Edgar Filing: PUBLIC SERVICE ELECTRIC & GAS CO

3B2 EDGAR HTML -- c58983_preflight.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED September 30, 2009
OR

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO


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

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes S 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 S

No £

PSEG Power LLC

Yes £

No £

Public Service Electric and Gas Company

Yes £

No £

(Cover continued on next page)

(Cover continued from previous page)

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 S	Accelerated filer £	Non-accelerated filer £	Smaller reporting company £
PSEG Power LLC	Large accelerated filer £	Accelerated filer £	Non-accelerated filer S	Smaller reporting company £
Public Service Electric and Gas Company	Large accelerated filer £	Accelerated filer £	Non-accelerated filer S	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 S

As of October 15, 2009, Public Service Enterprise Group Incorporated had outstanding 505,980,424 shares of its sole class of Common Stock, without par value.

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

As of October 15, 2009, 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.


		Page

FORWARD-LOOKING STATEMENTS			ii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated		1
	PSEG Power LLC		5
	Public Service Electric and Gas Company		8
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation		12
	Note 2. Recent Accounting Standards		13
	Note 3. Discontinued Operations and Dispositions		16
	Note 4. Available-for-Sale Securities		17
	Note 5. Pension and Other Postretirement Benefits (OPEB)		22
	Note 6. Commitments and Contingent Liabilities		23
	Note 7. Changes in Capitalization		34
	Note 8. Financial Risk Management Activities		35
	Note 9. Fair Value Measurements		43
	Note 10. Other Income and Deductions		50
	Note 11. Income Taxes		51
	Note 12. Comprehensive Income (Loss), Net of Tax		53
	Note 13. Earnings Per Share (EPS)		54
	Note 14. Financial Information by Business Segments		55
	Note 15. Related-Party Transactions		56
	Note 16. Guarantees of Debt		59
	Note 17. Subsequent Events		61
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview of 2009 and Future Outlook		62
	Results of Operations		67
	Liquidity and Capital Resources		77
	Capital Requirements		79
	Accounting Matters		80
Item 3.	Qualitative and Quantitative Disclosures About Market Risk		80
Item 4.	Controls and Procedures		82
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		83
Item 1A.	Risk Factors		83
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		84
Item 5.	Other Information		84
Item 6.	Exhibits		88
	Signatures		89

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “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 6. Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to

•

adverse changes in energy industry law, policies and regulation, including market structures and rules, and reliability standards,

•

any inability of our energy transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators,

•

changes in federal and/or state environmental requirements 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 that might adversely affect our ability to continue to operate that unit or other units 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 reasonable pricing terms 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 or cost escalations in our construction and development activities,

•

adverse investment performance of our decommissioning and defined benefit plan trust funds and changes in discount rates and funding requirements, and

•

changes in technology and/or increased customer conservation.

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.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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,
	2009				2008				2009				2008
OPERATING REVENUES		$	3,041			$	3,718			$	9,523			$	10,060
OPERATING EXPENSES
Energy Costs			1,241				1,899				4,376				5,552
Operation and Maintenance			622				609				1,925				1,856
Depreciation and Amortization			224				214				634				597
Taxes Other Than Income Taxes			30				31				100				101

Total Operating Expenses			2,117				2,753				7,035				8,106

OPERATING INCOME			924				965				2,488				1,954
Income from Equity Method Investments			10				8				29				27
Impairment on Equity Method Investments			(4	)			(1	)			(12	)			(1	)
Other Income			43				95				205				285
Other Deductions			(19	)			(43	)			(118	)			(156	)
Other-Than-Temporary Impairments			—				(65	)			(61	)			(135	)
Interest Expense			(129	)			(149	)			(407	)			(448	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			825				810				2,124				1,526
Income Tax Expense			(337	)			(334	)			(881	)			(780	)

INCOME FROM CONTINUING OPERATIONS			488				476				1,243				746
Income from Discontinued Operations, net of tax expense of $160 and $174 for the three and nine months ended 2008			—				180				—				208

NET INCOME		$	488			$	656			$	1,243			$	954

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC			505,982				507,724				505,986				508,233

DILUTED			507,242				508,326				506,957				508,890

EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS		$	0.96			$	0.94			$	2.45			$	1.47
NET INCOME		$	0.96			$	1.29			$	2.45			$	1.88
DILUTED
INCOME FROM CONTINUING OPERATIONS		$	0.96			$	0.94			$	2.45			$	1.47
NET INCOME		$	0.96			$	1.29			$	2.45			$	1.88

DIVIDENDS PAID PER SHARE OF COMMON STOCK		$	0.3325			$	0.3225			$	0.9975			$	0.9675

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)


	September 30, 2009				December 31, 2008
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	130			$	321
Accounts Receivable, net of allowances of $74 and $66 in 2009 and 2008, respectively			1,242				1,398
Unbilled Revenues			272				454
Fuel			942				938
Materials and Supplies			360				317
Prepayments			318				150
Restricted Funds			10				118
Derivative Contracts			217				237
Other			50				66

Total Current Assets			3,541				3,999

PROPERTY, PLANT AND EQUIPMENT			21,920				20,818
Less: Accumulated Depreciation and Amortization			(6,777	)			(6,385	)

Net Property, Plant and Equipment			15,143				14,433

NONCURRENT ASSETS
Regulatory Assets			5,806				6,352
Long-Term Investments			2,164				2,695
Nuclear Decommissioning Trust (NDT) Funds			1,177				970
Other Special Funds			145				133
Goodwill			16				16
Other Intangibles			110				53
Derivative Contracts			125				160
Other			207				238

Total Noncurrent Assets			9,750				10,617

TOTAL ASSETS		$	28,434			$	29,049

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)


	September 30, 2009				December 31, 2008
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	648			$	1,033
Commercial Paper and Loans			243				19
Accounts Payable			911				1,227
Derivative Contracts			232				356
Accrued Interest			146				99
Accrued Taxes			167				8
Clean Energy Program			163				142
Obligation to Return Cash Collateral			93				102
Other			390				424

Total Current Liabilities			2,993				3,410

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)			4,090				3,865
Regulatory Liabilities			472				355
Asset Retirement Obligations			605				576
Other Postretirement Benefit (OPEB) Costs			972				975
Accrued Pension Costs			899				1,196
Clean Energy Program			434				532
Environmental Costs			715				743
Derivative Contracts			60				164
Long-Term Accrued Taxes			717				1,241
Other			136				125

Total Noncurrent Liabilities			9,100				9,772

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6)

CAPITALIZATION LONG-TERM DEBT
Long-Term Debt			6,326				6,621
Securitization Debt			1,201				1,342
Project Level, Non-Recourse Debt			39				42

Total Long-Term Debt			7,566				8,005


SUBSIDIARY’S PREFERRED STOCK WITHOUT MANDATORY REDEMPTION			80				80


STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2009 and 2008—533,556,660 shares			4,780				4,756
Treasury Stock, at cost, 2009—27,575,156 shares; 2008—27,538,762 shares			(587	)			(581	)
Retained Earnings			4,523				3,773
Accumulated Other Comprehensive Loss			(31	)			(177	)

Total Common Stockholders’ Equity			8,685				7,771
Noncontrolling Interest - Equity Investments			10				11

Total Capitalization			16,341				15,867

TOTAL LIABILITIES AND CAPITALIZATION		$	28,434			$	29,049

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,
	2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	1,243			$	954
Adjustments to Reconcile Net Income to Net Cash Flows from
Operating Activities:
Gain on Disposal of Discontinued Operations			—				(374	)
Depreciation and Amortization			634				599
Amortization of Nuclear Fuel			88				75
Provision for Deferred Income Taxes (Other than Leases) and ITC			209				1
Non-Cash Employee Benefit Plan Costs			260				126
Lease Transaction Reserves, net of tax			—				490
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes			(542	)			20
Gain on Sale of Investments			(137	)			(1	)
Undistributed Earnings from Affiliates			(19	)			(32	)
Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives			(125	)			(77	)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs			55				(21	)
Over (Under) Recovery of Societal Benefits Charge (SBC)			40				(42	)
Cost of Removal			(38	)			(33	)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds			(25	)			22
Net Change in Certain Current Assets and Liabilities			252				(2	)
Employee Benefit Plan Funding and Related Payments			(426	)			(122	)
Other			(128	)			9

Net Cash Provided By Operating Activities			1,341				1,592

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(1,232	)			(1,237	)
Proceeds from Sale of Discontinued Operations			—				772
Proceeds from the Sale of Capital Leases and Investments			729				37
Proceeds from NDT Funds Sales			1,631				1,839
Investment in NDT Funds			(1,653	)			(1,864	)
Restricted Funds			113				(32	)
NDT Funds Interest and Dividends			30				37
Increase in Solar Loan Investments			(18	)			—
Investment in Joint Ventures and Partnerships			(11	)			—
Other			(8	)			(11	)

Net Cash Used In Investing Activities			(419	)			(459	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans			224				116
Issuance of Long-Term Debt			209				700
Purchase of Common Treasury Stock			—				(92	)
Redemptions of Long-Term Debt			(584	)			(1,263	)
Repayment of Non-Recourse Debt			(284	)			(38	)
Redemption of Securitization Debt			(133	)			(127	)
Premium Paid on Debt Exchange			(36	)			—
Net Premium Paid on Early Extinguishment of Debt			—				(80	)
Cash Dividends Paid on Common Stock			(505	)			(492	)
Other			(4	)			(8	)

Net Cash Used In Financing Activities			(1,113	)			(1,284	)

Net Decrease in Cash and Cash Equivalents			(191	)			(151	)
Cash and Cash Equivalents at Beginning of Period			321				380

Cash and Cash Equivalents at End of Period		$	130			$	229

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	1,060			$	865
Interest Paid, Net of Amounts Capitalized		$	344			$	375

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,
	2009				2008				2009				2008
OPERATING REVENUES		$	1,422			$	1,833			$	5,097			$	5,831
OPERATING EXPENSES
Energy Costs			526				904				2,551				3,360
Operation and Maintenance			255				282				784				796
Depreciation and Amortization			44				42				139				121

Total Operating Expenses			825				1,228				3,474				4,277

OPERATING INCOME			597				605				1,623				1,554
Other Income			40				88				196				267
Other Deductions			(17	)			(39	)			(111	)			(147	)
Other-Than-Temporary Impairments			—				(65	)			(60	)			(135	)
Interest Expense			(37	)			(42	)			(119	)			(125	)

INCOME BEFORE INCOME TAXES			583				547				1,529				1,414
Income Tax Expense			(236	)			(219	)			(607	)			(571	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	347			$	328			$	922			$	843

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, 2009				December 31, 2008
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	17			$	20
Accounts Receivable			379				472
Accounts Receivable—Affiliated Companies, net			740				732
Fuel			942				938
Materials and Supplies			260				233
Derivative Contracts			188				225
Restricted Funds			6				21
Prepayments			56				53
Other			2				11

Total Current Assets			2,590				2,705

PROPERTY, PLANT AND EQUIPMENT			7,940				7,441
Less: Accumulated Depreciation and Amortization			(2,144	)			(1,960	)

Net Property, Plant and Equipment			5,796				5,481

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds			1,177				970
Goodwill			16				16
Other Intangibles			101				43
Other Special Funds			29				27
Derivative Contracts			117				143
Other			84				74

Total Noncurrent Assets			1,524				1,273

TOTAL ASSETS		$	9,910			$	9,459

LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	—			$	250
Accounts Payable			475				752
Short-Term Loan from Affiliate			65				3
Derivative Contracts			224				338
Accrued Interest			80				35
Other			163				155

Total Current Liabilities			1,007				1,533

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)			587				335
Asset Retirement Obligations			354				334
Other Postretirement Benefit (OPEB) Costs			126				118
Derivative Contracts			32				111
Accrued Pension Costs			284				374
Environmental Costs			52				54
Long-Term Accrued Taxes			5				16
Other			67				47

Total Noncurrent Liabilities			1,507				1,389

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6) LONG-TERM DEBT
Total Long-Term Debt			3,166				2,653

MEMBER’S EQUITY
Contributed Capital			2,000				2,000
Basis Adjustment			(986	)			(986	)
Retained Earnings			3,197				2,988
Accumulated Other Comprehensive Income (Loss)			19				(118	)

Total Member’s Equity			4,230				3,884

TOTAL LIABILITIES AND MEMBER’S EQUITY		$	9,910			$	9,459

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,
	2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	922			$	843
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization			139				121
Amortization of Nuclear Fuel			88				75
Interest Accretion on Asset Retirement Obligations			20				19
Provision for Deferred Income Taxes and ITC			105				69
Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives			(126	)			(45	)
Non-Cash Employee Benefit Plan Costs			58				18
Net Realized (Gains) Losses and (Income) Expense from NDT Funds			(25	)			22
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies			(31	)			(287	)
Margin Deposit Asset			(9	)			146
Margin Deposit Liability			72				18
Accounts Receivable			312				45
Accounts Payable			(229	)			(118	)
Accounts Receivable/Payable-Affiliated Companies, net			258				209
Accrued Interest Payable			45				47
Other Current Assets and Liabilities			(43	)			5
Employee Benefit Plan Funding and Related Payments			(112	)			(20	)
Other			(25	)			42

Net Cash Provided By Operating Activities			1,419				1,209

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(632	)			(677	)
Proceeds from NDT Funds Sales			1,631				1,839
NDT Funds Interest and Dividends			30				37
Investment in NDT Funds			(1,653	)			(1,864	)
Restricted Funds			15				22
Other			(8	)			(10	)

Net Cash Used In Investing Activities			(617	)			(653	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt			209				—
Cash Dividend Paid			(725	)			(475	)
Redemption of Long-term Debt			(250	)			—
Short-Term Loan—Affiliated Company, net			62				(70	)
Accounts Receivable due from Affiliate Related to Debt Exchange			(101	)			—

Net Cash Used In Financing Activities			(805	)			(545	)

Net Increase (Decrease) in Cash and Cash Equivalents			(3	)			11
Cash and Cash Equivalents at Beginning of Period			20				11

Cash and Cash Equivalents at End of Period		$	17			$	22

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	464			$	458
Interest Paid, Net of Amounts Capitalized		$	87			$	84

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)


	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
	2009				2008				2009				2008
OPERATING REVENUES		$	1,943			$	2,274			$	6,321			$	6,750
OPERATING EXPENSES
Energy Costs			1,167				1,521				4,005				4,527
Operation and Maintenance			351				313				1,090				993
Depreciation and Amortization			169				161				462				443
Taxes Other Than Income Taxes			30				31				100				101

Total Operating Expenses			1,717				2,026				5,657				6,064

OPERATING INCOME			226				248				664				686
Other Income			2				2				7				9
Other Deductions			—				(2	)			(2	)			(3	)
Interest Expense			(77	)			(82	)			(236	)			(244	)

INCOME BEFORE INCOME TAXES			151				166				433				448
Income Tax Expense			(63	)			(68	)			(177	)			(161	)
NET INCOME			88				98				256				287
Preferred Stock Dividends			(1	)			(1	)			(3	)			(3	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	87			$	97			$	253			$	284

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, 2009				December 31, 2008
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	27			$	91
Accounts Receivable, net of allowances of $73 in 2009 and $65 in 2008, respectively			839				909
Unbilled Revenues			272				454
Materials and Supplies			70				61
Prepayments			227				45
Restricted Funds			4				1
Derivative Contracts			1				—
Deferred Income Taxes			45				52

Total Current Assets			1,485				1,613

PROPERTY, PLANT AND EQUIPMENT			12,824				12,258
Less: Accumulated Depreciation and Amortization			(4,297	)			(4,122	)

Net Property, Plant and Equipment			8,527				8,136

NONCURRENT ASSETS
Regulatory Assets			5,806				6,352
Long-Term Investments			179				158
Other Special Funds			50				46
Other			97				101

Total Noncurrent Assets			6,132				6,657

TOTAL ASSETS		$	16,144			$	16,406

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, 2009			December 31, 2008
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	594		$	248
Commercial Paper and Loans			73			19
Accounts Payable			330			336
Accounts Payable—Affiliated Companies, net			283			763
Accrued Interest			59			58
Accrued Taxes			3			3
Clean Energy Program			163			142
Derivative Contracts			8			14
Obligation to Return Cash Collateral			93			102
Other			190			227

Total Current Liabilities			1,796			1,912

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC			2,628			2,533
Other Postretirement Benefit (OPEB) Costs			799			813
Accrued Pension Costs			459			634
Regulatory Liabilities			472			355
Clean Energy Program			434			532
Environmental Costs			663			689
Asset Retirement Obligations			249			240
Derivative Contracts			24			53
Long-Term Accrued Taxes			94			82
Other			28			31

Total Noncurrent Liabilities			5,850			5,962

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt			3,065			3,463
Securitization Debt			1,201			1,342

Total Long-Term Debt			4,266			4,805

Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2009 and 2008—795,234 shares			80			80

STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2009 and 2008—132,450,344 shares			892			892
Contributed Capital			420			170
Basis Adjustment			986			986
Retained Earnings			1,850			1,597
Accumulated Other Comprehensive Income			4			2

Total Stockholder’s Equity			4,152			3,647

Total Capitalization			8,498			8,532

TOTAL LIABILITIES AND CAPITALIZATION		$	16,144		$	16,406

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,
	2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	256			$	287
Adjustments to Reconcile Net Income to Net Cash Flows from
Operating Activities:
Depreciation and Amortization			462				443
Provision for Deferred Income Taxes and ITC			99				33
Non-Cash Employee Benefit Plan Costs			177				97
Non-Cash Interest Expense			11				11
(Under) Over Recovery of Electric Energy Costs (BGS and NTC)			(9	)			32
Over (Under) Under Recovery of Gas Costs			64				(53	)
Over (Under) Recovery of SBC			40				(42	)
Other Non-Cash Charges			(2	)			(3	)
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues			253				198
Materials and Supplies			(9	)			(12	)
Prepayments			(182	)			(157	)
Accrued Taxes			—				(26	)
Accounts Payable			(6	)			40
Accounts Receivable/Payable-Affiliated Companies, net			(334	)			(264	)
Obligation to Return Cash Collateral			(9	)			102
Other Current Assets and Liabilities			(50	)			(16	)
Cost of Removal			(38	)			(33	)
Employee Benefit Plan Funding and Related Payments			(270	)			(92	)
Other			(31	)			—

Net Cash Provided By Operating Activities			422				545

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(580	)			(534	)
Proceeds from the Sale of Property, Plant and Equipment			2				1
Restricted Funds			2				(1	)
Increase in Solar Loan Investment			(18	)			—

Net Cash Used In Investing Activities			(594	)			(534	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt			54				116
Issuance of Long-Term Debt			—				700
Redemption of Long-Term Debt			(60	)			(651	)
Redemption of Securitization Debt			(133	)			(127	)
Contributed Capital			250				—
Deferred Issuance Costs			—				(4	)
Premium Paid on Early Retirement of Debt			—				(32	)
Preferred Stock Dividends			(3	)			(3	)

Net Cash Provided By (Used In) Financing Activities			108				(1	)

Net (Decrease) Increase In Cash and Cash Equivalents			(64	)			10
Cash and Cash Equivalents at Beginning of Period			91				32

Cash and Cash Equivalents at End of Period		$	27			$	42

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	47			$	109
Interest Paid, Net of Amounts Capitalized		$	223			$	235

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. 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 energy-related 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, PSEG’s, Power’s and PSE&G’s respective Annual Report on Form 10-K for the year ended December 31, 2008 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009.

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, 2008.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Reclassifications

Certain reclassifications were made to the prior period financial statements in accordance with new accounting guidance adopted in 2009. Minority interests of $11 million were reclassified from Other Noncurrent Liabilities to Noncontrolling Interests in PSEG’s Condensed Consolidated Balance Sheet as of December 31, 2008.

In addition, other-than-temporary impairments related to Power’s credit losses on available-for-sale debt securities in its Nuclear Decommissioning Trust (NDT) Funds were reclassified from Other Deductions to a separate line caption in the Condensed Consolidated Statement of Operations of PSEG and Power, for the three and nine months ended September 30, 2008.

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

Income from Equity Method Investments, as well as any impairments or gains/losses on the sale of equity method investments which were reflected in Operating Revenues and Operating Expenses prior to the fourth quarter of 2008, have been reclassified to below Operating Income in the Consolidated Statements of Operations of PSEG for the three and nine months ended September 30, 2008 since these equity method investments are no longer an integral part of the business.

Note 2. Recent Accounting Standards

New Standards Adopted during 2009

During 2009, we have adopted new accounting standards relating to

•

Noncontrolling Interests in Consolidated Financial Statements,

•

Disclosures about Derivative Instruments and Hedging Activities,

•

Subsequent Events,

•

Recognition and Presentation of Other-Than-Temporary Impairments,

•

Interim Disclosures about Fair Value of Financial Instruments, and

•

the Financial Accounting Standards Board (FASB) Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (GAAP).

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 guidance:

Noncontrolling Interests in Consolidated Financial Statements

•

changes the financial reporting relationship between a parent and noncontrolling interests,

•

requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated financial statements,

•

requires net income attributable to the noncontrolling interests to be shown on the face of the income statement in addition to net income attributable to the controlling interest, and

•

applies prospectively, except for presentation and disclosure requirements, which are applied retrospectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

We revised the balance sheet and income statement presentations as required by the standard. The income statement impact was immaterial.

Disclosures about Derivative Instruments and Hedging Activities

•

requires an entity to disclose an understanding of

how and why it uses derivatives,

how derivatives and related hedged items are accounted for, and

the overall impact of derivatives on an entity’s financial statements.

The required disclosures are included in Note 8. Financial Risk Management Activities.

Subsequent Events

•

establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued and

•

requires the disclosure of the date through which subsequent events have been evaluated and whether that date is the date on which the financial statements were issued or the date on which the financial statements were available to be issued.

We evaluated any subsequent events through October 30, 2009, which is the date the financial statements were issued. See Note 17. Subsequent Events.

Recognition and Presentation of Other-Than-Temporary Impairments

•

revises recognition guidance in determining whether a debt security is other-than-temporarily impaired. A debt security is considered other-than-temporarily impaired in either of the following circumstances if the fair value is less than the amortized cost

an entity has an intent to sell the security, or it is more-likely-than-not that an entity will be required to sell the security prior to the recovery of its amortized cost basis, or

an entity does not expect to recover the entire amortized cost basis of the security.

•

provides further guidance to determine the amount of impairment to be recorded in earnings (credit-related loss) and/or Accumulated Other Comprehensive Income (Loss) (non-credit related loss).

This standard was adopted April 1, 2009 and we recorded a cumulative-effect adjustment to reclassify $12 million of non-credit losses, net-of-tax, from Retained Earnings to Accumulated Other Comprehensive Income (Loss). The expanded disclosures required by the standard are included in Note 4. Available-for-Sale Securities.

Interim Disclosures about Fair Value of Financial Instruments

•

requires a publicly traded company to disclose the following information, in the notes to the financial statements:

fair value of its financial instruments in interim and annual reporting periods, together with the related carrying amounts,

methods and significant assumptions used to estimate the fair value, and

changes in methods and significant assumptions, if any.

The required disclosures are included in Note 9. Fair Value Measurements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles

•

issued as the single source of authoritative non-governmental GAAP other than the SEC rules and regulations, and

•

does not change current GAAP, but is intended to simplify user access by providing all the authoritative GAAP literature related to a particular topic in one place.

We eliminated specific accounting references in our SEC filings and other documents and replaced them with more general topical references.

New Accounting Standards issued but not yet adopted

Measuring Liabilities at Fair Value

•

issued by the FASB in August 2009,

•

provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value of such liability using one or more of the techniques prescribed by this standard, and

•

re-affirms the practice of measuring fair value using quoted market prices when a liability is traded as an asset.

We will adopt this standard effective for 2009 year-end reporting and do not anticipate a material impact on our financial statements.

Investments in Certain Entities That Calculate Net Asset Value Per Share

•

issued by the FASB in September 2009,

•

provides guidance on measuring fair value of certain alternative investments, and

•

permits the use of an investment’s net asset value to estimate its fair value, as a practical expedient, under certain circumstances.

We will adopt this standard for alternative investments, which are mainly included within our pension asset portfolio, effective for 2009 year-end reporting. We are currently assessing the impact of this standard on our financial statements.

Employers’ Disclosures about Postretirement Benefit Plan Assets

This accounting standard requires additional disclosures about the fair value of plan assets of a defined benefit pension or other postretirement plan, including

•

how investment allocation decisions are made by management,

•

major categories of plan assets,

•

significant concentrations of risk within plan assets, and

•

inputs and valuation techniques used to measure the fair value of plan assets and effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period.

We will adopt this standard effective for 2009 year-end reporting and do not anticipate that it will have a material impact on our financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Consolidation of Variable Interest Entities (VIEs)

New accounting guidance has been issued to amend the requirements for consolidation of VIEs which

•

removes the exception of applying consolidation guidance to qualifying special-purpose entities,

•

requires ongoing assessment of our involvement in the activities of the VIEs, and

•

amends the criteria in determination of a primary beneficiary, such that a primary beneficiary would be an enterprise with the power to direct the activities of a VIE that most significantly impact the economic performance of a VIE and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE.

We will adopt this guidance effective January 1, 2010. We are currently evaluating the impact of this guidance on our financial statements.

Note 3. Discontinued Operations and Dispositions

Discontinued Operations

Bioenergie

In November 2008, Energy Holdings sold its 85% ownership interest in Bioenergie for $40 million. The sale resulted in an after-tax loss of $15 million. Net cash proceeds, after realization of tax benefits, were approximately $70 million.

Bioenergie’s operating results for the quarter and nine months ended September 30, 2008, which were reclassified to Discontinued Operations, are summarized below:


	Three Months Ended September 30, 2008				Nine Months Ended September 30, 2008
	Millions
Operating Revenues		$	13			$	35
Loss Before Income Taxes		$	(29	)		$	(28	)
Net Loss		$	(8	)		$	(9	)

SAESA Group

In July 2008, Energy Holdings sold its investment in the SAESA Group for a total of $1.3 billion, including the assumption of $413 million of the consolidated debt of the group. The sale resulted in an after-tax gain of $187 million. Net cash proceeds, after Chilean and U.S. taxes of $269 million, were $612 million.

SAESA Group’s operating results for the quarter and nine months ended September 30, 2008, which were reclassified to Discontinued Operations, are summarized below:


	Three Months Ended September 30, 2008				Nine Months Ended September 30, 2008
	Millions
Operating Revenues		$	38			$	379
Income (Loss) Before Income Taxes		$	(5	)		$	36
Net Income		$	1			$	30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Dispositions

GWF Energy LLC (GWF Energy)

In May 2009, Energy Holdings entered into a Memorandum of Understanding under which it will sell, in two separate transactions, its 60% 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, selling a 10.1% interest in GWF Energy for approximately $7 million. The sale of Energy Holdings’ remaining 49.9% interest is subject to certain conditions, including the approval of a power purchase agreement by the California Public Utilities Commission and FERC’s approval of the sale.

PPN Power Generating Company Limited (PPN)

In May 2009, Energy Holdings sold its 20% ownership interest in PPN, which owns and operates a 330 MW generation facility in India for approximately book value.

Leveraged Leases

During 2009, Energy Holdings sold its interest in 12 leveraged leases with a total book value of approximately $551 million, including ten international leases for which the IRS has disallowed deductions taken in prior years. Total proceeds for the sales were approximately $679 million and resulted in after-tax gains of $52 million. Proceeds from these transactions are being used to reduce the tax exposure related to these lease investments. For additional information see Note 6. Commitments and Contingent Liabilities.

Other

In May 2009, Energy Holdings sold its 6.5% interest in the Midland Cogeneration Venture LP (MCV) for an after-tax gain of $2 million.

Note 4. Available-for-Sale Securities

NDT Funds

In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operations. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning.

Power maintains the external master nuclear decommissioning trust which 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. In the most recent study of the total cost of decommissioning, Power’s share related to its five nuclear units was estimated at approximately $2.1 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of September 30, 2009 was approximately $315 million and is included in the Asset Retirement Obligation (ARO). The trust funds are managed by third-party investment advisors who operate under investment guidelines developed by Power.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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, 2009
	Cost			Gross Unrealized Gains			Gross Unrealized Losses				Estimated Fair Value
	Millions
Equity Securities		$	458		$	166		$	(2	)		$	622

Debt Securities
Government Obligations			293			6			(1	)			298
Other Debt Securities			210			12			(3	)			219

Total Debt Securities			503			18			(4	)			517

Other Securities			39			—			(1	)			38

Total Available-for-Sale Securities		$	1,000		$	184		$	(7	)		$	1,177


	As of December 31, 2008
	Cost			Gross Unrealized Gains			Gross Unrealized Losses				Estimated Fair Value
	Millions
Equity Securities		$	386		$	32		$	(5	)		$	413

Debt Securities
Government Obligations			192			3			—				195
Other Debt Securities			284			6			—				290

Total Debt Securities			476			9			—				485
Other Securities			72			1			(1	)			72

Total Available-for-Sale Securities		$	934		$	42		$	(6	)		$	970

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 12 months:


	As of September 30, 2009 Less Than 12 Months*							As of December 31, 2008 Less Than 12 Months*
	Millions
	Fair Value			Gross Unrealized Losses				Fair Value			Gross Unrealized Losses
Equity Securities (A)		$	34		$	(2	)		$	85		$	(5	)

Debt Securities
Government Obligations (B)			42			(1	)			—			—
Other Debt Securities (C)			36			(3	)			—			—

Total Debt Securities			78			(4	)			—			—

Other Securities			1			(1	)			—			(1	)

Total Available-for-Sale Securities		$	113		$	(7	)		$	85		$	(6	)

There were no gross unrealized losses as of each of September 30, 2009 and December 31, 2008 for 12 months or longer.

(A)

Equity Securities—Investments in marketable equity securities within the NDT fund 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, 2009.

(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 that their amortized cost basis, assuming 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, 2009.

(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 at 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, 2009.

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


	Three Months Ended September 30, 2009				Three Months Ended September 30, 2008				Nine Months Ended September 30, 2009				Nine Months Ended September 30, 2008
	Millions
Proceeds from Sales		$	156			$	582			$	1,631			$	1,839

Net Realized Gains:
Gross Realized Gains		$	29			$	74			$	156			$	221
Gross Realized Losses			(14	)			(38	)			(125	)			(141	)

Net Realized Gains		$	15			$	36			$	31			$	80

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in Power’s Consolidated Statement of Operations. Net unrealized gains of $88 million (after-tax) were recognized in Accumulated Other Comprehensive Income in Power’s Condensed Consolidated Balance Sheet as of September 30, 2009.

The available-for-sale debt securities held as of September 30, 2009 had the following maturities:

•

$5 million less than one year,

•

$83 million after one through five years,

•

$126 million after five through 10 years, $51 million after 10 through 15 years, and

•

$12 million after 15 through 20 years, and $240 million over 20 years.

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 Other Comprehensive Income (OCI). In 2009, other-than-temporary impairments of $60 million were recognized on securities in the NDT Funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost detail of the securities.

Rabbi Trusts

PSEG maintains certain unfunded nonqualified benefit plans; assets have been set aside in grantor trusts commonly known as “Rabbi Trusts” to provide supplemental retirement and deferred compensation benefits to certain key employees.

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


	As of September 30, 2009
	Cost			Gross Unrealized Gains			Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities		$	10		$	3		$	—		$	13
Debt Securities			101			17			—			118
Other Securities			14			—			—			14

Total PSEG Available-for-Sale Securities		$	125		$	20		$	—		$	145

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	As of December 31, 2008
	Cost			Gross Unrealized Gains			Gross Unrealized Losses				Estimated Fair Value
	Millions
Equity Securities		$	11		$	—		$	(2	)		$	9
Debt Securities			102			9			(1	)			110
Other Securities			14			—			—				14

Total PSEG Available-for-Sale Securities		$	127		$	9		$	(3	)		$	133

The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. In the first nine months of 2009, other-than-temporary impairments of $1 million were recognized on the equity investments of the Rabbi Trusts.


	Three Months Ended September 30, 2009			Three Months Ended September 30, 2008			Nine Months Ended September 30, 2009				Nine Months Ended September 30, 2008
	Millions
Proceeds from Sales		$	—		$	—		$	2			$	23

Net Realized Gains (Losses):
Gross Realized Gains		$	—		$	—		$	—			$	2
Gross Realized Losses			—			—			(1	)			—

Net Realized Gains (Losses):		$	—		$	—		$	(1	)		$	2

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

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


	As of September 30, 2009			As of December 31, 2008
	Millions
Power		$	29		$	27
PSE&G			50			46
Other			66			60

Total PSEG Available-for-Sale Securities		$	145		$	133

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 5. Pension and OPEB

PSEG sponsors several qualified and nonqualified pension plans and other postretirement benefit 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.


	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,
	2009				2008				2009				2008				2009				2008				2009				2008
	Millions
Components of Net Periodic Benefit Cost:
Service Cost		$	19			$	19			$	3			$	4			$	57			$	58			$	9			$	11
Interest Cost			58				56				18				18				176				170				54				54
Expected Return on Plan Assets			(54	)			(72	)			(3	)			(4	)			(162	)			(217	)			(9	)			(11	)
Amortization of Net
Transition Obligation			—				—				7				7				—				—				21				21
Prior Service Cost			2				2				3				4				6				7				10				10
Actuarial Loss			29				4				—				—				85				10				(2	)			(1	)

Net Periodic Benefit Cost		$	54			$	9			$	28			$	29			$	162			$	28			$	83			$	84
Effect of Regulatory Asset			—				—				5				4				—				—				15				14

Total Benefit Expense, Including Effect of Regulatory Asset		$	54			$	9			$	33			$	33			$	162			$	28			$	98			$	98

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


	Pension Three Months Ended September 30,						OPEB Three Months Ended September 30,						Pension Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2009			2008			2009			2008			2009			2008			2009			2008
	Millions
Power		$	16		$	2		$	3		$	4		$	49		$	8		$	9		$	10
PSE&G			30			4			29			28			90			12			87			85
Other			8			3			1			1			23			8			2			3

Total Benefit Costs		$	54		$	9		$	33		$	33		$	162		$	28		$	98		$	98

During the nine months ended September 30, 2009, PSEG contributed its planned contributions for the year 2009 of $364 million and $11 million into its pension and postretirement healthcare plans respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6. Commitments and Contingent Liabilities

Guaranteed Obligations

Power has unconditionally guaranteed payments by its subsidiaries in commodity-related transactions to support current exposure, interest and other costs on sums due and payable in the ordinary course of business. These guarantees are provided to counterparties in order to 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 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). The probability of this is highly unlikely due to offsetting positions within the portfolio. For this reason, the current risk that others have from us 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 margins posted.

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

The face value of outstanding guarantees, current exposure and margin positions as of September 30, 2009 and December 31, 2008 are as follows:


	As of September 30, 2009				As of December 31, 2008
	Millions
Face value of outstanding guarantees		$	1,981			$	1,856
Exposure under current guarantees		$	385			$	585
Letters of Credit Margin Posted		$	190			$	201
Letters of Credit Margin Received		$	185			$	250
Net Cash Received
Counterparty Cash Margin Deposited		$	—			$	3
Counterparty Cash Margin Received			(150	)			(81	)
Net Broker Balance Received			(65	)			(74	)

Total Net Cash Received		$	(215	)		$	(152	)

Power nets the fair value of cash collateral receivables and payables with the corresponding net energy contract balances. Of the net cash received, Power has included $223 million and $112 million in its corresponding net derivative contract positions as of September 30, 2009 and December 31, 2008 respectively. The remaining balance of net cash (received) deposited shown above 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

further performance assurance. As of September 30, 2009, if Power was to lose its investment grade rating, additional collateral of approximately $850 million could be required.

As of September 30, 2009, there was $2.6 billion of available liquidity that could be used to post collateral under the PSEG and Power credit facilities.

In addition to amounts in the table above, Power had posted $96 million and $101 million in letters of credit as of September 30, 2009 and December 31, 2008 respectively, to support various other contractual and environmental obligations.

Environmental Matters

Passaic River

The U.S. Environmental Protection Agency (EPA) has determined that a six-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). The EPA later expanded its study area to include 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 river. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former Manufactured Gas Plant (MGP) sites. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. 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 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, with estimated costs from $900 million to $2.3 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study is expected to be released in 2010.

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.

NJDEP Litigation

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 Passaic River. 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. The third-party complaints seek statutory contribution and contribution under the New Jersey Spill Compensation and Control Act (Spill Act) to recover past and future removal costs and damages. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 November 2008, PSEG and a number of other PRPs agreed in an interim cooperative assessment agreement to pay an aggregate of $1 million for past costs incurred by the Federal trustees, and certain costs the trustees will incur going forward, and to work with the trustees for a 12-month period to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That initial 12 month period ends in December, 2009 and it is presently uncertain whether that effort will continue into 2010.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study that OCC was conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG is participating in and partially funding this study.

PSEG, Power and PSE&G cannot predict what further actions, if any, or the costs or the timing thereof, that 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 10 most significant sites for cleanup. One of the sites identified was PSE&G’s former Camden Coke facility.

During the second quarter of 2009, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $704 million and $804 million from June 30, 2009 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $704 million in its Condensed Consolidated Balance Sheet as of June 30, 2009. During the third quarter of 2009 PSE&G had $2 million of expenditures, reducing the liability to $702 million as of September 30, 2009. Of this amount, $39 million was recorded in Other Current Liabilities and $663 million was reflected as Environmental Costs in Noncurrent Liabilities. As such, PSE&G has recorded a $702 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,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 Hudson and Mercer designed to meet targeted reductions in emissions of sulfur dioxide (SO₂), nitrogen oxide (NO_x), particulate matter and mercury. As of December 2008, Power had installed selective catalytic reduction equipment and placed baghouses in service at Mercer at a total cost of $381 million. The remaining projects necessary to implement the balance of this program are expected to be completed by 2010 at an estimated cost of $200 million to $250 million for Mercer and $700 million to $750 million for Hudson, of which $643 million has been spent on both projects as of September 30, 2009.

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 made 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.

Mercury Regulation

In March 2005, the EPA established a New Source Performance Standard 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 February 2008, the United States Court of Appeals for the District of Columbia Circuit issued a decision rejecting the EPA’s mercury emissions program and requiring 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. Although the EPA initially filed a petition with the U.S. Supreme Court to review the lower court’s decision, in February 2009, the EPA withdrew its petition with the U.S. Supreme Court and indicated that it intended to move forward with a rule-making process to develop MACT standards consistent with the Court’s ruling. While certain industry litigants also petitioned the U.S. Supreme Court to review the lower court’s decision, in February 2009, the Supreme Court denied the petition. The full impact to PSEG of these developments is uncertain. It is expected that new MACT requirements, which the EPA has agreed to finalize by November 2011, 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 mercury-control requirements, as described below.

Pennsylvania

In February 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 Clean Air Mercury Rule (vacated by the court in February 2008) but not as stringent as would be required by a MACT process. In January 2009, the Commonwealth Court of Pennsylvania struck down the state rule, indicating that the rule violated Pennsylvania law because it is inconsistent with the Clean Air Act. The Commonwealth Court’s decision has been appealed to the Supreme Court of Pennsylvania. If the Commonwealth Court’s decision were to be overturned and the above-mentioned requirements are upheld, the Keystone and Conemaugh generating stations would be positioned by 2010 to meet Phase I of the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Pennsylvania mercury rule by benefiting from reductions realized from the installation of planned or completed controls for compliance with SO₂ and NO_x reductions. Total estimated costs for compliance for ongoing projects are between $150 million and $200 million with $137 million spent as of September 30, 2009. Power will evaluate Phase II of the Pennsylvania mercury rule after a full evaluation of the Phase I reductions. If the Commonwealth Court’s ruling is sustained and the EPA undertakes a MACT process, 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.

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, it 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 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 will have a significant impact on Power’s generation fleet, as it imposes NOx emissions limits that will likely require 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.

Power has been working with the NJDEP throughout the development of this rulemaking to minimize financial impact and to provide for transitional lead time for it 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 utilize Discrete Emission Reduction Credits (DERCs) to comply with certain NO_x emission limitations that were incorporated into the facilities’ operating permits. Power’s agreements with the State of Connecticut authorizing the DERC’s expire on May 1, 2010. If not extended, Power could potentially be forced to utilize lower NO_x-producing fuels, or install NO_xemission controls in order to operate the units. Power cannot predict the financial impact of such costs, but such costs could be material and could impact the continued viability of these units.

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 has a $50 million liability as of September 30, 2009 and December 31, 2008

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

related to these obligations, which is included in Environmental Costs in Power’s and PSEG’s Condensed Consolidated Balance Sheets.

Permit Renewals

In June 2001, the NJDEP issued a renewed New Jersey Pollutant Discharge Elimination System (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 Federal Water Pollution Control Act’s (FWPCA) Section 316(b) and the Phase II 316(b) rules, which govern cooling water intake structures at large electric generating facilities. Under these rules, 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. The Phase II Rule would also have been applicable to Bridgeport, and possibly, 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.

In January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision in litigation of the Phase II 316(b) regulations brought by several environmental groups, the Attorneys General of six Northeastern states, including New Jersey, Connecticut, and New York, the Utility Water Act Group and several of its members, including Power. In its ruling, the Court

•

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; and

•

instructed the EPA to reconsider the definition of “best technology available” without comparing the costs of the best performing technology to its benefits.

On April 1, 2009, the U.S. Supreme Court reversed the Second 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 Supreme Court’s decision became effective on April 27, 2009, and the matter was sent back to the Second Circuit for further proceedings consistent with the Supreme Court’s opinion. On September 29, 2009, the Second Circuit issued an order remanding the matter to the EPA in light of the Supreme Court’s opinion. The EPA will have to undertake a rulemaking which takes into account the Supreme Court’s opinion concerning the use of cost-benefit analysis, and the Second Circuit’s opinion with respect to significant portions of the Phase II rule which were remanded by the Second Circuit but which were not considered by the Supreme Court.

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 our ability to renew permits at our larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to our existing intake structures and cooling systems. The costs of those upgrades to one or more of our 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 are approximately $1 billion, of which Power’s share would be approximately $575 million. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 now 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 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 2009 are $18 million and are expected to continue through 2012. We anticipate expenditures in pursuit of additional output through an extended power up-rate of our co-owned Peach Bottom nuclear plants. The up-rate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Our share of the increased capacity is expected to be 133 MW with an anticipated cost of approximately $400 million.

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 June 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 2009 are $13 million, which are included in Other Noncurrent Assets in the Condensed Consolidated Balance Sheets of PSEG and Power.

PJM Interconnection L.L.C. (PJM)

Power plans to construct 178 MW of gas-fired peaking capacity at the Kearny site. This capacity was bid into and has 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 third quarter of 2011. The project is expected to be in-service by June 2012. Power estimates the cost of these generating units to be $160 million to $200 million. Total capitalized expenditures to date were $8 million which are included in Property, Plant and Equipment in Power’s and PSEG’s Condensed Consolidated Balance Sheets.

Solar Source

Energy Holdings has developed a solar project in western New Jersey and has acquired two additional solar projects to be developed in Florida and Ohio, which together have a total capacity of approximately 29 MW. Completion of the additional projects is expected by the end of 2010 with a total investment of approximately $100 million. Energy Holdings has issued guarantees of up to $95 million for payment of obligations related to the construction of these two projects. These guarantees will terminate upon successful completion of the projects.

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,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 load, as follows:

Auction Year

2006

2007

2008

2009

36-Month Terms Ending

May 2009

May 2010

May 2011

May 2012

(a)

Load (MW)

2,882

2,758

2,840

$per kWh

0.10251

0.09888

0.11150

0.10372

(a) Prices set in the 2009 BGS auction became effective on June 1, 2009 when
the 2006 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 15. Related-Party Transactions.

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 include estimated quantities to be purchased that are in excess of contractual minimum quantities.

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

As of September 30, 2009, the total minimum purchase requirements included in these commitments are as follows:

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


Fuel Type	Commitments through 2013			Power’s Share
	Millions
Nuclear Fuel
Uranium		$	772		$	487
Enrichment		$	445		$	252
Fabrication		$	261		$	171
Natural Gas		$	1,000		$	1,000
Coal/Oil		$	811		$	811

Included in the $811 million commitment for coal and oil above is $433 million related to a certain coal contract under which Power can cancel contractual deliveries at minimal cost. Through September 2009, Power has cancelled one million tons of coal and twelve freight shipments related to that coal at a total cost of approximately $17 million.

Power has entered into gas supply option agreements for the anticipated fuel requirements at the Texas generation facilities to satisfy obligations under the facilities forward energy sales contracts. As of September 30, 2009, Power’s fuel purchase options totaled $19 million under those agreements, which is not included in the above table.

The Texas generation facilities also have a contract for low BTU content gas commencing in late 2009 with a term of 15 years and a minimum volume of approximately 13 MMbtu’s per year. The gas must meet an availability and quality specification. PSEG has the right to cancel delivery of the gas at a minimal cost.

Nuclear Fuel Disposal

The Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund. Under the contracts, the US Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. Earlier this year, the Federal government announced that it would form a group to study and provide recommendations for a long-term resolution of the nuclear waste issue. Given the uncertainty of the timing and nature of the recommendations, it is not clear when the government will begin taking possession of the spent nuclear fuel.

On September 30, 2009, Power signed an agreement with the DOE applicable to Salem and Hope Creek under which we will be reimbursed for past and future reasonable and allowable costs resulting from the DOE’s delay in accepting spent nuclear fuel for permanent disposition. Under this settlement, we will receive approximately $47 million for our spent fuel management costs incurred through December 2007. Payment was received in October 2009. A similar settlement agreement was reached related to Peach Bottom in 2004. The majority of this amount is related to the recovery of the capitalized costs of building on-site storage and related improvements, therefore nearly all of this payment will result in a reduction of previously capitalized plant-related costs rather than an increase in earnings. Power has on-site storage facilities that are expected to satisfy its storage needs through current licensed lives plus an additional twenty years of operation.

Regulatory Proceedings

Competition Act

In April 2007, PSE&G and PSE&G Transition Funding LLC (Transition Funding) were served with a copy of 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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, or, in the alternative, for summary judgment. In October 2007, PSE&G’s and Transition Funding’s motion to dismiss the amended Complaint was granted. 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, which remains pending.

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 by the consultant to the BPU in April 2005.

That report, which addresses SBC, Market Transition Charge (MTC) and non-utility generation (NUG) deferred balances, found that the Phase II deferral balances complied in all material respects with applicable BPU Orders. It also noted that the BPU Staff had 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. The amount in dispute is $114 million, which if required to be refunded to customers with interest through September 2009, would be $142 million.

Hearings before an administrative law judge (ALJ) were held in July 2008. In January 2009, the 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 Advocate, and that these issues should not be subject to re-litigation in respect of 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. The amount in dispute with respect to this Phase II period is approximately $50 million.

The BPU requested supplemental briefs which were filed in September 2009 reiterating PSE&G’s position that the accounting approach followed was consistent with the BPU’s Restructuring Order. Reply briefs were filed in October 2009.

New Jersey Clean Energy Program

In the third quarter of 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 billion for all years. PSE&G’s share of the $1.2 billion program is $705 million. PSE&G has recorded a discounted liability of $597 million as of September 30, 2009. Of this amount, $163 million was recorded as a current liability and $434 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Leveraged Lease Investments

The Internal Revenue Service (IRS) has issued reports with respect to its audits of PSEG’s 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, five cases have been decided at the trial court level, three of which were decided in favor of the government. An appeal of one of these decisions was affirmed. The fourth 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.

The IRS has also issued letters to a number of taxpayers with these types of lease transactions containing settlement offers. While many bank lessors have agreed to settle on terms that are favorable to the IRS, PSEG has analyzed potential settlements with the IRS and to date has declined to participate.

In order to reduce the cash tax exposure related to these leases, Energy Holdings is pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds. Energy Holdings has terminated ten of these leasing transactions in 2009 and one in December 2008 and reduced the related cash tax exposure by $525 million. As of September 30, 2009 and December 31, 2008, PSEG’s total gross investment in such transactions was $490 million and $1 billion respectively.

Cash Impact

As of September 30, 2009, an aggregate of approximately $780 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 cash exposure to $460 million. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest.

As of September 30, 2009, 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 grow at the rate of $9 million per quarter during 2009. 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 $100 million to $130 million of tax would be due for tax positions through September 30, 2009.

PSEG currently anticipates that it may be required to pay between $120 million and $290 million in tax, interest and penalties for the tax years 1997-2000 during the first quarter of 2010 and subsequently commence litigation to recover these amounts. Further it is possible that an additional payment of between $220 million and $510 million could be required in the first quarter of 2010 for tax years 2001-2003 followed by further litigation to recover those taxes. These amounts are in addition to tax deposits already made.

Earnings Impact

As a result of the changes in the timing of projected cash flows related to these leases, in the second quarter of 2008, PSEG recalculated its lease transactions and recorded an after-tax charge of $355 million. This charge was reflected as a reduction in Operating Revenues of $485 million with a partially offsetting reduction in Income Tax Expense of $130 million. This represents PSEG’s view of most of the earnings impact 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 $100 million to $120 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 7. Changes in Capitalization

Power and Energy Holdings

In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Under this transaction, an aggregate principal amount of $368 million, or 74% of Energy Holdings’ Senior Notes, was exchanged for total consideration from Power of $404 million. The $404 million was comprised of $303 million of newly issued 5.32% Senior Notes due September 2016 and cash payments of $101 million. Since the debt exchange was between two subsidiaries of the same parent company, PSEG, the resulting premium of $36 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 PSEG’s Condensed Consolidated Balance Sheet.

As of September 30, 2009, Power had a receivable from Energy Holdings for the full consideration Power provided to Energy Holdings’ bondholders in this transaction. Energy Holdings had a payable to Power for the same amount. See Note 17. Subsequent Events for additional information.

Energy Holdings has $127 million of 8.50% Senior Notes due 2011 still outstanding as of September 30, 2009.

In addition to the debt exchange, the following capital transactions occurred in the first nine months of 2009:

PSEG

•

paid $200 million of 4.66% Senior Notes at maturity in September.

Power

•

converted $44 million of 4.00% Pollution Control Bonds to variable rate demand bonds backed by letters of credit expiring in 2012, and

•

established a program for the issuance of up to $500 million of unsecured medium-term notes (MTNs) to retail investors in January. Under this program we

issued $161 million of 6.5% MTNs due January 2014 (issued January, callable in one year), and

issued $48 million of 6% MTNs due January 2013 (issued January, callable in one year).

•

paid cash dividends of $725 million to PSEG, and

•

paid $250 million of 3.75% Senior Notes at maturity in April.

PSE&G

•

paid $44 million of 8.10% MTNs, Series A at maturity in May,

•

paid $16 million of 8.16% MTNs, Series A at maturity in May,

•

received a $250 million equity contribution from PSEG,

•

paid $128 million of Transition Funding’s securitization debt, and

•

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

Energy Holdings

•

redeemed $280 million of floating rate non-recourse project debt due in December 2009 associated with PSEG Texas,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

•

repurchased $10 million of its 8.5% Senior Notes due 2011, and

•

paid a total of $4 million of non-recourse project debt other than PSEG Texas.

In October 2009, PSEG paid $49 million of 6.89% Senior Notes at maturity. In addition, PSE&G purchased $100 million (Series 2003 B-1 and 2003 B-2) of tax-exempt variable rate bonds of the Pollution Control Financing Authority of Salem County (Salem County Authority Bonds). These bonds are serviced and secured by like principal amount of PSE&G’s pollution control Mortgage Bonds and were held by the broker/dealer or tendered by bondholders upon the mandatory tender in October 2009. These purchases were recorded as a reduction of PSE&G’s Long-Term Debt Due Within One Year included in its Condensed Consolidated Balance Sheets.

Note 8. 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 and Energy Holdings use physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Contracts that do not qualify for hedge accounting 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. The financial effect of using such modeling techniques is not material to PSEG’s or Power’s financial statements.

Cash Flow Hedges

Power and Energy Holdings use forward sale and purchase contracts, swaps, futures and firm transmission right contracts to hedge

•

forecasted energy sales from their generation stations and the related load obligations and

•

the price of fuel to meet their fuel purchase requirements.

These derivative transactions are designated and effective as cash flow hedges. As of September 30, 2009 and December 31, 2008, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	As of September 30, 2009			As of December 31, 2008

	Millions
Power
Fair Value of Cash Flow Hedges		$	372		$	331	*
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)		$	225		$	176
Energy Holdings
Fair Value of Cash Flow Hedges		$	—		$	3
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)		$	2		$	2

Power’s fair value of cash flow hedges of $331 million at December 31, 2008 shown in the table above was corrected from $320 million disclosed in our 2008 Form 10-K.

The expiration date of the longest-dated cash flow hedge at Power is in 2011. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the 12 months ending September 30, 2010 and September 30, 2011 are $133 million and $76 million respectively. Ineffectiveness associated with these hedges was $6 million at September 30, 2009.

The expiration date of the longest-dated cash flow hedge for Energy Holdings is in 2009. Therefore, substantially all of the after-tax unrealized gains on its commodity derivatives are expected to be reclassified to earnings during 2009. There was no ineffectiveness associated with these hedges.

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 some 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 represent approximately one percent of Power’s gross margin.

Other Derivatives

Power and Energy Holdings enter into other contracts that are derivatives, but do not qualify for cash flow hedge accounting.

For Power, 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.

For Energy Holdings, these are electricity forward and capacity sale contracts entered into to sell a portion of the Texas facilities’ capacity and gas purchase contracts to support the electricity forward sales contracts.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of September 30, 2009 and December 31, 2008 was as follows:


	As of September 30, 2009				As of December 31, 2008
	Millions
Net Fair Value of Other Derivatives
Power		$	(16	)		$	67	*
Energy Holdings		$	28			$	32

The net fair value of other derivatives related to energy contracts for Power of $67 million at December 31, 2008 in the table above was corrected from $(9) million disclosed in our 2008 Form 10-K.

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

In May and June 2009, we entered into three interest rate swaps to convert Power’s $250 million of 5.00% Senior Notes due April 2014 and $300 million of 5.50% Senior Notes due December 2015 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 fair value changes in the underlying debt. As of September 30, 2009, the fair value of the underlying hedges was $4 million.

Cash Flow Hedges

PSEG, PSE&G 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, 2009, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was less than $(1) million and $(7) million as of September 30, 2009 and December 31, 2008 respectively. The Accumulated Other Comprehensive Loss related to interest rate derivatives designated as cash flow hedges was $(5) million and $(6) million as of September 30, 2009 and December 31, 2008 respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Fair Values of Derivative Instruments

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


Balance Sheet Location	As of September 30, 2009
	Power (A)																PSE&G				Energy Holdings (A)			Consolidated
	Cash Flow Hedges				Non Hedges				Netting (B)				Total Power				Non Hedges				Non Hedges			Total Derivatives (C)
	Energy- Related Contracts				Energy- Related Contracts				Netting (B)				Total Power				Energy- Related Contracts				Energy- Related Contracts			Total Derivatives (C)
	Millions
Derivative Contracts
Current Assets		$	469			$	559			$	(840	)		$	188			$	1			$	20		$	217
Noncurrent Assets		$	383			$	160			$	(426	)		$	117			$	—			$	8		$	125

Total Mark-to-Market Derivative Assets		$	852			$	719			$	(1,266	)		$	305			$	1			$	28		$	342

Derivative Contracts
Current Liabilities		$	(100	)		$	(699	)		$	575			$	(224	)		$	(8	)		$	—		$	(232	)
Noncurrent Liabilities		$	(39	)		$	(123	)		$	130			$	(32	)		$	(24	)		$	—		$	(60	)

Total Mark-to-Market Derivative (Liabilities)		$	(139	)		$	(822	)		$	705			$	(256	)		$	(32	)		$	—		$	(292	)

Total Net Mark-to-Market Derivative Assets (Liabilities)		$	713			$	(103	)		$	(561	)		$	49			$	(31	)		$	28		$	50

Other Noncurrent Assets		$	—			$	—			$	—			$	—			$	—			$	—		$	—

(A)

The table above excludes intercompany derivatives between Power and Energy Holdings.

(B)

Represents the netting of fair value balances with the same counterparty and the application of collateral. Includes cash collateral of $(190) million and $(140) million netted against current assets and noncurrent assets respectively. Includes cash collateral of $74 million and $33 million netted against current liabilities and noncurrent liabilities respectively.

(C)

Includes PSEG parent company interest rate swap assets of $8 million and interest rate swap liability of $(4) million, designated as fair value hedges, recorded in Current Assets-Derivative Contracts and Noncurrent Liability-Derivative Contracts respectively.

The aggregate fair value of derivative contracts in a liability position as of September 30, 2009 that contain triggers for additional collateral was $600 million. This potential additional collateral is included in the $850 million discussed in Note 6. Commitments and Contingent Liabilities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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

						Millions

PSEG (A)
Energy-Related Contracts		$	(19	)	Operating Revenue		$	141		Operating Revenue		$	(8	)
Energy-Related Contracts			(6	)	Energy Costs			(19	)				—
Interest Rate Swaps			(3	)	Interest Expense			(1	)				—

Total PSEG		$	(28	)			$	121				$	(8	)

PSEG Power
Energy-Related Contracts		$	(20	)	Operating Revenue		$	129		Operating Revenue		$	(8	)
Energy-Related Contracts			(6	)	Energy Costs			(11	)				—

Total Power		$	(26	)			$	118				$	(8	)

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

Total PSE&G		$	—				$	—				$	—

Energy Holdings
Energy-Related Contracts		$	1		Operating Revenue		$	12				$	—
Energy-Related Contracts			—		Energy Costs			(8	)				—
Interest Rate Swaps			—		Interest Expense			—					—

Total Energy Holdings		$	1				$	4				$	—

(A)

Includes amounts for PSEG parent.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


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)

						Millions

PSEG (A)
Energy-Related Contracts		$	502		Operating Revenue		$	452		Operating Revenue		$	(17	)
Interest Rate Swaps			—		Income from Equity Method Investments			(1	)				—
Energy-Related Contracts			(50	)	Energy Costs			(82	)				—
Interest Rate Swaps			(4	)	Interest Expense			(7	)				—

Total PSEG		$	448				$	362				$	(17	)

PSEG Power
Energy-Related Contracts		$	483		Operating Revenue		$	417		Operating Revenue		$	(17	)
Energy-Related Contracts			(42	)	Energy Costs			(59	)				—

Total Power		$	441				$	358				$	(17	)

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

Total PSE&G		$	(1	)			$	(2	)			$	—

Energy Holdings
Energy-Related Contracts		$	19		Operating Revenue		$	35				$	—
Interest Rate Swaps		$	—		Income from Equity Method Investments		$	(1	)			$	—
Energy-Related Contracts			(8	)	Energy Costs			(23	)				—
Interest Rate Swaps			—		Interest Expense			(4	)				—

Total Energy Holdings		$	11				$	7				$	—

(A)

Includes amounts for PSEG parent.

The following reconciles the Accumulated Other Comprehensive Income for derivative activity included in the Accumulated Other Comprehensive Income of PSEG on a pre-tax and after-tax basis:


Accumulated Other Comprehensive Income	Pre-Tax				After-Tax
	Millions
Balance as of December 31, 2008		$	292			$	172
Gain Recognized in AOCI (Effective Portion)			477				282
Less: Gain Reclassified into Income (Effective Portion)			(243	)			(143	)

Balance as of June 30, 2009		$	526			$	311
Loss Recognized in AOCI (Effective Portion)			(28	)			(16	)
Less: Gain Reclassified into Income (Effective Portion)			(121	)			(73	)

Balance as of September 30, 2009		$	377			$	222

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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


Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated as Hedges		Three Months Ended September 30, 2009				Nine Months Ended September 30, 2009
		Millions
PSEG
Energy-Related Contracts	Operating Revenues		$	65			$	269
Energy-Related Contracts	Energy Costs			(33	)			(157	)
Interest Rate Swaps	Interest Expense			—				1
Derivatives in NDT Funds	Other Income			—				13

Total PSEG			$	32			$	126

Power
Energy-Related Contracts	Operating Revenue		$	(13	)		$	111
Energy-Related Contracts	Energy Costs			(33	)			(140	)
Derivatives in NDT Funds	Other Income			—				13

Total Power			$	(46	)		$	(16	)

Energy Holdings
Operating Revenue			$	78			$	158
Energy-Related Contracts	Energy Costs			—				(17	)
Interest Rate Swap	Interest Expense			—				1

Total Energy Holdings			$	78			$	142

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of those contracts are marked to market. The tables above do not include contracts for which Power has elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.

In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges for the three months and nine months ended September 30, 2009 was to reduce interest expense by $13 million and $8 million respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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


Type	Notional	Total		PSEG		Power		PSE&G		Energy Holdings
	Millions
Natural Gas	Dth		1,376		—		1,139		237		—
Electricity	MWh		201		—		196		—		5
Capacity	MW days		1		—		1		—		—
FTRs	MWh		33		—		33		—		—
Emissions Allowances	Tons		2		—		2		—		—
Oil	Barrels		2		—		2		—		—
Renewable Energy Credits	MWh		1		—		1		—		—
Interest Rate Swaps	US Dollars		550		550		—		—		—

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty.

In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s financial condition, results of operations or net cash flows. As of September 30, 2009, 99% of the credit exposure (MTM plus net receivables and payables, less cash collateral) for Power’s operations was with investment grade counterparties.

The following table provides information on Power’s credit risk from others, net of collateral, as of September 30, 2009. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of the company’s credit risk by credit rating of the counterparties.

Schedule of Credit Risk Exposure on Energy Contracts Net Assets as of September 30, 2009


Rating	Current Exposure			Securities held as Collateral			Net Exposure			Number of Counterparties >10%		Net Exposure of Counterparties >10%
	Millions											Millions
Investment Grade— External Rating		$	1,182		$	213		$	1,065		2		$	575(A	)
Non-Investment Grade— External Rating			5			5			—		—			—
Investment Grade— No External Rating			9			—			9		—			—
Non-Investment Grade— No External Rating			10			21			7		—			—

Total		$	1,206		$	239		$	1,081		2		$	575

(A)

Includes net exposure of $426 million with PSE&G. The remaining net exposure of $149 million is with a nonaffiliated power purchaser which is a regulated investment grade counterparty.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would not be exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of September 30, 2009, Power had 183 active counterparties.

Note 9. Fair Value Measurements

PSEG, Power and PSE&G adopted accounting guidance for “Fair Value Measurements” for financial assets and liabilities effective January 1, 2008, and for non-financial assets and liabilities effective January 1, 2009. The fair value measurements guidance defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities, exchange traded derivatives and certain U.S. government treasury securities.

Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist mainly of various financial transmission rights, other longer term capacity and transportation contracts and certain commingled securities.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The following tables present information about PSEG’s, Power’s, and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis at September 30, 2009 and December 31, 2008, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.


Description	Recurring Fair Value Measurements as of September 30, 2009
Description	Total				Cash Collateral Netting (E)				Quoted Market Prices of Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
	Millions
PSEG
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	334			$	(330	)		$	—		$	486			$	178
Interest Rate Swaps (B)		$	8			$	—			$	—		$	8			$	—
NDT Funds (C)
Equity Securities		$	622			$	—			$	621		$	1			$	—
Debt Securities-Government Obligations		$	298			$	—			$	—		$	298			$	—
Debt Securities-Other		$	219			$	—			$	—		$	219			$	—
Other Securities		$	38			$	—			$	13		$	6			$	19
Rabbi Trusts (C)		$	145			$	—			$	13		$	118			$	14
Other Long-Term Investments (D)		$	1			$	—			$	1		$	—			$	—
*Liabilities:*
Derivative Contracts:
Energy-Related Contracts (A)		$	(288	)		$	107			$	—		$	(343	)		$	(52	)
Interest Rate Swaps (B)		$	(4	)		$	—			$	—		$	(4	)		$	—
Power
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	305			$	(330	)		$	—		$	486			$	149
NDT Funds (C)
Equity Securities		$	622			$	—			$	621		$	1			$	—
Debt Securities-Government Obligations		$	298			$	—			$	—		$	298			$	—
Debt Securities-Other		$	219			$	—			$	—		$	219			$	—
Other Securities		$	38			$	—			$	13		$	6			$	19
Rabbi Trusts (C)		$	29			$	—			$	3		$	23			$	3
Liabilities:
*Derivative Contracts*
Energy-Related Contracts (A)		$	(256	)		$	107			$	—		$	(343	)		$	(20	)
PSE&G
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	1			$	—			$	—		$	—			$	1
Rabbi Trusts (C)		$	50			$	—			$	4		$	41			$	5
*Liabilities:*
Energy-Related Contracts (A)		$	(32	)		$	—			$	—		$	—			$	(32	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


Description	Recurring Fair Value Measurements as of December 31, 2008
Description	Total				Cash Collateral Netting (E)				Quoted Market Prices of Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
	Millions
PSEG
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	399			$	(154	)		$	—		$	439	*		$	114	*
NDT Funds (C)
Equity Securities		$	413			$	—			$	412		$	1			$	—
Debt Securities-Government Obligations		$	195			$	—			$	—		$	195			$	—
Debt Securities-Other		$	290			$	—			$	—		$	285			$	5
Other Securities		$	72			$	—			$	1		$	35			$	36
Rabbi Trusts (C)		$	133			$	—			$	9		$	110			$	14
Other Long-Term Investments (D)		$	1			$	—			$	1		$	—			$	—
*Liabilities:*
Derivative Contracts:
Energy-Related Contracts (A)		$	(510	)		$	42			$	—		$	(470	)*		$	(82	)*
Interest Rate Swaps (B)		$	(10	)		$	—			$	—		$	(10	)		$	—
Power
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	368			$	(154	)		$	—		$	450	*		$	72	*
NDT Funds (C)
Equity Securities		$	413			$	—			$	412		$	1			$	—
Debt Securities-Government Obligations		$	195			$	—			$	—		$	195			$	—
Debt Securities-Other		$	290			$	—			$	—		$	285			$	5
Other Securities		$	72			$	—			$	1		$	35			$	36
Rabbi Trusts (C)		$	27			$	—			$	2		$	22			$	3
*Liabilities:*
Derivative Contracts:		$	—
Energy-Related Contracts (A)		$	(449	)		$	42			$	—		$	(480	)*		$	(11	)*
PSE&G
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	2			$	—			$	—		$	—			$	2
Rabbi Trusts (C)		$	46			$	—			$	3		$	38			$	5
*Liabilities:*
Derivative Contracts:
Energy-Related Contracts (A)		$	(66	)		$	—			$	—		$	—			$	(66	)
Interest Rate Swaps (B)		$	(1	)		$	—			$	—		$	(1	)		$	—

The amounts shown in energy-related contract assets and liabilities in the table above have been corrected from such amounts shown in our 2008 Form 10-K to reflect a $22 million increase in the Level 2 net liability and a corresponding increase in the Level 3 net asset.

(A)

Whenever possible, fair values for energy-related contracts are obtained from quoted market sources in active markets. When this pricing is unavailable, contracts are valued using broker or dealer quotes or auction prices (primarily Level 2).

For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable (primarily Level 3).

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(B)

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

(C)

The NDT Funds maintain investments in various equity and fixed income securities classified as “available for sale.” These securities are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Most equity securities are priced utilizing the principal market close price or in some cases midpoint, bid or ask price (primarily Level 1). Fixed income securities are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). Short-term investments are valued based upon internal matrices using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3). The Rabbi Trust mutual funds are mainly invested in a US Bond Index fund, an S&P 500 Index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

(D)

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

(E)

Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under FIN 39-1.

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

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


Description	Balance as of July 1, 2009				Total Gains or (Losses) Realized/Unrealized						Transfers, Purchases, Sales and Settlements				Balance as of September 30, 2009
Description	Balance as of July 1, 2009				Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)			Transfers, Purchases, Sales and Settlements				Balance as of September 30, 2009
	Millions
PSEG
Net Derivative Assets		$	150			$	18		$	6		$	(48	)		$	126
NDT Funds		$	30			$	—		$	—		$	(11	)		$	19
Rabbi Trust Funds		$	14			$	—		$	—		$	—			$	14
Power
Net Derivative Assets		$	159			$	18		$	—		$	(48	)		$	129
NDT Funds		$	30			$	—		$	—		$	(11	)		$	19
Rabbi Trust Funds		$	3			$	—		$	—		$	—			$	3
PSE&G
Net Derivative Liabilities		$	(37	)		$	—		$	6		$	—			$	(31	)
Rabbi Trust Funds		$	5			$	—		$	—		$	—			$	5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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


Description	Balance as of January 1, 2009				Total Gains or (Losses) Realized/Unrealized							Transfers, Purchases, Sales and Settlements				Balance as of September 30, 2009
Description	Balance as of January 1, 2009				Included in Income (C)				Included in Regulatory Assets/ Liabilities (B)			Transfers, Purchases, Sales and Settlements				Balance as of September 30, 2009
	Millions
PSEG
Net Derivative Assets		$	32			$	102			$	33		$	(41	)		$	126
NDT Funds		$	41			$	(2	)		$	—		$	(20	)		$	19
Rabbi Trust Funds		$	14			$	—			$	—		$	—			$	14
Power
Net Derivative Assets		$	61			$	109			$	—		$	(41	)		$	129
NDT Funds		$	41			$	(2	)		$	—		$	(20	)		$	19
Rabbi Trust Funds		$	3			$	—			$	—		$	—			$	3
PSE&G
Net Derivative Liabilities		$	(64	)		$	—			$	33		$	—			$	(31	)
Rabbi Trust Funds		$	5			$	—			$	—		$	—			$	5

(A)

PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $29 million (realized) is included in Operating Revenues at Power and $(11) million is included in Other Comprehensive Income (OCI) at Power.

(B)

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

(C)

PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $94 million is included in Operating Revenues and $8 million is included in OCI. Of the $94 million in Operating Revenues, $(7) million unrealized is at PSEG Texas and $101 million, of which $38 million is unrealized, is at Power. The $8 million included in OCI is at Power.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months Ended September 30, 2008


Description	Balance as of July 1, 2008				Total Gains or (Losses) Realized/Unrealized							Purchases and (Sales) and Settlements				Balance as of September 30, 2008
Description	Balance as of July 1, 2008				Included in Income (A)				Included in Regulatory Assets/ Liabilities (B)			Purchases and (Sales) and Settlements				Balance as of September 30, 2008
	Millions
PSEG
Net Derivative Assets		$	1			$	147			$	14		$	(80	)		$	82
NDT Funds		$	32			$	(2	)		$	—		$	(7	)		$	23
Rabbi Trust Funds		$	14			$	—			$	—		$	—			$	14
Power
Net Derivative Assets		$	79			$	73			$	—		$	(59	)		$	93
NDT Funds		$	32			$	(2	)		$	—		$	(7	)		$	23
Rabbi Trust Funds		$	3			$	—			$	—		$	—			$	3
PSE&G
Net Derivative Liabilities		$	(89	)		$	—			$	14		$	—			$	(75	)
Rabbi Trust Funds		$	5			$	—			$	—		$	—			$	5

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Nine Months Ended September 30, 2008


Description	Balance as of January 1, 2008				Total Gains or (Losses) Realized/Unrealized								Purchases and (Sales) and Settlements				Balance as of September 30, 2008
Description	Balance as of January 1, 2008				Included in Income (C)				Included in Regulatory Assets/ Liabilities (B)				Purchases and (Sales) and Settlements				Balance as of September 30, 2008
	Millions
PSEG
Net Derivative Assets (Liabilities)		$	(9	)		$	184			$	(26	)		$	(67	)		$	82
NDT Funds		$	27			$	(3	)		$	—			$	(1	)		$	23
Rabbi Trust Funds		$	16			$	—			$	—			$	(2	)		$	14
Power
Net Derivative Assets		$	10			$	100			$	—			$	(17	)		$	93
NDT Funds		$	27			$	(3	)		$	—			$	(1	)		$	23
Rabbi Trust Funds		$	3			$	—			$	—			$	—			$	3
PSE&G
Net Derivative Liabilities		$	(49	)		$	—			$	(26	)		$	—			$	(75	)
Rabbi Trust Funds		$	6			$	—			$	—			$	(1	)		$	5

(A)

PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $153 million is included in Operating Revenues and $(6) million is included in OCI. Of the $153 million in Operating Revenues, $69 million unrealized is at PSEG Texas and $84 million (of which $22 million is unrealized) is at Power. Of the $(6) million in OCI, $5 million is at PSEG Texas and $(11) million is at Power.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(B)

(C)

PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $182 million is included in Operating Revenues and $2 million is included in OCI. Of the $182 million in Operating Revenues, $79 million unrealized is at PSEG Texas and $103 million (of which $47 million is unrealized) is at Power. Of the $2 million in OCI, $5 million is at PSEG Texas and $(3) million is at Power.

As of September 30, 2008, PSEG carried approximately $1.1 billion of net assets that are measured at fair value on a recurring basis, of which approximately $119 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no significant transfers in or out of Level 3 during the nine months ended September 30, 2008.

As discussed in Note 3, Energy Holdings sold a 10.1% interest in its GWF Energy investment and recorded an after-tax impairment charge of $3 million on the entire investment prior to the sale. The remaining investment of $63 million is carried as a nonrecurring fair value measurement as of September 30, 2009. This investment is considered a Level 3 within the fair value hierarchy based on the use of unobservable inputs.

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of September 30, 2009 and December 31, 2008.


	September 30, 2009						December 31, 2008
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	Millions
Long-Term Debt:
PSEG (Parent)*		$	53		$	53		$	249		$	250
Power			3,166			3,527			2,903			2,800
PSE&G			3,464			3,764			3,523			3,569
Transition Funding (PSE&G)			1,325			1,521			1,454			1,658
Transition Funding II (PSE&G)			71			76			76			80
Energy Holdings:
Senior Notes			127			133			505			474
Project Level, Non-Recourse Debt			44			44			328			328
		$	8,250		$	9,118		$	9,038		$	9,159

Amounts for 2009 exclude $36 million of unamortized discount related to the debt exchange between Power and Energy Holdings. See Note 7. Changes in Capitalization for a description of this transaction.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 10. Other Income and Deductions


Other Income	Power			PSE&G			Other (A)			Consolidated Total
	Millions
Three Months Ended September 30, 2009
NDT Fund Gains		$	29		$	—		$	—		$	29
NDT Interest, Dividend and Other Income			10			—			—			10
Other Interest and Dividend Income			1			—			1			2
Other			—			2			—			2

Total Other Income		$	40		$	2		$	1		$	43


Three Months Ended September 30, 2008
NDT Fund Gains		$	73		$	—		$	—		$	73
NDT Interest, Dividend and Other Income			14			—			—			14
Other Interest and Dividend Income			1			—			5			6
Other			—			2			—			2

Total Other Income		$	88		$	2		$	5		$	95


Nine Months Ended September 30, 2009
NDT Fund Gains		$	156		$	—		$	—		$	156
NDT Interest, Dividend and Other Income			35			—			—			35
Other Interest and Dividend Income			5			1			1			7
Other			—			6			1			7

Total Other Income		$	196		$	7		$	2		$	205


Nine Months Ended September 30, 2008
NDT Fund Gains		$	220		$	—		$	—		$	220
NDT Interest, Dividend and Other Income			40			—			—			40
Other Interest and Dividend Income			5			4			7			16
Other			2			5			2			9

Total Other Income		$	267		$	9		$	9		$	285

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


Other Deductions	Power			PSE&G			Other (A)			Consolidated Total
	Millions
Three Months Ended September 30, 2009
NDT Fund Losses and Expenses		$	16		$	—		$	—		$	16
Other			1			—			2			3

Total Other Deductions		$	17		$	—		$	2		$	19


Three Months Ended September 30, 2008
NDT Fund Losses and Expenses		$	39		$	—		$	—		$	39
Other			—			2			2			4

Total Other Deductions		$	39		$	2		$	2		$	43


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

Total Other Deductions		$	111		$	2		$	5		$	118


Nine Months Ended September 30, 2008
NDT Fund Losses and Expenses		$	147		$	—		$	—		$	147
Other			—			3			6			9

Total Other Deductions		$	147		$	3		$	6		$	156

(A)

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

Note 11. Income Taxes

PSEG’s effective tax rate for the three months ended September 30, 2009 was 40.8% as compared to 41.2% for the three months ended September 30, 2008. The decrease in the effective tax rate was due primarily to tax benefits from reductions of reserves for uncertain tax positions in 2009. This was partially offset by the sale of leveraged lease assets in 2009.

PSEG’s effective tax rate for the nine months ended September 30, 2009 was 41.5% as compared to 38.5% for the nine months ended September 30, 2008, excluding the tax effect of a charge of $490 million, after tax, taken in the second quarter of 2008 related to leveraged lease transactions. The increase in the effective tax rate was due primarily to the sale of leveraged lease assets in 2009 and the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim. This was partially offset by tax benefits from reductions of reserves for uncertain tax positions in 2009 and benefits of a manufacturing deduction under the American Jobs Creation Act of 2004.

Power’s effective tax rate for the three months ended September 30, 2009 was 40.5% as compared to 40.0% for the three months ended September 30, 2008. The increase in the effective tax rate was due primarily to higher earnings in the NDT fund, partially offset by increased benefits of a manufacturing deduction under the American Jobs Creation Act of 2004.

Power’s effective tax rate for the nine months ended September 30, 2009 was 39.7% as compared to 40.4% for the nine months ended September 30, 2008. The decrease in effective tax rate was due primarily to tax

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

benefits from reductions of reserves for uncertain tax positions and increased benefits of a manufacturing deduction under the American Jobs Creation Act of 2004, partially offset by higher earnings in the NDT Fund.

PSE&G’s effective tax rate for the three months ended September 30, 2009 was 41.7% as compared to 41.0% for the three months ended September 30, 2008. PSE&G’s effective tax rate for the nine months ended September 30, 2009 was 40.9% as compared to 35.9% for the nine months ended September 30, 2008. The increase in the effective tax rate for the nine months was due primarily to the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim

PSEG and PSE&G have $1.016 billion and $33 million respectively, of unrecognized tax benefits as of September 30, 2009. PSEG made tax deposits with the IRS totaling $320 million to defray interest costs associated with disputed tax assessments associated with certain lease investments (see Note 6. Commitments and Contingent Liabilities). The deposits are fully refundable and are recorded as a reduction to the Long-Term Accrued Taxes in PSEG’s Condensed Consolidated Balance Sheets, but are not reflected in the $1.016 billion amount shown above. PSEG and PSE&G are no longer subject to examination for New Jersey Corporate Business Tax for years 2000 to 2004. During 2009, PSEG materially reduced its unrecognized tax benefits by terminating several leases involved in the IRS lease issue. (see Note 6. Commitments and Contingent Liabilities).

It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 6. Commitments and Contingent Liabilities will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase by as much as $305 million or decrease by as much as $803 million. It is not possible to predict the magnitude, timing or direction of any such change.

It is reasonably possible that the total unrecognized tax benefits (including interest) at PSEG will decrease by approximately $71 million within the next 12 months due to either agreement with various taxing authorities upon audit or the expiration of the Statute of Limitations. This amount includes an $85 million decrease for Energy Holdings, a $26 million decrease for Services, a $30 million increase for PSE&G, a $5 million increase for Power and a $5 million increase for PSEG.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 12. Comprehensive Income (Loss), Net of Tax


	Power (A)				PSE&G			Other (B)				Consolidated Total
	Millions
Three Months Ended September 30, 2009:
Net Income		$	347			$	88		$	53			$	488
Other Comprehensive Income (Loss)			(31	)			1			(1	)			(31	)

Comprehensive Income		$	316			$	89		$	52			$	457


Three Months Ended September 30, 2008:
Net Income		$	328			$	98		$	230			$	656
Other Comprehensive Income (Loss)			775				—			(75	)			700

Comprehensive Income		$	1,103			$	98		$	155			$	1,356


Nine Months Ended September 30, 2009:
Net Income		$	922			$	256		$	65			$	1,243
Other Comprehensive Income			137				2			7				146

Comprehensive Income		$	1,059			$	258		$	72			$	1,389


Nine Months Ended September 30, 2008:
Net Income (Loss)		$	843			$	287		$	(176	)		$	954
Other Comprehensive Income (Loss)			115				—			(95	)			20

Comprehensive Income (Loss)		$	958			$	287		$	(271	)		$	974

(A)

Changes at Power primarily relate to changes in unrealized gains and losses on derivative contracts that qualify for hedge accounting in 2009 and 2008 and NDT Fund activity, as detailed below.

(B)

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

Accumulated Other Comprehensive Income (Loss)


	Balance as of December 31, 2008				Power			PSE&G			Other			Balance as of September 30, 2009
	Millions

Nine Months Ended September 30, 2009:
Derivative Contracts		$	172			$	49		$	—		$	1		$	222
Pension and OPEB Plans			(371	)			16			—			3			(352	)
NDT Funds (A)			18				70			—			—			88
Other			4				2			2			3			11

		$	(177	)		$	137		$	2		$	7		$	(31	)

(A)

Includes reclassification of $12 million of non-credit losses, net-of-tax, from Retained Earnings to Accumulated Other Comprehensive Income (Loss) recorded upon adoption of new guidance for

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

“Recognition and Presentation of Other-Than-Temporary-Impairments of Debt Securities” effective April 1, 2009. See Note 2. Recent Accounting Standards for additional information.


	Balance as of December 31, 2007				Power				PSE&G			Other				Balance as of September 30, 2008
	Millions
Nine Months Ended September 30, 2008:
Derivative Contracts		$	(259	)		$	181			$	—		$	5			$	(73	)
Pension and OPEB Plans			(167	)			1				—			—				(166	)
Currency Translation Adjustment			107				—				—			(99	)			8
NDT Funds			97				(67	)			—			—				30
Other			6				—				—			(1	)			5

		$	(216	)		$	115			$	—		$	(95	)		$	(196	)

Note 13. Earnings Per Share (EPS)

PSEG

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


	Three Months Ended September 30,												Nine Months Ended September 30,
	2009						2008						2009						2008
	Basic			Diluted			Basic			Diluted			Basic			Diluted			Basic			Diluted
EPS Numerator:
Earnings (Millions)
Continuing Operations		$	488		$	488		$	476		$	476		$	1,243		$	1,243		$	746		$	746
Discontinued Operations			—			—			180			180			—			—			208			208

Net Income		$	488		$	488		$	656		$	656		$	1,243		$	1,243		$	954		$	954

EPS Denominator (Thousands):
Weighted Average Common Shares Outstanding			505,982			505,982			507,724			507,724			505,986			505,986			508,233			508,233
Effect of Stock Options			—			181			—			369			—			187			—			435
Effect of Stock Performance Share Units			—			945			—			176			—			700			—			153
Effect of Restricted Stock Units			—			134			—			57			—			84			—			69

Total Shares			505,982			507,242			507,724			508,326			505,986			506,957			508,233			508,890

EPS:
Continuing Operations		$	0.96		$	0.96		$	0.94		$	0.94		$	2.45		$	2.45		$	1.47		$	1.47
Discontinued Operations			—			—			0.35			0.35			—			—			0.41			0.41

Net Income		$	0.96		$	0.96		$	1.29		$	1.29		$	2.45		$	2.45		$	1.88		$	1.88

Dividend payments on common stock for the quarters ended September 30, 2009 and 2008 were $0.3325 and $0.3225 per share respectively, and totaled $168 million and $164 million respectively. Dividend

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

payments on common stock for the nine months ended September 30, 2009 and 2008 were $0.9975 and $0.9675 per share respectively, and totaled approximately $505 million and $492 million respectively.

Note 14. Financial Information by Business Segments


	Power			PSE&G				Energy Holdings				Other (A)				Consolidated
	Millions
Three Months Ended September 30, 2009:
Total Operating Revenues		$	1,422		$	1,943			$	200			$	(524	)		$	3,041
Net Income			347			88				34				19				488
Preferred Securities Dividends			—			(1	)			—				1				—
Segment Earnings			347			87				34				20				488
Gross Additions to Long-Lived Assets			207			201				5				3				416

Three Months Ended September 30, 2008:
Total Operating Revenues		$	1,833		$	2,274			$	354			$	(743	)		$	3,718
Income (Loss) From Continuing Operations			328			98				56				(6	)			476
Income from Discontinued Operations, net of tax			—			—				180				—				180
Net Income (Loss)			328			98				236				(6	)			656
Preferred Securities Dividends			—			(1	)			—				1				—
Segment Earnings (Loss)			328			97				236				(5	)			656
Gross Additions to Long-Lived Assets			293			189				2				14				498

Nine Months Ended September 30, 2009:
Total Operating Revenues		$	5,097		$	6,321			$	493			$	(2,388	)		$	9,523
Net Income			922			256				51				14				1,243
Preferred Securities Dividends			—			(3	)			—				3				—
Segment Earnings			922			253				51				17				1,243
Gross Additions to Long-Lived Assets			632			580				18				2				1,232

Nine Months Ended September 30, 2008:
Total Operating Revenues		$	5,831		$	6,750			$	245			$	(2,766	)		$	10,060
Income (Loss) From Continuing Operations			843			287				(367	)			(17	)			746
Income from Discontinued Operations, net of tax			—			—				208				—				208
Net Income (Loss)			843			287				(159	)			(17	)			954
Preferred Securities Dividends			—			(3	)			—				3				—
Segment Earnings (Loss)			843			284				(159	)			(14	)			954
Gross Additions to Long-Lived Assets			677			534				6				20				1,237

As of September 30, 2009:
Total Assets		$	9,910		$	16,144			$	3,476			$	(1,096	)		$	28,434
Investments in Equity Method Subsidiaries		$	46		$	—			$	187			$	—			$	233

As of December 31, 2008:
Total Assets		$	9,459		$	16,406			$	4,256			$	(1,072	)		$	29,049
Investments in Equity Method Subsidiaries		$	35		$	—			$	180			$	—			$	215

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(A)

Other activities include amounts applicable to PSEG (as parent company), Services, and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are priced in accordance with applicable regulations, including affiliate pricing rules, or at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 15. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs.

Note 15. Related-Party Transactions

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

Power

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


Related Party Transactions	Three Months Ended September 30,								Nine Months Ended September 30,
Related Party Transactions	2009				2008				2009				2008
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)		$	126			$	210			$	1,309			$	1,606
Billings to PSE&G through BGS (A)			388				506				1,051				1,113

Total Revenue from Affiliates		$	514			$	716			$	2,360			$	2,719

Expense Billings from Affiliates:
Administrative Billings from Services (B)		$	(36	)		$	(41	)		$	(114	)		$	(122	)

Total Expense Billings from Affiliates		$	(36	)		$	(41	)		$	(114	)		$	(122	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


Related Party Balances	As of September 30, 2009				As of December 31, 2008
	Millions
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)		$	180			$	319
Receivables from PSE&G through BGS and BGSS Contracts (A)			149				475
Payable to Services (B)			(20	)			(26	)
Tax Sharing Payable to PSEG (C)			(8	)			(36	)
Current Unrecognized Tax Receivable from PSEG (C)			5				—
Amounts Receivable from Energy Holdings Relating to Debt Exchange (D)			405				—
Amounts Payable to PSEG Texas			(11	)			—
Amounts Receivable from PSEG			40				—

Accounts Receivable—Affiliated Companies, net		$	740			$	732

Short-Term Loan from Affiliate (Demand Note Payable to PSEG) (E)		$	(65	)		$	(3	)

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

Long-Term Accrued Taxes Payable (C)		$	(5	)		$	(16	)

PSE&G

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


Related Party Transactions	Three Months Ended September 30,								Nine Months Ended September 30,
Related Party Transactions	2009				2008				2009				2008
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)		$	(126	)		$	(210	)		$	(1,309	)		$	(1,606	)
Billings from Power through BGS (A)			(388	)			(506	)			(1,051	)			(1,113	)
Administrative Billings from Services (B)			(57	)			(61	)			(186	)			(194	)

Total Expense Billings from Affiliates		$	(571	)		$	(777	)		$	(2,546	)		$	(2,913	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


Related Party Balances	As of September 30, 2009				As of December 31, 2008
	Millions
Payable to Power Related to Gas Supply Hedges for BGSS (A)		$	(180	)		$	(319	)
Payable to Power through BGS and BGSS Contracts (A)			(149	)			(475	)
Payable to Services (B)			(29	)			(54	)
Tax Sharing Receivable from PSEG (C)			14				21
Current Unrecognized Tax Receivable from PSEG (C)			61				55
Amounts Receivable from PSEG			—				9

Accounts Payable—Affiliated Companies, net		$	(283	)		$	(763	)

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

Long-Term Accrued Taxes Payable (C)		$	(94	)		$	(82	)

(A)

PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 31, 2012 and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.

(B)

Services provides and bills administrative services to Power and PSE&G. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. Power and PSE&G believe that the costs of services provided by Services approximate market value for such services.

(C)

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

(D)

Amount represents the $404 million consideration paid by Power to Energy Holdings’ bondholders on completion of the debt exchange transaction in September 2009 combined with $1 million of transaction costs. See Note 7. Changes in Capitalization and Note 17. Subsequent Events for additional information.

(E)

Short-term loans are for short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

(F)

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 16. Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). The following table presents condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries.


	Power				Guarantor Subsidiaries				Other Subsidiaries				Consolidating Adjustments				Consolidated Total
	Millions
Three Months Ended September 30, 2009
Operating Revenues		$	—			$	1,702			$	28			$	(308	)		$	1,422
Operating Expenses			3				1,101				28				(307	)			825

Operating Income			(3	)			601				—				(1	)			597
Equity Earnings (Losses) of Subsidiaries			354				(4	)			—				(350	)			—
Other Income			11				43				—				(14	)			40
Other Deductions			(1	)			(15	)			—				(1	)			(17	)
Interest Expense			(30	)			(15	)			(6	)			14				(37	)
Income Tax Benefit (Expense)			16				(253	)			2				(1	)			(236	)

Net Income (Loss)		$	347			$	357			$	(4	)		$	(353	)		$	347


Three Months Ended September 30, 2008
Operating Revenues		$	—			$	2,129			$	31			$	(327	)		$	1,833
Operating Expenses			3				1,522				31				(328	)			1,228

Operating Income (Loss)			(3	)			607				—				1				605
Equity Earnings (Losses) of Subsidiaries			328				(10	)			—				(318	)			—
Other Income			38				110				—				(60	)			88
Other Deductions			—				(39	)			—				—				(39	)
Other Than Temporary Impairments			—				(65	)			—				—				(65	)
Interest Expense			(44	)			(43	)			(15	)			60				(42	)
Income Tax Benefit (Expense)			9				(232	)			5				(1	)			(219	)

Net Income (Loss)		$	328			$	328			$	(10	)		$	(318	)		$	328

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power				Guarantor Subsidiaries				Other Subsidiaries				Consolidating Adjustments				Consolidated Total
	Millions

Nine Months Ended September 30, 2009
Operating Revenues		$	—			$	5,958			$	90			$	(951	)		$	5,097
Operating Expenses			9				4,326				90				(951	)			3,474

Operating Income (Loss)			(9	)			1,632				—				—				1,623
Equity Earnings (Losses) of Subsidiaries			943				(15	)			—				(928	)			—
Other Income			48				216				—				(68	)			196
Other Deductions			(1	)			(110	)			—				—				(111	)
Other Than Temporary Impairments			—				(60	)			—				—				(60	)
Interest Expense			(119	)			(47	)			(21	)			68				(119	)
Income Tax Benefit (Expense)			60				(673	)			6				—				(607	)

Net Income (Loss)		$	922			$	943			$	(15	)		$	(928	)		$	922


Nine Months Ended September 30, 2009
Net Cash Provided By (Used In) Operating Activities		$	(123	)		$	2,178			$	(7	)		$	(629	)		$	1,419
Net Cash Provided By (Used In) Investing Activities		$	188			$	(1,229	)		$	(1	)		$	425			$	(617	)
Net Cash Provided By (Used In) Financing Activities		$	(66	)		$	(952	)		$	8			$	205			$	(805	)

Nine Months Ended September 30, 2008
Operating Revenues		$	—			$	6,661			$	90			$	(920	)		$	5,831
Operating Expenses			8				5,100				90				(921	)			4,277

Operating Income (Loss)			(8	)			1,561				—				1				1,554
Equity Earnings (Losses) of Subsidiaries			858				(30	)			—				(828	)			—
Other Income			111				317				—				(161	)			267
Other Deductions			—				(147	)			—				—				(147	)
Other Than Temporary Impairments			—				(135	)			—				—				(135	)
Interest Expense			(150	)			(92	)			(43	)			160				(125	)
Income Tax Benefit (Expense)			32				(616	)			13				—				(571	)

Net Income (Loss)		$	843			$	858			$	(30	)		$	(828	)		$	843


Nine Months Ended September 30, 2008
Net Cash Provided By (Used In) Operating Activities		$	(297	)		$	1,692			$	(104	)		$	(82	)		$	1,209
Net Cash Provided By (Used In) Investing Activities		$	774			$	(1,926	)		$	(20	)		$	519			$	(653	)
Net Cash Provided By (Used In) Financing Activities		$	(475	)		$	244			$	124			$	(438	)		$	(545	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments				Consolidated Total
	Millions
As of September 30, 2009:
Current Assets		$	3,140		$	5,894		$	455		$	(6,899	)		$	2,590
Property, Plant and Equipment, net			55			4,841			899			1				5,796
Investment in Subsidiaries			4,559			520			—			(5,079	)			—
Noncurrent Assets			227			1,398			61			(162	)			1,524

Total Assets		$	7,981		$	12,653		$	1,415		$	(12,139	)		$	9,910

Current Liabilities		$	148		$	6,980		$	778		$	(6,899	)		$	1,007
Noncurrent Liabilities			437			1,115			117			(162	)			1,507
Long-Term Debt			3,166			—			—			—				3,166
Member’s Equity			4,230			4,558			520			(5,078	)			4,230

Total Liabilities and Member’s Equity		$	7,981		$	12,653		$	1,415		$	(12,139	)		$	9,910

As of December 31, 2008:
Current Assets		$	2,395		$	5,507		$	439		$	(5,636	)		$	2,705
Property, Plant and Equipment, net			44			4,513			924			—				5,481
Investment in Subsidiaries			4,758			384			—			(5,142	)			—
Noncurrent Assets			244			1,166			50			(187	)			1,273

Total Assets		$	7,441		$	11,570		$	1,413		$	(10,965	)		$	9,459

Current Liabilities		$	371		$	5,880		$	919		$	(5,637	)		$	1,533
Noncurrent Liabilities			532			935			109			(187	)			1,389
Long-Term Debt			2,653			—			—			—				2,653
Member’s Equity			3,885			4,755			385			(5,141	)			3,884

Total Liabilities and Member’s Equity		$	7,441		$	11,570		$	1,413		$	(10,965	)		$	9,459

Note 17. Subsequent Events

On October 1, 2009, Energy Holdings distributed the outstanding stock of PSEG Texas to PSEG. PSEG in turn contributed the stock to Power as an additional equity investment. Power has been responsible for the operation of the Texas facilities under a management agreement since January 2008. PSEG Texas had operating revenues of $297 million and net income of $21 million for the nine months ended September 30, 2009. As of September 30, 2009, PSEG Texas had total assets of $763 million.

Power’s consolidated financial statements for any period subsequent to September 30, 2009 will include the earnings and assets and liabilities related to PSEG Texas, and will be restated to reflect such activity for any prior periods to be presented.

Also on October 1, 2009, Power distributed to PSEG its $405 million receivable from Energy Holdings. PSEG then contributed such receivable to Energy Holdings to offset Energy Holdings’ payable to Power related to the debt exchange transaction.

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

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

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

•

Power, our wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid Atlantic U.S.,

•

PSE&G, which provides transmission and distribution of electricity and gas in New Jersey, and

•

Energy Holdings, which owns our other generation assets and holds other energy-related investments.

Our business discussion in Part I Item 1 Business of our 2008 Annual Report on Form 10-K provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets. The following supplements that discussion and the discussion included in the Overview of 2008 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2009 and any changes to the key factors that we expect will drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This information should be read in conjunction with such Statements, Notes and the 2008 Annual Report on Form 10-K.

OVERVIEW OF 2009 AND FUTURE OUTLOOK

During 2009, our business has been impacted by many factors, including lower gas prices, milder weather, the economic slowdown and increased pension costs.

The milder weather and the economic slowdown have caused an overall reduction in customer demands for electricity and gas in the markets where we operate. As a result, our generation volumes for the first nine months in 2009 were approximately 10% lower than in the same period of 2008. This reduced volume was experienced mainly at our coal facilities as lower gas prices have made gas-fired generation more economic.

In addition to the overall reduction in customer demands during the first nine months of 2009, we have experienced a higher number of customers choosing to contract with independent electric suppliers rather than remain under the BGS contracts. This migration away from BGS could be sustained or increase if energy prices continue to be lower than the energy price component of the BGS contracts. Migration has and could continue to result in reduced margins as volumes that were previously sold to satisfy obligations under the BGS contracts are replaced with spot market sales at lower prices.

Our distribution operations were also impacted by both the economy and weather conditions in 2009. Our electric delivery volumes for the first nine months of 2009 declined by 4% due to reduced cooling loads in the summer of 2009, reflecting a temperature humidity index that was 22% cooler than the summer of 2008. However, we experienced a 4% increase in our gas delivery volumes for the first nine months of 2009 as compared to the same period in 2008. Winter weather in 2009, as measured by heating degree days, was 10% higher resulting in higher gas space heating demand and sales.

Excluding the impact of weather, residential electric and gas volumes were down 0.9% and 0.7% respectively. These declines were in line with our expectations for the impact of the economy on sales to this sector. Residential sales contribute approximately 45% of our electric margin and 75% of our gas margin. In the Commercial and Industrial segments, margins from electric customers are not based on total energy consumption as measured by kilowatt-hours, but are based on fixed, monthly demand charges that are set by the highest electric demand for an hour period during the previous 12-month period or, in the

case of some electric rates, by the peak demand during the current month. From May through September 2009, the number of hours exceeding 90 degrees was 67% lower than under normal summer weather conditions. This adversely impacted our billed demands, reducing revenues during the summer months. Commercial and Industrial gas customers also have a significant fixed component to billings. Therefore, any changes in energy usage over comparative periods may not have an equivalent effect on sales margin.

Current economic conditions have also caused deterioration in certain customer payment patterns resulting in a higher portion of our accounts receivable balances remaining outstanding for more than 180 days. This represents 15% of our total customer accounts receivable as of September 2009 as compared to 8% last year. We are increasing our activities on the oldest and largest accounts to expedite these collections. PSE&G believes it has sufficient liquidity to manage these delays in customer payments.

There have also been significant regulatory and legislative developments during the year which may affect our operations in the future as new rules and regulations are adopted.

•

In March 2009, the Federal Energy Regulatory Commission (FERC) issued an order regarding PJM Interconnection LLC’s (PJM) RPM. The effect of this order includes an increase in the cost of new entry to more accurately reflect construction and equipment costs. This should incent both new build and continued operation of existing facilities. For additional information, see Part II, Item 1. Legal Proceedings.

•

In April 2009, the U.S. Supreme Court concluded that the U.S. Environmental Protection Agency (EPA) permissibly relied 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 Section 316(b) regulations of the Federal Water Pollution Control Act. This is important to us because it allows the EPA to continue to use the site-specific cost-benefit test in determining best technology available for minimizing adverse environmental impact. For additional information, see Note 6. Commitments and Contingent Liabilities.

•

In April 2009, the EPA released a proposed finding under the Clean Air Act concluding that CO₂ isone type of six specific greenhouse gases which causes or contributes to the climate change problem and constitutes air pollution which endangers both public health and welfare. If applied to fossil fuel generation facilities, additional regulation of CO₂ emissions could affect our operations, our ability to renew permits and licenses and could result in additional material compliance costs.

•

In June 2009, the U.S. House of Representatives passed a bill that promotes renewable energy and requires a reduction in the emission of greenhouse gases from the majority of emission sources, including the generation sector. The bill sets forth major initiatives which include: 1) establishing a national renewable energy standard and 2) creating a market mechanism for the sale and purchase of greenhouse gas emission allowances (cap-and-trade program). If enacted in its current form, the bill could reduce or eliminate existing regional inconsistencies in greenhouse gas regulations. The Senate is expected to consider these issues as well as transmission planning, siting and cost allocation issues in the fourth quarter, but ultimate enactment into law of a bill with comparable provisions and rules is not certain.

•

In August 2009, the EPA announced that it is reconsidering whether coal ash, a by-product of generation at our coal facilities, should be re-regulated. The EPA indicated that it intends to propose a rule by the end of 2009. We currently have a program at Hudson, Mercer and Bridgeport to beneficially use the coal ash in other uses as currently allowed by Federal and state regulations. Proposed regulations which more stringently regulate coal ash, including the potential regulation of coal ash as hazardous waste, could materially increase costs for our coal facilities.

•

In September 2009, the EPA announced that it would be proposing rules which would subject many power generating units, including ours, to Clean Air Act permitting for greenhouse gases (GHG), including CO₂. The proposed rule would require installation of the best available control technologies whenever an applicable modification is made. Current limits for the implementation of such technologies are much lower for pollutants regulated under the Clean Air Act. The EPA

announced this proposal because it is expected to make an “endangerment” finding as it relates to GHG. Once such a finding is made, it will be immediately applicable to Clean Air Act requirements for permitting. We cannot predict the ultimate resolution of this matter, nor the effect on our operations.

•

During the year various legislative proposals have been made with the intention of enacting stricter regulation over derivatives in light of the financial market issues experienced last year, largely caused by derivative trading in connection with mortgage loans. The U.S. House of Representatives is working on a bill, which is expected to be finalized by the end of December. The Senate is expected to work on its own bills in the first quarter of 2010. It is difficult to predict what the final legislation will contain. If the final legislation required all trading to be done over an exchange, we would expect to see our collateral requirements increase substantially to support our activities. If the definition of the types of trades and traders included in the current House drafts remain, then it is unlikely that our collateral requirements will change.

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

Looking forward, continued lower market prices and reduced demands would result in lower margins for our generation output. To help offset these reduced margins, we will explore prudent growth opportunities and we have and will continue to look for ways to reduce costs while maintaining our safety, reliability and environmental standards. We will do this focusing on operational excellence, improving our financial strength and making disciplined investments.

Operational Excellence

While total generation volumes were down about 10% in 2009, our generating assets continued to perform well. Our lower cost nuclear generation output was 4% higher for the first nine months of 2009 than in the comparable period in 2008.

In addition, our hedging strategy has resulted in higher average realized electric prices which helped to mitigate the effect of our reduced generation resulting from recent mild weather and recessionary conditions. The increase in realized prices for the first nine months of 2009 as compared to the same period in 2008 was due to comparably higher-priced contracts entered into in prior years that replaced older, lower-priced contracts, such as the 2005 and 2006 Basic Generation Service (BGS) auction contracts which expired in May 2008 and May 2009.

We continue to receive fair pricing for our capacity. Prices set earlier in 2009 under the most recent Reliability Pricing Model (RPM) auction for the 2012-2013 period were higher than those set for 2011-2012 period and once again varied based on the constraints in each of the PJM zones, as compared to the uniform zonal pricing set for the periods from June 2010 to May 2012.

On October 1, 2009, ownership of the Texas facilities was transferred to Power (See Note 17. Subsequent Events for additional information). Since Power has been responsible for the operation of the Texas facilities under a management agreement since January 2008, there are no anticipated operational or commercial impacts resulting from this transaction.

Energy Holdings’ remaining portfolio consists primarily of its lease investments at Resources and smaller equity method investments at Global, including GWF Energy which we intend to sell pending the necessary approvals. See Note 3. Discontinued Operations and Dispositions for additional information. As a result, Energy Holdings is focused on:

•

continuing to reduce our cash tax exposure related to certain leveraged leases by pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds (See Note 6. Commitments and Contingent Liabilities for additional information),

•

earning adequate returns on its remaining investments, and

•

exploring opportunities for investment in renewable energy products, including solar investments, such as those discussed below, our offshore wind project and compressed air energy storage technology.

Financial Strength

Our businesses continued to generate strong cash from operations in 2009. In addition, Power established a program for the issuance of up to $500 million of unsecured medium-term notes (MTNs) to retail investors and has issued $209 million under this program. We used these funds, cash from operations, and cash on hand to:

•

contribute $364 million into our pension plans in 2009,

•

pay our maturing debt obligations in 2009 (See Note 7. Changes in Capitalization),

•

make an additional $140 million deposit with the IRS to defray potential interest costs associated with the disputed tax liability for the leveraged lease investments,

•

redeem $280 million of non-recourse debt at our Texas plants, and

•

repurchase $10 million of Energy Holdings’ remaining Senior Notes.

The Board of Directors has also approved an increase in the quarterly dividends from $0.3225 per share to $0.3325 per share of Common Stock for the first three quarters of 2009 resulting in an indicated annual dividend of $1.33 per share. This increase is consistent with maintaining our target payout ratio of 40% to 50% of Operating Earnings.

Disciplined Investment

We expect to continue to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include responding to climate change and continuing to improve environmental performance, upgrading critical energy infrastructure and providing new energy supplies in markets with growing demand. During 2009:

•

We were assigned construction and operating responsibility for an additional 500 kV transmission project in New Jersey. The project would run from Branchburg to Hudson. In October 2009, we filed a petition with FERC seeking incentive rate treatment for this project. We have requested that the incentives be effective January 1, 2010.

•

We are continuing to pursue obtaining all necessary regulatory approvals for the $750 million Susquehanna-Roseland transmission project. We are awaiting numerous regulatory approvals for this project, including a decision from the BPU which we expect in early 2010. We cannot predict the outcome of the regulatory approvals that are currently pending.

•

We requested approval from the BPU for a new solar loan program, called “Solar Loan II.” Under Solar Loan II, we would help finance the installation of an additional 40 MW of solar-powered generating systems in our electric service territory. Any remaining financing capacity from our current solar loan program would be rolled into this new program.

•

The BPU approved our Solar 4 All Program. Under this program, we anticipate investing approximately $515 million to develop 80 MW of utility-owned solar photovoltaic systems over a four-year horizon.

•

The BPU approved our Capital Economic Stimulus Program. Under this program, we anticipate accelerating $694 million of capital infrastructure investments through our distribution business for electric and gas programs in New Jersey over a 24-month period. The program seeks to support employment in New Jersey, while enhancing the distribution business infrastructure. This program provides for a charge for contemporaneous recovery of a return on the program expenditures plus depreciation of the assets which will be adjusted each January.

•

The BPU approved our Energy Efficiency Economic Stimulus Program. Under this program, we anticipate investing approximately $166 million in energy efficiency expenditures through PSE&G for electric and gas programs in New Jersey over an 18-month period. The program seeks to help New Jersey meet its Energy Master Plan goal of reducing energy consumption by 20% by 2020 and to support employment in New Jersey. This program provides for a charge for contemporaneous recovery of a return on the program expenditures.

•

We have approved the expenditure of $192 million for a steam path retrofit and related upgrades at Peach Bottom. Approximately $18 million has been spent as of September 2009. These upgrades are expected to result in an increase of our share of capacity by 32 MW (14 MW at Unit 3 in 2011 and 18 MW at Unit 2 in 2012). We also anticipate expenditures in pursuit of additional output through an extended power uprate at Peach Bottom. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Our share of the increased capacity is expected to be 133 MW with an anticipated cost of approximately $400 million.

•

We plan to construct 178 MW of gas-fired peaking capacity at our Kearny site. This capacity was bid and cleared the PJM RPM base residual capacity auction for the 2012-2013 period. We expect to begin construction in the third quarter of 2011. The project is expected to be in-service by June 2012. We estimate the cost of these generating units to be $160 million to $200 million, with approximately $8 million spent as of September 2009.

•

We developed a solar project in New Jersey and have acquired two additional solar projects at Energy Holdings to be developed in Florida and Ohio, which together have a total capacity of approximately 29 MW. Completion of these projects is expected by the end of 2010 with a total investment of approximately $100 million.

There is no guarantee that these or future initiatives will be achieved since many issues need to be favorably resolved, such as system conditions, regulatory approvals and funding of construction or development costs.

We receive immediate recovery of our transmission investments and costs through our FERC-approved formula transmission rate. The formula rate mechanism provides for an annual setting of our transmission rates as well as an annual true up to ensure timely recovery of the actual costs of providing transmission service and PSE&G’s approved return on equity. In accordance with our formula rate protocols, in October 2009, we filed our 2010 Annual Formula Rate Update with FERC. The update provides for approximately $23 million in increased revenues as part of our 2010 transmission rates.

In May 2009, we filed a Petition with the BPU for an increase in electric and gas distribution base rates. The amounts requested were $134 million and $97 million for electric and gas respectively. An update to the Petition was filed September 25, 2009 requesting $147 million and $106 million for electric and gas respectively. The matter is pending with a decision expected in the first half of 2010.

We anticipate that any current spending under the Capital Economic Stimulus Program will be included in our rate base with the expected decision in our Base Rate Case and that we will continue to receive contemporaneous recovery of future expenditures under this program with the return on equity adjusted to reflect the rate allowed in the Base Rate Case. The recovery mechanisms approved by the BPU for our Solar 4 All, Solar Loan, Energy Efficiency and Demand Response programs are scheduled to be reset on January 1st of each year, with the return on equity to be adjusted to reflect the rate allowed in the Base Rate Case at the time of the BPU Order.

RESULTS OF OPERATIONS

The results for PSEG, PSE&G, Power and Energy Holdings for the quarters and nine months ended September 30, 2009 and 2008 are presented below:


Earnings (Losses)	Three Months Ended September 30,							Nine Months Ended September 30,
	2009			2008				2009			2008
	Millions
Power		$	347		$	328			$	922		$	843
PSE&G			88			98				256			287
Energy Holdings			34			56				51			(367	)
Other			19			(6	)			14			(17	)

PSEG Income from Continuing Operations		$	488		$	476			$	1,243		$	746
Income from Discontinued Operations			—			180				—			208

Net Income		$	488		$	656			$	1,243		$	954


Earnings Per Share (Diluted)	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
PSEG Income from Continuing Operations		$	0.96		$	0.94		$	2.45		$	1.47
Income from Discontinued Operations			—			0.35			—			0.41

PSEG Net Income		$	0.96		$	1.29		$	2.45		$	1.88

Our results include the following after-tax impacts of mark-to-market (MTM) activity:


Non-Trading Mark-to-Market (MTM) Gains (Losses) After Tax	Three Months Ended September 30,							Nine Months Ended September 30,
Non-Trading Mark-to-Market (MTM) Gains (Losses) After Tax	2009			2008				2009				2008
	Millions
Power		$	1		$	(20	)		$	(15	)		$	10
Energy Holdings			16			31				(7	)			20

Total		$	17		$	11			$	(22	)		$	30

Both the quarter-over-quarter and nine-month over nine month increases in our Income from Continuing Operations reflect the following large drivers:

•

improved earnings at Power due to lower generation costs and higher contract pricing,

•

partially offset by lower sales volumes due to milder weather in the second and third quarter and economic conditions.

The nine-month over nine month increases also included:

•

the absence of a charge taken in June 2008 related to IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions, and

•

the absence of tax benefits taken in 2008 at PSE&G and Energy Holdings related to an IRS refund claim and other tax items.

PSEG

Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, and charitable contributions along with general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 15. Related-Party Transactions. For an explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings that follow the table below.


	Three Months Ended September 30,						Increase/ (Decrease)							Nine Months Ended September 30,						Increase/ (Decrease)
	2009			2008			2009 vs 2008							2009			2008			2009 vs 2008
	Millions						Millions				%			Millions						Millions				%
Operating Revenues		$	3,041		$	3,718		$	(677	)		(18	)		$	9,523		$	10,060		$	(537	)		(5	)
Energy Costs			1,241			1,899			(658	)		(35	)			4,376			5,552			(1,176	)		(21	)
Operation and Maintenance			622			609			13			2				1,925			1,856			69			4
Depreciation and Amortization			224			214			10			5				634			597			37			6
Income from Equity Method Investments			10			8			2			25				29			27			2			7
Impairment on Equity Method Investments			4			1			3			N/A				12			1			11			N/A
Other Income and (Deductions)			24			52			(28	)		(56	)			87			129			(42	)		(33	)
Other Than Temporary Impairments			—			65			(65	)		(100	)			61			135			(74	)		(55	)
Interest Expense			129			149			(20	)		(13	)			407			448			(41	)		(9	)
Income Tax Expense			337			334			3			1				881			780			101			13
Income from Discontinued Operations, net of tax			—			180			(180	)		(100	)			—			208			(208	)		(100	)

Power


	Three Months Ended September 30,						Increase/ (Decrease)		Nine Months Ended September 30,						Increase/ (Decrease)
	2009			2008			2009 vs 2008		2009			2008			2009 vs 2008
	Millions						Millions		Millions						Millions
Income from Continuing Operations		$	347		$	328		$ 19		$	922		$	843		$ 79
Net Income		$	347		$	328		$ 19		$	922		$	843		$ 79

For the three months ended September 30, 2009, the primary reasons for the $19 million increase in Income from Continuing Operations were

•

the absence of other-than-temporary losses on investments in the Nuclear Decommissioning Trust (NDT) Funds and lower maintenance costs,

•

partially offset by lower gains on the NDT Funds,

•

lower average gas sales prices under the Basic Gas Supply Service (BGSS) contract, and

•

lower sales volumes on generation and BGS contracts nearly mitigated by lower generation costs.

Included is the recognition of non-trading MTM gains of less than $1 million, after-tax, in 2009 as compared to $20 million of losses, after-tax, in 2008.

For the nine months ended September 30, 2009, the primary reasons for the $79 million increase in Income from Continuing Operations were

•

lower fuel costs and higher pricing under our BGS and other contracts partially offset by lower generation,

•

lower other-than-temporary impairments on investments in the NDT Funds, and

•

lower maintenance costs for planned outage work,

•

partially offset by higher depreciation due to additional assets having been placed in service and lower net gains on the NDT Funds.

Included is the recognition of non-trading MTM losses of $15 million, after-tax, in 2009 as compared to $10 million of after-tax MTM gains in 2008.

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


	Three Months Ended September 30,						Increase/ (Decrease)							Nine Months Ended September 30,						Increase/ (Decrease)
	2009			2008			2009 vs 2008							2009			2008			2009 vs 2008
				Millions							%						Millions							%
Operating Revenues		$	1,422		$	1,833		$	(411	)		(22	)		$	5,097		$	5,831		$	(734	)		(13	)
Energy Costs			526			904			(378	)		(42	)			2,551			3,360			(809	)		(24	)

Operation and Maintenance			255			282			(27	)		(10	)			784			796			(12	)		(2	)
Depreciation and Amortization			44			42			2			5				139			121			18			15

Other Income and (Deductions)			23			49			(26	)		(53	)			85			120			(35	)		(29	)
Other Than Temporary Impairments			—			65			(65	)		—				60			135			(75	)		(56	)

Interest Expense			37			42			(5	)		(12	)			119			125			(6	)		(5	)
Income Tax Expense			236			219			17			8				607			571			36			6

For the three months ended September 30, 2009 as compared to 2008

Operating Revenues decreased $411 million due to

•

Generation revenues decreased $254 million due to

lower revenues of $140 million resulting from lower volumes of generation sold at lower prices in PJM and NEPOOL and lower prices on a higher volume of generation sold in the New York power pool,

a net decrease of $136 million due to a lower volume of BGS contracts partially offset by higher prices, and

a reduction of $6 million in ancillary services,

partially offset by higher revenues of $27 million due to several new wholesale contracts that were entered into in late 2008 and early 2009.

•

Gas Supply revenues decreased $151 million due to

a net decrease of $105 million resulting from sales under the BGSS contract, comprised of $95 million from lower average gas prices in 2009 and $10 million of net losses on financial hedging transactions, and

a net decrease of $46 million due to lower prices partially offset by increased sales volume to third party customers.

•

Trading revenues decreased $6 million due primarily to losses on gas contracts, partly offset by gains on electric-related contracts.

Operating Expenses

•

Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased by $378 million due to

Generation costs decreased by $245 million due primarily to $300 million of lower fuel costs, reflecting lower average natural gas prices and lower volumes of natural gas and coal purchases, partly offset by $16 million of charges incurred in 2009 for cancelling coal shipments, $15 million of increased congestion charges, and $14 million for increased power purchases.

Gas costs decreased $133 million, reflecting a decrease of $88 million related to Power’s obligations under the BGSS contract, reflecting lower inventory costs and a decrease of $45 million in sales to third party customers

•

Operation and Maintenance decreased $27 million due primarily to 2008 planned maintenance costs at our Hudson, Mercer, Linden and Bridgeport stations.

•

Depreciation and Amortization increased $2 million due to

an increase of $4 million due to pollution control equipment being placed into service in December 2008 at our Mercer 1 and 2 generating facilities, and

an increase of $2 million resulting from larger depreciable asset bases in 2009 at both Fossil and Nuclear,

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

Other Income and Deductions decreased $26 million due primarily to

•

a decrease in net gains of $22 million on the NDT Fund securities,

•

and a decrease of $3 million in NDT interest, dividends and miscellaneous income.

Other Than Temporary Impairments decreased $65 million due to the absence of charges in 2009 related to the NDT Fund securities.

Interest Expense decreased $5 million due to higher capitalized interest related to increased construction activity in 2009 at Fossil, most notably the installation of back-end pollution-control technology.

Income Tax Expense increased $17 million due primarily to higher pre-tax income.

For the nine months ended September 30, 2009 as compared to 2008

Operating Revenues decreased $734 million due to

•

Generation revenues decreased $363 million due to

lower revenues of $325 million resulting from lower volumes of generation sold at lower prices in PJM and NEPOOL and lower prices on a higher volume of generation sold in the New York power pool,

a net decrease of $74 million due to a lower volume of BGS contracts partially offset by higher prices, and

a decrease of $22 million due to lower ancillary services revenues and reduced operating reserve credits and auction revenue rights,

partially offset by higher revenues of $60 million due to several new wholesale contracts that were entered into in late 2008 and early 2009.

•

Gas Supply revenues decreased $364 million

including a net decrease of $223 million resulting from sales under the BGSS contract, comprised of $262 million from lower average gas prices in 2009 net of gains on financial

hedging transactions, partly offset by higher sales volumes of $39 million due to colder winter temperatures in 2009, and

a net decrease of $141 million due to lower prices on a reduced sales volume to third party customers.

•

Trading revenues decreased $7 million due primarily to losses on gas contracts, partially offset by gains on electric-related contracts.

Operating Expenses

•

Generation costs decreased by $451 million due to $719 million of lower fossil fuel costs, primarily reflecting lower average natural gas prices and lower volumes of natural gas and coal purchases, partly offset by $15 million of higher nuclear fuel costs, net losses of $124 million from financial hedging transactions, $37 million for increased power purchases, $25 million for CO₂ allowances, $22 million for higher purchases of financial transmission rights, $17 million for cancellation charges on cancelled coal shipments, and $27 million for congestion charges.

Gas costs decreased $358 million, reflecting net decreases of $209 million and $149 million related to Power’s obligations under the BGSS contract and sales to third party customers respectively, reflecting lower inventory costs partially offset by higher volumes.

•

Operation and Maintenance decreased $12 million due primarily to

net decrease of $54 million due to lower planned maintenance costs at our fossil stations,

partially offset by $41million related to planned outages at Peach Bottom and Hope Creek in 2009 and preventative maintenance costs at all our nuclear stations.

•

Depreciation and Amortization increased $18 million due to

an increase of $13 million due to pollution control equipment being placed into service in December 2008 at our Mercer 1 and 2 generating facilities, and

an increase of $9 million resulting from larger depreciable asset bases in 2009 at both Fossil and Nuclear,

Other Income and Deductions decreased $35 million due primarily to

•

a decrease in net gains of $25 million on the NDT Fund securities, and

•

a decrease of $5 million in interest, dividends and gains on NDT Fund derivative instruments.

Other Than Temporary Impairments decreased $75 million due to the lower charges in 2009 related to the NDT Fund securities.

Interest Expense decreased $6 million due to

•

higher capitalized interest of $11 million in 2009 due primarily to increased installation of back-end pollution-control technology in 2009 at Fossil, and

•

lower interest expense of $5 million due to the maturity of $250 million of 3.75% Notes in April 2009,

•

partially offset by $9 million of higher interest expense in 2009 related to the issuance of $209 million of medium-term notes in January 2009.

Income Tax Expense increased $36 million in 2009 due primarily to

•

an increase of $47 million due to higher pre-tax income and $5 million due to higher earnings from the NDT Funds,

•

partially offset by $10 million from the reduction of the reserve for uncertain tax positions, and

•

also offset by $6 million due to increased benefits from a manufacturing deduction under the American Jobs Creation Act of 2004.

PSE&G


	Three Months Ended September 30,						2009 vs 2008 Increase/ (Decrease)				Nine months Ended September 30,						2009 vs 2008 Increase/ (Decrease)
	2009			2008			2009 vs 2008 Increase/ (Decrease)				2009			2008			2009 vs 2008 Increase/ (Decrease)
	Millions
Income from Continuing Operations		$	88		$	98		$	(10	)		$	256		$	287		$	(31	)
Net Income		$	88		$	98		$	(10	)		$	256		$	287		$	(31	)

For the quarter ended September 30, 2009, the primary reasons for the decreases in Income from Continuing Operations were

•

lower electric margins due to unfavorable weather and economic conditions, and

•

increased Operation and Maintenance expense and depreciation,

•

partially offset by a Transmission formula rate increase.

With the exception of gas margins, which were comparably higher for the nine month period in 2009 due to colder winter weather at the beginning of the year, the nine-month over nine month decrease in Income from Continuing Operations was driven by the same factors as the quarter combined with comparably higher taxes resulting from tax benefits recorded in 2008 related to an IRS refund claim and other tax items.

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


	Three Months Ended September 30,						Increase/ (Decrease) 2009 vs 2008							Nine Months Ended September 30,						Increase/ (Decrease) 2009 vs 2008
	2009			2008										2009			2008
				Millions							%						Millions							%
Operating Revenues		$	1,943		$	2,274		$	(331	)		(15	)		$	6,321		$	6,750		$	(429	)		(6	)
Energy Costs			1,167			1,521			(354	)		(23	)			4,005			4,527			(522	)		(12	)
Operation and Maintenance			351			313			38			12				1,090			993			97			10
Depreciation and Amortization			169			161			8			5				462			443			19			4
Other Income and (Deductions)			2			—			2			N/A				5			6			(1	)		N/A
Interest Expense			77			82			(5	)		(6	)			236			244			(8	)		(3	)
Income Tax Expense			63			68			(5	)		(7	)			177			161			16			10

For the three months ended September 30, 2009 as compared to 2008

Operating Revenues decreased $331 million due primarily to

•

Commodity related revenues decreased $356 million due to

decreased electric revenues of $272 million due primarily to

•

$206 million in lower BGS and non-utility generation charges (NGC) revenues due mainly to decreased sales of $202 million and lower prices of $4 million and

•

$67 million in lower non-utility generation (NUG) revenues due primarily to lower prices.

decreased gas revenues of $84 million due to $71 million in decreased BGSS prices and $13 million in lower sales due to economic conditions.

•

Delivery revenues increased $21 million due to

increased gas revenues of $5 million due to $10 million of higher Societal Benefits Clause (SBC) revenues, $2 million increase in Regional Greenhouse Gas Initiative (RGGI) revenues and $2 million in stimulus rate increases partially offset by $9 million of lower sales due primarily to lower prices and

increased electric revenues of $16 million due to

•

$15 million for SBC revenues, $11 million for net transmission rate increases, $10 million distribution rate increases due primarily to $5 million increase in RGGI revenues and $3 million in stimulus rate increases,

•

partially offset by $20 million in decreased distribution sales and demands due to weather and economic conditions, and

•

$4 million in other operating revenues.

PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses below.

Operating Expenses

•

Energy Costs decreased $354 million due to

decreased electric costs of $270 million due to $202 million or 16% in lower BGS and NUG volumes due to economic conditions and $68 million or 5% in lower prices for BGS and NUG purchases, and

decreased gas costs of $84 million due to $71 million or 32% lower prices and by $13 million or 6% in lower sales volumes due to economic conditions.

•

Operation and Maintenance increased $38 million due primarily to

increases in SBC expenses of $20 million,

$17 million of higher labor and benefits, primarily increased pension expense, and

higher overhead and administrative expenses of $4 million,

partially offset by lower materials usage of $3 million.

•

Depreciation and Amortization increased $8 million due primarily to $4 million in amortization of regulatory assets and $3 million additional plant in service.

Other Income and Deductions experienced no material change.

Interest Expense decreased $5 million due primarily to lower average debt balances.

Income Tax Expense decreased $5 million due primarily to lower pre-tax income.

For the nine months ended September 30, 2009 as compared to 2008

Operating Revenues decreased $429 million due primarily to

•

Commodity related revenues decreased $527 million due to

decreased electric revenues of $334 million due primarily to

$187 million in lower BGS and NGC revenues due to decreased sales of $327 million, partially offset by higher prices of $140 million,

$147 million in lower NUG revenues, due primarily to $133 million in lower prices and $14 million of lower sales and

decreased gas revenues of $193 million due to $209 million in decreased BGSS prices offset by $16 million in higher sales due to weather.

•

Delivery revenues increased $92 million due to

increased gas revenues of $43 million due to $25 million of higher SBC revenues, $14 million in higher volumes, $2 million in stimulus rate increases and $2 million in higher RGGI revenues and

increased electric revenues of $49 million due to

$39 million for SBC revenues, $30 million for net transmission rate increases, $18 million in distribution rate increases, to $5 million in RGGI revenues and $4 million in stimulus revenues,

partially offset by $37 million in decreased distribution sales and demands due to weather and economic conditions, and

$6 million in other operating revenues.

PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses below.

Operating Expenses

•

Energy Costs decreased $522 million due to

decreased electric costs of $332 million due to $339 million or 11% in lower BGS and NUG volumes due to unfavorable weather and economic conditions offset by $7 million or 1% in higher prices for BGS and NUG purchases and

decreased gas costs of $190 million due primarily to $209 million or 13% lower prices offset by $18 million or 1% in higher sales volumes due to favorable weather.

•

Operation and Maintenance increased $97 million due primarily to

increases in SBC expenses of $63 million,

$44 million of higher labor and benefits, primarily increased pension expense,

higher overhead and administrative expenses of $2 million, and

partially offset by lower materials usage of $12 million.

•

Depreciation and Amortization increased $19 million due primarily to $11 million additional plant in service and $6 million in amortization of regulatory assets.

Other Income and Deductions experienced no material change.

Interest Expense decreased $8 million due primarily to lower average debt balances.

Income Tax Expense increased $16 million due primarily to $20 million tax benefits taken in 2008 related to an IRS refund claim, partially offset by $5 million in lower pre-tax income.

Energy Holdings


	Three Months Ended September 30,						Increase/ (Decrease)				Nine Months Ended September 30,							Increase/ (Decrease)
	2009			2008			2009 vs 2008				2009			2008				2009 vs 2008
	Millions
Income (Loss) from Continuing Operations		$	34		$	56		$	(22	)		$	51		$	(367	)		$	418
Income from Discontinued Operations, net of tax			—			180			(180	)			—			208				(208	)

Net Income (Loss)		$	34		$	236		$	(202	)		$	51		$	(159	)		$	210

For the three months ended September 30, 2009, the primary reasons for the decrease in Income from Continuing Operations were

•

lower generation margins at Texas,

•

the premium paid on the debt exchange with Power (see Note 7. Changes in Capitalization for additional information), and

•

lower leveraged lease revenues due primarily to the sale of leveraged lease assets,

•

partially offset by gains on the sales and terminations of leveraged lease assets.

For the nine months ended September 30, 2009, the primary reasons for the increase in Income from Continuing Operations were

•

the absence of a charge taken in June 2008, related to IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions, and

•

gains on the sales and terminations of leveraged lease assets,

•

partially offset by lower leveraged lease revenues due primarily to the sale of leveraged lease assets,

•

lower generation margins at Texas,

•

the premium paid on the debt exchange with Power, and

•

lower tax benefits as a result of the absence of benefits recorded in 2008 related to an IRS refund claim.

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


	Three Months Ended September 30,							Increase/ (Decrease)							Nine Months Ended September 30,							Increase/ (Decrease)
	2009				2008			2009 vs 2008							2009				2008			2009 vs 2008
	Millions											%			Millions											%
Operating Revenues		$	200			$	354		$	(154	)		(44	)		$	493			$	245		$	248			N/A
Energy Costs			72				213			(141	)		(66	)			206				427			(221	)		(52	)
Operation and Maintenance			25				27			(2	)		(7	)			76				94			(18	)		(19	)
Depreciation and Amortization			7				8			(1	)		(13	)			21				22			(1	)		(5	)
Income from & Impairment on Equity Method Investments			6				7			(1	)		(14	)			17				26			(9	)		(35	)
Other Income and (Deductions)			(34	)			7			(41	)		N/A				(29	)			14			(43	)		N/A
Interest Expense			11				18			(7	)		(39	)			41				60			(19	)		(32	)
Income Tax Expense			23				46			(23	)		(50	)			86				49			37			76
Income from Discontinued Operations, net of Tax			—				180			(180	)		(100	)			—				208			(208	)		(100	)

For the three months ended September 30, 2009 as compared to 2008

Operating Revenues decreased $154 million due primarily to

•

$190 million in lower generation revenues at PSEG Texas due to a decrease in electricity prices and sales and lower unrealized MTM gains in 2009, and

•

lower leveraged lease revenues of $2 million, due primarily to the sale of leveraged lease assets,

•

partially offset by a gain of $39 million on the sales and terminations of leveraged lease assets and other investments in 2009.

Operating Expenses

•

Energy Costs decreased $141 million due primarily to lower fuel prices and lower fuel consumption and higher unrealized MTM gains.

•

Operation and Maintenance experienced no material change.

•

Depreciation and Amortization experienced no material change.

Income from and Impairment on Equity Method Investments experienced no material change.

Other Income and Deductions decreased by $41 million due to primarily to a premium paid on the debt exchange with Power.

Interest Expense decreased $7 million due primarily to lower average debt balances.

Income Tax Expense decreased $23 million due primarily to a lower pre-tax income, partially offset by the sale of leveraged lease assets in 2009.

Income from Discontinued Operations, net of tax

During 2008, we sold our investments in SAESA Group and Bioenergie. Income from Discontinued Operations relating to these investments for the three months ended September 30, 2008 totaled $180 million. See Note 3. Discontinued Operations and Dispositions for additional information.

For the nine months ended September 30, 2009 as compared to 2008

Operating Revenues increased $248 million due to

•

the absence of $485 million charge taken in June 2008, related to IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions, and

•

a $139 million increase due to sales and terminations of leveraged lease assets and other investments,

•

partially offset by a decrease of $350 million in generation revenues due to lower electricity prices and sales and higher unrealized MTM losses in 2009 and

•

lower leveraged lease revenues of $27 million due primarily to the sale of leveraged lease assets.

Operating Expenses

•

Energy Costs decreased $221 million, due primarily to lower fuel prices and lower fuel consumption and higher unrealized MTM gains.

•

Operation and Maintenance decreased $18 million due to

a decrease of $8 million in administrative costs due to the closure of our administrative office in Texas, and

a decrease of $10 million in outside service costs, wages, salaries and benefits.

•

Depreciation and Amortization experienced no material change.

Income from and Impairment on Equity Method Investments decreased by $9 million due primarily to a pre-tax write-down of GWF Energy in 2009, and reserves against GWF earnings.

Other Income and Deductions decreased by $43 million due primarily to a premium paid on the debt exchange with Power.

Interest Expense decreased $19 million due primarily to lower average debt balances.

Income Tax Expense increased $37 million due primarily to the sale of leverage lease assets in 2009 and the absence of tax benefits taken in 2008 related to an IRS refund claim.

Income from Discontinued Operations, net of tax

During 2008, we sold our investments in SAESA Group and Bioenergie. Income from Discontinued Operations relating to these investments for the nine months ended September 30, 2008 totaled $208 million. See Note 3. Discontinued Operations and Dispositions for additional information.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our three direct operating subsidiaries.

Operating Cash Flows

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

For the nine months ended September 30, 2009, our operating cash flow decreased by $251 million as compared to the same period in 2008. The net change was due primarily to net changes from our subsidiaries as discussed below.

Power

Power’s operating cash flow increased $210 million from $1.209 billion to $1.419 billion for the nine months ended September 30, 2009, as compared to the same period in 2008, primarily resulting from

a $256 million net reduction in spending on fuel inventories resulting from reduced pricing and demands, and

an increase of $267 million from net collections of counterparty receivables,

partially offset by a decrease of $111 million from net payments of counterparty payables,

a decrease $101 million in net cash collateral receipts, and

$92 million in increased pension fund contributions in 2009.

PSE&G

PSE&G’s operating cash flow decreased $123 million from $545 million to $422 million for the nine months ended September 30, 2009, as compared to the same period in 2008, due primarily to

$178 million in increased pension fund contributions, and

$111 million in lower cash collateral held by PSE&G, primarily under BGS contracts due to a decline in forward prices,

partially offset by $158 million in higher recovery of deferred energy costs.

Energy Holdings

Energy Holdings’ operating cash flow decreased $369 million from $(207) million to $(576) million for the nine months ended September 30, 2009, as compared to the same period in 2008. The decrease was mainly attributable to tax payments related to the termination of leveraged lease investments in 2009 and a $140 million tax deposit made with the IRS in 2009 compared to a tax deposit of $80 million in 2008. The decrease was partially offset by tax payments in 2008 related to the sales of SAESA and certain equity method investments.

Short-Term Liquidity

We have been managing our liquidity to assure that we continue to have sufficient access to cash to operate our businesses in the event the capital markets do not allow for near-term financing at reasonable terms. We are also closely monitoring the financial condition and concentration of lenders in our bank facilities. There is no provision in any of the credit facilities that would require other lenders in a facility to assume loan

commitments of any financial institution that fails to meet its loan commitments. As of September 30, 2009, no single institution represented more than 11% of the commitments in our credit facilities.

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of September 30, 2009 were as follows:


Company/Facility	As of September 30, 2009										Primary Purpose
Company/Facility	Total Facility			Usage			Available Liquidity			Expiration Date	Primary Purpose

	Millions

PSEG:
5-year Credit Facility (A)		$	1,000		$	187		$	813	Dec 2012	CP Support/Funding/ Letters of Credit
Uncommitted Bilateral Agreement			N/A			—			N/A	N/A	Funding

Total PSEG		$	1,000		$	187		$	813

Power:
5-year Credit Facility (A)		$	1,600		$	225		$	1,375	Dec 2012	Funding/Letters of Credit
2-year Credit Facility			350			—			350	July 2011	Funding
Bilateral Credit Facility			100			48			52	March 2010	Funding/Letters of Credit

Total Power		$	2,050		$	273		$	1,777

PSE&G:
5-year Credit Facility (A)		$	600		$	73		$	527	June 2012	CP Support/Funding/ Letters of Credit
Uncommitted Bilateral Agreement			N/A			—			N/A	N/A	Funding

Total PSE&G		$	600		$	73		$	527

(A)

In December 2011, facilities reduce by $47 million, $75 million, and $28 million for PSEG, Power and PSE&G, respectively.

On July 24, 2009, Power entered into a new $350 million syndicated credit facility that expires in July 2011. This new facility is available for funding the obligations of Power and its subsidiaries. Also on July 24, 2009, Energy Holdings terminated its $136 million syndicated credit facility. As noted above, the PSEG credit facilities can be used to support subsidiary liquidity needs, including those of Energy Holdings.

In September 2009, a $50 million bilateral credit facility and a $150 million bilateral credit facility expired at Power. We routinely review the liquidity requirements for Power. As of September 30, 2009, our total liquidity available was in excess of our anticipated maximum liquidity requirements through 2010. See Note 6. Commitments and Contingent Liabilities for additional information.

Long-Term Debt Financing

For a discussion of our long-term debt transactions during 2009, see Note 7. Changes in Capitalization.

Common Stock Dividends and Repurchases

Dividend payments on common stock for the three months ended September 30, 2009 were $0.3325 per share and totaled $168 million. Dividend payments on common stock for the three months ended September 30, 2008 were $0.3225 per share and totaled $164 million.

Dividend payments on common stock for the nine months ended September 30, 2009 were $0.9975 per share and totaled $505 million. Dividend payments on common stock for the nine months ended September 30, 2008 were $0.9675 per share and totaled $492 million.

In July 2008, our Board of Directors authorized the repurchase of up to $750 million of our common stock to be executed over 18 months beginning August 1, 2008. We are not obligated to acquire any specific number of shares and may suspend or terminate share repurchases at any time. We repurchased 2,382,200 shares of our common stock for $92 million under this authorization through September 30, 2008. No repurchases have been made since that date.

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

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. In March 2009, S&P affirmed the ratings and outlooks of PSEG, Power and PSE&G. In June 2009, Fitch affirmed the ratings and outlooks of PSEG, Power and PSE&G. In August, Moody’s upgraded the majority of senior secured debt ratings for investment grade regulated utilities. As a result, PSE&G’s senior secured rating improved from A3 to A2. In September and October, Moody’s published updated credit opinions for PSE&G, Power and PSEG which kept the ratings and outlooks unchanged.


	Moody’s(A)	S&P(B)	Fitch(C)
PSEG:
Outlook	Stable	Stable	Stable
Commercial Paper	P2	A2	F2
Power:
Outlook	Stable	Stable	Stable
Senior Notes	Baa1	BBB	BBB+
PSE&G:
Outlook	Stable	Stable	Stable
Mortgage Bonds	A2	A–	A
Preferred Securities	Baa3	BB+	BBB+
Commercial Paper	P2	A2	F2

(A)

Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.

(B)

S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

(C)

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

CAPITAL REQUIREMENTS

We expect that the majority of funding for our capital requirements over the next three years will come from internally generated funds. The balance will be provided by the issuance of debt at the respective subsidiary or project level and by equity contributions from us to our subsidiaries.

PSE&G’s projected construction and investment expenditures through 2011 are expected to increase by $1.5 billion as compared to amounts reported in our Annual Report on Form 10-K for the year ended December 31, 2008. The increase is due primarily to

•

$694 million of spending accelerated from later years under the Capital Economic Stimulus Program approved by the BPU in April 2009,

•

$166 million for the Energy Efficiency Economic Stimulus program approved by the BPU on July 1, 2009,

•

$418 million for Solar 4 All and $31 million for Demand Response, both of which were approved by the BPU on July 29, 2009, and

•

$100 million for transmission and distribution infrastructure and support investments.

These expenditures will be financed by a combination of external capital and internally generated funds and earn concurrent return on investment.

Other than this increase at PSE&G, our projected construction and investment expenditures through 2011 are consistent with the amounts disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008.

Power

During the nine months ended September 30, 2009, Power made $476 million of capital expenditures (excluding $156 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 6. Commitments and Contingent Liabilities.

PSE&G

During the nine months ended September 30, 2009, PSE&G made $580 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $580 million does not include expenditures for cost of removal, net of salvage, of $38 million, which are included in operating cash flows.

ACCOUNTING MATTERS

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

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Contracts

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

Value-at-Risk (VaR) Models

We use VaR models to assess the market risk of our commodity businesses. The portfolio VaR model includes our owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

We manage our exposure at the portfolio level, which consists of owned generation, electric load-serving contracts, fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While we manage our risk at the portfolio level, we also monitor separately the risk of our trading activities and hedges. Non-trading mark-to-market (MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The non-trading MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities. The MTM derivatives that are not hedges are included in the trading VaR.

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

As of each September 30, 2009 and December 31, 2008 trading VaR was less than $1 million.


For the Three Months Ended September 30, 2009	Trading VaR				Non-Trading MTM VaR
	Millions
95% confidence level,
Loss could exceed VaR one day in 20 days:
Period End		$	—	*		$	41
Average for the Period		$	1			$	36
High		$	2			$	47
Low		$	—	*		$	27
99.5% confidence level,
Loss could exceed VaR one day in 200 days:
Period End		$	1			$	65
Average for the Period		$	1			$	56
High		$	3			$	73
Low		$	1			$	42

less than $1 million

See Note 8. Financial Risk Management Activities for a discussion of credit risk.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer and Chief Financial Officer of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

Effective April 1, 2009, PSE&G replaced a stand alone legacy customer information system (CIS) with the SAP customer care system module (CCS). CCS is integrated with the existing series of SAP enterprise resource planning modules, including financial reporting, general ledger, property accounting, treasury, supply chain, payroll, human resources, and work management. CCS is used for customer bill production and integrates revenue, accounts receivable and cash management transactions with the general ledger module

The implementation of the CCS module and the related workflow capabilities has resulted in material changes to PSE&G’s internal controls over financial reporting (as that term is defined in Rules 13(a)-15(f) or 15(d)-15(f) under the Exchange Act). PSE&G is continuing to modify internal controls relating to the new system to replace and supplement existing internal controls over financial reporting, as appropriate. The system changes were undertaken to improve customer service and were not undertaken in response to any actual or perceived deficiencies in PSE&G’s internal control over financial reporting.

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. Other than the changes made related to the implementation of the CCS module and the related workflow capabilities at PSE&G, there have been no changes in internal control over financial reporting that occurred during the third quarter of 2009 that have materially affected, or are reasonably likely to materially affect, any registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the respective 2008 Annual Reports on Form 10-K of PSEG, Power and PSE&G and Item 1 of Part II of the respective Quarterly Reports on Form 10-Q of PSEG, Power and PSE&G for the quarters ended March 31, 2009 and June 30, 2009, see Note 6. Commitments and Contingent Liabilities and Item 5. Other Information, Federal Regulation.

RPM Auction

2008 Form 10-K, Page 43. Several state commissions, including the BPU and consumer advocates, filed a complaint at FERC in 2008 challenging the prices paid to generators, including us, as part of the RPM transitional auctions. FERC rejected the complaint and denied the RPM Buyer’s request for rehearing. In August 2009, both the BPU and the Maryland Public Service Commission filed an appeal of FERC’s rehearing order with the United States Court of Appeals for the Fourth Circuit. A decision is not expected until 2010. We cannot predict the outcome of this proceeding.

RPM Model

PJM FERC Filing to Prospectively Change Elements of RPM and FERC Order on PJM Filing

2008 Form 10-K, Page 43 and Second Quarter 2009 Form 10-Q, page 81. On September 1, 2009, PJM made two tariff filings with FERC proposing, among other things, a revised method for calculating the cost of new entry (CONE). Other major RPM design issues still being discussed at FERC as part of these filings include potential limits on the amount of capacity comprised of demand response/energy efficiency resources, elimination of a “hold-back” from the base auction of a portion of the capacity requirement, in order that prices will more accurately reflect demand, and the proper scope of locational delivery areas, to better reflect system constraints.

ITEM 1A. RISK FACTORS

The risk factors discussed below should be read in conjunction with, and update and supplement the risk factors discussed in PSEG’s, Power’s and PSE&G’s respective Annual Reports on Form 10-K for the year ended December 31, 2008 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009.

2008 Form 10-K, Page 32 and Second Quarter 2009 Form 10-Q, page 81. We are subject to numerous federal and state environmental laws and regulations that may significantly limit or affect our business, adversely impact our business plans or expose us to significant environmental fines and liabilities.

•

Greenhouse Gas Tailoring Rule—In September 2009, the EPA announced that it is proposing rules which could subject many power generating units and other facilities, including ours, to major Clean Air Act (CAA) permitting requirements for greenhouse gases (GHG), including CO₂. The proposed rule would also require installation of the best available control technologies whenever an applicable modification is made. EPA announced this rule because the agency expects to make an “endangerment” finding concerning GHG. If the EPA makes such a finding, then GHG would immediately become subject to other CAA requirements, including major facility permitting regarding the Prevention of Significant Deterioration (PSD) requirements for modifications that increase the emissions of GHG above levels established in the CAA. Those levels are extremely low and would potentially subject many facilities not regulated under the CAA to major permitting and PSD requirements. In order to avoid the applicability of these CAA provisions to these facilities, the EPA has proposed this rule to limit the applicability of the CAA requirements, including PSD, to larger industrial and commercial facilities, such as power generation units. Facilities emitting over the proposed new limit for CO2 equivalents would be subject to major CAA permitting requirements. Any modification which causes GHG emissions to increase by a significant level as proposed would require the owner to analyze the plant and install the best available control

technology to reduce GHG emissions. If adopted as proposed these requirements would apply to Power’s generating units and possibly to certain PSE&G facilities.

•

Coal Ash Management—Coal ash is produced as a byproduct of generation at our Mercer, Hudson and Bridgeport facilities. We currently have a program to beneficially reuse coal ash in other uses as currently allowed by Federal and state regulations. The EPA has announced that it is reconsidering whether coal ash should be re-regulated, potentially as a hazardous waste. The EPA has indicated that it intends to propose a rule by the end of 2009. Proposed regulations which more stringently regulate coal ash, including regulating coal ash as hazardous waste, could materially increase costs at Power’s coal assets.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In July 2008, our Board of Directors authorized the repurchase of up to $750 million of our Common Stock to be executed over 18 months beginning August 1, 2008. We are not obligated to acquire any specific number of shares and may suspend or terminate the share repurchases at any time. As of September 30, 2009, 2,382,200 shares were repurchased at a total price of $92 million.

There were no shares repurchased under the Board Authorized Program during the third quarter of 2009. All purchases in the third quarter were made to satisfy obligations as discussed below the table.


Three Months Ended September 30, 2009	Total Number of Shares Purchased (A)		Average Price Per Share			Total Number of Shares Purchased as Part of Publicly Announced Programs		Approximate Dollar Value of Shares that May Yet be Purchased Under Publicly Announced Programs
								Millions
July 1–July 31		101,000		$	29.41		N/A		$	658
August 1–August 31		190,000		$	31.13		N/A		$	658
September 1–September 30		60,000		$	33.72		N/A		$	658

(A)

Represents repurchase of shares in the open market to satisfy obligations under various equity compensation award grants.

ITEM 5. OTHER INFORMATION

Certain information reported under the 2008 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2008 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009. References are to the related pages on the Form 10-K or Form 10-Q as printed and distributed.

FEDERAL REGULATION

FERC

Transmission Regulation

2008 Form 10-K, Page 19. In accordance with our formula rate protocols, in October 2009, we filed our 2010 Annual Formula Rate Update with FERC. The update provides for approximately $23 million in increased revenues as part of our 2010 transmission rates.

Transmission Expansion

2008 Form 10-K, Page 20. In October 2009, PSE&G filed a petition with FERC seeking incentive rates for the planned Branchburg-Roseland-Hudson 500 kV transmission project (BRH Project). The BRH Project is a 500kV transmission line that will originate at PSE&G’s Branchburg 500 kV switching station, continue to a 500 kV switching station in Roseland, New Jersey, and end at a 500 kV switching station in Hudson County, New Jersey. PSE&G’s filing seeks the following incentives: (1) a return on equity (ROE) adder of 150 basis points above the Company’s base ROE; (2) recovery of one hundred percent of Construction Work in Progress in rate base; and (3) authorization to recover 100% of all prudently-incurred development

and construction costs if the project is abandoned or cancelled, in whole or in part, for reasons beyond the control of PSE&G.

The estimated cost of the project is approximately $1.1 billion. PJM has specified a June, 2013 in-service date.

PJM Transmission Rate Design

In 2007, FERC addressed the issue of how transmission rates, paid by PJM transmission customers and ultimately paid by our retail customers, should be designed in PJM. FERC ruled that the cost of new high voltage (500 kV and above) transmission facilities in PJM would be socialized and paid for by all transmission customers on a pro-rata basis, which share is calculated annually based upon a zone’s load ratio share within PJM. For all existing facilities, costs would be allocated using the pre-existing zonal rate design. For new lower voltage transmission facilities, costs would be allocated using a “beneficiary pays” approach. This FERC decision was subsequently upheld on rehearing but was then appealed by other parties to the United States Court of Appeals for the Seventh Circuit.

In August 2009, the Court ruled that with respect to new 500 kV and higher centrally-planned facilities, FERC had not adequately justified its decision to socialize these costs. Certain parties sought rehearing of the Court’s decision, which requests have been denied. The case has now been remanded to the FERC for further proceedings. FERC will either resolve this matter through settlement discussions or through issuance of a decision. Unless FERC acts to change its cost allocation mechanism, the current allocation for new 500 kV and higher centrally-planned projects will remain in place.

U.S. Department of Energy (DOE) Congestion Study—National Interest Electric Transmission Corridors and FERC Back-Stop Siting Authority

2008 Form 10-K, Page 20, First Quarter 2009 Form 10-Q, page 64 and Second Quarter 2009 Form 10-Q, page 82. In October 2007, the DOE acted to designate transmission corridors within critical congestion areas. One of the designated corridors is the Mid-Atlantic Area National Corridor. Thus, entities seeking to build transmission within the Mid-Atlantic Area Corridor, which includes New Jersey, most of Pennsylvania and New York, may be able to use FERC’s back-stop siting authority in the future under certain circumstances, if necessary, to site transmission, including with respect to the Susquehanna-Roseland line. Within the next few months, the DOE is expected to issue a new Congestion Study, as required by law, which may designate additional corridors and/or revise the existing corridors.

In February 2009, the United States Court of Appeals for the Fourth Circuit narrowed the scope of FERC’s back-stop siting authority. FERC sought reconsideration of this Court of Appeals decision, which was subsequently denied. The Fourth Circuit decision was appealed to the United States Supreme Court in September 2009.

Nuclear Regulatory Commission (NRC)

2008 Form 10-K, Page 20. In August 2009, we submitted applications to the NRC to extend the operating licenses of our Salem and Hope Creek Generating Stations for 20 years. Salem Unit 1’s current 40 year operating license expires in 2016 and Unit 2’s operating license expires in 2020. Hope Creek’s operating license expires in 2026. The NRC is expected to spend up to 30 months to review our applications before making a decision.

STATE REGULATION

Rates

Electric and Gas Base Rate Case

Second Quarter 2009 Form 10-Q, page 83. In May 2009, we filed a Petition with the BPU for an increase in electric and gas distribution base rates. The amounts requested are $134 million and $97 million for electric and gas respectively, to be effective March 1, 2010. An update was filed September 25, 2009

requesting $147 million and $106 million for electric and gas respectively. The matter is pending with a decision expected in early 2010.

SBC

2008 Form 10-K, Page 22. In February 2009, we filed a petition requesting a decrease in our electric SBC/NGC rates of $18.9 million and an increase in gas SBC rates of $3.7 million. In July 2009, a revision was filed requesting an increase in SBC/NGC rates of $104 million and $15 million for electric and gas respectively. Upon approval by the BPU, these revised rates will be effective January 2010.

Universal Service Fund (USF) Filing

2008 Form 10-K, Page 22. The USF is an energy assistance program mandated by the BPU under the Competition Act to provide payment assistance to low-income customers. The Lifeline program is a separately mandated energy assistance program to provide payment assistance to elderly and disabled customers. On June 30, 2009, the State’s electric and gas public utilities filed to reset statewide rates for the USF and the Lifeline program. The filed rates were subsequently updated and approved effective October 12, 2009. The revised statewide electric rates will recover $136 million while the revised statewide gas rates will recover $60 million. As part of this filing, the rates for the Lifeline program will recover a total of $77 million, $52 million for the electric program and $25 million for the gas program. PSE&G’s USF rates will recover $75 million and $38 million for electric and gas respectively. PSE&G’s Lifeline rates will recover $29 million and $16 million for electric and gas respectively. PSE&G earns no margin on the collection of the USF and Lifeline programs, resulting in no impact on Net Income.

Energy Supply

BGSS

2008 Form 10-K, Page 2, First Quarter 2009 Form 10-Q, page 65 and Second Quarter 2009 Form 10-Q, page 83. In May 2009, PSE&G made its Annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $133 million, excluding Sales and Use Tax, to be effective October 1, 2009. This represents a reduction of approximately 7% for a typical residential gas heating customer. The BPU approved the new lower BGSS rate on September 16, 2009 and it became effective immediately on a provisional basis.

Energy Policy

Solar Initiatives

2008 Form 10-K, Page 23, First Quarter 2009 Form 10-Q, page 65 and Second Quarter 2009 Form 10-Q, page 83. We are investing approximately $105 million over two years in a pilot program to help finance the installation of 30 MW of solar systems throughout our electric service area by providing loans to customers for the installation of solar photovoltaic (PV) systems on their premises. As of October 23, 2009, we have provided approximately $22 million in loans for approximately 6 MW of solar systems.

In July 2009, the BPU approved our Solar 4 All Program. Under this approved program, we are investing approximately $515 million to develop 80MW of utility-owned solar PV systems over a four-year horizon. The program consists of above 500 kW solar PV systems installed on PSE&G-owned property (25MW), small solar panels installed on distribution system poles (40MW) and PV systems installed on third-party sites in our electric service territory.

Susquehanna-Roseland BPU Petition

2008 Form 10-K, Page 25 and First Quarter 2009 Form 10-Q, page 65 and Second Quarter 2009 Form 10-Q, page 83. In January 2009, we filed a Petition with the BPU seeking authorization from the BPU to construct the New Jersey portion of the Susquehanna-Roseland line. The New Jersey portion of the line spans approximately 45 miles and crosses through 16 municipalities. The Petition seeks a finding from the BPU that municipal land use and zoning ordinances do not apply to this line. A procedural schedule has been established, and both the discovery phase and the public hearing phase of the process have been

completed. Under the procedural schedule, evidentiary hearings will occur in November, with a decision to be rendered thereafter although currently there is no decision date fixed in the procedural schedule.

In June 2009, the New Jersey Highlands Council provided a favorable applicability determination with respect to the portion of the project crossing the Highlands region. Approval by the New Jersey Department of Environmental Protection of the Highlands Council determination is now pending. We are in the process of seeking to obtain all other necessary environmental permits for the project including from the National Park Service, as may be necessary. Failure to obtain all permits on a timely basis could delay the project.

Compliance

Management/Affiliate Audits

By law, the BPU periodically conducts audits of New Jersey’s investor-owned utilities, including PSE&G, with respect to the effectiveness of management and transactions among affiliates. In August 2009, a firm was chosen to perform the PSE&G comprehensive management and affiliate transactions audits (Audits) following a competitive bidding process. The Audit process began in October 2009 and is expected to be completed as early as July 2010. The auditors will ultimately produce a report that can be expected to include recommendations for changes to practices at PSE&G and affiliates, upon which PSE&G will have an opportunity to provide comments and that the BPU may enforce in whole or in part by Order.

ENVIRONMENTAL MATTERS

Nuclear Fuel Disposal

2008 Form 10-K, Page 28. The Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund. On September 30, 2009, we signed an agreement with the DOE applicable to Salem and Hope Creek under which we will be reimbursed for past and future reasonable and allowable costs resulting from the DOE’s delay in accepting spent nuclear fuel for permanent disposition. For additional information, see Note 6. Commitments and Contingent Liabilities.

ITEM 6. EXHIBITS

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


a.	PSEG:
	Exhibit 12:	Computation of Ratios of Earnings to Fixed Charges
	Exhibit 31:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (1934 Act)
	Exhibit 31.1:	Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
	Exhibit 32:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 32.1:	Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 101.INS:	XBRL Instance Document*
	Exhibit 101.SCH:	XBRL Taxonomy Extension Schema*
	Exhibit 101.CAL:	XBRL Taxonomy Extension Calculation Linkbase*
	Exhibit 101.LAB:	XBRL Taxonomy Extension Labels Linkbase*
	Exhibit 101.PRE:	XBRL Taxonomy Extension Presentation Linkbase*
	Exhibit 101.DEF:	XBRL Taxonomy Extension Definition Document*

* XBRL information is furnished, not filed.


b.	Power:
	Exhibit 12.1:	Computation of Ratios of Earnings to Fixed Charges
	Exhibit 31.2:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
	Exhibit 31.3:	Certification Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
	Exhibit 32.2:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 32.3:	Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
c.	PSE&G:
	Exhibit 12.2:	Computation of Ratios of Earnings to Fixed Charges
	Exhibit 12.3:	Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
	Exhibit 31.4:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
	Exhibit 31.5:	Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
	Exhibit 32.4:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 32.5:	Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

SIGNATURE

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

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: October 30, 2009

SIGNATURE

PSEG POWER LLC
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: October 30, 2009

SIGNATURE

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: October 30, 2009