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.

[THIS PAGE INTENTIONALLY LEFT BLANK]

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