	)	$	66		$	63

	As of December 31, 2010
	Power												PSE&G			PSEG		Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			FairValue Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	204		$	403		$	(444	)	$	163		$	0		$	19	$	182
Noncurrent Assets		3			80			(41	)		42			17			20		79
Total Mark-to-Market Derivative Assets	$	207		$	483		$	(485	)	$	205		$	17		$	39	$	261
Derivative Contracts
Current Liabilities	$	(11	)	$	(454	)	$	374		$	(91	)	$	(12	)	$	0	$	(103	)
Noncurrent Liabilities		0			(72	)		50			(22	)		0			0		(22	)
Total Mark-to-Market Derivative (Liabilities)	$	(11	)	$	(526	)	$	424		$	(113	)	$	(12	)	$	0	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	196		$	(43	)	$	(61	)	$	92		$	5		$	39	$	136

(A) Represents the netting of fair value balances with the same counterparty and the application of collateral. As of September 30, 2011 and December 31, 2010, net cash collateral received of $10 million and $61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $10 million as of September 30, 2011, cash collateral of $(9) million and $(1) million were netted against current assets and noncurrent assets, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively.

The aggregate fair value of energy-related contracts in a liability position as of September 30, 2011 that contain triggers for additional collateral was $182 million. This potential additional collateral is included in the $765 million discussed in Note 8. Commitments and Contingent Liabilities.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended September 30, 2011 and 2010:

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 September 30,					Three Months Ended September 30,					Three Months Ended September 30,
	2011		2010			2011		2010			2011		2010
	Millions
PSEG
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Interest Rate Swaps		0		0	Interest Expense		0		0			0		0
Total PSEG	$	21	$	62		$	60	$	60		$	0	$	0
Power
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Total Power	$	21	$	62		$	60	$	60		$	0	$	0

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, 2011 and 2010:

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 September 30,					Nine Months Ended September 30,							Nine Months Ended September 30,
	2011		2010			2011			2010				2011		2010
	Millions
PSEG (A)
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Interest Rate Swaps		0		0	Interest Expense		(1	)		(1	)			0		0
Total PSEG	$	19	$	172		$	153		$	175			$	1	$	(3	)
Power
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Total Power	$	19	$	172		$	154		$	176			$	1	$	(3	)

(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, 2010	$	188		$	111
Loss Recognized in AOCI (Effective Portion)		(2	)		(1	)
Less: Gain Reclassified into Income (Effective Portion)		(93	)		(56	)
Balance as of June 30, 2011	$	93		$	54
Gain Recognized in AOCI (Effective Portion)		21			12
Less: Gain Reclassified into Income (Effective Portion)		(60	)		(35	)
Balance as of September 30, 2011	$	54		$	31

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, 2011 and 2010:

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 September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
		Millions						Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	24		$	(6	)	$	(18	)	$	3
Energy-Related Contracts	Energy Costs		(11	)		0			(10	)		(8	)
Total PSEG and Power		$	13		$	(6	)	$	(28	)	$	(5	)

Power's derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity 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 $6 million for each of the three month periods and $19 million and $18 million for the nine month periods ended September 30, 2011 and 2010, respectively.

The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2011 and December 31, 2010:

Type	Notional	Total		PSEG		Power		PSE&G
	Millions
As of September 30, 2011
Natural Gas	Dth		593		0		350		243
Electricity	MWh		145		0		145		0
Financial Transmission Rights (FTRs)	MWh		20		0		20		0
Interest Rate Swaps	US Dollars		1,400		1,400		0		0
As of December 31, 2010
Natural Gas	Dth		704		0		424		280
Electricity	MWh		154		0		154		0
Capacity	MW days		1		0		1		0
FTRs	MWh		23		0		23		0
Interest Rate Swaps	US Dollars		1,150		1,150		0		0

Credit Risk

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

As of September 30, 2011, 95% of the credit for Power's operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

The following table provides information on Power's credit risk from others, net of cash collateral, as of September 30, 2011. 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	$	396	$	46	$	392		3	$	242	(A)
Non-Investment Grade—External Rating		11		0		11		0		0
Investment Grade—No External Rating		9		0		9		0		0
Non-Investment Grade—No External Rating		9		0		9		0		0
Total Credit Risk	$	425	$	46	$	421		3	$	242

(A) Includes net exposure of $129 million with PSE&G. The remaining net exposure of $113 million is with two nonaffiliated power purchasers which are regulated investment grade counterparties.

 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, 2011, Power had 190 active counterparties.

Power [Member]

Financial Risk Management Activities

Note 10. Financial Risk Management Activities

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

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

• the price of fuel to meet its fuel purchase requirements.

These derivative transactions are designated and effective as cash flow hedges. As of September 30, 2011 and December 31, 2010, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:

	As of September 30, 2011		As of December 31, 2010
	Millions
Fair Value of Cash Flow Hedges	$	79	$	196
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	34	$	114

The expiration date of the longest-dated cash flow hedge at Power is in 2013. Power's after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $33 million. There was ineffectiveness of $3 million associated with these hedges as of September 30, 2011.

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 we serve. 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 are marked to market through the income statement and represented less than one percent of gross margin (revenues less energy costs) on an annual basis. Effective July 2011, Power anticipates that it will only enter into transactions that are associated with the output or fuel purchase requirements of its facilities.

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These asset backed transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of our expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of September 30, 2011 and December 31, 2010 was $19 million and $(4) million, respectively.

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, we 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. Since 2009, PSEG has entered into eleven interest rate swaps totaling $1.4 billion. These swaps convert $300 million of Power's $600 million of 6.95% Senior Notes due June 2012, Power's $250 million of 5% Senior Notes due April 2014, 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 debt. As of September 30, 2011 and December 31, 2010, the fair value of all the underlying hedges was $66 million and $39 million, respectively.

Cash Flow Hedges

PSEG and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of September 30, 2011, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of September 30, 2011 and December 31, 2010. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(3) million and $(3) million as of September 30, 2011 and December 31, 2010, respectively.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets:

	As of September 30, 2011
	Power												PSE&G			PSEG			Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	76		$	232		$	(213	)	$	95		$	0		$	18		$	113
Noncurrent Assets		7			44			(27	)		24			0			51			75
Total Mark-to-Market Derivative Assets	$	83		$	276		$	(240	)	$	119		$	0		$	69		$	188
Derivative Contracts
Current Liabilities	$	(2	)	$	(281	)	$	204		$	(79	)	$	(15	)	$	0		$	(94	)
Noncurrent Liabilities		(2	)		(41	)		26			(17	)		(11	)		(3	)		(31	)
Total Mark-to-Market Derivative (Liabilities)	$	(4	)	$	(322	)	$	230		$	(96	)	$	(26	)	$	(3	)	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	79		$	(46	)	$	(10	)	$	23		$	(26	)	$	66		$	63

	As of December 31, 2010
	Power												PSE&G			PSEG		Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			FairValue Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	204		$	403		$	(444	)	$	163		$	0		$	19	$	182
Noncurrent Assets		3			80			(41	)		42			17			20		79
Total Mark-to-Market Derivative Assets	$	207		$	483		$	(485	)	$	205		$	17		$	39	$	261
Derivative Contracts
Current Liabilities	$	(11	)	$	(454	)	$	374		$	(91	)	$	(12	)	$	0	$	(103	)
Noncurrent Liabilities		0			(72	)		50			(22	)		0			0		(22	)
Total Mark-to-Market Derivative (Liabilities)	$	(11	)	$	(526	)	$	424		$	(113	)	$	(12	)	$	0	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	196		$	(43	)	$	(61	)	$	92		$	5		$	39	$	136

(A) Represents the netting of fair value balances with the same counterparty and the application of collateral. As of September 30, 2011 and December 31, 2010, net cash collateral received of $10 million and $61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $10 million as of September 30, 2011, cash collateral of $(9) million and $(1) million were netted against current assets and noncurrent assets, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively.

The aggregate fair value of energy-related contracts in a liability position as of September 30, 2011 that contain triggers for additional collateral was $182 million. This potential additional collateral is included in the $765 million discussed in Note 8. Commitments and Contingent Liabilities.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended September 30, 2011 and 2010:

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 September 30,					Three Months Ended September 30,					Three Months Ended September 30,
	2011		2010			2011		2010			2011		2010
	Millions
PSEG
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Interest Rate Swaps		0		0	Interest Expense		0		0			0		0
Total PSEG	$	21	$	62		$	60	$	60		$	0	$	0
Power
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Total Power	$	21	$	62		$	60	$	60		$	0	$	0

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, 2011 and 2010:

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 September 30,					Nine Months Ended September 30,							Nine Months Ended September 30,
	2011		2010			2011			2010				2011		2010
	Millions
PSEG (A)
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Interest Rate Swaps		0		0	Interest Expense		(1	)		(1	)			0		0
Total PSEG	$	19	$	172		$	153		$	175			$	1	$	(3	)
Power
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Total Power	$	19	$	172		$	154		$	176			$	1	$	(3	)

(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, 2010	$	188		$	111
Loss Recognized in AOCI (Effective Portion)		(2	)		(1	)
Less: Gain Reclassified into Income (Effective Portion)		(93	)		(56	)
Balance as of June 30, 2011	$	93		$	54
Gain Recognized in AOCI (Effective Portion)		21			12
Less: Gain Reclassified into Income (Effective Portion)		(60	)		(35	)
Balance as of September 30, 2011	$	54		$	31

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, 2011 and 2010:

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 September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
		Millions						Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	24		$	(6	)	$	(18	)	$	3
Energy-Related Contracts	Energy Costs		(11	)		0			(10	)		(8	)
Total PSEG and Power		$	13		$	(6	)	$	(28	)	$	(5	)

Power's derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity 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 $6 million for each of the three month periods and $19 million and $18 million for the nine month periods ended September 30, 2011 and 2010, respectively.

The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2011 and December 31, 2010:

Type	Notional	Total		PSEG		Power		PSE&G
	Millions
As of September 30, 2011
Natural Gas	Dth		593		0		350		243
Electricity	MWh		145		0		145		0
Financial Transmission Rights (FTRs)	MWh		20		0		20		0
Interest Rate Swaps	US Dollars		1,400		1,400		0		0
As of December 31, 2010
Natural Gas	Dth		704		0		424		280
Electricity	MWh		154		0		154		0
Capacity	MW days		1		0		1		0
FTRs	MWh		23		0		23		0
Interest Rate Swaps	US Dollars		1,150		1,150		0		0

Credit Risk

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

As of September 30, 2011, 95% of the credit for Power's operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

The following table provides information on Power's credit risk from others, net of cash collateral, as of September 30, 2011. 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	$	396	$	46	$	392		3	$	242	(A)
Non-Investment Grade—External Rating		11		0		11		0		0
Investment Grade—No External Rating		9		0		9		0		0
Non-Investment Grade—No External Rating		9		0		9		0		0
Total Credit Risk	$	425	$	46	$	421		3	$	242

(A) Includes net exposure of $129 million with PSE&G. The remaining net exposure of $113 million is with two nonaffiliated power purchasers which are regulated investment grade counterparties.

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, 2011, Power had 190 active counterparties.

PSE&G [Member]

Financial Risk Management Activities

Note 10. Financial Risk Management Activities

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

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

• the price of fuel to meet its fuel purchase requirements.

These derivative transactions are designated and effective as cash flow hedges. As of September 30, 2011 and December 31, 2010, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:

	As of September 30, 2011		As of December 31, 2010
	Millions
Fair Value of Cash Flow Hedges	$	79	$	196
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	34	$	114

The expiration date of the longest-dated cash flow hedge at Power is in 2013. Power's after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $33 million. There was ineffectiveness of $3 million associated with these hedges as of September 30, 2011.

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 we serve. 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 are marked to market through the income statement and represented less than one percent of gross margin (revenues less energy costs) on an annual basis. Effective July 2011, Power anticipates that it will only enter into transactions that are associated with the output or fuel purchase requirements of its facilities.

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These asset backed transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of our expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of September 30, 2011 and December 31, 2010 was $19 million and $(4) million, respectively.

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, we 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. Since 2009, PSEG has entered into eleven interest rate swaps totaling $1.4 billion. These swaps convert $300 million of Power's $600 million of 6.95% Senior Notes due June 2012, Power's $250 million of 5% Senior Notes due April 2014, 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 debt. As of September 30, 2011 and December 31, 2010, the fair value of all the underlying hedges was $66 million and $39 million, respectively.

Cash Flow Hedges

PSEG and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of September 30, 2011, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of September 30, 2011 and December 31, 2010. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(3) million and $(3) million as of September 30, 2011 and December 31, 2010, respectively.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets:

	As of September 30, 2011
	Power												PSE&G			PSEG			Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	76		$	232		$	(213	)	$	95		$	0		$	18		$	113
Noncurrent Assets		7			44			(27	)		24			0			51			75
Total Mark-to-Market Derivative Assets	$	83		$	276		$	(240	)	$	119		$	0		$	69		$	188
Derivative Contracts
Current Liabilities	$	(2	)	$	(281	)	$	204		$	(79	)	$	(15	)	$	0		$	(94	)
Noncurrent Liabilities		(2	)		(41	)		26			(17	)		(11	)		(3	)		(31	)
Total Mark-to-Market Derivative (Liabilities)	$	(4	)	$	(322	)	$	230		$	(96	)	$	(26	)	$	(3	)	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	79		$	(46	)	$	(10	)	$	23		$	(26	)	$	66		$	63

	As of December 31, 2010
	Power												PSE&G			PSEG		Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			FairValue Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts									Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	204		$	403		$	(444	)	$	163		$	0		$	19	$	182
Noncurrent Assets		3			80			(41	)		42			17			20		79
Total Mark-to-Market Derivative Assets	$	207		$	483		$	(485	)	$	205		$	17		$	39	$	261
Derivative Contracts
Current Liabilities	$	(11	)	$	(454	)	$	374		$	(91	)	$	(12	)	$	0	$	(103	)
Noncurrent Liabilities		0			(72	)		50			(22	)		0			0		(22	)
Total Mark-to-Market Derivative (Liabilities)	$	(11	)	$	(526	)	$	424		$	(113	)	$	(12	)	$	0	$	(125	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	196		$	(43	)	$	(61	)	$	92		$	5		$	39	$	136

(A) Represents the netting of fair value balances with the same counterparty and the application of collateral. As of September 30, 2011 and December 31, 2010, net cash collateral received of $10 million and $61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $10 million as of September 30, 2011, cash collateral of $(9) million and $(1) million were netted against current assets and noncurrent assets, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively.

The aggregate fair value of energy-related contracts in a liability position as of September 30, 2011 that contain triggers for additional collateral was $182 million. This potential additional collateral is included in the $765 million discussed in Note 8. Commitments and Contingent Liabilities.

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended September 30, 2011 and 2010:

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 September 30,					Three Months Ended September 30,					Three Months Ended September 30,
	2011		2010			2011		2010			2011		2010
	Millions
PSEG
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Interest Rate Swaps		0		0	Interest Expense		0		0			0		0
Total PSEG	$	21	$	62		$	60	$	60		$	0	$	0
Power
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Total Power	$	21	$	62		$	60	$	60		$	0	$	0

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, 2011 and 2010:

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 September 30,					Nine Months Ended September 30,							Nine Months Ended September 30,
	2011		2010			2011			2010				2011		2010
	Millions
PSEG (A)
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Interest Rate Swaps		0		0	Interest Expense		(1	)		(1	)			0		0
Total PSEG	$	19	$	172		$	153		$	175			$	1	$	(3	)
Power
Energy-Related Contracts	$	18	$	171	Operating Revenues	$	152		$	178		Operating Revenues	$	1	$	(3	)
Energy-Related Contracts		1		1	Energy Costs		2			(2	)			0		0
Total Power	$	19	$	172		$	154		$	176			$	1	$	(3	)

(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, 2010	$	188		$	111
Loss Recognized in AOCI (Effective Portion)		(2	)		(1	)
Less: Gain Reclassified into Income (Effective Portion)		(93	)		(56	)
Balance as of June 30, 2011	$	93		$	54
Gain Recognized in AOCI (Effective Portion)		21			12
Less: Gain Reclassified into Income (Effective Portion)		(60	)		(35	)
Balance as of September 30, 2011	$	54		$	31

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, 2011 and 2010:

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 September 30,						Nine Months Ended September 30,
		2011			2010			2011			2010
		Millions						Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	24		$	(6	)	$	(18	)	$	3
Energy-Related Contracts	Energy Costs		(11	)		0			(10	)		(8	)
Total PSEG and Power		$	13		$	(6	)	$	(28	)	$	(5	)

Power's derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity 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 $6 million for each of the three month periods and $19 million and $18 million for the nine month periods ended September 30, 2011 and 2010, respectively.

The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2011 and December 31, 2010:

Type	Notional	Total		PSEG		Power		PSE&G
	Millions
As of September 30, 2011
Natural Gas	Dth		593		0		350		243
Electricity	MWh		145		0		145		0
Financial Transmission Rights (FTRs)	MWh		20		0		20		0
Interest Rate Swaps	US Dollars		1,400		1,400		0		0
As of December 31, 2010
Natural Gas	Dth		704		0		424		280
Electricity	MWh		154		0		154		0
Capacity	MW days		1		0		1		0
FTRs	MWh		23		0		23		0
Interest Rate Swaps	US Dollars		1,150		1,150		0		0

Credit Risk

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

As of September 30, 2011, 95% of the credit for Power's operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

The following table provides information on Power's credit risk from others, net of cash collateral, as of September 30, 2011. 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	$	396	$	46	$	392		3	$	242	(A)
Non-Investment Grade—External Rating		11		0		11		0		0
Investment Grade—No External Rating		9		0		9		0		0
Non-Investment Grade—No External Rating		9		0		9		0		0
Total Credit Risk	$	425	$	46	$	421		3	$	242

(A) Includes net exposure of $129 million with PSE&G. The remaining net exposure of $113 million is with two nonaffiliated power purchasers which are regulated investment grade counterparties.

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, 2011, Power had 190 active counterparties.

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Available-For-Sale Securities (Securities Held In The Rabbi Trusts) (Details) (USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	$ 16	$ 16
Gross Unrealized Gains	2	2
Gross Unrealized Losses	0	0
Estimated Fair Value	18	18
Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	147	142
Gross Unrealized Gains	5	0
Gross Unrealized Losses	0	0
Estimated Fair Value	152	142
Total Available-For-Sale Securities Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Cost	163	158
Gross Unrealized Gains	7	2
Gross Unrealized Losses	0	0
Estimated Fair Value	$ 170	$ 160

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Pension And OPEB (Schedule Of Pension And OPEB Costs) (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Power [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 6	$ 13	$ 24	$ 40
PSE&G [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	9	24	41	72
Others [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	3	6	11	18
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	18	43	76	130
Power [Member] | OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	3	4	9	13
PSE&G [Member] | OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	16	30	51	90
Others [Member] | OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	0	1	2	3
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Benefit Costs	$ 19	$ 35	$ 62	$ 106

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Financial Risk Management Activities (Schedule Of Derivative Transactions Designated And Effective As Cash Flow Hedges) (Details) (Power [Member], USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Power [Member]
Fair Value of Cash Flow Hedges	$ 79	$ 196
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$ 34	$ 114

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Income Taxes [Abstract]

Schedule Of Effective Tax Rates

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
PSEG		43.1	%		40.4	%		42.0	%		40.3	%
Power		40.7	%		39.6	%		41.0	%		40.3	%
PSE&G		40.1	%		39.5	%		40.5	%		38.4	%

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Comprehensive Income, Net Of Tax

9 Months Ended

Sep. 30, 2011

Comprehensive Income, Net Of Tax

Note 14. Comprehensive Income, Net of Tax

Comprehensive Income	Power			PSE&G			Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Net Income	$	302		$	154		$	(162	)	$	294
Other Comprehensive Income (Loss)		(80	)		1			2			(77	)
Comprehensive Income	$	222		$	155		$	(160	)	$	217
Three Months Ended September 30, 2010
Net Income	$	384		$	155		$	28		$	567
Other Comprehensive Income (Loss)		38			(6	)		(4	)		28
Comprehensive Income	$	422		$	149		$	24		$	595
Nine Months Ended September 30, 2011
Net Income	$	871		$	422		$	(150	)	$	1,143
Other Comprehensive Income (Loss)		(112	)		2			10			(100	)
Comprehensive Income	$	759		$	424		$	(140	)	$	1,043
Nine Months Ended September 30, 2010
Net Income	$	952		$	276		$	54		$	1,282
Other Comprehensive Income (Loss)		13			(5	)		(3	)		5
Comprehensive Income	$	965		$	271		$	51		$	1,287

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

Accumulated Other Comprehensive Income (Loss)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2010			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2011							Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2011
				Power (A)			PSE&G (B)		Other (C)
	Millions
Derivative Contracts	$	111		$	(80	)	$	0	$	0	$	31
Pension and OPEB Plans		(377	)		45			0		8		(324	)
NDT Funds		109			(77	)		0		0		32
Other		1			0			2		2		5
Accumulated Other Comprehensive Income (Loss)	$	(156	)	$	(112	)	$	2		10	$	(256	)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2009			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2010									Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2010
				Power (A)			PSE&G (B)			Other (C)
	Millions
Derivative Contracts	$	180		$	(2	)	$	0		$	0		$	178
Pension and OPEB Plans		(400	)		18			0			1			(381	)
NDT Funds		91			0			0			0			91
Other		13			(3	)		(5	)		(4	)		1
Accumulated Other Comprehensive Income (Loss)	$	(116	)	$	13		$	(5	)	$	(3	)	$	(111	)

(A) Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $54 million, $(31) million and $78 million, respectively for the nine months ended September 30, 2011. Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $1 million, $(12) million and $1 million, respectively for the nine months ended September 30, 2010.

(B) Net of tax of $(1) million for the nine months ended September 30, 2011 and $3 million for the nine months ended September 30, 2010.

(C) Net of tax of $(7) million for the nine months ended September 30, 2011 and $2 million for the nine months ended September 30, 2010.

Power [Member]

Comprehensive Income, Net Of Tax

Note 14. Comprehensive Income, Net of Tax

Comprehensive Income	Power			PSE&G			Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Net Income	$	302		$	154		$	(162	)	$	294
Other Comprehensive Income (Loss)		(80	)		1			2			(77	)
Comprehensive Income	$	222		$	155		$	(160	)	$	217
Three Months Ended September 30, 2010
Net Income	$	384		$	155		$	28		$	567
Other Comprehensive Income (Loss)		38			(6	)		(4	)		28
Comprehensive Income	$	422		$	149		$	24		$	595
Nine Months Ended September 30, 2011
Net Income	$	871		$	422		$	(150	)	$	1,143
Other Comprehensive Income (Loss)		(112	)		2			10			(100	)
Comprehensive Income	$	759		$	424		$	(140	)	$	1,043
Nine Months Ended September 30, 2010
Net Income	$	952		$	276		$	54		$	1,282
Other Comprehensive Income (Loss)		13			(5	)		(3	)		5
Comprehensive Income	$	965		$	271		$	51		$	1,287

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

Accumulated Other Comprehensive Income (Loss)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2010			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2011							Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2011
				Power (A)			PSE&G (B)		Other (C)
	Millions
Derivative Contracts	$	111		$	(80	)	$	0	$	0	$	31
Pension and OPEB Plans		(377	)		45			0		8		(324	)
NDT Funds		109			(77	)		0		0		32
Other		1			0			2		2		5
Accumulated Other Comprehensive Income (Loss)	$	(156	)	$	(112	)	$	2		10	$	(256	)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2009			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2010									Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2010
				Power (A)			PSE&G (B)			Other (C)
	Millions
Derivative Contracts	$	180		$	(2	)	$	0		$	0		$	178
Pension and OPEB Plans		(400	)		18			0			1			(381	)
NDT Funds		91			0			0			0			91
Other		13			(3	)		(5	)		(4	)		1
Accumulated Other Comprehensive Income (Loss)	$	(116	)	$	13		$	(5	)	$	(3	)	$	(111	)

(A) Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $54 million, $(31) million and $78 million, respectively for the nine months ended September 30, 2011. Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $1 million, $(12) million and $1 million, respectively for the nine months ended September 30, 2010.

(B) Net of tax of $(1) million for the nine months ended September 30, 2011 and $3 million for the nine months ended September 30, 2010.

(C) Net of tax of $(7) million for the nine months ended September 30, 2011 and $2 million for the nine months ended September 30, 2010.

PSE&G [Member]

Comprehensive Income, Net Of Tax

Note 14. Comprehensive Income, Net of Tax

Comprehensive Income	Power			PSE&G			Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Net Income	$	302		$	154		$	(162	)	$	294
Other Comprehensive Income (Loss)		(80	)		1			2			(77	)
Comprehensive Income	$	222		$	155		$	(160	)	$	217
Three Months Ended September 30, 2010
Net Income	$	384		$	155		$	28		$	567
Other Comprehensive Income (Loss)		38			(6	)		(4	)		28
Comprehensive Income	$	422		$	149		$	24		$	595
Nine Months Ended September 30, 2011
Net Income	$	871		$	422		$	(150	)	$	1,143
Other Comprehensive Income (Loss)		(112	)		2			10			(100	)
Comprehensive Income	$	759		$	424		$	(140	)	$	1,043
Nine Months Ended September 30, 2010
Net Income	$	952		$	276		$	54		$	1,282
Other Comprehensive Income (Loss)		13			(5	)		(3	)		5
Comprehensive Income	$	965		$	271		$	51		$	1,287

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

Accumulated Other Comprehensive Income (Loss)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2010			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2011							Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2011
				Power (A)			PSE&G (B)		Other (C)
	Millions
Derivative Contracts	$	111		$	(80	)	$	0	$	0	$	31
Pension and OPEB Plans		(377	)		45			0		8		(324	)
NDT Funds		109			(77	)		0		0		32
Other		1			0			2		2		5
Accumulated Other Comprehensive Income (Loss)	$	(156	)	$	(112	)	$	2		10	$	(256	)

	Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2009			Other Comprehensive Income (Loss) for the Nine Months Ended September 30, 2010									Accumulated Other Comprehensive Income (Loss) Balance as of September 30, 2010
				Power (A)			PSE&G (B)			Other (C)
	Millions
Derivative Contracts	$	180		$	(2	)	$	0		$	0		$	178
Pension and OPEB Plans		(400	)		18			0			1			(381	)
NDT Funds		91			0			0			0			91
Other		13			(3	)		(5	)		(4	)		1
Accumulated Other Comprehensive Income (Loss)	$	(116	)	$	13		$	(5	)	$	(3	)	$	(111	)

(A) Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $54 million, $(31) million and $78 million, respectively for the nine months ended September 30, 2011. Net of tax related to Derivative Contracts, Pension and OPEB Plans and NDT Funds/Other of $1 million, $(12) million and $1 million, respectively for the nine months ended September 30, 2010.

(B) Net of tax of $(1) million for the nine months ended September 30, 2011 and $3 million for the nine months ended September 30, 2010.

(C) Net of tax of $(7) million for the nine months ended September 30, 2011 and $2 million for the nine months ended September 30, 2010.

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Condensed Consolidated Statements Of Operations (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
OPERATING REVENUES	$ 2,620	$ 3,114	$ 8,443	$ 9,048
OPERATING EXPENSES
Energy Costs	1,167	1,261	3,740	4,021
Operation and Maintenance	603	591	1,829	1,862
Depreciation and Amortization	263	260	739	716
Taxes Other Than Income Taxes	31	31	102	101
Total Operating Expenses	2,064	2,143	6,410	6,700
OPERATING INCOME	556	971	2,033	2,348
Income from Equity Method Investments	1	4	8	12
Other Income	45	75	176	165
Other Deductions	(11)	(9)	(39)	(37)
Other-Than-Temporary Impairments	(8)	(3)	(13)	(9)
Interest Expense	(117)	(120)	(361)	(356)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	466	918	1,804	2,123
Income Tax (Expense) Benefit	(201)	(371)	(757)	(856)
INCOME FROM CONTINUING OPERATIONS	265	547	1,047	1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(11) for the three months and $(51) and $(10) for the nine months ended 2011 and 2010, respectively	29	20	96	15
NET INCOME	294	567	1,143	1,282
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC	505,909	505,945	505,959	506,001
DILUTED	506,999	506,968	506,963	507,068
EARNINGS PER SHARE
INCOME FROM CONTINUING OPERATIONS, BASIC	$ 0.52	$ 1.08	$ 2.07	$ 2.50
NET INCOME, BASIC	$ 0.58	$ 1.12	$ 2.26	$ 2.53
INCOME FROM CONTINUING OPERATIONS, DILUTED	$ 0.52	$ 1.08	$ 2.06	$ 2.50
NET INCOME, DILUTED	$ 0.58	$ 1.12	$ 2.25	$ 2.53
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$ 0.3425	$ 0.3425	$ 1.0275	$ 1.0275
Power [Member]
OPERATING REVENUES	1,398	1,523	4,650	4,983
OPERATING EXPENSES
Energy Costs	597	620	2,335	2,483
Operation and Maintenance	262	253	810	764
Depreciation and Amortization	56	43	166	130
Total Operating Expenses	915	916	3,311	3,377
OPERATING INCOME	483	607	1,339	1,606
Other Income	37	44	156	126
Other Deductions	(10)	(9)	(37)	(36)
Other-Than-Temporary Impairments	(8)	(2)	(10)	(8)
Interest Expense	(42)	(37)	(134)	(119)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	460	603	1,314	1,569
Income Tax (Expense) Benefit	(187)	(239)	(539)	(632)
INCOME FROM CONTINUING OPERATIONS	273	364	775	937
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(11) for the three months and $(51) and $(10) for the nine months ended 2011 and 2010, respectively	29	20	96	15
NET INCOME	302	384	871	952
PSE&G [Member]
OPERATING REVENUES	1,841	2,007	5,718	5,987
OPERATING EXPENSES
Energy Costs	943	1,115	3,124	3,572
Operation and Maintenance	342	327	1,014	1,084
Depreciation and Amortization	197	209	548	563
Taxes Other Than Income Taxes	31	31	102	101
Total Operating Expenses	1,513	1,682	4,788	5,320
OPERATING INCOME	328	325	930	667
Other Income	7	14	16	22
Other Deductions	(1)	(1)	(2)	(2)
Other-Than-Temporary Impairments	0	0	(1)	0
Interest Expense	(77)	(82)	(234)	(239)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	257	256	709	448
Income Tax (Expense) Benefit	(103)	(101)	(287)	(172)
NET INCOME	154	155	422	276
Preferred Stock Dividends	0	0	0	(1)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$ 154	$ 155	$ 422	$ 275

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Earnings Per Share (EPS) (Tables)

9 Months Ended

Sep. 30, 2011

Earnings Per Share (EPS) [Abstract]

Basic And Diluted Earnings Per Share Computation

	Three Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2011				2010
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Continuing Operations	$	265	$	265	$	547	$	547	$	1,047	$	1,047	$	1,267	$	1,267
Discontinued Operations		29		29		20		20		96		96		15		15
Net Income	$	294	$	294	$	567	$	567	$	1,143	$	1,143	$	1,282	$	1,282
EPS Denominator (Thousands)
Weighted Average Common Shares Outstanding		505,909		505,909		505,945		505,945		505,959		505,959		506,001		506,001
Effect of Stock Options		0		193		0		165		0		172		0		148
Effect of Stock Performance Share Units		0		599		0		662		0		607		0		785
Effect of Restricted Stock Units		0		298		0		196		0		225		0		134
Total Shares		505,909		506,999		505,945		506,968		505,959		506,963		506,001		507,068
EPS:
Continuing Operations	$	0.52	$	0.52	$	1.08	$	1.08	$	2.07	$	2.06	$	2.50	$	2.50
Discontinued Operations		0.06		0.06		0.04		0.04		0.19		0.19		0.03		0.03
Net Income	$	0.58	$	0.58	$	1.12	$	1.12	$	2.26	$	2.25	$	2.53	$	2.53

Dividend Payments On Common Stock

	Three Months Ended September 30,				Nine Months Ended September 30,
Dividend Payments on Common Stock	2011		2010		2011		2010
Per Share	$	0.3425	$	0.3425	$	1.0275	$	1.0275
in Millions	$	173	$	173	$	520	$	520

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Fair Value Measurements (Fair Value Of Debt) (Details) (USD $) In Millions	Sep. 30, 2011		Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Carrying Amount	$ 8,969		$ 8,940
Long-term Debt, Fair Value	10,055	[1]	9,836	[1]
Power - Recourse Debt [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Carrying Amount	3,350		3,455
Long-term Debt, Fair Value	3,710	[1]	3,831	[1]
PSE&G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Carrying Amount	4,535		4,283
Long-term Debt, Fair Value	5,099	[1]	4,615	[1]
Transition Funding (PSE&G) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Carrying Amount	948		1,090
Long-term Debt, Fair Value	1,080	[1]	1,245	[1]
Transition Funding II [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Carrying Amount	50		55
Long-term Debt, Fair Value	54	[1]	59	[1]
Energy Holdings Project Level, Non-Recourse Debt [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Carrying Amount	46		47
Long-term Debt, Fair Value	46	[1]	47	[1]
PSEG (Parent) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Carrying Amount	40		10
Long-term Debt, Fair Value	$ 66	[1]	$ 39	[1]

[1] Fair value excludes unamortized discounts, including amounts related to the Debt Exchange between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company.

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Related-Party Transactions (Schedule Of Related Party Transactions, Payables) (Details) (USD $)	1 Months Ended			9 Months Ended		12 Months Ended		9 Months Ended		12 Months Ended		9 Months Ended
	Jan. 31, 2008	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011 Power [Member]		Dec. 31, 2010 Power [Member]		Sep. 30, 2011 PSE&G [Member]		Dec. 31, 2010 PSE&G [Member]		Sep. 30, 2011 Power's Share Of PSE&G's Liability [Member]
Related Party Transaction [Line Items]
Payable to Power through BGS and BGSS								$ (110,000,000)	[1]	$ (372,000,000)	[1]
Payable to Power Related to Gas Supply Hedges for BGSS								(64,000,000)	[1]	(58,000,000)	[1]
Payable to Power for SREC Liability								(7,000,000)	[2]	(7,000,000)	[2]
Payable to Services				(23,000,000)	[3]	(26,000,000)	[3]	(42,000,000)		(48,000,000)
Tax Sharing Receivable from PSEG				(18,000,000)	[4]	380,000,000	[4]	467,000,000	[4]	321,000,000	[4]
Current Unrecognized Tax Receivable from PSEG				5,000,000	[4]	(1,000,000)	[4]	59,000,000	[4]	73,000,000	[4]
Receivable from PSEG								1,000,000		6,000,000
Accounts Payable-Affiliated Companies, net								304,000,000		(85,000,000)
Working Capital Advances to Services				17,000,000	[5]	17,000,000	[5]	33,000,000	[5]	33,000,000	[5]
Long-Term Accrued Taxes Payable		(234,000,000)	(248,000,000)					(54,000,000)	[4]	(74,000,000)	[4]
Accrued liability for excess SREC costs								17,000,000		17,000,000		7,000,000
Limit set for costs in excess of amount per solar renewable energy credit	$ 300

[1] PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G's BGSS and other contractual requirements through March 31, 2012 and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.

[2] In 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU's 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court's ruling. PSE&G, along with other New Jersey utilities and Power participated at the hearing and filed comments. The BPU has not yet issued a decision. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of September 30, 2011 and December 31, 2010, including approximately $7 million for Power's share which is included in PSE&G's Accounts Payable—Affiliated Companies as of December 31, 2010. Under current guidance, Power is unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G's liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG's Condensed Consolidated Balance Sheet as of September 30, 2011 and December 31, 2010.

[3] 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.

[4] 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.

[5] 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.

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Financial Risk Management Activities (Schedule Providing Credit Risk From Others, Net Of Collateral) (Details) (USD $) In Millions	Sep. 30, 2011
Power [Member] | Investment Grade- External Rating [Member]
Derivative [Line Items]
Current Exposure	$ 396
Securities held as Collateral	46
Net Exposure	392
Number of Counterparties greater than 10%	3
Net Exposure of Counterparties greater than 10%	242	[1]
Power [Member] | Non-Investment Grade- External Rating [Member]
Derivative [Line Items]
Current Exposure	11
Securities held as Collateral	0
Net Exposure	11
Number of Counterparties greater than 10%	0
Net Exposure of Counterparties greater than 10%	0
Power [Member] | Investment Grade- No External Rating [Member]
Derivative [Line Items]
Current Exposure	9
Securities held as Collateral	0
Net Exposure	9
Number of Counterparties greater than 10%	0
Net Exposure of Counterparties greater than 10%	0
Power [Member] | Non-Investment Grade- No External Rating [Member]
Derivative [Line Items]
Current Exposure	9
Securities held as Collateral	0
Net Exposure	9
Number of Counterparties greater than 10%	0
Net Exposure of Counterparties greater than 10%	0
Power [Member]
Derivative [Line Items]
Current Exposure	425
Securities held as Collateral	46
Net Exposure	421
Number of Counterparties greater than 10%	3
Net Exposure of Counterparties greater than 10%	242
PSE&G [Member]
Derivative [Line Items]
Net Exposure	129
Nonaffiliated [Member]
Derivative [Line Items]
Net Exposure	$ 113

[1] Includes net exposure of $129 million with PSE&G. The remaining net exposure of $113 million is with two nonaffiliated power purchasers which are regulated investment grade counterparties.

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Available-For-Sale Securities (Narrative) (Details) (USD $) In Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Aug. 31, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Schedule of Available-for-sale Securities [Line Items]
Gross realized gains		$ 26	$ 26	$ 121	$ 86
Nuclear Decommissioning Trust (NDT) Funds [Member]
Schedule of Available-for-sale Securities [Line Items]
Amount of other-than-temporary impairments				10
Nuclear Decommissioning Trust (NDT) Funds [Member] | Power [Member] | Debt Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
After tax amount of net unrealized gains recognized in AOCI				32
Rabbi Trusts [Member]
Schedule of Available-for-sale Securities [Line Items]
Gross realized gains	31	0	31	0	31
Amount of other-than-temporary impairments				$ 3

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Pension And OPEB (Narrative) (Details) (USD $)	9 Months Ended							3 Months Ended	9 Months Ended		3 Months Ended
	Sep. 30, 2011	Sep. 30, 2011 Maximum [Member] Pension Plans, Defined Benefit [Member]	Sep. 30, 2011 Maximum [Member] Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2011 Minimum [Member] Pension Plans, Defined Benefit [Member]	Sep. 30, 2011 Minimum [Member] Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2011 Pension Plans, Defined Benefit [Member]	May 31, 2011 Pension Plans, Defined Benefit [Member]	Mar. 31, 2011 Pension Contribution [Member]	Sep. 30, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]	May 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]	Mar. 31, 2011 Postretirement Healthcare Plans Contribution [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension plans, contributions								$ 415,000,000			$ 11,000,000
Defined benefit plans, weighted average discount rate percent		5.51%	5.50%	5.31%	5.30%
Expected long-term rate of return on plan assets	8.50%
Actual rate of return	6.70%
Decreased defined benefit plans, annual net benefit cost						32,000,000			6,000,000
Defined benefit plans, projected benefit and accumulated benefit obligations							$ 4,300,000,000			$ 1,200,000,000

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Changes In Capitalization (Details) (USD $)	9 Months Ended	1 Months Ended					9 Months Ended
	Sep. 30, 2011 Power [Member] 2.75% Senior Notes Due 2016 [Member]	Sep. 30, 2011 Power [Member] 4.15% Senior Notes Due 2021 [Member]	Apr. 30, 2011 Power [Member] 7.75% Senior Notes Maturity In April 2011 [Member]	Aug. 31, 2011 PSE&G [Member] 0.85% Series G Medium Term Notes Due 2014 [Member]	Sep. 30, 2011 PSE&G [Member] Pollution Control Financing Authority Bonds [Member]	Sep. 30, 2011 PSE&G [Member] New Jersey Economic Development Authority Bonds [Member]	Sep. 30, 2011 Power [Member]	Sep. 30, 2011 PSE&G [Member]	Sep. 30, 2011 Energy Holdings [Member]
Debt Instrument [Line Items]
Cash dividend paid							$ 350,000,000
Payments of Transition Fundings' securitization debt								142,000,000
Payments of Transition Funding II's securitization debt								5,000,000
Payment of nonrecourse project debt									1,000,000
Payment of senior debt			606,000,000
Issuance of senior debt	250,000,000	250,000,000		250,000,000
Debt instrument maturity period	September 2016	September 2021	April	August 2014
Stated interest rate of debt instrument	2.75%	4.15%	7.75%	0.85%	0.95%	1.20%
Tax-exempt bonds carrying value					$ 164,000,000	$ 100,000,000

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Financing Receivables (Schedule Of Credit Risk Profile Based On Payment Activity) (Details) (PSE&G [Member], USD $) In Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2011	Dec. 31, 2010
Concentration Risk [Line Items]
Credit Risk	$ 93	$ 66
Commercial/Industrial Concentration Credit Risk [Member]
Concentration Risk [Line Items]
Credit Risk	86	62
Residential Concentration Credit Risk [Member]
Concentration Risk [Line Items]
Credit Risk	$ 7	$ 4

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Financing Receivables (Gross And Net Lease Investments) (Details) (Energy Holdings [Member], USD $) In Millions	Sep. 30, 2011	Dec. 31, 2010
Energy Holdings [Member]
Lease Receivables (net of Non-Recourse Debt)	$ 763	$ 896
Estimated Residual Value of Leased Assets	684	905
Total Investment in Rental Receivables	1,447	1,801
Unearned and Deferred Income	(450)	(546)
Gross Investments in Leases	997	1,255
Deferred Tax Liabilities	(804)	(899)
Net Investment in Leases	$ 193	$ 356

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Available-For-Sale Securities (Amount Of Available-For-Sale Debt Securities By Maturity Periods) (Details) (USD $) In Millions	Sep. 30, 2011
Available-For-Sale Securities [Abstract]
Available-for-sale debt securities, less than 1 year	$ 11
Available-for-sale debt securities, 1-5 Years	141
Available-for-sale debt securities, 6-10 Years	172
Available-for-sale debt securities, 11-15 Years	43
Available-for-sale debt securities, 16-20 Years	18
Available-for-sale debt securities, over 20 Years	254
Available-for-sale debt securities, total	$ 639

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Financial Information By Business Segments (Tables)

9 Months Ended

Sep. 30, 2011

Financial Information By Business Segments [Abstract]

Financial Information By Business Segments

	Power		PSE&G			Energy Holdings			Other(A)			Consolidated
	Millions
Three Months Ended September 30, 2011
Total Operating Revenues	$	1,398	$	1,841		$	(247	)	$	(372	)	$	2,620
Income (Loss) From Continuing Operations		273		154			(166	)		4			265
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		29		0			0			0			29
Net Income (Loss)		302		154			(166	)		4			294
Segment Earnings (Loss)		302		154			(166	)		4			294
Gross Additions to Long-Lived Assets		207		265			1			4			477
Three Months Ended September 30, 2010
Total Operating Revenues	$	1,523	$	2,007		$	58		$	(474	)	$	3,114
Income (Loss) From Continuing Operations		364		155			24			4			547
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		20		0			0			0			20
Net Income (Loss)		384		155			24			4			567
Segment Earnings (Loss)		384		155			24			4			567
Gross Additions to Long-Lived Assets		251		341			12			2			606
Nine Month Ended September 30, 2011
Total Operating Revenues	$	4,650	$	5,718		$	(206	)	$	(1,719	)	$	8,443
Income (Loss) From Continuing Operations		775		422			(164	)		14			1,047
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		96		0			0			0			96
Net Income (Loss)		871		422			(164	)		14			1,143
Segment Earnings (Loss)		871		422			(164	)		14			1,143
Gross Additions to Long-Lived Assets		530		939			2			8			1,479
Nine Months Ended September 30, 2010
Total Operating Revenues	$	4,983	$	5,987		$	114		$	(2,036	)	$	9,048
Income (Loss) From Continuing Operations		937		276			43			11			1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		15		0			0			0			15
Net Income (Loss)		952		276			43			11			1,282
Preferred Securities Dividends		0		(1	)		0			1			0
Segment Earnings (Loss)		952		275			43			12			1,282
Gross Additions to Long-Lived Assets		579		871			61			6			1,517
As of September 30, 2011
Total Assets	$	11,484	$	17,235		$	1,959		$	(767	)	$	29,911
Investments in Equity Method Subsidiaries	$	30	$	0		$	113		$	0		$	143
As of December 31, 2010
Total Assets	$	11,452	$	16,873		$	2,234		$	(650	)	$	29,909
Investments in Equity Method Subsidiaries	$	25	$	0		$	105		$	0		$	130

(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 at cost 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 17. Related-Party Transactions.