Edgar Filing: PUBLIC SERVICE ELECTRIC & GAS CO

FORM 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, 2010

¨ 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 ¨	No ¨
Public Service Electric and Gas Company	Yes ¨	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 15, 2010, Public Service Enterprise Group Incorporated had outstanding 505,933,984 shares of its sole class of Common Stock, without par value.

As of October 15, 2010, 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		9
	Notes to Condensed Consolidated Financial Statements		13
	Note 1. Organization and Basis of Presentation		13
	Note 2. Recent Accounting Standards		14
	Note 3. Variable Interest Entities		15
	Note 4. Asset Dispositions		16
	Note 5. Available-for-Sale Securities		17
	Note 6. Pension and Other Postretirement Employee Benefits (OPEB)		21
	Note 7. Commitments and Contingent Liabilities		22
	Note 8. Changes in Capitalization		34
	Note 9. Financial Risk Management Activities		35
	Note 10. Fair Value Measurements		42
	Note 11. Other Income and Deductions		49
	Note 12. Income Taxes		50
	Note 13. Comprehensive Income, Net of Tax		52
	Note 14. Earnings Per Share (EPS)		53
	Note 15. Financial Information by Business Segments		54
	Note 16. Related-Party Transactions		55
	Note 17. Guarantees of Debt		58
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		61
	Overview of 2010 and Future Outlook		61
	Results of Operations		66
	Liquidity and Capital Resources		76
	Capital Requirements		79
	Accounting Matters		79
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		80
Item 4.	Controls and Procedures		81
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		82
Item 1A.	Risk Factors		82
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		82
Item 5.	Other Information		82
Item 6.	Exhibits		87
	Signatures		88

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. These include, but are not limited to, future performance, revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial Statements—Note 7. 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, transmission planning and cost allocation rules, including rules regarding who is permitted to build transmission going forward, 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 operations of our generating units,

•

changes in nuclear regulation and/or developments in the nuclear power industry generally 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,

•

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,

•

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.

iii

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,
	2010			2009			2010			2009
OPERATING REVENUES	$	3,254		$	3,040		$	9,389		$	9,520
OPERATING EXPENSES
Energy Costs		1,355			1,241			4,270			4,376
Operation and Maintenance		601			621			1,915			1,922
Depreciation and Amortization		265			224			730			634
Taxes Other Than Income Taxes		31			30			101			100

Total Operating Expenses		2,252			2,116			7,016			7,032

OPERATING INCOME		1,002			924			2,373			2,488
Income from Equity Method Investments		4			6			12			17
Other Income		75			43			165			205
Other Deductions		(9	)		(19	)		(37	)		(118	)
Other-Than-Temporary Impairments		(3	)		0			(9	)		(61	)
Interest Expense		(120	)		(129	)		(356	)		(407	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		949			825			2,148			2,124
Income Tax (Expense) Benefit		(382	)		(337	)		(866	)		(881	)

NET INCOME	$	567		$	488		$	1,282		$	1,243

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC		505,945			505,982			506,001			505,986

DILUTED		506,968			507,242			507,068			506,957

EARNINGS PER SHARE:
BASIC		1.12		$	0.96		$	2.53		$	2.45

DILUTED		1.12		$	0.96		$	2.53		$	2.45

DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.3425		$	0.3325		$	1.0275		$	0.9975

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	September 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	332		$	350
Accounts Receivable, net of allowances of $57 and $79 in 2010 and 2009, respectively		1,211			1,229
Unbilled Revenues		276			411
Fuel		812			806
Materials and Supplies, net		373			361
Prepayments		331			161
Derivative Contracts		275			243
Other		61			85

Total Current Assets		3,671			3,646

PROPERTY, PLANT AND EQUIPMENT		23,458			22,069
Less: Accumulated Depreciation and Amortization		(6,995	)		(6,629	)

Net Property, Plant and Equipment		16,463			15,440

NONCURRENT ASSETS
Regulatory Assets		4,105			4,402
Regulatory Assets of Variable Interest Entities (VIEs)		1,181			1,367
Long-Term Investments		1,698			2,032
Nuclear Decommissioning Trust (NDT) Funds		1,270			1,199
Other Special Funds		158			149
Goodwill		16			16
Other Intangibles		129			123
Derivative Contracts		172			123
Restricted Cash of VIEs		21			17
Other		220			216

Total Noncurrent Assets		8,970			9,644

TOTAL ASSETS	$	29,104		$	28,730

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	September 30,			December 31,
	2010			2009
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	800		$	323
Securitization Debt of VIEs Due Within One Year		204			198
Commercial Paper and Loans		0			530
Accounts Payable		992			1,081
Derivative Contracts		123			201
Accrued Interest		159			102
Accrued Taxes		38			90
Deferred Income Taxes		76			0
Clean Energy Program		189			166
Obligation to Return Cash Collateral		101			95
Other		336			428

Total Current Liabilities		3,018			3,214

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		4,232			4,139
Regulatory Liabilities		498			397
Regulatory Liabilities of VIEs		8			7
Asset Retirement Obligations		454			439
Other Postretirement Benefit (OPEB) Costs		1,088			1,095
Accrued Pension Costs		711			1,094
Clean Energy Program		270			400
Environmental Costs		671			704
Derivative Contracts		39			40
Long-Term Accrued Taxes		247			538
Other		151			140

Total Noncurrent Liabilities		8,369			8,993

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		7,121			6,481
Securitization Debt of VIEs		998			1,145
Project Level, Non-Recourse Debt		33			19

Total Long-Term Debt		8,152			7,645

SUBSIDIARY'S PREFERRED STOCK WITHOUT MANDATORY REDEMPTION		0			80

STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2010 and 2009—533,556,660 shares		4,796			4,788
Treasury Stock, at cost, 2010—27,622,433 shares; 2009—27,567,030 shares		(594	)		(588	)
Retained Earnings		5,466			4,704
Accumulated Other Comprehensive Loss		(111	)		(116	)

Total Common Stockholders’ Equity		9,557			8,788
Noncontrolling Interest		8			10

Total Stockholders’ Equity		9,565			8,798
Total Capitalization		17,717			16,523

TOTAL LIABILITIES AND CAPITALIZATION	$	29,104		$	28,730

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For the Nine Months Ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,282		$	1,243
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		730			634
Amortization of Nuclear Fuel		102			88
Provision for Deferred Income Taxes (Other than Leases) and ITC		205			209
Non-Cash Employee Benefit Plan Costs		236			260
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes		(391	)		(542	)
Net (Gain) Loss on Lease Investments		(51	)		(135	)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(42	)		(125	)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		35			55
Over (Under) Recovery of Societal Benefits Charge (SBC)		(55	)		40
Market Transition Charge Refund, net		98			0
Cost of Removal		(47	)		(38	)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(73	)		(25	)
Realized Gains from Rabbi Trust		(31	)		0
Net Change in Certain Current Assets and Liabilities		(237	)		252
Employee Benefit Plan Funding and Related Payments		(483	)		(426	)
Other		61			(149	)

Net Cash Provided By (Used In) Operating Activities		1,339			1,341

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(1,517	)		(1,232	)
Proceeds from the Sale of Capital Leases and Investments		427			729
Proceeds from Sales of Available-for-Sale Securities		886			1,633
Investments in Available-for-Sale Securities		(905	)		(1,655	)
Restricted Funds		(2	)		113
Other		15			(7	)

Net Cash Provided By (Used In) Investing Activities		(1,096	)		(419	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans		(530	)		224
Issuance of Long-Term Debt		1,608			209
Redemption of Long-Term Debt		(548	)		(584	)
Repayment of Non-Recourse Debt		(3	)		(284	)
Redemption of Securitization Debt		(140	)		(133	)
Premium Paid on Debt Exchange		(13	)		(36	)
Cash Dividends Paid on Common Stock		(520	)		(505	)
Redemption of Preferred Securities		(80	)		0
Other		(35	)		(4	)

Net Cash Provided By (Used In) Financing Activities		(261	)		(1,113	)

Net Increase (Decrease) in Cash and Cash Equivalents		(18	)		(191	)
Cash and Cash Equivalents at Beginning of Period		350			321

Cash and Cash Equivalents at End of Period	$	332		$	130

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	1,080		$	1,060
Interest Paid, Net of Amounts Capitalized	$	299		$	344

See Notes to Condensed Consolidated Financial Statements.

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	For The Three Months Ended September 30,						For The Nine Months Ended September 30,
	2010			2009			2010			2009
OPERATING REVENUES	$	1,663		$	1,564		$	5,324		$	5,391
OPERATING EXPENSES
Energy Costs		714			599			2,732			2,757
Operation and Maintenance		263			265			817			820
Depreciation and Amortization		48			48			144			152

Total Operating Expenses		1,025			912			3,693			3,729

OPERATING INCOME		638			652			1,631			1,662
Other Income		44			40			126			196
Other Deductions		(9	)		(17	)		(36	)		(111	)
Other-Than-Temporary Impairments		(2	)		0			(8	)		(60	)
Interest Expense		(37	)		(37	)		(119	)		(125	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		634			638			1,594			1,562
Income Tax (Expense) Benefit		(250	)		(256	)		(642	)		(619	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	384		$	382		$	952		$	943

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

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	September 30, 2010			December 31, 2009
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	26		$	64
Accounts Receivable		379			425
Accounts Receivable—Affiliated Companies, net		283			459
Short-Term Loan to Affiliate		309			0
Fuel		812			806
Materials and Supplies, net		286			290
Derivative Contracts		254			231
Prepayments		72			64
Other		0			3

Total Current Assets		2,421			2,342

PROPERTY, PLANT AND EQUIPMENT		9,104			8,579
Less: Accumulated Depreciation and Amortization		(2,415	)		(2,194	)

Net Property, Plant and Equipment		6,689			6,385

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds		1,270			1,199
Goodwill		16			16
Other Intangibles		122			114
Other Special Funds		31			30
Derivative Contracts		89			118
Long-Term Accrued Taxes		11			39
Other		86			90

Total Noncurrent Assets		1,625			1,606

TOTAL ASSETS	$	10,735		$	10,333

LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	650			0
Accounts Payable		470			622
Short-Term Loan from Affiliate		0			194
Derivative Contracts		123			201
Deferred Income Taxes		123			0
Accrued Interest		84			43
Other		116			163

Total Current Liabilities		1,566			1,223

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		660			644
Asset Retirement Obligations		239			226
Other Postretirement Benefit (OPEB) Costs		166			158
Derivative Contracts		39			26
Accrued Pension Costs		227			344
Environmental Costs		51			52
Other		99			72

Total Noncurrent Liabilities		1,481			1,522

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
LONG-TERM DEBT
Total Long-Term Debt		2,805			3,121

MEMBER’S EQUITY
Contributed Capital		2,028			2,028
Basis Adjustment		(986	)		(986	)
Retained Earnings		3,889			3,486
Accumulated Other Comprehensive Loss		(48	)		(61	)

Total Member’s Equity		4,883			4,467

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	10,735		$	10,333

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

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For the Nine Months Ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	952		$	943
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		144			152
Amortization of Nuclear Fuel		102			88
Provision for Deferred Income Taxes and ITC		145			105
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(42	)		(125	)
Non-Cash Employee Benefit Plan Costs		53			58
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(73	)		(25	)
Realized Gains from Rabbi Trust		(7	)		0
Impairment of Emissions Allowances		15			0
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies		(2	)		(39	)
Margin Deposits		(26	)		63
Accounts Receivable		16			312
Accounts Payable		(99	)		(236	)
Accounts Receivable/Payable-Affiliated Companies, net		186			260
Accrued Interest Payable		41			45
Other Current Assets and Liabilities		(42	)		(50	)
Employee Benefit Plan Funding and Related Payments		(131	)		(112	)
Other		24			(10	)

Net Cash Provided By (Used In) Operating Activities		1,256			1,429

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(579	)		(636	)
Proceeds from Sales of Available-for-Sale Securities		759			1,633
Investments in Available-for-Sale Securities		(778	)		(1,653	)
Short-Term Loan—Affiliated Company, net		(309	)		55
Restricted Funds		2			111
Other		26			20

Net Cash Provided By (Used In) Investing Activities		(879	)		(470	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt		594			209
Contributed Capital		0			229
Cash Dividend Paid		(550	)		(815	)
Redemption of Long-Term Debt		(248	)		(530	)
Short-Term Loan—Affiliated Company, net		(194	)		65
Cash Payment for Debt Exchange		(13	)		0
Accounts Receivable due from Affiliate Related to Debt Exchange		0			(101	)
Other		(4	)		0

Net Cash Provided By (Used In) Financing Activities		(415	)		(943	)

Net Increase (Decrease) in Cash and Cash Equivalents		(38	)		16
Cash and Cash Equivalents at Beginning of Period		64			40

Cash and Cash Equivalents at End of Period	$	26		$	56

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	558		$	464
Interest Paid, Net of Amounts Capitalized	$	85		$	94

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

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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,
	2010			2009			2010			2009
OPERATING REVENUES	$	2,007		$	1,943		$	5,987		$	6,321
OPERATING EXPENSES
Energy Costs		1,115			1,167			3,572			4,005
Operation and Maintenance		327			351			1,084			1,090
Depreciation and Amortization		209			169			563			462
Taxes Other Than Income Taxes		31			30			101			100

Total Operating Expenses		1,682			1,717			5,320			5,657

OPERATING INCOME		325			226			667			664
Other Income		14			2			22			7
Other Deductions		(1	)		0			(2	)		(2	)
Interest Expense		(82	)		(77	)		(239	)		(236	)

INCOME (LOSS) BEFORE INCOME TAXES		256			151			448			433
Income Tax (Expense) Benefit		(101	)		(63	)		(172	)		(177	)

NET INCOME		155			88			276			256
Preferred Stock Dividends		0			(1	)		(1	)		(3	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	155		$	87		$	275		$	253

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	September 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	115		$	240
Accounts Receivable, net of allowances of $56 in 2010 and $78 in 2009, respectively		818			800
Unbilled Revenues		276			411
Materials and Supplies		87			70
Prepayments		212			86
Deferred Income Taxes		37			52
Other		22			3

Total Current Assets		1,567			1,662

PROPERTY, PLANT AND EQUIPMENT		13,749			12,933
Less: Accumulated Depreciation and Amortization		(4,311	)		(4,187	)

Net Property, Plant and Equipment		9,438			8,746

NONCURRENT ASSETS
Regulatory Assets		4,105			4,402
Regulatory Assets of VIEs		1,181			1,367
Long-Term Investments		218			204
Other Special Funds		54			51
Derivative Contracts		37			5
Restricted Cash of VIEs		21			17
Other		87			79

Total Noncurrent Assets		5,703			6,125

TOTAL ASSETS	$	16,708		$	16,533

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	September 30,		December 31,
	2010		2009
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	0	$	300
Securitization Debt of VIEs Due Within One Year		204		198
Accounts Payable		401		337
Accounts Payable—Affiliated Companies, net		141		496
Accrued Interest		68		56
Clean Energy Program		189		166
Obligation to Return Cash Collateral		101		95
Other		206		214

Total Current Liabilities		1,310		1,862

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC		2,815		2,710
Other Postretirement Benefit (OPEB) Costs		870		887
Accrued Pension Costs		338		565
Regulatory Liabilities		498		397
Regulatory Liabilities of VIEs		8		7
Clean Energy Program		270		400
Environmental Costs		620		652
Asset Retirement Obligations		213		211
Long-Term Accrued Taxes		118		96
Other		27		29

Total Noncurrent Liabilities		5,777		5,954

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		4,282		3,271
Securitization Debt of VIEs		998		1,145

Total Long-Term Debt		5,280		4,416

Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized;issued and outstanding, 2009—795,234 shares		0		80

STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized;issued and outstanding, 2010 and 2009—132,450,344 shares		892		892
Contributed Capital		420		420
Basis Adjustment		986		986
Retained Earnings		2,043		1,918
Accumulated Other Comprehensive Income		0		5

Total Stockholder’s Equity		4,341		4,221

Total Capitalization		9,621		8,717

TOTAL LIABILITIES AND CAPITALIZATION	$	16,708	$	16,533

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For The Nine Months Ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	276		$	256
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		563			462
Provision for Deferred Income Taxes and ITC		41			99
Non-Cash Employee Benefit Plan Costs		162			177
Realized Gains from Rabbi Trust		(11	)		0
Non-Cash Interest Expense		10			11
Cost of Removal		(47	)		(38	)
Market Transition Charge Refund, net		98			0
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		35			55
Over (Under) Recovery of SBC		(55	)		40
Other Non-Cash Charges		0			(2	)
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		117			253
Materials and Supplies		(17	)		(9	)
Prepayments		(126	)		(182	)
Accounts Payable		11			(6	)
Accounts Receivable/Payable-Affiliated Companies, net		(318	)		(334	)
Other Current Assets and Liabilities		8			(59	)
Employee Benefit Plan Funding and Related Payments		(305	)		(270	)
Other		(15	)		(31	)

Net Cash Provided By (Used In) Operating Activities		427			422

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(871	)		(580	)
Proceeds from Sales of Available-for-Sale Securities		54			1
Investments in Available-for-Sale Securities		(54	)		(1	)
Solar Loan Investments		(11	)		(18	)
Other		(4	)		4

Net Cash Provided By (Used In) Investing Activities		(886	)		(594	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt		0			54
Issuance of Long-Term Debt		1,014			0
Redemption of Long-Term Debt		(300	)		(60	)
Redemption of Securitization Debt		(140	)		(133	)
Redemption of Preferred Securities		(80	)		0
Contributed Capital		0			250
Deferred Issuance Costs		(9	)		0
Common Stock Dividend		(150	)		0
Preferred Stock Dividends		(1	)		(3	)

Net Cash Provided By (Used In) Financing Activities		334			108

Net Increase (Decrease) In Cash and Cash Equivalents		(125	)		(64	)
Cash and Cash Equivalents at Beginning of Period		240			91

Cash and Cash Equivalents at End of Period	$	115		$	27

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	182		$	47
Interest Paid, Net of Amounts Capitalized	$	213		$	223

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Note 1. Organization and Basis of Presentation

Organization

PSEG is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid Atlantic United States and in other select markets. PSEG’s four principal direct wholly owned subsidiaries are:

•

Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, 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. Pursuant to applicable BPU orders, PSE&G is also investing in the development of solar generation projects and energy efficiency programs within its service territory.

•

PSEG Energy Holdings L.L.C. (Energy Holdings)—which owns and operates primarily domestic projects engaged in the generation of energy and has invested in leveraged leases 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 is also investing in solar generation projects and 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.

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, 2009 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010.

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, 2009.

Reclassifications

Certain reclassifications have been made to the prior period financial statements to conform to the current presentation.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As a result of new guidance adopted in 2010 on Variable Interest Entities (VIEs), we are required to present certain consolidated amounts related to VIEs separately on the face of our Condensed Consolidated Balance Sheets for PSEG and PSE&G with prior period amounts being reclassified as appropriate. See Note 2. Recent Accounting Standards for additional information.

On October 1, 2009, Energy Holdings distributed the outstanding equity of PSEG Texas, LP (PSEG Texas) to PSEG. PSEG in turn contributed it to Power as an additional equity investment. This transaction was accounted for as a noncash transfer of an equity interest between entities under common control with prior period financial statements for Power being retrospectively adjusted to include the earnings related to PSEG Texas. As a result, Power’s Operating Revenues for the three months and nine months ended September 30, 2009 increased by $142 million and $294 million, respectively. Power’s Net Income for the three months and nine months ended September 30, 2009 increased by $35 million and $21 million, respectively.

Note 2. Recent Accounting Standards

New Standards Adopted during 2010

During 2010, we have adopted the following new accounting standards. The new standards adopted did not have a material impact on our financial statements. The following is a summary of the requirements and impacts of the new standards.

Accounting for VIEs

This accounting standard amends the criteria used to determine which enterprise has a controlling financial interest in a VIE. The amended standard includes the following provisions:

•

requires an enterprise to qualitatively assess whether it should consolidate a VIE based on whether it has (i) the power to direct the activities of a VIE that most significantly impact the economic performance of a VIE, and (ii) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,

•

requires an ongoing reconsideration of the primary beneficiary,

•

amends the VIE reconsideration events (triggering events), and

•

requires additional disclosures for the enterprise that consolidates a VIE (the primary beneficiary)—to present separately on the face of the consolidated balance sheet (i) assets of the consolidated VIE that can be used only to settle obligations of the consolidated VIE and (ii) liabilities of a consolidated VIE for which creditors have no recourse to the general credit of the primary beneficiary.

We adopted the standard on January 1, 2010 and there was no impact on our financial statements upon initial adoption, other than presentation. In accordance with the guidance, we continuously assess the primary beneficiaries of VIEs for which we have a variable interest. See Note 3. Variable Interest Entities for further information.

Improving Disclosures about Fair Value Measurements

•

requires disclosure of transfers between Level 1 and Level 2 and reasons for transfer,

•

requires disaggregation beyond the financial statement line item when disclosing fair value instruments in the hierarchy table, and

•

requires gross presentation in Level 3 rollforward (purchases, sales, issuances, and settlements) effective January 1, 2011.

We adopted the standard on January 1, 2010. We disclose the fair value instruments by appropriate classes, as required by this standard, and we do not have any transfers between Levels 1 and 2. See Note 10. Fair Value Measurements for further information.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

New Accounting Standards Issued But Not Yet Adopted

Disclosures about Credit Quality of Financing Receivables and Allowance for Credit Losses

This accounting standard update has been issued to provide greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables by requiring:

•

quantitative and qualitative information about the credit quality of financing receivables,

•

description of accounting policies and methodology used to estimate the allowance for credit losses, and

•

an analysis of financing receivables on “nonaccrual” or “past due” status.

We will adopt this new guidance effective December 31, 2010 and expect to enhance disclosure related to leveraged lease receivables.

Note 3. Variable Interest Entities

VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary of 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 the 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. The Transition Funding and Transition Funding II creditors do not have 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 and 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, 2010 and December 31, 2009. 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 2010 or in 2009. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding and Transition Funding II.

VIE for which Energy Holdings is the Primary Beneficiary

Energy Holdings has a variable interest through its equity investment in a project for energy storage where it is also the primary beneficiary. Energy Holdings has the power to direct the activities of the entity that most significantly impact the entity’s economic performance. Energy Holdings also has the obligation to fund up to $15 million in operating losses of the VIE through 2011. As of September 30, 2010, $7 million had been extended in the form of a note receivable.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As a result, Energy Holdings consolidates the assets and liabilities of this project which are disclosed below (excluding intercompany balances which are eliminated in consolidation):


	As of September 30,		As of December 31,
	2010		2009
	Millions
Current Assets	$	1	$	1
Noncurrent Assets	$	8	$	8

Other than the $15 million obligation to fund operating losses through 2011, Energy Holdings does not have any contractual or other obligation to provide additional financial support to the VIE. There are no third party debt obligations for this VIE.

Note 4. Asset Dispositions

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 Internal Revenue Service (IRS) has indicated its intention to disallow certain tax deductions taken in prior years.

During the first nine months of 2009, Energy Holdings sold its interest in twelve leveraged leases, including ten 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		2009		2010		2009
	Millions
Proceeds from Sales	$	204	$	219	$	365	$	679
Gain (Loss) on the Sales, after-tax	$	15	$	17	$	27	$	52

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 7. Commitments and Contingent Liabilities.

GWF Energy LLC (GWF Energy)

In May 2009, Energy Holdings entered into a Memorandum of Understanding under which it would sell, in two separate transactions, its ownership interest in GWF Energy, an equity method investment, for a total purchase price of $70 million. As a result, Energy Holdings recorded an after-tax impairment charge of $3 million.

Energy Holdings completed the first stage of the sale in June 2009 for approximately $7 million. Energy Holdings completed the second stage of the sale in September 2010 for approximately $63 million. The total proceeds from both sales were approximately the book value of the investment.

PPN Power Generating Company Limited (PPN)

In May 2009, Energy Holdings sold its ownership interest in PPN, which owns and operates a 330 MW generation facility in India for approximately book value.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Other

In May 2009, Energy Holdings sold its ownership interest in the Midland Cogeneration Venture LP for an after-tax gain of $2 million.

Note 5. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Funds

Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective 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, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	499	$	164	$	(6	)	$	657

Debt Securities
Government Obligations		316		10		0			326
Other Debt Securities		244		18		(1	)		261

Total Debt Securities		560		28		(1	)		587
Other Securities		26		0		0			26

Total Available-for-Sale Securities	$	1,085	$	192	$	(7	)	$	1,270


	As of December 31, 2009
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	475	$	180	$	(5	)	$	650

Debt Securities
Government Obligations		296		4		(3	)		297
Other Debt Securities		209		10		(3	)		216

Total Debt Securities		505		14		(6	)		513
Other Securities		37		0		(1	)		36

Total Available-for-Sale Securities	$	1,017	$	194	$	(12	)	$	1,199

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, 2010										As of December 31, 2009
	Less Than 12					Greater Than 12					Less Than 12					Greater Than 12
	Months					Months					Months					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)	$	80	$	(6	)	$	0	$	0		$	61	$	(5	)	$	0	$	0

Debt Securities
Government Obligations(B)		16		0			2		0			78		(2	)		15		(1	)
Other Debt Securities(C)		12		0			7		(1	)		59		(3	)		0		0

Total Debt Securities		28		0			9		(1	)		137		(5	)		15		(1	)

Other Securities		0		0			0		0			1		(1	)		0		0

Total Available-for-Sale Securities	$	108	$	(6	)	$	9	$	(1	)	$	199	$	(11	)	$	15	$	(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 several hundred companies with limited impairment durations and a severity that is generally less than ten percent of cost. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2010.

(B)

Debt Securities (Government)—Unrealized losses on Power’s NDT investments in US Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the US government or an agency of the US 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, 2010.

(C)

Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily with 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, 2010.

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,
	2010			2009			2010			2009
		Millions
Proceeds from Sales	$	302		$	156		$	728		$	1,631

Net Realized Gains (Losses):
Gross Realized Gains	$	26		$	29		$	86		$	156
Gross Realized Losses		(8	)		(14	)		(31	)		(125	)

Net Realized Gains	$	18		$	15		$	55		$	31

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions on Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $91 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on Power’s Condensed Consolidated Balance Sheet as of September 30, 2010.

The available-for-sale debt securities held as of September 30, 2010 had the following maturities:


Time Frame	Fair Value
	Millions
Less than one year	$	16
1 - 5 years		104
6 - 10 years		174
11 - 15 years		53
16 - 20 years		8
Over 20 years		232

	$	587

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

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (OCI). In 2010, other-than-temporary impairments of $8 million were recognized on securities in the NDT Funds. Any subsequent recoveries in the value of these securities would be recognized in OCI unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

Rabbi Trust

PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust”. In August 2010, PSEG revised the asset structure of the Rabbi Trust and realized gains of approximately $31 million as the investments were transitioned to a new asset allocation and investment manager. The new structure is expected to result in lower investment management fees.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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


	As of September 30, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	0	$	0	$	16
Debt Securities		141		1		0		142
Other Securities		0		0		0		0

Total PSEG Available-for-Sale Securities	$	157	$	1	$	0	$	158


	As of December 31, 2009
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	10	$	3	$	0	$	13
Debt Securities		101		21		0		122
Other Securities		14		0		0		14

Total PSEG Available-for-Sale Securities	$	125	$	24	$	0	$	149

The Rabbi Trust is 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. In each of the nine months ended September 30, 2010 and 2009, other-than-temporary impairments of $1 million were recognized on the equity investments of the Rabbi Trust.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
		Millions
Proceeds from Sales	$	158	$	0	$	158	$	2

Net Realized Gains (Losses)
Gross Realized Gains	$	31	$	0	$	31	$	0
Gross Realized Losses		0		0		0		(1	)

Net Realized Gains (Losses)	$	31	$	0	$	31	$	(1	)

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

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, 2010		As of December 31, 2009
	Millions
Power	$	31	$	30
PSE&G		54		51
Other		73		68

Total PSEG Available-for-Sale Securities	$	158	$	149

Note 6. Pension and Other Postretirement Employee Benefits (OPEB)

PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis. 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 12. Income Taxes for additional information.

Pension and OPEB costs for PSEG, Power and PSE&G 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,
	2010			2009			2010			2009			2010			2009			2010			2009
	Millions
Components of Net Periodic Benefit Cost:
Service Cost	$	21		$	19		$	4		$	3		$	65		$	57		$	12		$	9
Interest Cost		58			58			18			18			173			176			54			54
Expected Return on Plan Assets		(67	)		(54	)		(4	)		(3	)		(200	)		(162	)		(11	)		(9	)
Amortization of Net
Transition Obligation		0			0			6			7			0			0			20			21
Prior Service Cost		0			2			4			3			0			6			10			10
Actuarial Loss		31			29			2			0			92			85			6			(2	)

Net Periodic Benefit Cost	$	43		$	54		$	30		$	28		$	130		$	162		$	91		$	83
Effect of Regulatory Asset		0			0			5			5			0			0			15			15

Total Benefit Costs, Including Effect of Regulatory Asset	$	43		$	54		$	35		$	33		$	130		$	162		$	106		$	98

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	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,
	2010		2009		2010		2009		2010		2009		2010		2009
	Millions
Power	$	13	$	16	$	4	$	3	$	40	$	49	$	13	$	9
PSE&G		24		30		30		29		72		90		90		87
Other		6		8		1		1		18		23		3		2

Total Benefit Costs	$	43	$	54	$	35	$	33	$	130	$	162	$	106	$	98

As of May 31, 2010, PSEG had contributed its planned contributions for the year 2010 of $415 million and $11 million into its pension and postretirement healthcare plans, respectively.

Note 7. Commitments and Contingent Liabilities

Guaranteed Obligations

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

Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to

•

support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and

•

obtain credit.

Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.

In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to

•

fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and

•

all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).

Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Power is subject to

•

counterparty collateral calls related to commodity contracts, and

•

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

Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The face value of outstanding guarantees, current exposure and margin positions as of September 30, 2010 and December 31, 2009 are shown below:


	As of September 30, 2010			As of December 31, 2009
	Millions
Face Value of Outstanding Guarantees	$	1,924		$	1,783
Exposure under Current Guarantees	$	333		$	403
Letters of Credit Margin Posted	$	162		$	122
Letters of Credit Margin Received	$	133		$	123

Cash Deposited and Received
Counterparty Cash Margin Deposited	$	0		$	0
Counterparty Cash Margin Received	$	(43	)	$	(90	)
Net Broker Balance Received	$	(52	)	$	(31	)
In the event Power were to lose its investment grade rating:
Additional Collateral that could be Required	$	840		$	986
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	2,779		$	2,368
Additional Amounts Posted
Other Letters of Credit	$	107		$	52

Power nets receivables and payables with the corresponding net energy contract balances. See Note 9. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Payable.

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 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 by 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 U.S. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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. 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 69 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 proposes 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 2011.

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.

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 the 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. 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.

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 NJ 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.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

PSEG, Power and PSE&G cannot predict what further actions, if any, or the costs or the timing thereof, may be required with respect to the Passaic River, the NJDEP Litigation, the Newark Bay Study Area or with respect to natural resource damages claims; however, such costs could be material.

MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. The NJDEP has also announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface water bodies that have been impacted by hazardous substances from adjoining sites. In 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the ten most significant sites for cleanup. One of the sites identified was PSE&G’s former Camden Coke facility.

During the third quarter of 2010, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $668 million and $774 million from September 30, 2010 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $668 million on its Condensed Consolidated Balance Sheet as of September 30, 2010. Of this amount, $48 million was recorded in Other Current Liabilities and $620 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $668 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 November 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. The remaining projects necessary to implement this program are expected to be completed by the end of 2010 at an estimated cost of $200 million to $250 million for Mercer and $750 million to $800 million for Hudson, of which $932 million has been spent on both projects as of September 30, 2010.

In January 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Mercury Regulation

In 2005, the EPA established a limit for nickel emissions from oil fired electric generating units and a cap-and-trade program for mercury emissions from coal fired electric generating units.

In 2008, the United States Court of Appeals for the District of Columbia Circuit rejected the EPA’s mercury emissions program and required the EPA to develop standards for mercury and nickel emissions that adhere to the Maximum Available Control Technology (MACT) provisions of the Clean Air Act. In 2009, the EPA indicated that it intended to move forward with a rule-making process to develop MACT standards consistent with the Court’s ruling and agreed to finalize them by November 2011.

The full impact to PSEG of these developments is uncertain. It is expected that new MACT requirements will require more stringent control than the cap-and-trade program struck down by the D.C. Circuit Court; however, the costs of compliance with mercury MACT standards will have to be compared with the existing state level mercury control requirements, as described below.

Pennsylvania

In 2007, Pennsylvania finalized its “state-specific” requirements to reduce mercury emissions from coal fired electric generating units. These requirements were more stringent than the EPA’s vacated Clean Air Mercury Rule but not as stringent as would be required by a MACT process. In 2009, the Commonwealth Court of Pennsylvania struck down the state rule, indicating that the rule violated Pennsylvania law because it was inconsistent with the Clean Air Act. In December 2009, the Commonwealth Court’s decision was affirmed by the Supreme Court of Pennsylvania. Unless the law in Pennsylvania is changed requiring the regulation of mercury by the Pennsylvania Department of Environmental Protection, then our Pennsylvania generating stations likely will be subject to regulation under the EPA’s MACT rule. It is uncertain whether the Keystone and Conemaugh generating stations will be able to achieve the necessary reductions at these stations with currently planned capital projects under MACT regulation.

Connecticut

Mercury emissions control standards were effective in July 2008 and require coal fired power plants to achieve either an emissions limit or 90% mercury removal efficiency through technology installed to control mercury emissions. With the recently installed activated carbon injection and baghouse at Bridgeport Unit 3, Power has demonstrated that it complies with the mercury limits in these standards.

New Jersey

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.

Power has achieved or will achieve the required reductions with mercury control technologies 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 Reduction

New Jersey

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 generation 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 generation units (approximately 800 MW) by April 30, 2015.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Power has been working with the NJDEP throughout the development of this rulemaking to minimize financial impact and to provide for transitional lead time to address the retirement of electric generation units. Power cannot predict the financial impact resulting from compliance with this rulemaking.

Connecticut

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. On April 30, 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.

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 the second quarter of 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, 2010 and December 31, 2009.

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 the 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. Power has filed or will be filing applications for permits in a variety of states that require discharge.

Pursuant to a consent decree with environmental groups, the EPA was required to promulgate rules governing cooling water intake structures under Section 316(b) of the FWPCA. In 2004, the EPA published a rule which did not mandate the use of cooling towers at large existing generating plants. Rather, the rule 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.

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 Phase II 316(b) rules published in 2004, which govern cooling water intake structures at large electric generating facilities. Power had historically used restoration and/or a site-specific cost-benefit test in applications it had filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer. However, the 316(b) rules would also have been applicable to Bridgeport, and possibly, the Sewaren and New Haven stations. In addition to the Salem renewal application, permit renewal applications have been submitted to the NJDEP for Hudson and Sewaren and to the Connecticut Department of Environmental Protection for Bridgeport.

Portions of the 316(b) rule were challenged by certain northeast states, environmentalists and industry groups. In January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision that remanded major portions of the regulations and determined that Section 316(b) of the FWPCA does not support the use of restoration and the site-specific cost-benefit test. In April 2009, the U.S. Supreme Court reversed the Second

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Circuit’s opinion, concluding 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. The matter was sent back to the Second Circuit for further proceedings consistent with the Supreme Court’s opinion. In September 2009, the Second Circuit issued an order remanding the matter to the EPA in light of the Supreme Court’s opinion.

The Supreme Court’s ruling allows the EPA to continue to use the site-specific cost-benefit test in determining best technology available for minimizing adverse environmental impact. However, 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 could 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.

The EPA has stated that it anticipates proposing a rule in February 2011, and publishing a final rule in July 2012. Until a new rule governing cooling water intake structures at existing power generating stations is finalized, the EPA and states implementing the FWPCA have been instructed to issue permits on a case-by-case basis using the agency’s best professional judgment.

In addition to the anticipated 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 will 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. The draft permit is subject to public comment and review prior to being finalized by the NJDEP. We 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.

Stormwater

In October 2008, the NJDEP notified Power that it must apply for an individual stormwater discharge permit for its Hudson generating station. Hudson stores its coal in an open air pile and, as a result, it is exposed to precipitation. Discharge of stormwater from Hudson has been regulated pursuant to a Basic Industrial Stormwater General Permit, authorization of which has been previously approved by the NJDEP. The NJDEP has determined that Hudson is no longer eligible to utilize this general permit and must apply for an individual NJPDES permit for stormwater discharges. While the full extent of these requirements remains unclear, to the extent Power may be required to reduce or eliminate the exposure of coal to stormwater, or be required to construct technologies preventing the discharge of stormwater to surface water or groundwater, those costs could be material.

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. Completion of these upgrades is expected to result in an increase of Power’s share of nominal capacity by 32 MW (14 MW at Unit 3 in 2011 and 18 MW at Unit 2 in 2012). Total expenditures through September 30, 2010 were $44 million and are expected to continue through 2012.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 133 MW with an anticipated cost of approximately $400 million. Total expenditures through September 30, 2010 were $10 million and are expected to continue through 2016.

Connecticut

Power has been selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval has been received and construction is expected to commence 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 $130 million to $140 million. Total capitalized expenditures through September 30, 2010 were $25 million, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. 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. Final approval has been received and construction is expected to commence in the second quarter of 2011. The project is expected to be in service by June 2012. In addition, capacity in the amount of 89 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 period. Final approval has been received, and the project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through September 30, 2010 were $16 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 40MW 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’s remaining 2010 expenditures for these solar units are anticipated to be approximately $20 million, with additional purchases made on a quarterly basis during the remaining two-year term of the purchase agreement.

Another aspect of the Solar 4 All program is the installation of another 40 MW solar systems on land and buildings owned by PSE&G and third parties. As of September 30, 2010, there were 15 projects in various phases of development representing 24 MW, with an estimated investment of about $115 million. These projects include the following:

•

PSE&G has entered into contracts with four developers for solar capacity to be developed on land it owns in Edison, Linden, Trenton and Hamilton. The Trenton project is operational. The other projects are under construction and are expected to be operational during the fourth quarter of 2010.

•

PSE&G has also awarded another 11 contracts for the installation of solar systems on third party owned sites. Construction started during the third quarter on a number of these projects, and all are expected to be operational in the fourth quarter of 2010.

Solar Source

Energy Holdings has developed a solar project in western New Jersey and has acquired two additional solar projects in Florida and Ohio, which together have a total capacity of approximately 29 MW. The projects have all commenced operations. Energy Holdings issued guarantees to cover the construction costs of the Florida and Ohio projects and as of September 30, 2010 had $8 million of future payment obligations related to the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

remaining construction milestones to be achieved. By the end of the fourth quarter 2010, it is expected that these payment obligations will be zero. The total investment for the three projects is expected to be approximately $117 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 (SMA) 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

2007

2008

2009

2010

36-Month Terms Ending

May 2010

May 2011

May 2012

May 2013

(A)

Eligible Load (MW)

2,758

2,800

2,900

2,800

$ per kWh

0.09888

0.11150

0.10372

0.09577

(A)	Prices set in the 2010 BGS auction became effective on June 1, 2010 when the 2007 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 16. 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 concentrates and uranium hexafluoride 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2011 and a portion for 2012, 2013 and 2014 at Salem, Hope Creek and Peach Bottom.

As of September 30, 2010, the total minimum purchase requirements included in these commitments were as follows:


Fuel Type	Commitments through 2014		Power’s Share
		Millions
Nuclear Fuel
Uranium	$	623	$	360
Enrichment	$	543	$	325
Fabrication	$	206	$	127
Natural Gas	$	738	$	738
Coal/Oil/Limestone	$	1,100	$	1,100

Included in the $1,100 million commitment for coal, oil and limestone above is $520 million related to a certain coal contract under which Power can cancel contractual deliveries at minimal cost. Through the nine months ended September 2010, Power has cancelled coal shipments at a total cost of $8 million.

The Texas generation facilities also have a contract for low BTU content gas which commenced in late 2009 with a term of 15 years and a minimum volume of approximately 13 MMBTUs per year. The gas must meet availability and quality specifications. Power has the right to cancel delivery of the gas at a minimal cost.

Regulatory Proceedings

Competition Act

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 July 2007, PSE&G filed a motion to dismiss the amended Complaint, which was granted in October 2007. 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. PSE&G has not yet received the written order from the BPU memorializing its decision.

BPU Deferral Audit

The BPU Energy and Audit Division conducts audits of deferred balances under various adjustment clauses. A draft Deferral Audit Phase II report relating to the 12-month period ended July 31, 2003 was released to the BPU in April 2005.

That report, which addressed Societal Benefits Charges (SBC), Market Transition Charge (MTC) and non-utility generation (NUG) deferred balances, found that the Phase II deferral balances complied in all

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

material respects with applicable BPU Orders. However, the BPU Staff raised certain questions with respect to the reconciliation method PSE&G had employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. The matter was referred to the Office of Administrative Law.

In January 2009, the Administrative Law Judge (ALJ) issued a decision which upheld PSE&G’s central contention that the 2004 BPU Order approving the Phase I settlement resolved the issues being raised by the Staff and the NJ Division of Rate Counsel, and that these issues should not be subject to re-litigation with respect to the first three years of the transition period. The ALJ’s decision stated that the BPU could elect to convene a separate proceeding to address the fourth and final year reconciliation of MTC recoveries.

In September 2009, the BPU rejected the ALJ’s initial decision and elected to maintain jurisdiction over the matter. In June 2010, the BPU approved a settlement agreement resolving the MTC issue. Under the agreement, PSE&G will refund $122 million to electric customers over a two-year period through a new component of the NUG charge. As a result, during the second quarter of 2010, PSE&G recorded a pre-tax charge of $122 million, which is included in Operating Revenues and the corresponding Regulatory Liability. Through September 2010, $24 million has been refunded.

Retail Gas Transportation Rates

In July 2010, as part of PSE&G’s gas base rate proceeding, the BPU ordered a supplemental and expedited review of certain issues related to the gas transportation rate that PSE&G charges to Power, including:

•

whether the current rate charged to Power should be changed prospectively,

•

whether any retroactive relief is warranted with respect to these charges to Power since 2002,

•

whether the SBC and other clause charges are applicable, and

•

whether the Transportation Service Gas-Nonfirm (TSG-NF) rate should apply to Power and other electric generation customers in PSE&G’s service territory.

In the event that the BPU were to find that the rate charged to Power was not proper and order refunds, the results could be material. PSE&G believes such refunds would constitute retroactive ratemaking and are prohibited under applicable law. However, the outcome of the regulatory proceeding cannot be predicted. Hearings before the BPU were scheduled to commence on October 25, 2010. Since settlement discussions are in progress, the BPU has adjourned the hearings so that settlement efforts can continue. In July, a complaint was filed by an independent power generator against Power at FERC related to the gas transportation rate. The complaint asserts that the existing rate charged to Power violates FERC’s affiliate rules and Power’s market-based rate authority. The complaint requests, among other things, that Power’s market-based rate authority be revoked. While Power views revocation of its market-based rate authority as unlikely, it is not possible to predict the outcome of this proceeding. PSEG believes that the rates charged to Power were and continue to be lawful and appropriate, and has asserted this position vigorously at FERC.

Consolidated Tax Adjustments

A BPU proceeding regarding consolidated tax adjustments is expected to begin in 2010. New Jersey is one of five states that make consolidated tax adjustments. These adjustments are intended to allocate tax benefits realized by non-regulated subsidiaries to utility customers under certain circumstances. The generic proceeding is expected to address the appropriateness of the adjustment and the methodology and mechanics of the calculation. The policy adopted by the BPU will influence the non-regulated investments made by PSEG in the future.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

billion for all years. PSE&G’s share is $705 million. PSE&G has recorded a discounted liability of $459 million as of September 30, 2010. Of this amount, $189 million was recorded as a current liability and $270 million as a noncurrent liability. 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 SBC.

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, four of which were decided in favor of the government. An appeal of one of these decisions was affirmed. The fifth 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 continues to pursue opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds. Including four terminations this year, Energy Holdings has terminated a total of 17 of these leasing transactions since December 2008, leaving only one remaining in its portfolio, and reduced the related cash tax exposure by $1 billion. PSEG’s total gross investment in such transactions decreased from $347 million as of December 31, 2009 to $63 million as of September 30, 2010.

Cash Impact

As of September 30, 2010, an aggregate of approximately $330 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, reducing its potential net cash exposure to $10 million. 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 the rate of $4 million per quarter during 2010. 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 $30 million to $50 million of tax would be due for tax positions through September 30, 2010.

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 $210 million and $540 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 proposed by the IRS, would result in an additional earnings charge of $120 million to $140 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 8. Changes in Capitalization

The following capital transactions occurred in the first nine months of 2010:

Power

•

issued $300 million of 2.50% unsecured Senior Notes due April 2013 in April,

•

issued $250 million of 5.125% unsecured Senior Notes due April 2020 in April,

•

redeemed $161 million of 6.50% Medium-Term Notes (MTNs) due 2014 in April,

•

redeemed $48 million of 6.00% MTNs due 2013 in April,

•

exchanged an aggregate principal amount of $195 million of 7.75% Senior Notes due 2011 for $208 million comprised of $156 million in newly issued 5.125% Senior Notes due April 2020 and cash payments of $52 million. Since the debt exchange was treated as a debt modification, the resulting premium of $13 million was deferred and will be amortized over the term of the newly issued debt. The deferred amount is reflected as an offset to Long-Term Debt on Power’s Condensed Consolidated Balance Sheet.

•

converted $44 million of its Senior Notes servicing and securing the 4.00% Pollution Control Bonds of the Pennsylvania Economic Development Authority (PEDFA) to variable rate in January 2009 when the PEDFA Bonds were converted to variable rate demand bonds. Power reacquired the PEDFA Bonds in December 2009. In January 2010, Power caused the PEDFA Bonds to be converted from Alternative Minimum Tax (AMT) to non-AMT status and to be remarketed as variable rate demand bonds backed by a letter of credit expiring in January 2011.

•

paid cash dividends of $550 million to PSEG.

PSE&G

•

remarketed $64 million 2003 Series A due May 2028, $50 million 2003 Series B-1 due November 2033 and $50 million 2003 Series B-2 due November 2033, totaling $164 million, tax-exempt variable rate bonds of the Pollution Control Financing Authority of Salem County (Salem County Authority Bonds) (non-AMT) as The Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds (Public Service Electric and Gas Company Project) mandatory puts due November 2011 at an initial term rate of 0.95% in September,

•

issued $250 million of 3.50% MTNs, Series G due August 2020 in August,

•

issued $300 million of 2.70% MTNs, Series G due May 2015 in May,

•

redeemed all of its $80 million of outstanding preferred stock in March,

•

paid $300 million of floating rate (Libor + .875%) First and Refunding Mortgage Bonds at maturity in March,

•

issued $300 million of 5.50% MTNs, Series G due March 2040 in March,

•

paid cash dividends of $150 million to PSEG,

•

paid $135 million of Transition Funding’s securitization debt, and

•

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

Energy Holdings

•

paid $3 million of nonrecourse project debt.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

PSE&G

In October 2010, at PSE&G’s request, the New Jersey Economic Development Authority (EDA) called $100 million of its 6.40% tax-exempt Pollution Control Revenue Refunding Bonds, 1994 Series A (Public Service Electric and Gas Company Project) due May 2032, and refinanced them with the issuance of $100 million of its Exempt Facility Revenue Refunding Bonds, 2010 Series A (Public Service Electric and Gas Project) (AMT), due December 2031 as multi-mode bonds with a mandatory put due December 2011 and an initial term rate of 1.20%. The EDA bonds that were redeemed were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds, Pollution Control Series P which were also redeemed. The new EDA bonds are serviced and secured by PSE&G’s First and Refunding Mortgage Bonds, Pollution Control Series AE of similar tenor.

Energy Holdings

In October 2010, Energy Holdings issued a call for redemption of the remaining $127 million outstanding principal balance of its 8.50% Senior Notes due June 2011. The call is expected to be completed in December 2010.

Note 9. 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 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, futures and firm transmission right 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, 2010 and December 31, 2009, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:


	As of September 30, 2010		As of December 31, 2009
		Millions
Fair Value of Cash Flow Hedges	$	329	$	286
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	181	$	184

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The expiration date of the longest-dated cash flow hedge at Power is in 2012. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the 12 months ending September 30, 2011 and September 30, 2012 are $150 million and $31 million, respectively. Ineffectiveness associated with these hedges was $(3) million at September 30, 2010.

Trading Derivatives

In general, the main 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. Power does engage in trading of electricity and energy-related products where such transactions are not associated with the output or fuel purchase requirements of our facilities. This trading consists mostly of energy supply contracts where we secure sales commitments with the intent to supply the energy services from purchases in the market rather than from our owned generation. Such trading activities are marked to market through the income statement and represent approximately two percent of Power’s gross margin.

Other Derivatives

Power enters into other contracts that are derivatives, but do not qualify for cash flow hedge accounting. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Prior to June 2009, some of the derivative contracts were also used in Power’s NDT Funds. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of September 30, 2010 and December 31, 2009 was $63 million and $8 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 through the use of fixed and floating rate debt and interest rate derivatives.

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. In January 2010, we entered into a series of interest rate swaps totaling $600 million converting $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and $300 million of Power’s $600 million of 6.95% of Senior Notes due June 2012 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. In 2009, PSEG had entered into three interest rate swaps also designated as fair value hedges. As of September 30, 2010 and December 31, 2009, the fair value of all the underlying hedges was $64 million and $(3) million, respectively.

Cash Flow Hedges

PSEG, Power 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, 2010, 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, 2010 and December 31, 2009. The Accumulated Other Comprehensive Loss related to interest rate derivatives designated as cash flow hedges was $(3) million and $(4) million as of each of September 30, 2010 and December 31, 2009, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Values of Derivative Instruments

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


	As of September 30, 2010
	Power												PSE&G		PSEG		Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges		Fair Value Hedges		Total Derivatives
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts			Netting (A)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
		Millions
Derivative Contracts
Current Assets	$	286		$	787		$	(819	)	$	254		$	3	$	18	$	275
Noncurrent Assets	$	70		$	200		$	(181	)	$	89		$	37	$	46	$	172

Total Mark-to-Market Derivative Assets	$	356		$	987		$	(1,000	)	$	343		$	40	$	64	$	447

Derivative Contracts
Current Liabilities	$	(24	)	$	(814	)	$	715		$	(123	)	$	0	$	0	$	(123	)
Noncurrent Liabilities	$	(3	)	$	(194	)	$	158		$	(39	)	$	0	$	0	$	(39	)

Total Mark-to-Market Derivative (Liabilities)	$	(27	)	$	(1,008	)	$	873		$	(162	)	$	0	$	0	$	(162	)

Total Net Mark-to-Market Derivative Assets (Liabilities)	$	329		$	(21	)	$	(127	)	$	181		$	40	$	64	$	285


	As of December 31, 2009
	Power												PSE&G		PSEG			Consolidated
Balance Sheet Location	Cash Flow Hedges			Non Hedges			Netting * (A) (as restated)			Total Power			Non Hedges		Fair Value Hedges			Total Derivatives
Balance Sheet Location	Energy- Related Contracts * (as restated)			Energy- Related Contracts * (as restated)			Netting * (A) (as restated)			Total Power			Energy- Related Contracts		Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	195		$	622		$	(586	)	$	231		$	1	$	11		$	243
Noncurrent Assets	$	162		$	125		$	(169	)	$	118		$	5	$	0		$	123

Total Mark-to-Market Derivative Assets	$	357		$	747		$	(755	)	$	349		$	6	$	11		$	366

Derivative Contracts
Current Liabilities	$	(57	)	$	(662	)	$	518		$	(201	)	$	0	$	0		$	(201	)
Noncurrent Liabilities	$	(14	)	$	(106	)	$	94		$	(26	)	$	0	$	(14	)	$	(40	)

Total Mark-to-Market Derivative (Liabilities)	$	(71	)	$	(768	)	$	612		$	(227	)	$	0	$	(14	)	$	(241	)

Total Net Mark-to-Market Derivative Assets (Liabilities)	$	286		$	(21	)	$	(143	)	$	122		$	6	$	(3	)	$	125

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

*	Disclosure Restatement

Subsequent to the issuance of Power’s Form 10-Q for the period ended June 30, 2010, Management determined that certain classifying entries were incorrectly included in the above Cash Flow Hedges, Non Hedges, and Netting disclosure table as of December 31, 2009, resulting in offsetting overstatements of both the previously disclosed gross balances of derivative assets and liabilities, as well as the disclosed netting amounts. As a result, such amounts disclosed in the table have been restated from the amounts previously reported to properly reflect the gross amounts of Cash Flow Hedge contracts and Non Hedge contracts and related Netting amounts. These corrections have no impact on Power’s Total Net Mark-to-Market Derivative Assets (Liabilities), amounts reflected in Power’s balance sheet (the “Total Power” column above), or PSEG’s consolidated “Total Derivatives.”

(A)

Represents the netting of fair value balances with the same counterparty and the application of collateral. As of September 30, 2010 and December 31, 2009, net cash collateral received of $127 million and $143 million, respectively, was netted against the corresponding net derivative contract positions. Of the $127 million as of September 30, 2010, cash collateral of $(182) million and $(51) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $78 million and $28 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $143 million as of December 31, 2009, cash collateral of $(114) million and $(109) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $47 million and $33 million were netted against current liabilities and noncurrent liabilities, respectively.

The aggregate fair value of derivative contracts in a liability position as of September 30, 2010 that contain triggers for additional collateral was $531 million. This potential additional collateral is included in the $840 million discussed in Note 7. Commitments and Contingent Liabilities.

The following shows the effect on the Condensed Consolidated Statements of Operations and Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended September 30, 2010 and 2009:


Derivatives in SFAS 133 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,
	2010		2009					2010		2009					2010		2009
		Millions
PSEG(A)
Energy-Related Contracts	$	62	$	(19	)		Operating Revenues	$	60	$	141			Operating Revenues	$	0	$	(8	)
Energy-Related Contracts		0		(6	)		Energy Costs		0		(19	)				0		0
Interest Rate Swaps		0		(3	)		Interest Expense		0		(1	)				0		0

Total PSEG	$	62	$	(28	)			$	60	$	121				$	0	$	(8	)

PSEG Power
Energy-Related Contracts	$	62	$	(19	)		Operating Revenues	$	60	$	141			Operating Revenues	$	0	$	(8	)
Energy-Related Contracts		0		(6	)		Energy Costs		0		(19	)				0		0

Total Power	$	62	$	(25	)			$	60	$	122				$	0	$	(8	)

PSE&G
Interest Rate Swaps	$	0	$	0			Interest Expense	$	0	$	0				$	0	$	0

Total PSE&G	$	0	$	0				$	0	$	0				$	0	$	0

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 nine months ended September 30, 2010 and 2009:


Derivatives in SFAS 133 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,
	2010		2009					2010			2009					2010			2009
		Millions
PSEG(A)
Energy-Related Contracts	$	171	$	502			Operating Revenues	$	178		$	452			Operating Revenues	$	(3	)	$	(17	)
Interest Rate Swaps		0		0			Income from Equity Method Investments		0			(1	)				0			0
Energy-Related Contracts		1		(50	)		Energy Costs		(2	)		(82	)				0			0
Interest Rate Swaps		0		(4	)		Interest Expense		(1	)		(7	)				0			0

Total PSEG	$	172	$	448				$	175		$	362				$	(3	)	$	(17	)

PSEG Power
Energy-Related Contracts	$	171	$	502			Operating Revenues	$	178		$	452			Operating Revenues	$	(3	)	$	(17	)
Energy-Related Contracts		1		(50	)		Energy Costs		(2	)		(82	)				0			0
Interest Rate Swaps		0		0			Interest Expense		0			(4	)				0			0

Total Power	$	172	$	452				$	176		$	366				$	(3	)	$	(17	)

PSE&G
Interest Rate Swaps	$	0	$	(1	)		Interest Expense	$	0		$	(2	)			$	0		$	0

Total PSE&G	$	0	$	(1	)			$	0		$	(2	)			$	0		$	0

Energy Holdings
Interest Rate Swaps	$	0	$	0			Income from Equity Method Investments	$	0		$	(1	)			$	0		$	0

	$	0	$	0				$	0		$	(1	)			$	0		$	0

(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, 2009	$	305		$	180
Gain Recognized in AOCI (Effective Portion)		110			65
Less: Gain Reclassified into Income (Effective Portion)		(115	)		(68	)

Balance as of June 30, 2010	$	300		$	177

Gain Recognized in AOCI (Effective Portion)	$	62		$	37
Less: Gain Reclassified into Income (Effective Portion)	$	(60	)	$	(36	)

Balance as of September 30, 2010	$	302		$	178

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months and nine months ended September 30, 2010 and 2009:


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,
			2010			2009			2010			2009
PSEG and Power
Energy-Related Contracts		Operating Revenues	$	(2	)	$	65		$	32		$	269
Energy-Related Contracts		Energy Costs		(5	)		(33	)		(23	)		(157	)
Interest Rate Swaps		Interest Expense		0			0			0			1
Derivatives in NDT Funds		Other Income		0			0			0			13

Total PSEG and Power			$	(7	)	$	32		$	9		$	126

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 for the three months and the nine months ended September 30, 2010 was to reduce interest expense by approximately $6 million and $18 million, respectively.

The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2010 and December 31, 2009:


Type	Notional		Total		PSEG		Power		PSE&G
	Millions
As of September 30, 2010
Natural Gas		Dth		1,083		0		789		294
Electricity		MWh		191		0		191		0
Capacity		MW days		1		0		1		0
FTRs		MWh		36		0		36		0
Emissions Allowances		Tons		0		0		0		0
Renewable Energy Credits		MWh		0		0		0		0
Interest Rate Swaps		US Dollars		1,150		1,150		0		0
As of December 31, 2009
Natural Gas		Dth		842		0		613		229
Electricity		MWh		194		0		194		0
Capacity		MW days		1		0		1		0
FTRs		MWh		23		0		23		0
Emissions Allowances		Tons		1		0		1		0
Renewable Energy Credits		MWh		1		0		1		0
Interest Rate Swaps		US Dollars		550		550		0		0

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 financial condition, results of operations or net cash flows. As of September 30, 2010, 99% of the credit exposure (MTM plus net receivables and payables, less cash collateral) for Power’s operations was with investment grade counterparties.

The following table provides information on Power’s credit risk from others, net of collateral, as of September 30, 2010. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions. 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 the company’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	$	1,108	$	117	$	1,078		2	$	511
Non-Investment Grade— External Rating		12		1		11		0		0
Investment Grade— No External Rating		46		11		35		0		0
Non-Investment Grade— No External Rating		3		0		3		0		0

Total	$	1,169	$	129	$	1,127		2	$	511

(A)	Includes net exposure of $347 million with PSE&G. The remaining net exposure of $164 million is with a nonaffiliated power purchaser which is a regulated investment grade counterparty.

The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would be no exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of September 30, 2010, Power had 202 active counterparties.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 10. Fair Value Measurements

Fair value measurements guidance defines fair value, establishes a framework for measuring fair value and expands disclosures about 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. The fair value measurement guidance 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 financial transmission rights, certain full requirements contracts, other longer term capacity and transportation contracts and certain commingled securities.

In addition to establishing a measurement framework, the fair value measurement guidance nullified the prior guidance which did not allow an entity to recognize an unrealized gain or loss at the inception of a derivative instrument unless the fair value of that instrument was obtained from a quoted market price in an active market or was otherwise evidenced by comparison to other observable current market transactions or based on a valuation technique incorporating observable market data.

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 at September 30, 2010 and December 31, 2009, 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, 2010
				Cash Collateral			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	Total			Netting(E)			(Level 1)		(Level 2)			(Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy Related Contracts(A)	$	383		$	(233	)	$	0	$	347		$	269
Interest Rate Swaps(B)	$	64		$	0		$	0	$	64		$	0
NDT Funds:(C)
Equity Securities	$	657		$	0		$	657	$	0		$	0
Debt Securities—Govt Obligations	$	326		$	0		$	0	$	326		$	0
Debt Securities—Other	$	261		$	0		$	0	$	261		$	0
Other Securities	$	26		$	0		$	1	$	16		$	9
Rabbi Trust—Mutual Funds(C)	$	158		$	0		$	16	$	142		$	0
Other Long-Term Investments(D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy Related Contracts(A)	$	(162	)	$	106		$	0	$	(195	)	$	(73	)
Power
Assets:
Derivative Contracts:
Energy Related Contracts(A)	$	343		$	(233	)	$	0	$	347		$	229
NDT Funds(C)
Equity Securities	$	657		$	0		$	657	$	0		$	0
Debt Securities—Govt Obligations	$	326		$	0		$	0	$	326		$	0
Debt Securities—Other	$	261		$	0		$	0	$	261		$	0
Other Securities	$	26		$	0		$	1	$	16		$	9
Rabbi Trust—Mutual Funds(C)	$	31		$	0		$	3	$	28		$	0
Liabilities:
Derivative Contracts:
Energy Related Contracts(A)	$	(162	)	$	106		$	0	$	(195	)	$	(73	)
PSE&G
Assets:
Derivative Contracts:
Energy Related Contracts(A)	$	40		$	0		$	0	$	0		$	40
Rabbi Trust—Mutual Funds(C)	$	54		$	0		$	5	$	49		$	0

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Recurring Fair Value Measurements as of December 31, 2009
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)	$	355		$	(223	)	$	0	$	415		$	163
Interest Rate Swaps(B)	$	11		$	0		$	0	$	11		$	0
NDT Funds:(C)
Equity Securities	$	650		$	0		$	650	$	0		$	0
Debt Securities-Government
Obligations	$	297		$	0		$	0	$	297		$	0
Debt Securities-Other	$	216		$	0		$	0	$	216		$	0
Other Securities	$	36		$	0		$	0	$	27		$	9
Rabbi Trust—Mutual Funds(C)	$	149		$	0		$	14	$	121		$	14
Other Long-Term Investments(D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(227	)	$	80		$	0	$	(267	)	$	(40	)
Interest Rate Swaps(B)	$	(14	)	$	0		$	0	$	(14	)	$	0
Power
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	349		$	(223	)	$	0	$	415		$	157
NDT Funds:(C)
Equity Securities	$	650		$	0		$	650	$	0		$	0
Debt Securities-Government
Obligations	$	297		$	0		$	0	$	297		$	0
Debt Securities-Other	$	216		$	0		$	0	$	216		$	0
Other Securities	$	36		$	0		$	0	$	27		$	9
Rabbi Trust—Mutual Funds(C)	$	30		$	0		$	3	$	24		$	3
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(227	)	$	80		$	0	$	(267	)	$	(40	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	6		$	0		$	0	$	0		$	6
Rabbi Trust—Mutual Funds(C)	$	51		$	0		$	5	$	41		$	5

(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 midpoint 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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)

The 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 have primarily been 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 investments in fixed income securities are primarily with investment grade corporate bonds and US 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 are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3).

The Rabbi Trust mutual funds are mainly invested in a US 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for 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


	Balance as of July 1, 2010		Total Gains or (Losses) Realized/Unrealized					Purchases, (Sales) and Settlements			Balance as of September 30, 2010
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	$	179	$	34	$	(11	)	$	(6	)	$	196
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	16	$	0	$	0		$	(16	)	$	0
Power
Net Derivative Assets	$	128	$	34	$	0		$	(6	)	$	156
NDT Funds	$	6	$	0	$	0		$	3		$	9
Rabbi Trust Funds	$	3	$	0	$	0		$	(3	)	$	0
PSE&G
Net Derivative Liabilities	$	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


	Balance as of January 1, 2010		Total Gains or (Losses) Realized/Unrealized				Purchases, (Sales) and Settlements			Balance as of September 30, 2010
Description	Balance as of January 1, 2010		Included in Income(C)		Included in Regulatory Assets/ Liabilities(B)		Purchases, (Sales) and Settlements			Balance as of September 30, 2010
	Millions
PSEG
Net Derivative Assets	$	123	$	64	$	34	$	(25	)	$	196
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	14	$	0	$	0	$	(14	)	$	0
Power
Net Derivative Assets	$	117	$	64	$	0	$	(25	)	$	156
NDT Funds	$	9	$	0	$	0	$	0		$	9
Rabbi Trust Funds	$	3	$	0	$	0	$	(3	)	$	0
PSE&G
Net Derivative Liabilities	$	6	$	0	$	34	$	0		$	40
Rabbi Trust Funds	$	5	$	0	$	0	$	(5	)	$	0

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for three months and nine months ended September 30, 2009 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended September 30, 2009


	Balance as of July 1, 2009			Total Gains or (Losses) Realized/Unrealized				Purchases, (Sales) and Settlements			Balance as of September 30, 2009
Description	Balance as of July 1, 2009			Included in Income(A)		Included in Regulatory Assets/ Liabilities(B)		Purchases, (Sales) and Settlements			Balance as of September 30, 2009
	Millions
PSEG
Net Derivative Assets	$	150		$	18	$	6	$	(48	)	$	126
NDT Funds	$	30		$	0	$	0	$	(11	)	$	19
Rabbi Trust Funds	$	14		$	0	$	0	$	0		$	14
Power
Net Derivative Assets	$	187		$	18	$	0	$	(48	)	$	157
NDT Funds	$	30		$	0	$	0	$	(11	)	$	19
Rabbi Trust Funds	$	3		$	0	$	0	$	0		$	3
PSE&G
Net Derivative Liabilities	$	(37	)	$	0	$	6	$	0		$	(31	)
Rabbi Trust Funds	$	5		$	0	$	0	$	0		$	5

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Nine Months Ended September 30, 2009


	Balance as of January 1, 2009			Total Gains or (Losses) Realized/Unrealized					Purchases, (Sales) and Settlements			Balance as of September 30, 2009
Description	Balance as of January 1, 2009			Included in Income(C)			Included in Regulatory Assets/ Liabilities(B)		Purchases, (Sales) and Settlements			Balance as of September 30, 2009
	Millions
PSEG
Net Derivative Assets	$	32		$	102		$	33	$	(41	)	$	126
NDT Funds	$	41		$	(2	)	$	0	$	(20	)	$	19
Rabbi Trust Funds	$	14		$	0		$	0	$	0		$	14
Power
Net Derivative Assets	$	96		$	102		$	0	$	(41	)	$	157
NDT Funds	$	41		$	(2	)	$	0	$	(20	)	$	19
Rabbi Trust Funds	$	3		$	0		$	0	$	0		$	3
PSE&G
Net Derivative Liabilities	$	(64	)	$	0		$	33	$	0		$	(31	)
Rabbi Trust Funds	$	5		$	0		$	0	$	0		$	5

(A)

PSEG’s and Power’s gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $20 million and $29 million are included in Operating Income and $14 million and $(11) million are included in OCI in 2010 and 2009, respectively. Of the $20 million in Operating Income in 2010, $30 million is unrealized and $(10) million is realized. The $29 million in Operating Income in 2009 is realized.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

(C)

PSEG’s and Power’s gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $36 million and $94 million are included in Operating Income and $28 million and $8 million are included in OCI in 2010 and 2009, respectively. Of the $36 million in Operating Income in 2010, $12 million is unrealized and $24 million is realized. Of the $94 million in Operating Income in 2009, $31 million is unrealized and $63 million is realized.

As of September 30, 2010, PSEG carried approximately $1.7 billion of net assets that are measured at fair value on a recurring basis, of which approximately $205 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 between levels during the three months and nine months ended September 30, 2010.

As of September 30, 2009, PSEG carried approximately $1.4 billion of net assets that were measured at fair value on a recurring basis, of which approximately $159 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represented less than 1% of PSEG’s total assets. During the three months and nine months ended September 30, 2009, approximately $15 million of net derivative liabilities were transferred from Level 3 to Level 2 due to more observable pricing in the Texas market.

It is PSEG’s policy to recognize transfers in and out of levels, as of the beginning of the quarter in which the transfer occurs.

Non-Recurring Fair Value Measurements:

•

Due to a significant decline in market prices at June 30, 2010, Power assessed the recoverability of its SO₂ emission allowances not expected to be consumed. As a result of this evaluation, Power recorded a pre-tax impairment charge of $15 million related to its forecasted excess SO₂ allowances during the quarter ended June 30, 2010, which was included in Energy Costs on the Condensed Consolidated Statements of Operations. The fair value of remaining excess SO₂ emission allowances of $6 million was determined based on a comparison of quoted market prices where available for each vintage year to the carrying value of the related allowances (Level 2 measurement within the fair value hierarchy). Due to the lack of observable prices beyond certain vintage years, significant internal assumptions were used in the valuation of approximately $2 million of those allowances (Level 3 measurement within the fair value hierarchy).

•

As a result of the execution of a new lease, Energy Holdings assessed the recoverability of existing property located in Michigan. As a result of the evaluation, Energy Holdings recorded a pre-tax impairment of $10 million during the quarter ended June 30, 2010, which was included in Operating Revenues on the Condensed Consolidated Statements of Operations. The fair value of the property ($6 million) was determined using an internal model based on a discounted cash flow analysis (income approach valuation technique) with significant unobservable inputs (Level 3).

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Value of Debt

The estimated fair values were determined using market quotations or values of instruments with similar terms, credit ratings, remaining maturities, and redemptions as of September 30, 2010 and December 31, 2009.


	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value(A)		Carrying Amount			Fair Value(A)
	Millions
Long-Term Debt:
PSEG (Parent)	$	34	$	64	$	(38	)	$	(3	)
Power—Recourse Debt		3,455		3,944		3,121			3,473
PSE&G		4,282		4,688		3,571			3,807
Transition Funding (PSE&G)		1,141		1,323		1,276			1,449
Transition Funding II (PSE&G)		61		66		67			71
Energy Holdings:
Senior Notes		127		130		127			134
Project Level, Non-Recourse Debt		56		56		42			42

	$	9,156	$	10,271	$	8,166		$	8,973

(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.

Note 11. Other Income and Deductions


Other Income	Power		PSE&G		Other(A)		Consolidated Total
	Millions

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

Three Months Ended September 30, 2009
NDT Fund Gains, Interest, Dividend and Other Income	$	39	$	0	$	0	$	39
Other		1		2		1		4

Total Other Income	$	40	$	2	$	1	$	43

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

Nine Months Ended September 30, 2009
NDT Fund Gains, Interest, Dividend and Other Income	$	191	$	0	$	0	$	191
Other		5		7		2		14

Total Other Income	$	196	$	7	$	2	$	205

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


Other Deductions	Power		PSE&G		Other(A)			Consolidated Total
	Millions
Three Months Ended September 30, 2010
NDT Fund Losses and Expenses	$	9	$	0	$	0		$	9
Other		0		1		(1	)		0

Total Other Deductions	$	9	$	1	$	(1	)	$	9

Three Months Ended September 30, 2009
NDT Fund Losses and Expenses	$	16	$	0	$	0		$	16
Other		1		0		2			3

Total Other Deductions	$	17	$	0	$	2		$	19

Nine Months Ended September 30, 2010
NDT Fund Losses and Expenses	$	35	$	0	$	0		$	35
Other		1		2		(1	)		2

Total Other Deductions	$	36	$	2	$	(1	)	$	37

Nine Months Ended September 30, 2009
NDT Fund Losses and Expenses	$	105	$	0	$	0		$	105
Other		6		2		5			13

Total Other Deductions	$	111	$	2	$	5		$	118

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

Note 12. Income Taxes


	Three Months Ended September 30,						Nine Months Ended September 30,
Effective Tax Rate	2010			2009			2010			2009
PSEG		40.3	%		40.8	%		40.3	%		41.5	%
Power		39.4	%		40.1	%		40.3	%		39.6	%
PSE&G		39.5	%		41.7	%		38.4	%		40.9	%

For the quarter ended September 30, 2010, the change in the effective tax rate for PSEG was due primarily to

•

reevaluating PSEG’s reserves for uncertain tax positions primarily related to Nuclear Decommissioning Trusts,

•

the impact of taxes recorded in 2009 resulting from the sales of leveraged lease assets, and

•

the flow-through of tax benefits at PSE&G, primarily related to uncollectible accounts.

For the nine months ended September 30, 2010, the change in the effective tax rate for PSEG was due primarily to

•

reevaluating PSEG’s reserves for uncertain tax positions primarily related to Power’s manufacturer’s deductions under the American Jobs Creation Act of 2004 and Nuclear Decommissioning Trusts,

•

the impact of taxes recorded in 2009 resulting from the sales of leveraged lease assets,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

•

the impacts of new health care legislation enacted in March 2010, and

•

the flow-through of tax benefits at PSE&G, primarily related to uncollectible accounts.

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. Although this change does not take effect immediately, the accounting impact was required to be recognized when the legislation was signed. 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.


Unrecognized Tax Benefits	As of September 30, 2010
		Millions
PSEG	$	533
Tax Deposits Associated with Disputed Tax Assessments		(320	)

PSEG Unrecognized Tax Benefits Net of Deposit	$	213

Power	$	(27	)
PSE&G	$	46

PSEG and PSE&G had unrecognized tax benefits as of September 30, 2010. 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 the Long-Term Accrued Taxes on PSEG’s Condensed Consolidated Balance Sheets, but are not reflected in the PSEG unrecognized tax benefits. PSEG materially reduced its unrecognized tax benefits by terminating some leases involved in the IRS lease issue. For additional information, see Note 7. Commitments and Contingent Liabilities.

It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 7. Commitments and Contingent Liabilities will change significantly in the next 12 months. 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 or decrease. It is not possible to predict the magnitude, timing or direction of any such change. Unrecognized tax benefits, shown above, include certain beneficial refund claims and adjustments as follows: PSEG $150 million, Power $56 million and PSE&G $42 million.


Possible Increase (Decrease) in Total Unrecognized Tax Benefits Including Interest	Over the next 12 Months
		Millions
PSEG	$	(388	)
Power	$	15
PSE&G	$	39

It is reasonably possible that the total unrecognized tax benefits (including interest) at PSEG will decrease within the next 12 months due to either agreement with various taxing authorities upon audit or the expiration of the Statute of Limitations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Possible Increase (Decrease) in unrecognized tax benefits, shown above, include certain beneficial refund claims and adjustments as follows: PSEG $94 million, PSE&G $42 million.

Note 13. Comprehensive Income, Net of Tax

Comprehensive Income


	Power(A)			PSE&G			Other(A)			Consolidated
							Millions
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

Three Months Ended September 30, 2009
Net Income	$	382		$	88		$	18		$	488
Other Comprehensive Income (Loss)		(32	)		1			0			(31	)

Comprehensive Income	$	350		$	89		$	18		$	457

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

Nine Months Ended September 30, 2009
Net Income	$	943		$	256		$	44		$	1,243
Other Comprehensive Income (Loss)		140			2			4			146

Comprehensive Income	$	1,083		$	258		$	48		$	1,389

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

Accumulated Other Comprehensive Income (Loss)


	Balance as of December 31, 2009			Power			PSE&G			Other			Balance as of September 30, 2010
	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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Balance as of December 31, 2008			Power		PSE&G		Other			Balance as of September 30, 2009
	Millions
Derivative Contracts	$	172		$	52	$	0	$	(2	)	$	222
Pension and OPEB Plans		(371	)		16		0		3			(352	)
NDT Funds(A)		18			70		0		0			88
Other		4			2		2		3			11

Accumulated Other Comprehensive Income (Loss)	$	(177	)	$	140	$	2	$	4		$	(31	)

(A)	Includes reclassification of $12 million of non-credit losses, net of tax, from Retained Earnings to Accumulated Other Comprehensive Income (Loss) recorded upon adoption of accounting guidance for determining whether an available-for-sale debt security is other-than-temporarily impaired.

Note 14. 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,
	2010				2009				2010				2009
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator: (Millions)
Net Income	$	567	$	567	$	488	$	488	$	1,282	$	1,282	$	1,243	$	1,243

EPS Denominator: (Thousands)
Weighted Average Common Shares Outstanding		505,945		505,945		505,982		505,982		506,001		506,001		505,986		505,986
Effect of Stock Options		0		165		0		181		0		148		0		187
Effect of Stock Performance Share Units		0		662		0		945		0		785		0		700
Effect of Restricted Stock Units		0		196		0		134		0		134		0		84

Total Shares		505,945		506,968		505,982		507,242		506,001		507,068		505,986		506,957

EPS:
Net Income	$	1.12	$	1.12	$	0.96	$	0.96	$	2.53	$	2.53	$	2.45	$	2.45

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Three Months Ended September 30,				Nine Months Ended September 30,
Dividend Payments on Common Stock	2010		2009		2010		2009
Per Share	$	0.3425	$	0.3325	$	1.0275	$	0.9975
in Millions	$	173	$	168	$	520	$	505

Note 15. Financial Information by Business Segments


	Power		PSE&G			Energy Holdings			Other(A)			Consolidated
	Power		PSE&G			Energy Holdings			Other(A)			Consolidated
	Millions
Three Months Ended September 30, 2010
Operating Revenues	$	1,663	$	2,007		$	58		$	(474	)	$	3,254
Net Income (Loss)		384		155			24			4			567
Preferred Securities Dividends		0		0			0			0			0
Segment Earnings (Loss)		384		155			24			4			567
Gross Additions to Long-Lived Assets		251		341			12			2			606

Three Months Ended September 30, 2009
Operating Revenues	$	1,564	$	1,943		$	57		$	(524	)	$	3,040
Net Income (Loss)		382		88			(1	)		19			488
Preferred Securities Dividends		0		(1	)		0			1			0
Segment Earnings (Loss)		382		87			(1	)		20			488
Gross Additions to Long-Lived Assets		207		201			5			3			416

Nine Months Ended September 30, 2010
Operating Revenues	$	5,324	$	5,987		$	114		$	(2,036	)	$	9,389
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

Nine Months Ended September 30, 2009
Operating Revenues	$	5,391	$	6,321		$	196		$	(2,388	)	$	9,520
Net Income (Loss)		943		256			30			14			1,243
Preferred Securities Dividends		0		(3	)		0			3			0
Segment Earnings (Loss)		943		253			30			17			1,243
Gross Additions to Long-Lived Assets		636		580			14			2			1,232

As of September 30, 2010
Total Assets	$	10,735	$	16,708		$	2,359		$	(698	)	$	29,104
Investments in Equity Method Subsidiaries	$	28	$	0			112		$	0		$	140

As of December 31, 2009
Total Assets	$	10,333	$	16,533		$	2,605		$	(741	)	$	28,730
Investments in Equity Method Subsidiaries	$	36	$	0		$	176		$	0		$	212

(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 16. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 16. 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	2010			2009			2010			2009
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS(A)	$	118		$	126		$	1,102		$	1,309
Billings to PSE&G through BGS(A)		345			388			904			1,051

Total Revenue from Affiliates	$	463		$	514		$	2,006		$	2,360

Expense Billings from Affiliates:
Administrative Billings from Services(B)	$	(34	)	$	(36	)	$	(106	)	$	(114	)

Total Expense Billings from Affiliates	$	(34	)	$	(36	)	$	(106	)	$	(114	)


Related Party Transactions	September 30, 2010			December 31, 2009
	Millions
Receivables from PSE&G through BGS and BGSS Contracts(A)	$	132		$	404
Receivables from PSE&G Related to Gas Supply Hedges for BGSS(A)		119			120
Payable to Services(B)		(22	)		(27	)
Tax Sharing Receivable from (Payable to) PSEG(C)		41			(28	)
Current Unrecognized Tax Receivable from PSEG(C)		15			3
Payable to PSEG		(2	)		(13	)

Accounts Receivable—Affiliated Companies, net	$	283		$	459

Short-Term Loan to (from) Affiliate (Demand Note to (from) PSEG)(D)	$	309		$	(194	)

Working Capital Advances to Services(E)	$	17		$	17

Long-Term Accrued Taxes Receivable(C)	$	11		$	39

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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,
	Three Months Ended September 30,						Nine Months Ended September 30,
Related Party Transactions	2010			2009			2010			2009
	Millions
Expense Billings from Affiliates:
Billings From Power through BGSS(A)	$	(118	)	$	(126	)	$	(1,102	)	$	(1,309	)
Billings From Power through BGS(A)		(345	)		(388	)		(904	)		(1,051	)
Administrative Billings from Services(B)		(47	)		(57	)		(151	)		(186	)

Total Expense Billings from Affiliates	$	(510	)	$	(571	)	$	(2,157	)	$	(2,546	)


Related Party Transactions	September 30, 2010			December 31, 2009
	Millions
Payable to Power through BGS and BGSS Contracts(A)	$	(132	)	$	(404	)
Payable to Power Related to Gas Supply Hedges for BGSS(A)		(119	)		(120	)
Payable to Power for SREC Liability(F)		(7	)		(7	)
Payable to Services(B)		(42	)		(42	)
Tax Sharing Receivable from (Payable to) PSEG(C)		86			13
Current Unrecognized Tax Receivable from PSEG(C)		72			61
Receivable from PSEG		1			3

Accounts Payable—Affiliated Companies, net	$	(141	)	$	(496	)

Working Capital Advances to Services(E)	$	33		$	33

Long-Term Accrued Taxes Payable(C)	$	(118	)	$	(96	)

(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.

PSEG and its subsidiaries adopted the accounting guidance for “Accounting for Uncertainty in Income Taxes” effective January 1, 2007, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that it has taken or expects to take on a tax return.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(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 January 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. The N.J. Division of Rate Counsel filed an appeal of the BPU decision and the Appellate Division of the Superior Court affirmed the BPU order in November 2009. However, the N.J. Supreme Court granted the N.J. Division of Rate Counsel’s Petition for Certification and the matter is pending before the Supreme Court. The Supreme Court held oral arguments on October 14, 2010 and a decision is expected within the next few months. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million and $15 million as of September 30, 2010 and December 31, 2009, respectively, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies. 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, 2010 and December 31, 2009.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 17. 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 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, 2010
Operating Revenues	$	0		$	1,817		$	170		$	(324	)	$	1,663
Operating Expenses		0			1,207			143			(325	)		1,025

Operating Income (Loss)		0			610			27			1			638
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	)		(9	)		0			(250	)

Net Income (Loss)	$	384		$	378		$	14		$	(392	)	$	384


Three Months Ended September 30, 2009
Operating Revenues	$	0		$	1,702		$	170		$	(308	)	$	1,564
Operating Expenses		3			1,102			115			(308	)		912

Operating Income (Loss)		(3	)		600			55			0			652
Equity Earnings (Losses) of Subsidiaries		389			31			0			(420	)		0
Other Income		11			43			0			(14	)		40
Other Deductions		(1	)		(16	)		0			0			(17	)
Other-Than-Temporary Impairments		0			0			0			0			0
Interest Expense		(30	)		(15	)		(6	)		14			(37	)
Income Tax Benefit (Expense)		16			(254	)		(18	)		0			(256	)

Net Income (Loss)	$	382		$	389		$	31		$	(420	)	$	382

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Nine Months Ended September 30, 2010
Operating Revenues	$	0		$	5,853		$	436		$	(965	)	$	5,324
Operating Expenses		0			4,236			423			(966	)		3,693

Operating Income (Loss)		0			1,617			13			1			1,631
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	)		(1	)		0			(642	)

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	)

Nine Months Ended September 30, 2009
Operating Revenues	$	0		$	5,958		$	384		$	(951	)	$	5,391
Operating Expenses		9			4,326			345			(951	)		3,729

Operating Income (Loss)		(9	)		1,632			39			0			1,662
Equity Earnings (Losses) of Subsidiaries		964			6			0			(970	)		0
Other Income		48			216			0			(68	)		196
Other Deductions		(1	)		(110	)		0			0			(111	)
Other-Than-Temporary Impairments		0			(60	)		0			0			(60	)
Interest Expense		(119	)		(47	)		(27	)		68			(125	)
Income Tax Benefit (Expense)		60			(673	)		(6	)		0			(619	)

Net Income (Loss)	$	943		$	964		$	6		$	(970	)	$	943


Nine Months Ended September 30, 2009
Net Cash Provided By (Used In) Operating Activities	$	(123	)	$	2,178		$	3		$	(629	)	$	1,429
Net Cash Provided By (Used In) Investing Activities	$	188		$	(1,229	)	$	149		$	422		$	(470	)
Net Cash Provided By (Used In) Financing Activities	$	(66	)	$	(952	)	$	(133	)	$	208		$	(943	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated Total
	Millions
As of September 30, 2010
Current Assets	$	3,573	$	6,605	$	535	$	(8,292	)	$	2,421
Property, Plant and Equipment, net		63		5,202		1,424		0			6,689
Investment in Subsidiaries		5,031		1,090		0		(6,121	)		0
Noncurrent Assets		220		1,509		44		(148	)		1,625

Total Assets	$	8,887	$	14,406	$	2,003	$	(14,561	)	$	10,735

Current Liabilities	$	786	$	8,327	$	745	$	(8,292	)	$	1,566
Noncurrent Liabilities		413		1,050		165		(147	)		1,481
Long-Term Debt		2,805		0		0		0			2,805
Member’s Equity		4,883		5,029		1,093		(6,122	)		4,883

Total Liabilities and Member’s Equity	$	8,887	$	14,406	$	2,003	$	(14,561	)	$	10,735

As of December 31, 2009
Current Assets	$	3,039	$	5,614	$	560	$	(6,871	)	$	2,342
Property, Plant and Equipment, net		61		4,872		1,452		0			6,385
Investment in Subsidiaries		4,865		1,093		0		(5,958	)		0
Noncurrent Assets		253		1,452		52		(151	)		1,606

Total Assets	$	8,218	$	13,031	$	2,064	$	(12,980	)	$	10,333

Current Liabilities	$	107	$	7,167	$	818	$	(6,869	)	$	1,223
Noncurrent Liabilities		522		1,002		150		(152	)		1,522
Long-Term Debt		3,121		0		0		0			3,121
Member’s Equity		4,468		4,862		1,096		(5,959	)		4,467

Total Liabilities and Member’s Equity	$	8,218	$	13,031	$	2,064	$	(12,980	)	$	10,333

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 U.S.,

•

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 leveraged leases and other investments.

Our business discussion in Part I Item 1 Business of our 2009 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. The following supplements that discussion and the discussion included in the Overview of 2009 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2010 and any changes to the key factors that we expect will 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 2009 Annual Report on Form 10-K.

OVERVIEW OF 2010 AND FUTURE OUTLOOK

During 2010, our business continues to face many of the same challenges experienced in 2009. Lower natural gas prices and current economic conditions have had a significant adverse impact on our results.

The market price for electricity is based upon the cost of generation at the margin. In the eastern part of PJM, the marginal generating unit is usually fueled by gas. As a result, the sustained decline in natural gas pricing that we are experiencing has significantly reduced the gross margin we expect to realize on sales from our units in the eastern part of PJM, as nuclear and coal fuel costs have not declined similarly. Our practice of selling a substantial portion of our electricity production in forward transactions has limited the impact of lower wholesale electricity prices on our 2010 results, as much of the electricity that we produce in 2010 is being sold at the higher forward market prices that prevailed in 2007 through 2009. We expect that, as these pre-2010 transactions wind down, the lower energy prices that now prevail will have a more significant adverse impact on our results for 2011 and 2012.

Economic conditions and other policy initiatives have resulted in increased conservation efforts by residential customers and have also caused some erosion in our commercial and industrial customer base. This has contributed to lower demand for electricity, which also tends to reduce congestion, thereby reducing the hours that higher priced units in the eastern part of PJM are called to operate. These factors have put additional downward pressure on Power’s revenues. Economic conditions also put downward pressure on delivered volumes and fixed demand revenues from commercial and industrial customers at PSE&G. For both businesses, the impact on electric volumes caused by economic conditions and pricing was offset by the impact of weather which resulted in higher demand for energy during the third quarter.

Lower market prices for electricity also tend to create a greater incentive for customers to choose an alternate electric supplier rather than receive electricity from Power under our Basic Generation Service (BGS) contracts, as the current market prices are lower than the BGS contract energy price components which were set when forward prices were higher. We experienced an increasing level of this “migration” away from BGS contracts beginning toward the second half of last year which has continued into 2010. We expect this trend

could continue as long as current market prices remain below the BGS rates. The BGS rates are reset gradually with prices set for only one-third of the anticipated load through the BGS auction each year. The rate of migration may also increase as third party suppliers have started to offer additional incentives for customers to switch to an alternate electric supplier. If this customer migration trend continues it may have a material impact on Power’s financial results.

In an effort to mitigate some of these impacts, Power has entered into additional sales contracts with third parties and increased sales in the spot market. We have also recently requested that the New Jersey Board of Public Utilities (BPU) hold a stakeholder proceeding and collect additional data to evaluate unintended adverse consequences of increased switching activity, with the objective of appropriately allocating risks between BGS suppliers and third party suppliers in future BGS auctions. No assurances can be given that our efforts to offset any adverse impacts will be successful or that the outcome of the requested proceeding will be favorable.

In addition to the impacts discussed above, the economic conditions have also contributed to a significant deterioration in certain customer payment patterns resulting in a higher portion of our accounts receivable balances remaining outstanding for more than 180 days as compared to prior years. The over 180 day balance at September 30, 2010 was 14% of total accounts receivable. We continue to focus our efforts on the oldest and largest accounts to expedite collections. We believe we have adequate bad debt reserves and have sufficient liquidity to manage these delays in customer payments.

Our gas sales volumes were also lower in 2010 due primarily to warmer winter weather. Heating degree days, as a measure of winter weather in 2010, were 14% lower than in 2009. The weather, the economy and other factors all contributed to an overall reduction of approximately 8% in Power’s Basic Gas Supply Service (BGSS) sales volumes and PSE&G’s gas delivery volumes as compared to the same period in 2009.

In June 2010, the BPU accepted and approved a settlement agreement reached by the parties to our base rate case proceeding. The final settlement agreement included an increase of $73.5 million and $26.5 million in annual electric and gas revenues, respectively, with a return on equity of 10.3%. The new rates and rate designs were effective on June 7, 2010 for the electric portion and July 9, 2010 for gas. The BPU also approved PSE&G’s gas weather normalization clause.

As part of the gas base rate proceeding, the BPU ordered a supplemental and expedited review of certain issues related to the gas transportation rate that PSE&G charges to Power. The BPU provisionally approved the stipulated Transportation Service Gas—Nonfirm (TSG-NF) rate subject to refund pending the outcome of this review. In the event that the BPU were to find that the rate charged to Power was not proper and order refunds, the results could be material. We believe such refunds would constitute retroactive ratemaking and be prohibited under applicable law. However, the outcome of the regulatory proceeding, which is currently at the hearing stage, cannot be predicted. Since settlement discussions are in progress, the BPU has adjourned the hearings so that settlement efforts can continue. In July 2010, a complaint was filed against Power at the Federal Energy Regulatory Commission (FERC) related to the gas transportation rate. The complaint asserts that the existing rate charged to Power violates FERC’s affiliate rules and Power’s market-based rate authority. The complaint requests, among other things, that Power’s market-based rate authority be revoked. While we view revocation of our market-based rate authority as unlikely, it is not possible to predict the outcome of this proceeding. We believe that the rates charged to Power were and continue to be lawful and appropriate, and have asserted this position vigorously at FERC.

Also in June 2010, the BPU approved a separate agreement under which PSE&G will refund $122 million to electric customers during the next two years to resolve an issue regarding the Market Transition Charge (MTC) which was part of New Jersey’s deregulation law implemented in 1999. For additional information, see Note 7. Commitments and Contingent Liabilities.

Another proceeding regarding consolidated tax adjustments is expected to begin later in 2010. These adjustments are intended to allocate tax benefits realized by non-regulated subsidiaries to utility customers under certain circumstances. The outcome of such a proceeding cannot be predicted, however, it could impact PSEG’s ability to make certain non-regulated investments in the future.

Following the completion of the rate case, PSE&G initiated a business planning effort to establish long-term financial plans designed to achieve its allowed return and continue to provide safe and reliable service to customers. Action plans could include reductions of capital expenditures and other costs.

We currently have FERC-approved formula rates in effect to recover the costs related to our existing and future transmission investments. The formula rate mechanism provides for an annual setting of our transmission rates, as well as an annual true up, to ensure timely recovery of the annual costs and capital expenditures and an approved return on equity (ROE) of 11.68% for our transmission investments once the facilities are placed in service. We have received incentive ROE rates of 12.93% for certain large scale transmission investments, including an immediate return on the Construction Work in Progress dollars spent on these projects. Our 2010 transmission rates which became effective on January 1 provide for approximately $23 million in increased annual revenues. We filed our 2011 Annual Formula Rate Update with FERC in October 2010, which would provide for approximately $45 million in increased annual revenues as part of our 2011 transmission rates to be effective January 1, 2011.

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.

•

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 were signed into law. This new legislation includes various health care related provisions that will go into effect over the next several years including, but not limited to, expanding insurance coverage eligibility, prohibiting denial of coverage based on pre-existing conditions and prohibiting restrictive annual and lifetime coverage limits. This legislation also 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, which resulted in additional deferred tax liabilities being recorded in the first quarter. For additional information, see Note 12. Income Taxes. In October 2010, we made various changes to our active employee medical programs, generally effective January 1, 2011 to comply with the new requirements. For our retiree health care programs, we have contracted with a group Prescription Drug Plan, effective January 1, 2013, for coordination of the government-provided Retiree Drug Subsidy. We also applied, and have been approved for funds under the Early Retiree Reinsurance Program. We will evaluate any additional guidance on this legislation as it becomes available. To help mitigate the effect of the increasing health care costs, we are changing our pre-65 and post-65 retiree prescription drug formularies to an incentive design for the majority of retirees, to be phased in over a three year period beginning January 1, 2011.

•

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was passed in an attempt to increase control over the financial markets and prevent future financial crises and market issues such as those experienced recently. As part of this new legislation, the SEC and the Commodity Futures Trading Commission (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). 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 issues them. 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.

•

Another new issue has arisen in the context of a pending FERC rulemaking proceeding, in which FERC has proposed to significantly change its transmission planning rules to (i) make it easier to plan transmission for “public policy” considerations and (ii) open up the construction of transmission projects to companies that are not franchised utilities or that seek to build outside of their franchised service territory. PSEG is actively participating in this proceeding.

•

In June 2010, the U.S. Environmental Protection Agency (EPA) formally published a proposed rule offering three main options for the management of coal combustion residuals to limit impacts on human health and the environment. The outcome of the EPA rulemaking can not be predicted. For additional information, see Item 5. Other Information.

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In August 2010, the EPA proposed the Clean Air Transport Rule to limit emissions in 32 states that contribute to the ability of downwind states to attain and/or maintain air quality standards. The Transport Rule is scheduled to be effective January 1, 2012, with further reductions in emissions as part of a second phase effective January 1, 2014. By 2014, the EPA estimates that this rule, along with other concurrent state and EPA actions, would reduce power plant sulfur dioxide (SO₂) emissions by 71% and nitrogen oxide (NO_X) emissions by 52% as compared to 2005 levels. In October 2010, we submitted comments generally supporting the EPA’s proposal. We would expect the final implementation of this rule to be beneficial to us based on our generation mix and our investment in emissions controls, however, no assurances can be given. For additional information, see Item 5. Other Information.

•

During the second quarter, the Governor of New Jersey directed the BPU to review the State’s current Energy Master Plan (EMP). The purpose of the EMP is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. The current EMP was issued in October 2008 and identified a number of the actions to improve energy efficiency, increase the use of renewable resources, ensure a reliable supply of energy and stimulate investment in clean energy technologies. We expect the BPU to release a new draft EMP by the first quarter of 2011 with a final plan expected to be completed later next year. We cannot predict what modifications or new goals will be included in the new EMP or the potential impacts to our businesses.

Our future success will also depend on our ability to respond to the challenges and opportunities presented by these and other regulatory and legislative initiatives.

Operational Excellence

Generation volumes at Power in 2010 were approximately 12% higher than in 2009, primarily at our combined cycle facilities, to meet increased demands due to hotter weather. A seventeen day unplanned outage at our Salem 1 Nuclear plant reduced generation volumes in July, partially offsetting the weather impacts in the period since the reduced volumes were replaced with comparatively higher cost generation. As discussed previously, our ability to meet the increased weather-related demands through the strong operations of our generation fleet helped to offset the impacts of migration and reduced market prices for electricity.

Our generating capacity continues to receive pricing recognizing the locational value of our assets through the Reliability Pricing Model (RPM) auction. Under the most recent auction for the 2013-2014 period, the prices set for our generation assets in PJM were $245 per MW-day for the Eastern MAAC and PSEG North zones and $226.15 per MW-day for the MAAC zone. These prices were significantly higher than prices set for previous periods.

During 2010, PSE&G has demonstrated its commitment to system reliability by limiting customer outages. However, in mid-March, PSE&G experienced the worst storm in its history. The storm caused severe damage to our system downing more than 1,000 poles throughout our service territory and disrupting service to over 600,000 customers. With the assistance of mutual aid crews from other utilities, PSE&G’s associates worked to fully restore service to all of its customers within one week. PSE&G has deferred the incremental storm related costs and will be seeking recovery.

We have also maintained our focus on reducing our cash tax exposure related to certain leveraged leases by pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds. Including four terminations this year, Energy Holdings has terminated a total of 17 of these leasing transactions since December 2008, leaving only one remaining in its portfolio, and reduced the related cash tax exposure by $1 billion. As of September 30, 2010, an aggregate of approximately $330 million would become currently payable if we conceded all deductions taken through that date. We have deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, reducing our potential net cash exposure to $10 million. See Note 7. Commitments and Contingent Liabilities for additional information.

We have looked, and are continuing to look, for ways to reduce our operating costs at each of our businesses while maintaining our safety, reliability and compliance standards.

Financial Strength

Our businesses continued to generate strong cash from operations in 2010. We used these funds combined with external financing to:

•

contribute over $400 million into our qualified pension plans,

•

fund our capital expenditures, and

•

continue funding our shareholder dividends.

The Board of Directors also approved an increase in the quarterly dividends from $0.3325 per share to $0.3425 per share of Common Stock for each of the first three quarters of 2010 resulting in an indicated annual dividend of $1.37 per share.

We also completed several financing transactions during 2010, including paying our maturing debt obligations, redeeming PSE&G’s preferred stock and completing a debt exchange at Power to manage long-term debt maturities. See Note 8. Changes in Capitalization for additional information.

Disciplined Investment

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

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We are continuing to pursue obtaining the necessary regulatory approvals for the Susquehanna-Roseland transmission project but have incurred delays in obtaining environmental approvals. This failure to obtain these approvals on a timely basis has delayed the project implementation date. The estimated cost of construction is up to $750 million for this project. In October, the PJM Board approved a modified Branchburg to Hudson project, specifically a 230 kV project running from Roseland to Hudson. The Roseland to Hudson project has an expected in-service date of June 2015. The estimated cost of construction is up to $700 million for this project. Delays in the construction schedules of these projects could impact the timing of expected transmission revenues. For additional information, see Part II, Item 5. Other Information, State Regulation.

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We made additional investments in our solar initiatives. Under our solar loan program we have provided $57 million in loans for 149 projects as of September 30, 2010, representing over 15 MW to date. Under our Solar 4 All program we have had total expenditures of over $127 million as of September 30, 2010, with over 10 MW of solar panels installed on distribution poles and 15 solar system installation projects in various phases of development representing another 24 MW. Our total anticipated expenditures to develop all 80 MW approved have been reduced from $515 million to approximately $465 million. See Note 7. Commitments and Contingent Liabilities for additional information.

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We made additional expenditures under our Capital Economic Stimulus and Energy Efficiency Economic Stimulus programs. As of September 30, 2010, total expenditures since inception of these projects were $472 million and $58 million, respectively.

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We continued various construction activities at Power, including installation of back end technology at our Mercer and Hudson stations, 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 7. 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.

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We filed an application for an Early Site Permit for a new nuclear generating station to be located at the current site of the Salem and Hope Creek generating stations.

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Our solar projects in Ohio and Florida have commenced operations. The two projects total 27 MW. (See Note 7. Commitments and Contingent Liabilities for additional information).

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

In the third quarter, we also announced that we are exploring the potential sale of our two 1,000 MW combined-cycle generation facilities in Texas through an auction process. Any sale would be dependent on the receipt of bids that we feel reflect the appropriate value for the assets.

RESULTS OF OPERATIONS

The results for PSEG, PSE&G, Power and Energy Holdings for the three months and nine months ended September 30, 2010 and 2009 are presented below:


	Three Months Ended September 30,					Nine Months Ended September 30,
Earnings (Losses)	2010		2009			2010		2009
		Millions
Power	$	384	$	382		$	952	$	943
PSE&G		155		88			276		256
Energy Holdings		24		(1	)		43		30
Other		4		19			11		14

PSEG Income from Continuing Operations		567		488			1,282		1,243

PSEG Net Income	$	567	$	488		$	1,282	$	1,243

Three Months Ended
September 30,

Nine Months Ended
September 30,

Earnings Per Share (Diluted)

2010

2009

2010

2009

PSEG Income from Continuing Operations

1.12

0.96

2.53

2.45

PSEG Net Income

1.12

0.96

2.53

2.45

Our results include the realized gains, losses and earnings on Power’s NDT Funds and other related activity. This includes the net realized gains and other-than-temporary impairments, as well as interest and dividend income and other costs related to the NDT Funds which are recorded in Other Income and Deductions. This also includes 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.

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,
	2010		2009		2010		2009
		In Millions, after tax
NDT Fund Income (Expense)	$	10	$	7	$	30	$	1
Non-Trading Mark-to-Market Gains (Losses)	$	19	$	17	$	30	$	(22	)

In addition to the changes in NDT and MTM, our increases in Income from Continuing Operations for the three and nine months ended September 30, 2010 were driven by:

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higher electric sales volumes and market pricing due primarily to warmer summer weather,

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higher electric delivery revenues due to our base rate increase approved in June, and

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realized gains on the investments in our Rabbi Trust,

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partially offset by higher priced sales under our BGS contracts being replaced with comparatively lower priced sales into the various power pools and under new wholesale contracts entered into during 2010 as customer migration levels have increased, and

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losses on certain wholesale electric energy supply contracts.

Also offsetting the increases for the nine months ended September 30, 2010 were:

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a $122 million charge recorded in June related to our agreement to refund previous MTC collections during the next two years,

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lower gas sales volumes and pricing due to milder winter weather and economic conditions, and

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lower gains on lease sales.

PSEG

Our results of operations are 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, donations and general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 16. 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)
	2010		2009		2010 vs 2009					2010		2009		2010 vs 2009
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	3,254	$	3,040	$	214		7		$	9,389	$	9,520	$	(131	)	(1	)
Energy Costs		1,355		1,241		114		9			4,270		4,376		(106	)	(2	)
Operation and Maintenance		601		621		(20	)	(3	)		1,915		1,922		(7	)	(0	)
Depreciation and Amortization		265		224		41		18			730		634		96		15
Income from Equity Method Investments		4		6		(2	)	(33	)		12		17		(5	)	(29	)
Other Income and (Deductions)		66		24		42		N/A			128		87		41		47
Other-Than-Temporary Impairments		3		0		3		N/A			9		61		(52	)	(85	)
Interest Expense		120		129		(9	)	(7	)		356		407		(51	)	(13	)
Income Tax Expense		382		337		45		13			866		881		(15	)	(2	)

Power

As discussed in Note 1. Organization and Basis of Presentation, Power’s results have been retrospectively adjusted to include the earnings related to PSEG Texas for prior periods.


	Three Months Ended September 30,				Increase/ (Decrease)		Nine Months Ended September 30,				Increase/ (Decrease)
	2010		2009		2010 vs 2009		2010		2009		2010 vs 2009
		Millions
Income from Continuing Operations	$	384	$	382	$	2	$	952	$	943	$	9
Net Income	$	384	$	382	$	2	$	952	$	943	$	9

For the three months ended September 30, 2010, the primary reasons for the $2 million increase in Income from Continuing Operations were

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higher volumes of generation sold at higher market prices in various power pools due to warmer summer weather, and

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realized gains on the investments in our Rabbi Trust,

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largely offset by higher priced sales under our BGS contracts being replaced with comparatively lower priced sales into the various power pools and under new wholesale contracts entered into during 2010 as customer migration levels have increased, and

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also offset by losses on certain wholesale electric energy supply contracts.

For the nine months ended September 30, 2010, the primary reasons for the $9 million increase in Income from Continuing Operations were

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favorable amounts related to our NDT and MTM activity discussed previously,

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higher volumes of generation sold at higher market prices in various power pools due to warmer summer weather, and

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realized gains on the investments in our Rabbi Trust,

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also offset by losses on certain wholesale electric energy supply contracts and

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lower gas sales volumes and pricing due to more moderate winter weather in 2010 and economic conditions.

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)
	2010		2009		2010 vs 2009					2010		2009		2010 vs 2009
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	1,663	$	1,564		$ 99		6		$	5,324	$	5,391	$	(67	)	(1	)
Energy Costs		714		599		115		19			2,732		2,757		(25	)	(1	)
Operation and Maintenance		263		265		(2	)	(1	)		817		820		(3	)	(0	)
Depreciation and Amortization		48		48		0		0			144		152		(8	)	(5	)
Other Income and (Deductions)		35		23		12		52			90		85		5		6
Other-Than-Temporary Impairments		2		0		2		N/A			8		60		(52	)	(87	)
Interest Expense		37		37		0		0			119		125		(6	)	(5	)
Income Tax Expense		250		256		(6	)	(2	)		642		619		23		4

For the three months ended September 30, 2010 as compared to 2009

Operating Revenues increased $99 million due to

Generation Revenues increased $111 million due primarily to

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higher revenues of $121 million resulting from higher volumes of generation sold at higher prices in the PJM, NE and NY power pools, partially offset by less favorable results from financial hedging transactions, and

•

an increase of $32 million from new wholesale load contracts commencing in 2010,

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partially offset by a net decrease of $37 million due to a lower volume of electricity sold at lower average prices under our BGS contracts, reflecting customer migration to alternative suppliers, and

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a decrease of $6 million due to lower auction revenue rights in PJM and migration of customers in 2010.

Gas Supply Revenues increased $10 million

•

including a net increase of $15 million due to higher average gas prices on higher sales volumes to third party customers,

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partially offset by a net decrease of $5 million resulting from a decrease of $9 million in lower volumes of sales under the BGSS contract caused mainly by economic conditions partly offset by a $4 million increase from higher average gas prices.

Trading Revenues decreased $22 million due primarily to losses on certain electric energy supply contracts in 2010 partly offset by losses on certain gas supply contracts realized in 2009 that expired in December 2009.

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 increased by $115 million due to

•

Generation costs increased by $108 million due to $152 million of higher fossil fuel costs, primarily reflecting the utilization of higher volumes of both coal and natural gas and higher average natural gas prices, partly offset by $19 million of lower congestion charges incurred from PJM in 2010, $16 million of lower purchases of firm transmission rights in 2010, and higher net gains of $11 million from financial hedging transactions.

•

Gas costs increased $7 million, reflecting a net increase of $15 million for higher inventory costs related to increased sales to third parties partially offset by a net decrease of $8 million in volume delivered related to Power’s obligations under the BGSS contract, reflecting lower demand due mainly to economic conditions.

Operation and Maintenance experienced no material change.

Depreciation and Amortization reflected no change due to

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an increase of $4 million due to a reversal of depreciation expense in September 2009 related to the reimbursement of previously capitalized storage costs for spent nuclear fuel resulting from a favorable settlement of such costs by the U.S. Department of Energy, and

•

an increase of $2 million due to pollution control equipment being placed into service in October 2009 at our Keystone station,

•

offset by a $6 million decrease due to an extension of the remaining useful lives of the Mercer and Hudson generating facilities resulting from significant plant upgrades as well as revisions in assumptions regarding the decommissioning of our plants.

Other Income and (Deductions)-Net Other Income increased $12 million due primarily to

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a gain of $7 million on the investments in our Rabbi Trust in August 2010, and

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higher earnings of $5 million in 2010 on our NDT Funds.

Other-Than-Temporary Impairments increased $2 million due to charges in 2010 related to certain NDT Fund securities.

Interest Expense experienced no change.

Income Tax Expense decreased $6 million in 2010 due primarily to

•

a decrease of $2 million due to lower pre-tax income, and

•

a decrease of $5 million due to reevaluating uncertain tax positions primarily related to the NDT Funds and manufacturer’s deductions under the American Jobs Creation Act of 2004,

•

partially offset by $1 million due to higher earnings related to the NDT Funds.

For the nine months ended September 30, 2010 as compared to 2009

Operating Revenues decreased $67 million due to

Gas Supply Revenues decreased $278 million

•

including a net decrease of $269 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales caused by milder weather in 2010 as well as lower net gains on financial hedging transactions in 2010, and

•

a net decrease of $9 million due to reduced sales volumes to third party customers.

Trading Revenues decreased $62 million due primarily to net losses on certain electric energy supply contracts in 2010 partly offset by losses on certain gas supply contracts realized in 2009 that expired in December 2009.

Generation Revenues increased $273 million due primarily to

•

higher net revenues of $271 million resulting from higher volumes of generation sold at higher prices in PJM, NY and NE power pools and higher sales prices in the Texas (ERCOT) power pool, partially offset by less favorable results from financial hedging transactions and a lower volume of generation sold in ERCOT,

•

an increase of $104 million from new wholesale load contracts in PJM commencing in 2010,

•

$31 million of increased revenues from operating reserves in the PJM and NE regions and various ancillary services, and $24 million of higher capacity payments largely due to changes in PJM’s capacity market,

•

partially offset by a net decrease of $132 million due to a lower volume of electricity sold at lower average prices under our BGS contracts, reflecting customer migration to alternative suppliers, and

•

a decrease of $24 million in auction revenue rights reflecting lower rates and migration of PJM customers in 2010.

Operating Expenses

•

Gas costs decreased $273 million, principally related to Power’s obligations under the BGSS contract, reflecting lower demand due mainly to milder weather in 2010 and lower inventory costs.

•

Generation costs increased by $248 million due to $339 million of higher fossil fuel costs, primarily reflecting the utilization of higher volumes of both coal and natural gas and higher average natural gas prices, $ 13 million of higher nuclear fuel costs due to higher prices, and a $15 million impairment charge in 2010 related to forecasted excess SO₂ emissions allowances, partly offset by higher net gains of $71 million from financial hedging transactions, $25 million of lower congestion charges incurred in 2010 from PJM and $25 million of lower purchases of firm transmission rights in 2010.

Operation and Maintenance decreased $3 million due primarily to

•

a net decrease of $26 million due primarily to lower nuclear outage costs and lower ARO accretion expense, and

•

a decrease of $10 million due primarily to reduced labor and fringe benefit costs,

•

partially offset by a net increase of $33 million due to planned outage costs in 2010 at the Guadalupe, Linden and Bethlehem Energy Center fossil stations in Texas, New Jersey and New York, respectively, partially mitigated by lower planned maintenance at certain of our other fossil stations.

Depreciation and Amortization decreased $8 million due to

•

an $18 million decrease due to an extension of the remaining useful lives of the Mercer and Hudson generating facilities resulting from significant plant upgrades as well as revisions in assumptions regarding the decommissioning of our plants,

•

partially offset by an increase of $7 million due to pollution control equipment being placed into service in October 2009 at our Keystone station, and

•

Other Income and (Deductions)-Net Other Income increased $5 million due primarily to

•

a $7 million gain realized on the investments in our Rabbi Trust in August 2010, and

•

a $5 million loss in 2009 from the early retirement of obsolete pollution control equipment,

•

partially offset by $7 million in lower earnings in our NDT Fund.

Other-Than-Temporary Impairments decreased $52 million due to the lower charges in 2010 related to certain NDT Fund securities.

Interest Expense decreased $6 million due to

•

higher capitalized interest of $16 million due primarily to an increased level of projects under construction in 2010,

•

partially offset by higher net interest costs of $8 million related to higher interest and debt issuance costs related to two note issuances aggregating $550 million in April 2010 and $303 million of senior notes issued in September 2009 as part of a debt exchange with Energy Holdings, partly offset by the effects of the early redemption of two medium-term note obligations and a note exchange that all occurred in April 2010 (see Note 8. Changes in Capitalization) as well as the redemption of Texas project loans in February 2009 and the maturity of $250 million of Senior Notes in April 2009, and

•

an increase of $2 million in credit facility fees.

Income Tax Expense increased $23 million in 2010 due primarily to

•

an increase of $13 million due to higher pre-tax income,

•

an increase of $8 million due to the impacts of new health care legislation (see Note 12. Income Taxes),

•

an increase of $4 million due to reevaluating uncertain tax positions primarily related to manufacturer’s deductions under the American Jobs Creation Act of 2004 and the NDT Funds, and

•

an increase of $3 million due to higher earnings related to the NDT Funds,

•

partially offset by a decrease of $5 million related to the absence in 2010 of a prior year state audit settlement.

PSE&G


	Three Months Ended September 30,				Increase/ (Decrease)		Nine Months Ended September 30,				Increase/ (Decrease)
	2010		2009		2010 vs 2009		2010		2009		2010 vs 2009
		Millions
Income from Continuing Operations	$	155	$	88	$	67	$	276	$	256	$	20
Net Income	$	155	$	88	$	67	$	276	$	256	$	20

For the three months ended September 30, 2010, the primary reasons for the $67 million increase in Income from Continuing Operations were

•

higher electric delivery revenues due to our base rate increase and higher volumes due primarily to warmer weather, and

•

an increase in our transmission formula rates.

For the nine months ended September 30, 2010, the primary reasons for the $20 million increase in Income from Continuing Operations were

•

higher electric delivery revenues due to our base rate increase and higher volumes due primarily to warmer weather, and

•

an increase in our transmission formula rates,

•

partially offset by the $122 million charge related to our agreement to refund previous MTC collections, and

•

lower gas sales volumes due to milder winter weather.

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)
	2010		2009		2010 vs 2009					2010		2009		2010 vs 2009
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	2,007	$	1,943	$	64		3		$	5,987	$	6,321	$	(334	)	(5	)
Energy Costs		1,115		1,167		(52	)	(4	)		3,572		4,005		(433	)	(11	)
Operation and Maintenance		327		351		(24	)	(7	)		1,084		1,090		(6	)	(1	)
Depreciation and Amortization		209		169		40		24			563		462		101		22
Other Income and (Deductions)		13		2		11		N/A			20		5		15		N/A
Interest Expense		82		77		5		6			239		236		3		1
Income Tax (Benefit) Expense		101		63		38		60			172		177		(5	)	(3	)

For the three months ended September 30, 2010 as compared to 2009

Operating Revenues increased $64 million due primarily to

Delivery Revenues increased $82 million due primarily to an increase in sales volumes and prices for electric distribution and transmission.

•

Electric distribution revenues were up $72 million due primarily to higher sales volumes of $35 million due to weather, the impact of the June base rate increases of $29 million, stimulus revenue increases of $4 million and higher Regional Greenhouse Gas Initiative (RGGI) revenues of $4 million.

•

Transmission revenues increased $5 million due to net rate increases.

•

Gas distribution revenues were up $5 million due primarily to higher sales prices of $6 million due to a change in the mix of customers, partially offset by decreased revenues from our capital stimulus program of $1 million. The July base rate increase will be realized in the winter months.

Clause Revenues increased by $28 million due to higher Securitization Transition Charges (STC) of $30 million, partially offset by lower Societal Benefits Charges (SBC) of $2 million. The increased STC and decreased SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) into Operation and Maintenance, Depreciation and Amortization and Interest. PSE&G earns no margins on SBC or STC collections.

Other Operating Revenues increased $6 million due primarily to increased revenues from late payment charges and our appliance repair business.

Commodity Revenue decreased $52 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 $40 million due primarily to $106 million of decreases in BGS prices and volumes, partially offset by $66 million in higher revenues from the sale of Non-Utility Generation (NUG) energy and collections of Non-utility Generation Charges (NGC). BGS sales were down 1% due primarily to large customer migration to Third Party Suppliers (TPS); in contrast delivery sales were up 9% due to the weather.

•

Gas revenues decreased $12 million due to lower BGSS volumes of $10 million due to weather and economic conditions and decreased BGSS prices of $2 million. The average price of gas was 1% lower in 2010 than 2009.

Energy Costs decreased $52 million. This was entirely offset by Commodity Revenue. Details are as follows:

•

Electric costs decreased $40 million due to $28 million in lower BGS and NUG prices and $12 million or 1% in lower BGS and NUG volumes due to large customer migration to TPS.

•

Gas costs decreased $12 million due to $10 million or 7% in lower sales volumes due primarily to warmer weather and economic conditions and $2 million, or 1%, in lower prices.

Operation and Maintenance decreased $24 million due to

•

a $16 million decrease in electric and gas operating expenses as part of our overall cost reduction efforts,

•

a $5 million reduction in Services company charges for gains on the investments in our Rabbi Trust, and

•

a net $3 million of lower expenses associated with SBC, STC, RGGI and Stimulus clauses.

Depreciation and Amortization increased $40 million due to

•

an increase of $35 million for amortization of regulatory assets,

•

an increase of $4 million for additional plant in service, and

•

an increase of $1 million in software amortization.

Other Income and (Deductions)-Net Other Income increased $11 million due primarily to gains realized on the investments in our Rabbi Trust.

Interest Expense increased by $5 million due primarily to new debt issued in the third quarter of 2010.

Income Tax Expense increased by $38 million due primarily to higher pre-tax income, partially offset by flow-through tax benefits primarily related to uncollectible accounts.

For the nine months ended September 30, 2010 as compared to 2009

Operating Revenues decreased $334 million due primarily to

Commodity Revenue decreased $433 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.

•

Gas revenues decreased $236 million due to decreased BGSS prices of $127 million and lower BGSS volumes of $109 million due to warmer weather and economic conditions. The average price of gas was 9% lower in 2010 than 2009.

•

Electric revenues decreased $197 million due primarily to $271 million in lower BGS revenues, partially offset by $74 million in higher NUG and NGC revenues due primarily to higher prices. BGS sales were down 8% due primarily to large customer migration to TPS; in contrast delivery sales were up 6% due to warmer weather.

Clause Revenues decreased by $62 million due primarily to the MTC refund of $122 million. In addition, the STC was $68 million higher and the SBC was $8 million lower. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in Operation and Maintenance, Depreciation and Amortization and Interest. PSE&G earns no margins on SBC or STC collections.

Delivery Revenues increased $144 million due primarily to an increase in prices for electric distribution and transmission partially offset by a decrease in gas distribution.

•

Electric distribution revenues were up $126 million due primarily to higher sales volumes of $54 million, the impact of the June base rate increases of $38 million, stimulus revenue increases of $17 million and RGGI revenue increases of $17 million.

•

Transmission revenues were up $27 million due primarily to net rate increases.

•

Gas distribution revenues were down $9 million due primarily to lower sales volumes of $22 million partially offset by increased capital stimulus revenues of $9 million and RGGI revenue increases of $5 million. The impact of the July base rate increase will be realized in the winter months.

Other Operating Revenues increased $17 million due primarily to increased revenues from our appliance repair business and late payment charges.

Energy Costs decreased $433 million. This is entirely offset by Commodity Revenue. Details are as follows:

•

Gas costs decreased $236 million due to $126 million or 9% in lower prices and by $110 million or 8% in lower sales volumes due primarily to warmer weather and economic conditions.

•

Electric costs decreased $197 million due to $204 million or 8% in lower BGS and NUG volumes due to large customer migration to TPS, warmer weather and economic conditions, partially offset by $7 million of higher BGS and NUG prices.

Operation and Maintenance decreased $6 million due primarily to

•

a $30 million decrease in electric and gas operating expenses as part of our overall cost reduction efforts, and

•

a $5 million reduction in Services company charges for gains on the investments in our Rabbi Trust,

•

partially offset by a $14 million write-off of deferred costs associated with the new customer accounting system,

•

$11 million in storm restoration work, and

•

a net $4 million of higher expenses associated with SBC, STC, RGGI and Stimulus clauses.

Depreciation and Amortization increased $101 million due primarily to

•

an increase of $88 million for amortization of regulatory assets,

•

an increase of $8 million for additional plant in service, and

•

an increase of $4 million in software amortization.

Other Income and (Deductions)-Net Other Income increased $15 million due primarily to $11 million of gains realized on the investments in our Rabbi Trust and $4 million in higher investment income.

Interest Expense increased by $3 million due primarily to new debt issued in 2010.

Income Tax Expense decreased by $5 million due primarily to flow-through tax benefits primarily related to uncollectible accounts, partially offset by higher pre-tax income.

Energy Holdings


	Three Months Ended September 30,					Increase/ (Decrease)		Nine Months Ended September 30,				Increase/ (Decrease)
	2010		2009			2010 vs 2009		2010		2009		2010 vs 2009
		Millions
Income from Continuing Operations	$	24	$	(1	)	$	25	$	43	$	30	$	13
Net Income	$	24	$	(1	)	$	25	$	43	$	30	$	13

For the three months ended September 30, 2010, the primary reason for the $25 million increase in Income from Continuing Operations was the absence of the premium paid on the debt exchange with Power in 2009.

For the nine months ended September 30, 2010, the primary reasons for the $13 million increase in Income from Continuing Operations were

•

the absence of the premium paid on the debt exchange with Power in 2009,

•

partially offset by lower gains on the sales of leveraged lease assets, and

•

an asset impairment charge (see Note 10. Fair Value Measurements).

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)
	2010		2009			2010 vs 2009						2010		2009			2010 vs 2009
	Millions					Millions			%			Millions					Millions			%
Operating Revenues	$	58	$	57		$	1			2		$	114	$	196		$	(82	)		(42	)
Operation and Maintenance		10		14			(4	)		(29	)		32		37			(5	)		(14	)
Depreciation and Amortization		4		3			1			33			10		8			2			25
Income from Equity Method Investments		4		6			(2	)		(33	)		12		17			(5	)		(29	)
Other Income and (Deductions)		7		(34	)		41			N/A			9		(29	)		38			N/A
Interest Expense		4		10			(6	)		(60	)		8		35			(27	)		(77	)
Income Tax Expense		27		3			24			N/A			42		74			(32	)		(43	)

For the three months ended September 30, 2010 as compared to 2009

Operating Revenues increased by $1 million due to revenues from our solar projects which have commenced operations, partially offset by lower gains on sales of lease investments.

Operation and Maintenance decreased $4 million due primarily to reduction of Services company charges and decreases in labor and outside service costs as part of our overall cost reduction efforts.

Depreciation and Amortization increased $1 million due primarily to our solar projects which have commenced operations.

Income from Equity Method Investments decreased $2 million due primarily to higher reserves against GWF Energy in 2010, which was sold in September. See Note 4. Asset Dispositions for additional information.

Other Income and (Deductions) increased $41 million due primarily to the absence of premium paid on the debt exchange with Power in 2009 combined with gains of $3 million on the investments in our Rabbi Trust.

Interest Expense decreased $6 million due primarily to lower debt balances following the debt exchange with Power.

Income Tax Expense increased $24 million due primarily to the absence of the tax benefit related to the premium paid on the debt exchange with Power in 2009 and higher pre-tax income.

For the nine months ended September 30, 2010 as compared to 2009

Operating Revenues decreased $82 million due primarily to lower gains on the sale and termination of leveraged lease assets, the resultant loss of revenues previously generated by such assets and pre-tax impairment recorded during the quarter ended June 30, 2010. See Note 7. Commitments and Contingent Liabilities and Note 10. Fair Value Measurements for additional information.

Operation and Maintenance decreased $5 million due primarily to reduction of Services company charges and decreases in labor and outside service costs as part of our overall cost reduction efforts.

Depreciation and Amortization increased $2 million due primarily to our solar projects which have commenced operations.

Income from Equity Method Investments decreased $5 million due primarily to lower earnings at GWF Power Systems, LP and higher reserves recorded against GWF Energy in 2010 partially offset by the absence of an impairment related to GWF Energy recorded in the second quarter of 2009. See Note 4. Asset Dispositions for additional information.

Other Income and (Deductions) increased $38 million due primarily to the absence of premium paid on the debt exchange with Power in 2009 combined with gains of $3 million on the investments in our Rabbi Trust.

Interest Expense decreased $27 million due primarily to lower debt balances following the debt exchange with Power.

Income Tax Expense decreased $32 million due primarily to lower gains on sales of leveraged lease assets, partially offset by the absence of the tax benefit related to premium paid on the debt exchange with Power in 2009.

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, 2010, our operating cash flow decreased by $2 million as compared to the same period in 2009. 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 decreased $173 million from $1,429 million to $1,256 million for the nine months ended September 30, 2010, as compared to the same period in 2009, due primarily to lower pricing realized on higher generation volumes combined with a decrease of $89 million related to our net cash collateral outflow in 2010 as compared to net receipts in the prior year.

PSE&G

PSE&G’s operating cash flow increased $5 million from $422 million to $427 million for the nine months ended September 30, 2010, as compared to the same period in 2009, due primarily to higher delivery margins realized due to higher customer demand and our base rate increase offset by lower recovery of deferred gas costs and other clauses as compared to the prior year.

Energy Holdings

Energy Holdings’ operating cash flow improved by $275 million due primarily to lower tax payments in 2010 due to reduced lease sale activity this year and the $140 million additional tax deposit made with the IRS in June 2009.

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 PSEG’s credit facilities are provided by a diverse bank group. As of September 30, 2010, no single institution represented more than 11% of the total commitments in our credit facilities.

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, 2010 were as follows:


	As of September 30, 2010
Company/Facility	Total Facility		Usage			Available Liquidity		Expiration Date		Primary Purpose
	Millions
PSEG
5-year Credit Facility (A)	$	1,000	$	16	(C)	$	984		Dec 2012	Commercial Paper (CP) Support/Funding/ Letters of Credit

Total PSEG	$	1,000	$	16		$	984

Power
5-year Credit Facility (A)	$	1,600	$	155	(C)	$	1,445		Dec 2012	Funding/Letters of Credit
2-year Credit Facility	$	350	$	0		$	350		July 2011	Funding
Bilateral Credit Facility	$	100	$	100	(C)	$	0		Sep 2015	Letters of Credit

Total Power	$	2,050	$	255		$	1,795

PSE&G
5-year Credit Facility (B)	$	600	$	0		$	600		June 2012	CP Support/Funding/ Letters of Credit

Total PSE&G	$	600	$	0		$	600

Total	$	3,650	$	271		$	3,379

(A)	In December 2011, these facilities will be reduced by $47 million and $75 million, for PSEG and Power, respectively.

(B)	In June 2011, this facility will be reduced by $28 million.

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

On March 16, 2010, a $100 million bilateral credit facility at Power expired. On August 6, 2010, Power entered into a new $100 million bilateral credit facility that expires in September 2015. This new credit facility is being used to issue letters of credit. We continually monitor our available liquidity and seek to add capacity as needed to meet our liquidity requirements. As of September 30, 2010, our total credit facility capacity continued to be in excess of our anticipated maximum liquidity requirements through 2010.

Long-Term Debt Financing

For a discussion of our long-term debt transactions during 2010, see Note 8. Changes in Capitalization.

Common Stock Dividends

Dividend payments on common stock for the three months ended September 30, 2010 were $0.3425 per share and totaled $173 million. Dividend payments on common stock for the three months ended September 30, 2009 were $0.3325 per share and totaled $168 million.

Dividend payments on common stock for the nine months ended September 30, 2010 were $1.0275 per share and totaled $520 million. Dividend payments on common stock for the nine months ended September 30, 2009 were $0.9975 per share and totaled $505 million.

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 August 2010, Fitch affirmed the ratings of PSEG, Power and PSE&G. In September and October 2010, both Moody’s and S&P published updated credit opinions for PSEG, Power and PSE&G, which kept the ratings and outlooks unchanged.

Moody’s(A)

S&P(B)

Fitch(C)

PSEG:

Outlook

Stable

Commercial Paper

Power:

Outlook

Stable

Senior Notes

Baa1

BBB

BBB+

PSE&G:

Outlook

Stable

Mortgage Bonds

A–

Commercial Paper

(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

As part of its business planning efforts which were initiated following the completion of the base rate case proceedings, PSE&G has reduced certain of its projected capital expenditures for distribution through 2012 by approximately $140 million per year, as compared to the amounts disclosed in our Form 10-K for the year ended December 31, 2009. PSE&G has also assessed the overall timing and level of its capital spending to meet the transmission needs of the region, including the impacts of delays in capital spending for the Susquehanna-Roseland transmission project and changes to the scope of the Branchburg to Hudson project as described in Item 5. Other Information – Federal Regulation – FERC, and State Regulation – Energy Policy. PSE&G expects to pursue other transmission projects which will partially offset the delay or reduction in spending on the Susquehanna-Roseland and Branchburg to Hudson projects. The implementation and timing of the projected capital expenditures shown below are subject to obtaining timely government approvals. These governmental approvals include siting and environmental approvals, and in some instances, approval of construction work in progress rate treatment. PSE&G has revised its projected capital expenditures as follows:


	2010		2011		2012		2013
			Millions
PSE&G:
Transmission	$	350	$	670	$	910	$	1,140
Distribution		900		460		390		420
Renewables/EMP		350		320		190		30

Total PSE&G	$	1,600	$	1,450	$	1,490	$	1,590

There were no material changes to our projected capital expenditures at Power or Energy Holdings as compared to amounts disclosed in the 2009 Form 10-K, except for an increase of approximately $140 million of projected capital expenditures at Power in 2011 which are primarily related to construction of additional peaking facilities.

We expect that the majority of funding for our capital requirements over the next three years will come from a combination of internally generated funds and external financings. These amounts are subject to change, based on various factors.

Power

During the nine months ended September 30, 2010, Power made $453 million of capital expenditures (excluding $126 million for nuclear fuel), related primarily to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 7. Commitments and Contingent Liabilities.

PSE&G

During the nine months ended September 30, 2010, PSE&G made $882 million of capital expenditures, including $871 million of investment in plant, primarily for reliability of transmission and distribution systems and $11 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $47 million and other renewables of $56 million, which are included in operating cash flows.

Energy Holdings

During the nine months ended September 30, 2010, Energy Holdings made $61 million of capital expenditures, primarily related to construction of its two solar projects in Florida and Ohio.

ACCOUNTING MATTERS

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Contracts

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

We manage our exposure at the portfolio level, which consists of owned generation, electric load-serving contracts, fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While we manage our risk at the portfolio level, we also monitor separately the risk of our trading activities and hedges. Non-trading mark-to-market (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, and a 95% confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.

As of September 30, 2010 and December 31, 2009, trading VaR was $1 million.


For the Three Months Ended September 30, 2010	Trading VaR		Non-Trading MTM VaR
	Millions
95% Confidence level,
Loss could exceed VaR one day in 20 days
Period End	$	1	$	4
Average for the Period	$	1	$	9
High	$	1	$	15
Low	$	0	$	4
99.5% Confidence level,
Loss could exceed VaR one day in 200 days
Period End	$	1	$	7
Average for the Period	$	1	$	13
High	$	2	$	23
Low	$	1	$	7

See Note 9. Financial Risk Management Activities for a discussion of credit risk.

ITEM 4.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer 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 2010 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the respective 2009 Annual Reports on Form 10-K of PSEG, Power and PSE&G, see Note 7. Commitments and Contingent Liabilities and Item 5. Other Information.

Certain information reported under the 2009 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010 is updated below. References are to the related pages on the Form 10-K or Form 10-Q as printed and distributed.

Con Edison (Con Ed)

2009 Form 10-K, Page 41. In 2001, Con Ed filed a complaint with FERC against PSE&G, PJM and the NYISO asserting a failure to comply with agreements between PSE&G and Con Ed covering 1,000 MW of transmission. On September 16, 2010, the FERC approved a settlement agreement entered into by PSE&G, Con Ed, PJM, the NYISO and others in 2008. This settlement provides the basis for moving forward with Con Ed after the current contracts expire in 2012 and settles all issues associated with the existing contracts, including cases pending in the D.C. Circuit Court of Appeals. However, dismissal of these court cases is contingent upon receipt of a final, non-appealable order from the FERC. One party to the proceeding has sought rehearing of the FERC approval order and will likely appeal an adverse decision on rehearing. As a result, the settlement has not yet taken effect and may not take effect for some time.

ITEM 1A.

RISK FACTORS

There are no additional Risk Factors to be added to those disclosed in Part I Item 1A of our 2009 Annual Reports on Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation award grants during the third quarter of 2010:


Three Months Ended September 30, 2010	Total Number of Shares Purchased		Average Price Paid per Share
July 1-July 31		0	$	0
August 1-August 31		30,139	$	32.97
September 1-September 30		11,000	$	32.41

ITEM 5.

OTHER INFORMATION

Certain information reported under the 2009 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2009 Annual Report on Form 10-K and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010. References are to the related pages on the Form 10-K or Form 10-Q as printed and distributed.

FEDERAL REGULATION

Greenhouse Gas—CO₂

March 31, 2010 Form 10-Q, Page 69 and June 30, 2010 Form 10-Q, Page 80. In April 2010, the EPA and the National Highway Transportation Safety Board (NHTSB) jointly issued a final rule to regulate greenhouse gas (GHG) emissions from certain motor vehicles (Motor Vehicle Rule). Under the Clean Air Act, the adoption of the Motor Vehicle Rule would have automatically subjected many emission sources, including ours, to Clean Air Act permitting for major facility modifications that increase the emission of GHGs, including CO₂. However, guidance issued by the EPA in March 2010 interpreted the Clean Air Act to require permitting for GHGs at other facilities, such as ours, only when the Motor Vehicle Rule takes effect in January 2011. On May 13, 2010, the EPA finalized a “Tailoring Rule” that will phase in, beginning in 2011, the application of this permitting requirement to facilities such as ours. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, the owner of the facility would need to evaluate and perhaps install best available control technology (BACT) for GHG emissions. The EPA is developing guidance to state and local permitting authorities to undertake BACT determinations for new and modified emission sources. The EPA is also developing a database of potential control technologies and processes that a permit applicant should consider in undertaking a BACT determination. This guidance has not yet been made available and as such what constitutes BACT for GHG cannot be predicted.

Clean Air Transport Rule (CATR)

June 30, 2010 Form 10-Q, Page 81. On August 2, 2010, the EPA proposed the CATR to limit emissions in 32 states that contribute to the ability of downwind states to attain and/or maintain the 1997 and 2006 PM2.5 nonattainment areas and the 1997 ozone National Ambient Air Quality Standards (NAAQS). The rule is proposed to be implemented through 32 federal implementation plans (FIPs). Beginning in 2012, emissions reductions would be governed by this rule, rather than the Clean Air Interstate Rule (CAIR). By 2014, the EPA estimates that this rule, along with other concurrent state and EPA actions, would reduce power plant SO₂ emissions by 71% and NO_X emissions by 52% as compared to 2005 levels. The EPA has acknowledged that further reductions may be necessary to meet several eastern states’ NAAQS. In addition to the states covered by CAIR, the CATR includes Kansas, Nebraska, Oklahoma and the District of Columbia. Minnesota is proposed to be included as well. The outcome of the EPA’s rulemaking can not be predicted.

Coal Combustion Residuals (CCRs)

June 30, 2010 Form 10-Q, Page 81. In June 2010, the EPA formally published a proposed rule in the Federal Register offering three main options for the management of CCRs under the Resource Conservation and Recovery Act. One of these options regulates CCRs as a hazardous waste and the other two options are variations of a non-hazardous designation. All options communicate the EPA’s intent of ceasing wet ash transfer and instituting engineering controls on ash ponds and landfills to limit impact on human health and the environment. We currently have a program to beneficially reuse coal ash as presently allowed by Federal and state regulations. The outcome of the EPA rulemaking can not be predicted.

FERC

Transmission Expansion

2009 Form 10-K, Page 19, March 31, 2010 Form 10-Q, Page 70 and June 30, 2010 Form 10-Q, page 81. In December 2008, PJM approved a 500 kV transmission project, originating in Branchburg and ending in Hudson County, New Jersey, with an estimated cost of $1.1 billion. In October 2009, we filed a petition with FERC seeking incentive rates for the planned project. In December 2009, FERC granted our request for incentive rate treatment. The FERC order approved a Return on Equity (ROE) adder of 125 basis points above our base ROE, recovery of 100% of Construction Work in Progress in rate base and authorization to recover 100% of all prudently incurred development and construction costs if the project is abandoned or cancelled, in whole or in part, for reasons beyond our control. In place of the original project, PJM has just approved a modified 230 kV project, originating in Roseland and terminating in Hudson County, at an estimated cost of

up to $700 million. The project will have an expected in-service date of June 2015. Development and siting activities for this project are expected to commence in 2011. PSE&G believes the modified project will be eligible for the same rate incentives as the original project, but has not received confirmation from the FERC.

STATE REGULATION

Rates

Electric and Gas Base Rate Case

2009 Form 10-K, page 21, March 31, 2010 Form 10-Q, Page 70 and June 30, 2010 Form 10-Q, Page 81. In May 2009, we filed briefs in our base rate case supporting an increase in electric and gas distribution base rates. We filed an update in March 2010 requesting an increase of $140 million and $64 million for electric and gas, respectively.

The BPU adopted the stipulation at its June 7, 2010 Agenda Meeting. The BPU accepted and approved the electric portion of the settlement including the electric revenue requirement, the capital structure, re-setting the electric component of the Capital Infrastructure Charge, as well as accepting the modifications to the electric tariff. The new electric rates were put into effect on June 7, 2010. The settlement included a $73.5 million increase in annual electric revenues and an allowed ROE of 10.3%. On June 18, 2010, the BPU approved the gas revenue requirement and rate design set forth in the stipulation and an allowed ROE of 10.3%, resulting in a $26.5 million increase effective July 9, 2010. The BPU also approved PSE&G’s gas weather normalization clause.

Retail Gas Transportation Rates

June 30, 2010 Form 10-Q, Page 82. Since settlement discussions are in progress, the BPU has adjourned the hearings so that settlement efforts can continue. See Note 7. Commitments and Contingent Liabilities for more detail.

Consolidated Tax Adjustments

June 30, 2010 Form 10-Q, Page 82. See Note 7. Commitments and Contingent Liabilities for more detail.

Universal Service Fund (USF) Filing

2009 Form 10-K, Page 22. The USF is an energy assistance program mandated by the BPU under the Competition Act to provide payment assistance to low income customers. The Lifeline program is a separately mandated energy assistance program to provide payment assistance to elderly and disabled customers. On June 30, 2010, the State’s electric and gas utilities filed to reset the statewide rates for the USF and the Lifeline program. The filed rates were subsequently updated and approved effective November 1, 2010 in a written Order dated October 20, 2010. The filed rates were set to recover $215 million on a statewide basis. Of this amount, the revised statewide electric rates will recover $150 million and the statewide gas rates will recover $65 million. The rates for the Lifeline program are set to recover $73 million, $49 million and $24 million for electric and gas respectively. We earn no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.

SBC/NGC

2009 Form 10-K, Page 22, March 31, 2010 Form 10-Q, Page 70 and June 30, 2010 Form 10-Q, Page 82. In February 2009, we filed a petition requesting a decrease in our electric SBC/NGC rates of $18.9 million and an increase in gas SBC rates of $3.7 million. In July 2009, a revision was filed requesting an increase in SBC/NGC rates of $104 million and $15 million for electric and gas, respectively. The electric increase was due to increased non-utility generation (NUG) contract costs. The ALJ issued an initial decision in April 2010 that recommended a revenue increase of $119 million and a disallowance of approximately $254,000 in PJM costs from the NGC and approximately $540,000 of interest that accrued on the electric SBC. Although PSE&G filed exceptions to the recommendation, the BPU issued a written order in June 2010, adopting the ALJ’s initial decision. PSE&G filed a notice of appeal on August 9, 2010 regarding the disallowances related to the NGC and electric SBC. We cannot predict the outcome of this appeal.

In August 2010, PSE&G made its 2010 annual SBC/NGC filing requesting an $85.4 million electric increase and a $17.2 million gas decrease. This matter has been transferred to the Office of Administrative Law for establishment of a procedural schedule and hearings.

RAC 17

2009 Form 10-K, Page 22 and June 30, 2010 Form 10-Q, page 82. In August 2010, the BPU issued an order approving a settlement agreement which provides for the recovery of $23.9 million for the twelve months ended July 2009.

Regional Green House Gas Initiative (RGGI) Energy Efficiency and Renewable Energy Programs

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. PSE&G is proposing to implement the revised RRC rates on January 1, 2011.

Energy Supply

BGSS

2009 Form 10-K Page 23 and June 30, 2010 Form 10-Q, page 82. On July 9, 2010, PSE&G self-implemented a reduction in the BGSS rate. The reduction targets an approximate $90 million decrease in the BGSS deferred balance on an annual basis. The reduction in the BGSS-RSG Commodity Charge for a typical gas residential heating customer would be a decrease of approximately 5%.

In July 2010, PSE&G made its annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $123 million, excluding sales and use tax, to be effective October 1, 2010. This represented a reduction of approximately 6.8% for a typical residential gas heating customer. The new BGSS rate was approved by the BPU in September 2010, on a provisional basis, and was made effective immediately.

Energy Policy

Susquehanna-Roseland BPU Petition

2009 Form 10-K, Page 25, March 31, 2010 Form 10-Q, Page 70 and June 30, 2010 Form 10-Q, page 82. In January 2009, we filed a Petition with the BPU seeking authorization to construct the New Jersey portion of the Susquehanna-Roseland line. The New Jersey portion of the line spans approximately 45 miles and crosses through 16 municipalities. The Petition sought a finding from the BPU that municipal land use and zoning ordinances do not apply to this line. On February 11, 2010, the BPU granted approval to PSE&G to construct the New Jersey portion of this project. On April 21, 2010, the BPU issued a written order memorializing the action taken on February 11, which in turn enabled PSE&G to commence condemnation proceedings for the eastern segment of the project. PSE&G is currently pursuing condemnation action with respect to three properties on this eastern segment. Two interveners have appealed the BPU Order and they are now seeking to supplement the appellate record. Regarding environmental approvals, in June 2009, the New Jersey Highlands Council provided a favorable applicability determination with respect to the portion of the project crossing the Highlands region and the New Jersey Department of Environmental Protection (NJDEP) approved this determination on January 15, 2010. We have not obtained from the NJDEP certain environmental approvals that are required for each of the Eastern and Western segments of the line. We believe it unlikely that we will obtain until late 2012, at the earliest, all of the state environmental approvals that are required for completion of either portion of the line. The Western portion of the line requires certain permits from the National Park Service, whose review is not expected to be completed until late 2012. Consequently, at this time, we do not expect the Eastern portion of the line to be in service before June 2014, and do not expect the Western portion to be in service before June 2015. Further delays are possible for both portions. Delays in the construction schedule could impact the timing of expected transmission revenues. We cannot predict what action, if any, PJM might take in response to these delays.

Federal Transmission Policy Developments

June 30, 2010 Form 10-Q, Page 83. In June 2010, the FERC issued a Notice of Proposed Rulemaking proposing to modify current transmission planning and cost allocation processes. Specifically, FERC has

proposed that transmission planning take into account “public policy” requirements established by state or federal laws or regulations, such as state Renewable Portfolio Requirements. FERC has also questioned whether it is appropriate for transmission planning to utilize a “bright line” test to identify needed transmission projects or whether “flexible criteria” should be used. These proposed changes would likely result in more transmission being planned. FERC has proposed to eliminate provisions in FERC-approved tariffs or agreements that permit a transmission owner within whose franchised service territory a transmission project is being constructed to exercise a “right of first refusal” to construct the project. PSEG is actively participating in this rulemaking proceeding. We filed initial comments on these issues on September 29, 2010 and will be filing reply comments on November 12th. There are also two pending FERC litigated proceedings, in which we are not a party, addressing and challenging this “right of first refusal.” A change in FERC rules or adverse decisions in these proceedings could result in third parties constructing transmission within PSE&G’s service territory in the future.

ENVIRONMENTAL MATTERS

Fuel and Waste Disposal

2009 Form 10-K, Page 28, March 31, 2010 Form 10-Q, Page 71 and June 30, 2010 Form 10-Q, Page 83. The Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund. Under the contracts, the US Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The Nuclear Waste Policy Act requires the DOE to perform an annual review of the Nuclear Waste Fee to determine whether that fee is set appropriately to fund the national nuclear waste disposal program. In October 2009 the DOE stated that the current fee of 1/10 cent per kWh was adequate to recover program costs. In April 2010, we joined the Nuclear Energy Institute and fifteen other nuclear plant operators in petitioning the United States Court of Appeals for the District of Columbia District to review the DOE decision to continue to collect the Nuclear Waste Fee at the current rate. That proceeding is still on-going. The Nuclear Waste Fee litigation is not expected to have any effect on Power’s September 2009 settlement agreement with DOE applicable to Salem and Hope Creek under which Power will be reimbursed for past and future reasonable and allowable costs resulting from the DOE delay in accepting spent nuclear fuel for permanent disposition.

ITEM 6.

EXHIBITS

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

a. PSEG:

Exhibit 12:

Computation of Ratios of Earnings to Fixed Charges

Exhibit 31:

Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (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*

*	XBRL information is furnished, not filed.

b. Power:

Exhibit 12.1:

Computation of Ratios of Earnings to Fixed Charges

Exhibit 31.2:

Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act

Exhibit 31.3:

Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act

Exhibit 32.2:

Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the 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

c. PSE&G:

Exhibit 4:

Supplemental Indenture, dated October 1, 2010

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

SIGNATURE

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


PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

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

Date: October 29, 2010

SIGNATURE


PSEG Power LLC
(Registrant)

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

Date: October 29, 2010

SIGNATURE


PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:		/S/ DEREK M. DIRISIO

		Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: October 29, 2010