Edgar Filing: PUBLIC SERVICE ELECTRIC & GAS CO

3B2 EDGAR HTML -- c57480_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 March 31, 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). Yes £ No £

(Cover continued on next page)

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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 April 15, 2009, Public Service Enterprise Group Incorporated had outstanding 505,985,764 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 April 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.

TABLE OF CONTENTS


		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		15
	Note 4. Pension and Other Postretirement Benefits (OPEB)		16
	Note 5. Commitments and Contingent Liabilities		17
	Note 6. Changes in Capitalization		28
	Note 7. Financial Risk Management Activities		28
	Note 8. Fair Value Measurements		35
	Note 9. Other Income and Deductions		40
	Note 10. Income Taxes		40
	Note 11. Comprehensive Income (Loss), Net of Tax		41
	Note 12. Earnings Per Share		42
	Note 13. Financial Information by Business Segments		43
	Note 14. Related-Party Transactions		43
	Note 15. Guarantees of Debt		46
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		48
	Overview of 2009 and Future Outlook		48
	Results of Operations		50
	Liquidity and Capital Resources		57
	Capital Requirements		60
	Accounting Matters		60
Item 3.	Qualitative and Quantitative Disclosures About Market Risk		60
Item 4.	Controls and Procedures		62
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		63
Item 1A.	Risk Factors		63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		63
Item 4.	Submission of Matters to a Vote of Security Holders		64
Item 5.	Other Information		64
Item 6.	Exhibits		66
	Signatures		67

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 5. 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, policies and regulation, including market structures and rules.

•

New energy legislation.

•

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 regulations that could increase our costs or limit operations of our generating units.

•

Changes in nuclear regulation and/or developments in the nuclear power industry generally, that could limit operations of our nuclear generating units.

•

Actions or activities at one of our nuclear units 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.

•

Increases 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.

•

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.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)


	For the Three Months Ended March 31,
	2009				2008
OPERATING REVENUES		$	3,921			$	3,792
OPERATING EXPENSES
Energy Costs			2,068				2,119
Operation and Maintenance			675				627
Depreciation and Amortization			207				192
Taxes Other Than Income Taxes			44				43

Total Operating Expenses			2,994				2,981

OPERATING INCOME			927				811
Income from Equity Method Investments			10				12
Other Income			71				93
Other Deductions			(115	)			(95	)
Interest Expense			(145	)			(153	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			748				668
Income Tax Expense			(304	)			(233	)

INCOME FROM CONTINUING OPERATIONS			444				435
Income from Discontinued Operations, net of tax expense of $6			—				13

NET INCOME		$	444			$	448

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC			505,986				508,490

DILUTED			506,548				510,107

EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS		$	0.88			$	0.86
NET INCOME		$	0.88			$	0.88

DILUTED
INCOME FROM CONTINUING OPERATIONS		$	0.88			$	0.85
NET INCOME		$	0.88			$	0.88

DIVIDENDS PAID PER SHARE OF COMMON STOCK		$	0.3325			$	0.3225

See Notes to Condensed Consolidated Financial Statements.

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


	March 31, 2009				December 31, 2008
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	1,232			$	321
Accounts Receivable, net of allowances of $72 in 2009 and $66 in 2008			1,285				1,398
Unbilled Revenues			521				454
Fuel			520				938
Materials and Supplies			326				317
Prepayments			81				150
Restricted Funds			15				118
Derivative Contracts			207				237
Other			91				66

Total Current Assets			4,278				3,999

PROPERTY, PLANT AND EQUIPMENT			21,172				20,818
Less: Accumulated Depreciation and Amortization			(6,531	)			(6,385	)

Net Property, Plant and Equipment			14,641				14,433

NONCURRENT ASSETS
Regulatory Assets			6,236				6,352
Long-Term Investments			2,570				2,695
Nuclear Decommissioning Trust (NDT) Funds			954				970
Other Special Funds			136				133
Goodwill and Other Intangibles			104				69
Derivative Contracts			155				160
Other			228				238

Total Noncurrent Assets			10,383				10,617

TOTAL ASSETS		$	29,302			$	29,049

See Notes to Condensed Consolidated Financial Statements.

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


	March 31, 2009				December 31, 2008
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	1,055			$	1,033
Commercial Paper and Loans			—				19
Accounts Payable			925				1,227
Derivative Contracts			374				356
Accrued Interest			160				99
Accrued Taxes			387				8
Clean Energy Program			145				142
Obligation to Return Cash Collateral			105				102
Other			447				424

Total Current Liabilities			3,598				3,410

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)			3,925				3,865
Regulatory Liabilities			415				355
Asset Retirement Obligations			586				576
Other Postretirement Benefit (OPEB) Costs			970				975
Accrued Pension Costs			962				1,196
Clean Energy Program			489				532
Environmental Costs			739				743
Derivative Contracts			135				164
Long-Term Accrued Taxes			1,200				1,241
Other			135				125

Total Noncurrent Liabilities			9,556				9,772

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)

CAPITALIZATION LONG-TERM DEBT
Long-Term Debt			6,521				6,621
Securitization Debt			1,297				1,342
Project Level, Non-Recourse Debt			41				42

Total Long-Term Debt			7,859				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			4,764				4,756
Treasury Stock, at cost, 2009—27,570,896 shares; 2008—27,538,762 shares			(583	)			(581	)
Retained Earnings			4,049				3,773
Accumulated Other Comprehensive Loss			(31	)			(177	)

Total Common Stockholders’ Equity			8,199				7,771
Noncontrolling Interest—Equity Investments			10				11

Total Capitalization			16,148				15,867

TOTAL LIABILITIES AND CAPITALIZATION		$	29,302			$	29,049

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)


	For the Three Months Ended March 31,
	2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	444			$	448
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization			207				193
Amortization of Nuclear Fuel			29				24
Provision for Deferred Income Taxes (Other than Leases) and ITC			19				3
Non-Cash Employee Benefit Plan Costs			87				42
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes			(106	)			(26	)
Undistributed Earnings from Affiliates			(7	)			(21	)
Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives			(48	)			(20	)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs			60				(38	)
Over Recovery of Societal Benefits Charge (SBC)			44				31
Cost of Removal			(9	)			(9	)
Net Realized Losses and Expense from NDT Funds			39				8
Net Change in Certain Current Assets and Liabilities			927				400
Employee Benefit Plan Funding and Related Payments			(281	)			(24	)
Other			(16	)			32

Net Cash Provided By Operating Activities			1,389				1,043

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(402	)			(323	)
Proceeds from the Sale of Capital Leases and Investments			140				40
Proceeds from NDT Funds Sales			559				623
Investment in NDT Funds			(568	)			(631	)
Restricted Funds			105				21
NDT Funds Interest and Dividends			10				11
Other			(9	)			(2	)

Net Cash Used In Investing Activities			(165	)			(261	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans			(19	)			63
Issuance of Long-Term Debt			209				300
Payment of Long-Term Debt			(10	)			(1,013	)
Payment of Non-Recourse Debt			(281	)			(13	)
Payment of Securitization Debt			(42	)			(40	)
Net Premium Paid on Early Extinguishment of Debt			—				(48	)
Cash Dividends Paid on Common Stock			(168	)			(164	)
Other			(2	)			4

Net Cash Used In Financing Activities			(313	)			(911	)

Net Increase (Decrease) in Cash and Cash Equivalents			911				(129	)
Cash and Cash Equivalents at Beginning of Period			321				380

Cash and Cash Equivalents at End of Period		$	1,232			$	251

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	9			$	133
Interest Paid, Net of Amounts Capitalized		$	76			$	89

See Notes to Condensed Consolidated Financial Statements.

PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)


	For the Three Months Ended March 31,
	2009				2008
OPERATING REVENUES		$	2,374			$	2,375
OPERATING EXPENSES
Energy Costs			1,462				1,589
Operation and Maintenance			258				239
Depreciation and Amortization			47				38

Total Operating Expenses			1,767				1,866

OPERATING INCOME			607				509
Other Income			70				86
Other Deductions			(110	)			(91	)
Interest Expense			(43	)			(42	)

INCOME BEFORE INCOME TAXES			524				462
Income Tax Expense			(206	)			(187	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	318			$	275

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

PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)


	March 31, 2009				December 31, 2008
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	15			$	20
Accounts Receivable			360				472
Accounts Receivable—Affiliated Companies, net			486				732
Short-Term Loan to Affiliate			951				—
Fuel			520				938
Materials and Supplies			237				233
Derivative Contracts			182				225
Restricted Funds			12				21
Prepayments			36				53
Other			19				11

Total Current Assets			2,818				2,705

PROPERTY, PLANT AND EQUIPMENT			7,604				7,441
Less: Accumulated Depreciation and Amortization			(2,040	)			(1,960	)

Net Property, Plant and Equipment			5,564				5,481

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds			954				970
Goodwill			16				16
Other Intangibles			78				43
Other Special Funds			27				27
Derivative Contracts			140				143
Other			69				74

Total Noncurrent Assets			1,284				1,273

TOTAL ASSETS		$	9,666			$	9,459

LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	250			$	250
Accounts Payable			500				752
Short-Term Loan from Affiliate			—				3
Derivative Contracts			359				338
Accrued Interest			84				35
Other			173				155

Total Current Liabilities			1,366				1,533

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)			441				335
Asset Retirement Obligations			341				334
Other Postretirement Benefit (OPEB) Costs			121				118
Derivative Contracts			95				111
Accrued Pension Costs			303				374
Environmental Costs			54				54
Long-Term Accrued Taxes			17				16
Other			57				47

Total Noncurrent Liabilities			1,429				1,389

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
LONG-TERM DEBT
Total Long-Term Debt			2,862				2,653

MEMBER’S EQUITY
Contributed Capital			2,000				2,000
Basis Adjustment			(986	)			(986	)
Retained Earnings			2,981				2,988
Accumulated Other Comprehensive Income (Loss)			14				(118	)

Total Member’s Equity			4,009				3,884

TOTAL LIABILITIES AND MEMBER’S EQUITY		$	9,666			$	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 Three Months Ended March 31,
	2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	318			$	275
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization			47				38
Amortization of Nuclear Fuel			29				24
Interest Accretion on Asset Retirement Obligations			7				6
Provision for Deferred Income Taxes and ITC			14				19
Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives			(53	)			(23	)
Non-Cash Employee Benefit Plan Costs			19				6
Net Realized Losses and Expense from NDT Funds			39				8
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies			414				405
Margin Deposit Asset			7				(65	)
Margin Deposit Liability			151				—
Accounts Receivable			218				7
Accounts Payable			(208	)			(12	)
Accounts Receivable/Payable-Affiliated Companies, net			325				189
Accrued Interest Payable			49				47
Other Current Assets and Liabilities			(37	)			(3	)
Employee Benefit Plan Funding and Related Payments			(78	)			—
Other			2				17

Net Cash Provided By Operating Activities			1,263				938

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(207	)			(174	)
Short-Term Loan—Affiliated Company, net			(951	)			(407	)
Proceeds from NDT Funds Sales			559				623
NDT Funds Interest and Dividends			10				11
Investment in NDT Funds			(568	)			(631	)
Restricted Funds			9				7
Other			(1	)			(6	)

Net Cash Used In Investing Activities			(1,149	)			(577	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt			209				—
Cash Dividend Paid			(325	)			(125	)
Short-Term Loan—Affiliated Company, net			(3	)			(238	)

Net Cash Used In Financing Activities			(119	)			(363	)

Net Decrease in Cash and Cash Equivalents			(5	)			(2	)
Cash and Cash Equivalents at Beginning of Period			20				11

Cash and Cash Equivalents at End of Period		$	15			$	9

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	1			$	19
Interest Paid, Net of Amounts Capitalized		$	3			$	3

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 March 31,
	2009				2008
OPERATING REVENUES		$	2,735			$	2,618
OPERATING EXPENSES
Energy Costs			1,859				1,793
Operation and Maintenance			395				360
Depreciation and Amortization			149				143
Taxes Other Than Income Taxes			44				43

Total Operating Expenses			2,447				2,339

OPERATING INCOME			288				279
Other Income			1				5
Other Deductions			(1	)			(1	)
Interest Expense			(79	)			(81	)

INCOME BEFORE INCOME TAXES			209				202
Income Tax Expense			(85	)			(65	)

NET INCOME			124				137
Preferred Stock Dividends			(1	)			(1	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	123			$	136

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)


	March 31, 2009				December 31, 2008
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	45			$	91
Accounts Receivable, net of allowances of $71 in 2009 and $65 in 2008, respectively			928				909
Unbilled Revenues			521				454
Materials and Supplies			65				61
Prepayments			10				45
Restricted Funds			3				1
Derivative Contracts			1				—
Deferred Income Taxes			54				52

Total Current Assets			1,627				1,613

PROPERTY, PLANT AND EQUIPMENT			12,453				12,258
Less: Accumulated Depreciation and Amortization			(4,184	)			(4,122	)

Net Property, Plant and Equipment			8,269				8,136

NONCURRENT ASSETS
Regulatory Assets			6,236				6,352
Long-Term Investments			165				158
Other Special Funds			47				46
Other			100				101

Total Noncurrent Assets			6,548				6,657

TOTAL ASSETS		$	16,444			$	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)


	March 31, 2009			December 31, 2008
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	550		$	248
Commercial Paper and Loans			—			19
Accounts Payable			322			336
Accounts Payable—Affiliated Companies, net			774			763
Accrued Interest			59			58
Accrued Taxes			46			3
Clean Energy Program			145			142
Derivative Contracts			15			14
Obligation to Return Cash Collateral			105			102
Other			282			227

Total Current Liabilities			2,298			1,912

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC			2,544			2,533
Other Postretirement Benefit (OPEB) Costs			804			813
Accrued Pension Costs			498			634
Regulatory Liabilities			415			355
Clean Energy Program			489			532
Environmental Costs			685			689
Asset Retirement Obligations			243			240
Derivative Contracts			40			53
Long-Term Accrued Taxes			85			82
Other			32			31

Total Noncurrent Liabilities			5,835			5,962

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)

CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt			3,164			3,463
Securitization Debt			1,297			1,342

Total Long-Term Debt			4,461			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

COMMON STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized;
issued and outstanding, 2009 and 2008—132,450,344 shares			892			892
Contributed Capital			170			170
Basis Adjustment			986			986
Retained Earnings			1,720			1,597
Accumulated Other Comprehensive Income			2			2

Total Common Stockholder’s Equity			3,770			3,647

Total Capitalization			8,311			8,532

TOTAL LIABILITIES AND CAPITALIZATION		$	16,444		$	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 Three Months Ended March 31,
	2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	124			$	137
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization			149				143
Provision for Deferred Income Taxes and ITC			6				(13	)
Non-Cash Employee Benefit Plan Costs			59				33
Cost of Removal			(9	)			(9	)
Over Recovery of Electric Energy Costs (BGS and NTC)			20				15
Over (Under) Recovery of Gas Costs			40				(53	)
Over Recovery of SBC			44				31
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues			(86	)			(130	)
Materials and Supplies			(4	)			(6	)
Prepayments			35				50
Accrued Taxes			43				37
Accrued Interest			1				(3	)
Accounts Payable			(14	)			(38	)
Accounts Receivable/Payable-Affiliated Companies, net			(62	)			(20	)
Obligation to Return Cash Collateral			3				23
Other Current Assets and Liabilities			51				75
Employee Benefit Plan Funding and Related Payments			(172	)			(19	)
Other			(12	)			8

Net Cash Provided By Operating Activities			216				261

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(194	)			(145	)
Other			(6	)			—

Net Cash Used In Investing Activities			(200	)			(145	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt			(19	)			63
Issuance of Long-Term Debt			—				300
Redemption of Long-Term Debt			—				(401	)
Redemption of Securitization Debt			(42	)			(40	)
Deferred Issuance Costs			—				(1	)
Preferred Stock Dividends			(1	)			(1	)

Net Cash Used In Financing Activities			(62	)			(80	)

Net Increase (Decrease) In Cash and Cash Equivalents			(46	)			36
Cash and Cash Equivalents at Beginning of Period			91				32

Cash and Cash Equivalents at End of Period		$	45			$	68

Supplemental Disclosure of Cash Flow Information:
Income Taxes Received		$	(12	)		$	—
Interest Paid, Net of Amounts Capitalized		$	75			$	81

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:

•

PSEG Power LLC (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 function 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.

•

Public Service Electric and Gas Company (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 the FERC.

•

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. Energy Holdings’ subsidiaries are subject to regulation by the FERC and the states or countries in which they operate.

•

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 Reports on Form 10-K for the year ended December 31, 2008.

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.

Reclassifications

A reclassification was made to PSEG’s Condensed Consolidated Balance Sheet as of December 31, 2008 to conform to the 2009 presentation. In accordance with the adoption of a new accounting standard in 2009, $11 million of minority interests was reclassified from Other Noncurrent Liabilities to Noncontrolling Interests. See Note 2. Recent Accounting Standards for additional information.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 2. Recent Accounting Standards

The following is a summary of new accounting guidance adopted in 2009 and guidance issued but not yet adopted that could impact our businesses. We do not anticipate that any of the guidance adopted in 2009 will have a material impact on our financial statements.

Accounting standards adopted in 2009

Statement of Financial Accounting Standards (SFAS) No. 141 (revised 2007), “Business Combinations” (SFAS 141(R))

•

changes financial accounting and reporting of business combination transactions

•

requires all assets acquired and liabilities assumed in a business combination to be measured at their acquisition date fair value, with limited exceptions

•

requires acquisition-related costs and certain restructuring costs to be recognized separately from the business combination

•

applies to all transactions and events in which an entity obtains control of one or more businesses of an acquiree.

We adopted SFAS 141(R) effective January 1, 2009. Any new business combination transactions will be accounted for under this guidance.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin (ARB) No. 51” (SFAS 160)

•

changes the financial reporting relationship between a parent and non-controlling interests

•

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

•

requires net income attributable to the non-controlling interest to be shown on the face of the income statement in addition to net income attributable to the controlling interest

•

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

We adopted SFAS 160 effective January 1, 2009 and revised our balance sheet presentation as required by the standard. The income statement impact is immaterial.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (SFAS 161)

•

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.

We adopted SFAS 161 effective January 1, 2009.

Accounting standards to be adopted effective April 1, 2009

FASB Staff Position (FSP) FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2)

•

issued by the FASB in April 2009

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

•

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

An entity has the 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, and

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 and/ or other comprehensive income.

We are currently assessing the impact of this standard on our financial statements.

FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)

•

issued by the FASB in April 2009

•

requires a publicly traded company to disclose 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 fair value, and

changes in methods and significant assumptions, if any.

Upon adoption, the standard will impact our interim financial statements by requiring additional fair value information.

FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP FAS 157-4)

•

issued by the FASB in April 2009

•

provides guidance:

to determine if there has been a significant decrease in the volume and level of activity for the asset or liability, and

to estimate fair values, when transactions or quoted process are not determinative of fair value

•

requires management to use judgment to determine whether a market is distressed or not orderly, even if there has been a significant decrease in the volume and level of activity for the asset or liability.

Upon adoption, we do not anticipate that this standard will have a material impact on our financial statements.

Accounting standard to be adopted for 2009 year-end reporting

FSP FAS 132(R)-1, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (FSP FAS 132(R)-1)

•

issued by the FASB in December 2008

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

•

requires additional disclosures about the fair value of plan assets of a defined benefit 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 are currently assessing the potential impact of this standard 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 ended March 31, 2008, which were reclassified to Discontinued Operations, are summarized below:


	Quarter Ended March 31, 2008
	(Millions)
Operating Revenues		$	11
Income Before Income Taxes		$	1
Net Loss		$	(1	)

SAESA Group

In July 2008, Energy Holdings sold its investment in the SAESA Group for a total purchase price 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 ended March 31, 2008, which were reclassified to Discontinued Operations, are summarized below:


	Quarter Ended March 31, 2008
	(Millions)
Operating Revenues		$	186
Income Before Income Taxes		$	20
Net Income		$	14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Dispositions

PPN Power Generating Company Limited (PPN)

In March 2009, Energy Holdings entered into an agreement to sell its 20% ownership interest in PPN, which owns and operates a 330 MW naphtha and natural gas-fired combined cycle plant in Tamil Nadu, India. The sale is expected to close in the second quarter. The sale price is expected to be approximately $15 million, which is the book value of the investment as of March 31, 2009. This amount is included in Other Current Assets in PSEG’s Condensed Consolidated Balance Sheet.

Leveraged Leases

In February 2009, Energy Holdings sold its interest in the Westland gas distribution facility leveraged lease and its interest in the Whitehorn gas turbine facility leveraged lease for an after-tax gain of $8 million.

In January 2009, Energy Holdings sold its 51% interest in the EPZ Swentibold facility leveraged lease and its interest in the Dutch Rail Locomotives leveraged lease for an after-tax gain of $4 million.

Note 4. 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 Quarters Ended March 31,								OPEB Quarters Ended March 31,
	2009				2008				2009				2008
	(Millions)
Components of Net Periodic Benefit Cost:
Service Cost		$	19			$	19			$	3			$	4
Interest Cost			59				57				18				18
Expected Return on Plan Assets			(54	)			(72	)			(3	)			(4	)
Amortization of Net
Transition Obligation			—				—				7				7
Prior Service Cost			2				2				4				3
Actuarial Loss (Gain)			28				3				(1	)			—

Net Periodic Benefit Cost		$	54			$	9			$	28			$	28
Effect of Regulatory Asset			—				—				5				5

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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


	Pension Benefits Quarters Ended March 31,						OPEB Quarters Ended March 31,
	2009			2008			2009			2008
	(Millions)
Power		$	16		$	3		$	3		$	3
PSE&G			30			4			29			29
Other			8			2			1			1

Total Benefit Costs		$	54		$	9		$	33		$	33

During the quarter ended March 31, 2009, PSEG contributed $257 million of the approximately $370 million it expects to contribute into its pension plans in the calendar year 2009. During the first quarter of 2009, PSEG contributed $8 million of its $11 million planned contribution for the calendar year 2009 into its postretirement healthcare plan.

Note 5. 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 a liability for the face value of the outstanding guarantees, its subsidiaries would have to fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee and all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). The probability of this is highly unlikely due to offsetting positions within the portfolio. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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


	March 31, 2009				December 31, 2008
	(Millions)
Face value of outstanding guarantees		$	2,041			$	1,856
Exposure under current guarantees		$	589			$	585
Letters of Credit Margin Posted		$	128			$	201
Letters of Credit Margin Received		$	258			$	250
Net Cash Received
Counterparty Cash Margin Deposited		$	3			$	3
Counterparty Cash Margin (Received)			(232	)			(81	)
Net Broker Balance (Received) Deposited			(81	)			(74	)

Total Net Cash Received		$	(310	)		$	(152	)

Power nets the fair value of cash collateral receivables and payables with the corresponding net energy contract balances. As a result, of the net cash received, Power has included $282 million and $112 million in its corresponding net derivative contract positions as of March 31, 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 further performance assurance. As of March 31, 2009, if Power were to lose its investment grade rating, additional collateral of approximately $1.2 billion could be required. As of March 31, 2009, there was $2.7 billion of available liquidity under PSEG and Power’s credit facilities that could be used to post collateral. In addition to amounts in the table above, Power had posted $105 million and $121 million in letters of credit as of March 31, 2009 and December 31, 2008, respectively, to support various other contractual and environmental obligations. The available liquidity as of March 31, 2009 does not include $150 million under a bilateral credit facility that Power executed in April 2009 to replace a credit agreement that expired during March 2009.

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) and has undertaken a study of the river. The study area includes 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. 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. Power assumed any environmental liabilities of the Essex Site when it was transferred from PSE&G, and PSE&G obtained releases and indemnities for liabilities arising out of the former generating station when it was sold. The costs associated with the MGP Remediation Program have historically been recovered through the Societal Benefits Clause (SBC) charges to PSE&G ratepayers.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The EPA has indicated that it believed hazardous substances had been released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site), which also includes facilities for PSE&G’s ongoing gas operations. In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study will greatly exceed its original estimated cost of $20 million. 73 PRPs, including Power and PSE&G, have agreed to assume responsibility for the study and to divide the associated costs among themselves according to a mutually agreed-upon formula. The PRP group is presently executing the study. The percentage of costs allocable to Power and PSE&G has varied depending on the number of PRPs funding the study and currently is approximately 6% of the study cost, approximately 80% of which is attributable to PSE&G’s former MGP sites and approximately 20% 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 contamination cleanup in the lower eight miles of the Passaic River, with estimated costs ranging from $900 million to $2.3 billion, in addition to a “No Action” alternative. 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 later in 2009.

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. The work will cost an estimated $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.

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and related companies in New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects on the Passaic River of the PRP’s former operations which resulted in the discharge of hazardous substances. On February 4,2009, third-party complaints were filed against some 320 third-party defendants, including Power and PSE&G, claiming that each of the third-party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances it discharged into the Passaic River and seeking statutory contribution and contribution under the New Jersey Spill Compensation and Control Act (Spill Act) to recover past and future removal costs and damages.

In 2003, the NJDEP directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the Spill Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent a letter 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 companies 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.

Newark Bay Study Area

The EPA established the Newark Bay Study Area, which it defined 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 this 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 is conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG is participating in and partially funding the 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, Newark Bay Study Area or other 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 fourth quarter of 2008, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $709 million and $820 million from December 31, 2008 through 2021. Since no amount within the range was considered to be most likely, PSE&G recorded a liability of $709 million as of December 31, 2008. As of March 31, 2009, PSE&G’s remaining accrual was $705 million. Of this amount, $20 million was recorded in Other Current Liabilities and $685 million was reflected as Environmental Costs in Noncurrent Liabilities. As such, PSE&G has recorded a $705 million Regulatory Asset with respect to these costs.

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

The PSD/NSR regulations, promulgated under the Clean Air Act, require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.

In November 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at Power’s Mercer, Hudson and Bergen generating stations. Under this agreement, Power is 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 and to repower Bergen Unit 2 utilizing low-emission combined cycle combustion turbine technology.

Pursuant to this program, Power has installed selective catalytic reduction equipment at Mercer at a cost of $118 million and baghouses were placed in service in December 2008, with costs as of March 31, 2009 of $260 million. The cost of assets to be placed in service in order to implement the balance of the agreement is estimated at $200 million to $250 million for Mercer, to be completed by May 2010, and $700 million to $750 million for Hudson, to be completed by the end of 2010, of which $334 million has been spent through March 31, 2009. All back end pollution control technology construction is expected to be completed by the end of 2010. Bergen Unit 2 was repowered in 2002 consistent with the consent decree.

On January 14, 2009, the EPA issued a notice of violation to Power and 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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. In October 2008, the EPA filed a petition with the U.S. Supreme Court to review the lower court’s decision. On February 6, 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, although certain industry litigants pursued Supreme Court review of the lower court’s decision. On February 23, 2009, the Supreme Court denied the petition. The full impact to PSEG of these developments is uncertain. It is expected that new MACT requirements will require more stringent control than the cap-and-trade program struck down by the D.C. Circuit Court; however, the costs of compliance with mercury MACT standards will have to be compared with the existing New Jersey and Connecticut mercury-control requirements, as described below.

Some uncertainty exists regarding the feasibility of achieving the reductions in mercury emissions required by the New Jersey regulations, discussed below. The estimated costs of technology believed to be capable of meeting these emissions limits at Power’s coal-fired units in New Jersey and Pennsylvania have been incurred or are included in Power’s capital expenditure forecast. Total estimated costs for each project are between $150 million and $200 million.

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, are permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012.

Power achieved the reductions required in 2007 through the installation of carbon injection technology and baghouses at both Mercer units and anticipates compliance with the remaining reductions required by December 2012 will be achieved through the installation of a baghouse at its Hudson plant by the end of 2010. The mercury-control technologies are part of Power’s multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

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 as required under a strict interpretation of the Clean Air Act. On January 30, 2009, the Commonwealth Court of Pennsylvania struck down the 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 Pennsylvania mercury rule by benefiting from reductions realized from the installation of planned or completed controls for compliance with SO₂ and NO_xreductions. Power will evaluate Phase II of the 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

uncertain at this time whether the Keystone and Conemaugh generating stations will be able to achieve the necessary reductions with their respective currently planned capital expenditures.

Emission Fees

Section 185 of the Clean Air Act requires states (or in the absence of state action, the EPA) in severe and extreme non-attainment areas to adopt a penalty fee for major stationary sources if the area fails to attain the one-hour ozone National Ambient Air Quality Standard (NAAQS) set by the EPA. In June 2007, the U.S. Court of Appeals for the District of Columbia Circuit ruled against the EPA, which had sought to vacate imposition of fees for NO_x emissions because the one hour standard was superseded by an eight-hour standard. Power operates electric generation stations, major stationary sources, in the New Jersey-Connecticut severe non-attainment area that did not meet the required NAAQS by November 2007. Neither the EPA nor the states in the non-attainment areas in which Power operates have initiated any process for imposing fees in compliance with the court ruling; however, preliminary analysis suggests that penalty fees could be approximately $6 million annually, which Power is currently accruing. This analysis could change if the EPA or the states issue additional guidance addressing the imposition of fees, or if Power is able to reduce its emissions of NO_x in the future.

On January 9, 2009, the NJDEP provided notice that it is in the process of assessing fees under Section 185 for 2008 emissions. These fees are expected to be paid in 2010 after the NJDEP determines the need for statutory or regulatory changes.

NO_x Reduction

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 is expected to have a significant impact on Power’s generation fleet, including the likely retirement of a significant portion of Power’s units by April 30, 2015. The rule is expected to require the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW). 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. Power cannot predict the financial impact resulting from compliance with this rulemaking.

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability as of March 31, 2009 and December 31, 2008, respectively, 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 prepared in accordance with the Federal Water Pollution Control Act’s (FWPCA) Section 316(b) and the Phase II 316(b) rules, allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

New Haven stations. In addition to the Salem renewal application, permit renewal applications have been submitted to the NJDEP for Hudson, and the Connecticut Department of Environmental Protection for Bridgeport. A renewal application is expected to be filed for Sewaren later this year.

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, 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.

•

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

In May 2007, Power and other industry petitioners filed a request for a rehearing with the Second Circuit Court, which was denied. The parties, including Power, requested U.S. Supreme Court review of the matter.

On April 1, 2009, the U.S. Supreme Court reversed the Second Circuit’s opinion, concluding that the 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 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.

It is premature to determine when the Second Circuit will act on this ruling or its ultimate disposition of the case. However, because there were major portions of the Phase II regulations which were originally remanded by the Second Circuit that were not considered by the Supreme Court, the EPA will need to undertake a rulemaking in the future.

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 costs estimated 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.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

New Generation and Development

Nuclear

Power has approved the expenditure of $192 million for 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). Significant project expenditures will begin later in 2009 and continue through 2012.

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 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 to date are $11 million which are included in Other Noncurrent Assets in Power’s and PSEG’s Consolidated Balance Sheets.

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

PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third-party suppliers through the annual New Jersey BGS auctions. Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Interconnection L.L.C. (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 February 2009 BGS Auction will become effective on June 1, 2009 when
the 2006 Auction Year agreements expire.

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 14. Related-Party Transactions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 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 March 31, 2009, the total minimum purchase requirements included in these commitments are as follows:


Fuel Type	Commitments through 2013			Power’s share
	(Millions)
Nuclear Fuel
Uranium		$	704		$	441
Enrichment		$	475		$	270
Fabrication		$	245		$	149
Natural Gas		$	910		$	910
Coal/Oil		$	955		$	955

Included in the $955 million commitment for coal and oil above is $457 million related to a certain coal contract under which Power can cancel tonnage at minimal cost.

Power has entered into gas supply option agreements for the anticipated fuel requirements at the PSEG Texas generation facilities to satisfy obligations under their forward energy sales contracts. As of March 31, 2009, Power’s fuel purchase options totaled $51 million under those agreements, which is not included in the above table.

PSEG Texas also has 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 Texas also has the right to cancel delivery of the gas at a minimal cost.

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 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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. The plaintiff has filed a petition for certification with the New Jersey Supreme Court requesting that the Appellate Division decision be overturned.

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 March 2009, would be $141 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.

Exceptions to the ALJ’s decision were filed on February 9, 2009. The BPU may choose to accept, modify or reject the ALJ’s decision in reaching its final decision. A BPU decision is expected by June 1, 2009. We cannot predict the final outcome of this proceeding.

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 $634 million as of March 31, 2009. Of this amount, $145 million was recorded as a current liability and $489 million as a noncurrent liability. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the SBC.

Leveraged Lease Investments

In November 2006, the Internal Revenue Service (IRS) issued Revenue Agent’s Reports with respect to its audit of PSEG’s federal corporate income tax returns for tax years 1997 through 2000, which disallowed all deductions associated with certain lease transactions that are similar to a type that the IRS publicly announced its intention to challenge. In addition, the IRS Reports proposed a 20% penalty for substantial

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

understatement of tax liability. In February 2007, PSEG filed a protest of these findings with the Office of Appeals of the IRS.

In April 2008, the IRS issued its Revenue Agent’s Report for tax years 2001 through 2003, which disallowed all deductions associated with lease transactions similar to those disallowed in its 1997 through 2000 Report. As in its prior report, the IRS proposed a 20% penalty. PSEG also filed a protest to this report with the Office of Appeals of the IRS.

As of March 31, 2009 and December 31, 2008, PSEG’s total gross investment in such transactions was $924 million and $1 billion, respectively.

There are several tax cases involving other taxpayers with similar leveraged lease investments that are pending. To date, three cases have been decided at the trial court level, two of which were decided in favor of the government. An appeal of one of these decisions was recently affirmed. The third case involves a jury verdict that is currently being challenged by both parties on inconsistency grounds.

In August 2008, the IRS publicly announced that it was issuing letters to a number of taxpayers with these types of lease transactions containing a generic settlement offer. PSEG did not accept the IRS’ settlement offer and will likely proceed to litigation.

Earnings Impact

Assuming all rental payments are made pursuant to the original lease agreement, and there are no changes in tax legislation and rates, the total cash and income included in a leveraged lease transaction will not change over the lease term. However, the timing of the cash flow can change due to changes in the timing of tax deductions. Changes in the timing of cash flows affect the overall return, or yield, that is recorded as income at a constant rate throughout the lease term. If there is a change in cash flow timing, pursuant to FSP 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” the lease must be recalculated from inception assuming the new lease yield. Differences between the current gross lease investment and the gross lease investment per the recalculated lease must be recognized immediately in income.

In the second quarter of 2008, PSEG recalculated its lease transactions, incorporating potential cash payments (discussed below) consistent with the FIN 48 reserve position, 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 in PSEG’s Condensed Consolidated Statement of Operations. The $355 million is being recognized as income over the remaining term of the affected leases.

This represents PSEG’s view of most of the financial statement exposure related to these lease transactions, although a total loss, consistent with the broad settlement offer recently proposed by the IRS, would result in an additional earnings charge of $100 million to $120 million.

Cash Impact

As of March 31, 2009, an aggregate $1.2 billion would become currently payable if PSEG conceded 100% of deductions taken through that date. PSEG has deposited $180 million with the IRS to defray potential interest costs associated with this disputed tax liability. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest.

These deposits reduce the $1.2 billion cash exposure noted above to $1 billion. As of March 31, 2009, penalties of $152 million would also become payable if the IRS was successful in its deficiency claims against PSEG, and asserted and successfully litigated a case against PSEG regarding penalties. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Should PSEG lose its case in litigation, and the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $130 million to $150 million of tax would be due for tax positions through March 31, 2009.

PSEG currently anticipates that it will pay between $230 million and $370 million in tax, interest and penalties for the tax years 1997 through 2000 during the second half of 2009 and subsequently commence litigation to recover these amounts. Further it is possible that an additional payment of between $270 million and $550 million could be required in late 2009 for tax years 2001 through 2003 followed by further litigation to recover those taxes. These amounts are in addition to tax deposits already made.

The actions described above concerning the leveraged lease investments are not expected to violate any covenant or result in a default under either Energy Holdings’ credit facility or Senior Notes indenture.

Note 6. Changes in Capitalization

The following capital transactions occurred in the first quarter of 2009:

Power

•

Converted $44 million of 4.00% Pollution Control Bonds to variable rate demand bonds backed by letters of credit.

•

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 (callable in one year), and

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

•

paid a cash dividend of $325 million to PSEG.

PSE&G

•

paid $42 million of Transition Funding’s securitization debt.

Energy Holdings

•

Redeemed $280 million of floating rate non-recourse project debt due on December 31, 2009 associated with PSEG Texas.

•

Repurchased $10 million of its 8.5% Senior Notes due 2011.

In April 2009, Power paid $250 million of 3.75% Senior Notes at maturity.

Note 7. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 in accordance with SFAS 133, with changes in fair value charged to 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 effect of using such modeling techniques is not material to Power’s or Energy Holdings’ financial statements.

Cash Flow Hedges

Power uses forward sale and purchase contracts, swaps, futures and firm transmission right contracts to hedge:

•

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

•

the price of fuel to meet its fuel purchase requirements.

Energy Holdings uses forward sale and purchase contracts and swaps to hedge:

•

forecasted energy sales from its Texas generation stations; and

•

to hedge the price of fuel for one of the Texas generation facilities.

These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of March 31, 2009 and December 31, 2008, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:


	March 31, 2009			December 31, 2008
	(Millions)
Power
Fair Values of Cash Flow Hedges		$	498		$	331	*
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)		$	300		$	176
Energy Holdings
Fair Values of Cash Flow Hedges		$	—		$	3
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)		$	12		$	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 March 31, 2010 and March 31, 2011 are $170 million and $80 million, respectively. Ineffectiveness associated with these hedges, as defined in SFAS 133, was $15 million at March 31, 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

associated with the output or fuel purchase requirements of our facilities. This trading consists mostly of load deals 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 less than one percent of Power’s revenues.

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. A portion is also used in Power’s Nuclear Decommissioning Trust (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.

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


	March 31, 2009			December 31, 2008
	(Millions)
Net Fair Value of Other Derivatives
Power		$	88		$	67	*
Energy Holdings		$	40		$	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

On April 1, 2009, PSEG’s interest rate swap that had converted Power’s $250 million of 3.75% Senior Notes due April 2009 into variable-rate debt matured. The interest rate swap was designated and effective as a fair value hedge. The fair value changes of the interest rate swap were fully offset by the fair value changes in the underlying debt.

Cash Flow Hedges

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 March 31, 2009, there was no hedge ineffectiveness associated with these hedges. The fair values of our interest rate derivatives were $(1) million and $(7) million as of March 31, 2009 and December 31, 2008, respectively. The AOCI related to interest rate derivatives designated as cash flow hedges was $(3) million and $(6) million as of March 31, 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:


Derivatives Designated as Hedging Instruments under SFAS 133	Derivatives in Asset Position as of March 31, 2009					Derivatives in Liability Position as of March 31, 2009
	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value

		(Millions)					(Millions)
PSEG
Interest Rate Swaps			$	—		Derivative Contracts- Current Liabilities		$	(1	)

PSEG & Power (A)
Energy-Related Contracts	Derivative Contracts- Current Assets		$	673		Derivative Contracts- Current Assets		$	(336	)
Energy-Related Contracts	Derivative Contracts- Noncurrent Assets			538		Derivative Contracts- Noncurrent Assets			(271	)
Energy-Related Contracts	Derivative Contracts- Current Liabilities			108		Derivative Contracts- Current Liabilities			(176	)
Energy-Related Contracts	Derivative Contracts- Noncurrent Liabilities			43		Derivative Contracts- Noncurrent Liabilities			(81	)
Margin Collateral				(362	)				16
Total PSEG & Power			$	1,000		Total PSEG & Power		$	(848	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


Derivatives Not Designated as Hedges in SFAS 133 Fair Value Hedging Relationships	Derivatives in Asset Position as of March 31, 2009					Derivatives in Liability Position as of March 31, 2009
	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value

		(Millions)					(Millions)

PSEG
Energy-Related Contracts	Derivative Contracts- Current Assets		$	566		Derivative Contracts- Current Assets		$	(481	)
Energy-Related Contracts	Derivative Contracts- Noncurrent Assets			221		Derivative Contracts- Noncurrent Assets			(145	)
Energy-Related Contracts	Derivative Contracts- Current Liabilities			502		Derivative Contracts- Current Liabilities			(905	)
Energy-Related Contracts	Derivative Contracts- Noncurrent Liabilities			126		Derivative Contracts- Noncurrent Liabilities			(247	)
Margin Collateral				(40	)				105
Other Contracts	NDT Funds			127		NDT Funds			(19	)

Total PSEG			$	1,502		Total PSEG		$	(1,692	)

Power (A)
Energy-Related Contracts	Derivative Contracts- Current Assets		$	540		Derivative Contracts- Current Assets		$	(481	)
Energy-Related Contracts	Derivative Contracts- Noncurrent Assets			206		Derivative Contracts- Noncurrent Assets			(145	)
Energy-Related Contracts	Derivative Contracts- Current Liabilities			502		Derivative Contracts- Current Liabilities			(890	)
Energy-Related Contracts	Derivative Contracts- Noncurrent Liabilities			126		Derivative Contracts- Noncurrent Liabilities			(207	)
Margin Collateral				(40	)				105
Other Contracts	NDT Funds		$	127		NDT Funds		$	(19	)

Total Power			$	1,461		Total Power		$	(1,637	)

PSE&G
Energy-Related Contracts	Derivative Contracts- Current Assets		$	1		Derivative Contracts- Current Liabilities		$	(15	)
Energy-Related Contracts				—		Derivative Contracts- Noncurrent Liabilities			(40	)

Total PSE&G			$	1		Total PSE&G		$	(55	)

Energy Holdings
Energy-Related Contracts	Derivative Contracts- Current Assets		$	25				$	—
Energy-Related Contracts	Derivative Contracts- Noncurrent Assets			15					—

Total Energy Holdings			$	40				$	—

(A)

Energy-related contracts for Power are subject to master netting arrangements with the right of offset for certain counterparties. Contract amounts are shown gross in the above table and are not necessarily reflective of amounts presented in the Condensed Consolidated Balance Sheets.

The aggregate fair value of derivative contracts in a liability position as of March 31, 2009 that contain triggers for additional collateral is $787 million. This potential additional collateral is included in the $1.2 billion discussed in Note 5. 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 quarter ended March 31, 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
Energy-Related Contracts		$	382		Operating Revenue		$	156		Operating Revenue		$	8
Energy-Related Contracts			(28	)	Energy Costs			(26	)				—
Interest Rate Swaps			—		Interest Expense			(4	)				—

Total PSEG		$	354				$	126				$	8

PSEG Power
Energy-Related Contracts		$	354		Operating Revenue		$	142		Operating Revenue		$	8
Energy-Related Contracts			(21	)	Energy Costs			(19	)				—

Total Power		$	333				$	123				$	8

Energy Holdings
Energy-Related Contracts		$	28		Operating Revenue		$	14				$	—
Energy-Related Contracts			(7	)	Energy Costs			(7	)				—
Interest Rate Swaps			—		Interest Expense			(4	)				—

Total Energy Holdings		$	21				$	3				$	—

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

Accumulated Other Comprehensive Income	Pre-Tax				After-Tax
	(Millions)
Balance as of December 31, 2008		$	292			$	172
Gain Recognized in AOCI (Effective Portion)			354				211
Less: Gain Reclassified into Income (Effective Portion)			(126	)			(74	)

Balance as of March 31, 2009		$	520			$	309

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 quarter ended March 31, 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
		(Millions)
PSEG
Energy-Related Contracts	Operating Revenues		$	131
Energy-Related Contracts	Energy Costs			(87	)
Interest Rate Swaps	Interest Expense			(1	)
Derivatives in NDT Funds	Other Income			9

Total PSEG			$	52

Power
Energy-Related Contracts	Operating Revenue		$	71
Energy-Related Contracts	Energy Costs			(75	)
Derivatives in NDT Funds	Other Income			9

Total Power			$	5

Energy Holdings
Energy-Related Contracts	Operating Revenue		$	60
Energy-Related Contracts	Energy Costs			(12	)
Interest Rate Swap	Interest Expense			(1	)

Total Energy Holdings			$	47

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 in accordance with SFAS 133. The tables above do not include contracts for which Power has elected the normal purchase/normal sales exemption under SFAS 133, such as its BGS contracts and certain other load-type contracts that it has with other utilities and companies with retail load.

The following reflects the gross volume, on an absolute value basis, of derivatives as of March 31, 2009:


Type	Notional	Total		PSEG		Power		PSE&G		Energy Holdings
						(Millions)
Natural Gas	Dth		1,200		—		947		253		—
Electricity	MWh		138		—		138		—		—
Capacity	MW days		2		—		2		—		—
FTRs	MWh		7		—		7		—		—
Emissions Allowances	Tons		1		—		1		—		—
Oil	Barrels		2		—		2		—		—
Foreign Currency Option	Indian Rupees		800		—		—		—		800
Interest Rate Swaps	US Dollars		290		250		—		40		—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 8. Fair Value Measurements

Effective January 1, 2008, PSEG, Power and PSE&G adopted SFAS No. 157, “Fair Value Measurements” (SFAS 157), except for non-financial assets and liabilities as described in FSP FAS 157-2. PSEG, Power and PSE&G adopted SFAS 157 for non-financial assets and liabilities on January 1, 2009. SFAS 157 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. SFAS 157 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, SFAS 157 nullifies the guidance of EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” 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 March 31, 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.


	Recurring Fair Value Measurements as of March 31, 2009
Description	Total				Cash Collateral Netting (E)				Quoted Market Prices of Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
	(Millions)
PSEG
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	362			$	(402	)		$	—		$	546			$	218
NDT Funds (C)		$	954			$	—			$	366		$	566			$	22
Rabbi Trusts (C)		$	136			$	—			$	8		$	113			$	15
Other Long-Term Investments (D)		$	1			$	—			$	1		$	—			$	—
*Liabilities:*
Derivative Contracts:
Energy-Related Contracts (A)		$	(509	)		$	120			$	—		$	(577	)		$	(52	)
Interest Rate Swaps (B)		$	(1	)		$	—			$	—		$	(1	)		$	—
Power
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	322			$	(402	)		$	—		$	547			$	177
NDT Funds (C)		$	954			$	—			$	366		$	566			$	22
Rabbi Trusts (C)		$	27			$	—			$	2		$	22			$	3
*Liabilities:*
Derivative Contracts:
Energy-Related Contracts (A)		$	(454	)		$	120			$	—		$	(577	)		$	3
PSE&G
*Assets:*
Derivative Contracts:
Energy-Related Contracts (A)		$	1			$	—			$	—		$	—			$	1
Rabbi Trusts (C)		$	47			$	—			$	3		$	39			$	5
*Liabilities:*
Energy-Related Contracts (A)		$	(55	)		$	—			$	—		$	—			$	(55	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	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)		$	970			$	—			$	413		$	516			$	41
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)		$	970			$	—			$	413		$	516			$	41
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 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).

(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 and the Rabbi Trusts maintain investments in various equity and fixed income securities classified as “available for sale.” These securities are valued using quoted market prices,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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).

(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 Quarter Ended March 31, 2009


Description	Balance as of January 1, 2009				Total Gains or (Losses) Realized/Unrealized						Purchases and (Sales) and Settlements				Balance March 31, 2009
Description	Balance as of January 1, 2009				Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)			Purchases and (Sales) and Settlements				Balance March 31, 2009
	(Millions)
PSEG
Net Derivative Assets		$	32			$	131		$	10		$	(7	)		$	166
NDT Funds		$	41			$	—		$	—		$	(19	)		$	22
Rabbi Trust Funds		$	14			$	—		$	—		$	1			$	15
Power
Net Derivative Assets		$	61			$	126		$	—		$	(7	)		$	180
NDT Funds		$	41			$	—		$	—		$	(19	)		$	22
Rabbi Trust Funds		$	3			$	—		$	—		$	—			$	3
PSE&G
Net Derivative Liabilities		$	(64	)		$	—		$	10		$	—			$	(54	)
Rabbi Trust Funds		$	5			$	—		$	—		$	—			$	5

(A)

PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $102 million is included in Operating Revenues and $29 million is included in Other Comprehensive Income. Of the $102 million in Operating Revenues, $5 million (unrealized) is at PSEG Texas and $ 97 million (unrealized) is at Power. The $29 million included in Other Comprehensive Income is at Power.

(B)

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

As of March 31, 2009, PSEG carried approximately $943 million of net assets that are measured at fair value on a recurring basis, of which approximately $203 million were measured using unobservable inputs

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets.

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Quarter Ended March 31, 2008


Description	Balance as of January 1, 2008				Total Gains or (Losses) Realized/Unrealized								Purchases/ (Sales) and Settlements				Balance March 31, 2008
Description	Balance as of January 1, 2008				Included in Income (A)				Included in Regulatory Assets/ Liabilities (B)				Purchases/ (Sales) and Settlements				Balance March 31, 2008
	(Millions)
PSEG
Net Derivative Assets/(Liabilities)		$	(11	)		$	18			$	(22	)		$	9			$	(6	)
NDT Funds		$	27			$	(1	)		$	—			$	1			$	27
Rabbi Trust Funds		$	16			$	—			$	—			$	(2	)		$	14
Power
Net Derivative Assets/(Liabilities)		$	10			$	(15	)		$	—			$	9			$	4
NDT Funds		$	27			$	(1	)		$	—			$	1			$	27
Rabbi Trust Funds		$	3			$	—			$	—			$	—			$	3
PSE&G
Net Derivative Assets/(Liabilities)		$	(49	)		$	—			$	(22	)		$	—			$	(71	)
Rabbi Trust Funds		$	6			$	—			$	—			$	(1	)		$	5

(A)

PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $22 million is included in Operating Revenues and $(4) million is included in Other Comprehensive Income. Of the $22 million in Operating Revenues, $33 million (unrealized) is at PSEG Texas and $(11) million (of which $(10) is unrealized) is at Power. The $(4) million included in Other Comprehensive Income is at Power.

(B)

As of March 31, 2008, PSEG carried approximately $911 million of net assets that are measured at fair value on a recurring basis, of which approximately $35 million are 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.

NOTES TO CONDENSED CONSOLIDATED STATEMENTS
(UNAUDITED)

Note 9. Other Income and Deductions


Other Income:	Power			PSE&G			Other (A)				Consolidated Total
	(Millions)
Quarter Ended March 31, 2009
NDT Fund Realized Gains		$	50		$	—		$	—			$	50
NDT Interest, Dividend and Other Income			17			—			—				17
Other Interest and Dividend Income			3			—			(1	)			2
Other			—			1			1				2

Total Other Income		$	70		$	1		$	—			$	71


Quarter Ended March 31, 2008
NDT Fund Realized Gains		$	75		$	—		$	—			$	75
NDT Interest, Dividend and Other Income			8			—			—				8
Other Interest and Dividend Income			2			2			1				5
Other			1			3			1				5

Total Other Income		$	86		$	5		$	2			$	93

Other Deductions:

Quarter Ended March 31, 2009
NDT Fund Realized Losses and Expenses		$	46		$	—		$	—			$	46
Loss on Disposition of Assets			4			—			—				4
Other-Than-Temporary Impairment of Investments			60			—			—				60
Other			—			1			4				5

Total Other Deductions		$	110		$	1		$	4			$	115


Quarter Ended March 31, 2008
NDT Fund Realized Losses and Expenses		$	53		$	—		$	—			$	53
Other-Than-Temporary Impairment of Investments			38			—			—				38
Other			—			1			3				4

Total Other Deductions		$	91		$	1		$	3			$	95

(A)

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

Note 10. Income Taxes

PSEG’s effective tax rate for the quarter ended March 31, 2009 was 40.6% as compared to 34.9% for the quarter ended March 31, 2008. The increase in the effective tax rate was primarily due to the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim and the sale of leveraged lease assets in 2009.

Power’s effective tax rate for the quarter ended March 31, 2009 was 39.3% as compared to 40.5% for the quarter ended March 31, 2008. The decrease in the effective tax rate was due to primarily due to lower earnings in the Nuclear Decommissioning Trust Funds and increased benefits of a manufacturing deduction under the American Jobs Creation Act of 2004.

NOTES TO CONDENSED CONSOLIDATED STATEMENTS
(UNAUDITED)

PSE&G’s effective tax rate for the quarter ended March 31, 2009 was 40.7% as compared to 32.2% for the quarter ended March 31, 2008. The increase in the effective tax rate was primarily due to the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim.

PSEG, Power and PSE&G have $1,359 million, $17 million and $26 million, respectively of unrecognized tax benefits as of March 31, 2009 which have not materially changed since December 31, 2008.

It is reasonably possible that the total unrecognized tax benefits (including interest) at PSEG will decrease by approximately $168 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 a $13 million decrease for Power, a $7 million decrease for PSE&G, a $25 million decrease for Services, a $128 million decrease for Energy Holdings and a $5 million increase for PSEG.

Note 11. Comprehensive Income (Loss), Net of Tax


	Power (A)				PSE&G			Other (B)			Consolidated Total
	(Millions)
Quarter Ended March 31, 2009:
Net Income		$	318			$	124		$	2		$	444
Other Comprehensive Income			132				—			14			146

Comprehensive Income		$	450			$	124		$	16		$	590


Quarter Ended March 31, 2008:
Net Income		$	275			$	137		$	36		$	448
Other Comprehensive Income (Loss)			(272	)			—			52			(220	)

Comprehensive Income		$	3			$	137		$	88		$	228

(A)

Changes at Power primarily relate to changes in SFAS 133 unrealized gains and losses on derivative contracts that qualify for hedge accounting in 2009 and 2008, 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 March 31, 2009
	(Millions)
Quarter Ended March 31, 2009:
Derivative Contracts		$	172			$	124		$	—		$	13		$	309
Pension and OPEB Plans			(371	)			6			—			—			(365	)
NDT Funds			18				2			—			—			20
Other			4				—			—			1			5

		$	(177	)		$	132		$	—		$	14		$	(31	)

NOTES TO CONDENSED CONSOLIDATED STATEMENTS
(UNAUDITED)


	Balance as of December 31, 2007				Power				PSE&G			Other				Balance as of March 31, 2008
	(Millions)
Quarter Ended March 31, 2008:
Derivative Contracts		$	(259	)		$	(242	)		$	—		$	(4	)		$	(505	)
Pension and OPEB Plans			(167	)			—				—			—				(167	)
Currency Translation Adjustment			107				—				—			56				163
NDT Funds			97				(30	)			—			—				67
Other			6				—				—			—				6

		$	(216	)		$	(272	)		$	—		$	52			$	(436	)

Note 12. Earnings Per Share (EPS)

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


	Quarters Ended March 31,
	2009						2008
	Basic			Diluted			Basic			Diluted
EPS Numerator:
Earnings (Millions)
Continuing Operations		$	444		$	444		$	435		$	435
Discontinued Operations			—			—			13			13

Net Income		$	444		$	444		$	448		$	448


EPS Denominator (Thousands):
Weighted Average Common Shares Outstanding			505,986			505,986			508,490			508,490
Effect of Stock Options			—			192			—			539
Effect of Stock Performance Share Units			—			334			—			965
Effect of Restricted Stock			—			—			—			19
Effect of Restricted Stock Units			—			36			—			94

Total Shares			505,986			506,548			508,490			510,107


EPS:
Continuing Operations		$	0.88		$	0.88		$	0.86		$	0.85
Discontinued Operations			—			—			0.02			0.03

Net Income		$	0.88		$	0.88		$	0.88		$	0.88

Dividend payments on common stock for the quarters ended March 31, 2009 and 2008 were $0.3325 and $0.3225 per share, respectively, and totaled $168 million and $164 million, respectively.

NOTES TO CONDENSED CONSOLIDATED STATEMENTS
(UNAUDITED)

Note 13. Financial Information by Business Segments


	Power			PSE&G				Energy Holdings			Other (A)				Consolidated
	(Millions)
Quarter Ended March 31, 2009:
Total Operating Revenues		$	2,374		$	2,735			$	135		$	(1,323	)		$	3,921
Net Income (Loss)			318			124				7			(5	)			444
Preferred Securities Dividends			—			(1	)			—			1				—
Segment Earnings (Loss)			318			123				7			(4	)			444
Gross Additions to Long-Lived Assets			207			194				3			(2	)			402
As of March 31, 2009:
Total Assets		$	9,666		$	16,444			$	3,919		$	(727	)		$	29,302
Investments in Equity Method Subsidiaries		$	37		$	—			$	186		$	—			$	223

Quarter Ended March 31, 2008:
Total Operating Revenues		$	2,375		$	2,618			$	131		$	(1,332	)		$	3,792
Income (Loss) From Continuing Operations			275			137				29			(6	)			435
Income from Discontinued Operations, net of tax			—			—				13			—				13
Net Income (Loss)			275			137				42			(6	)			448
Preferred Securities Dividends			—			(1	)			—			1				—
Segment Earnings (Loss)			275			136				42			(5	)			448
Gross Additions to Long-Lived Assets		$	174		$	145			$	2		$	2			$	323

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

(A)

PSEG’s 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 14. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs.

Note 14. Related-Party Transactions

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

NOTES TO CONDENSED CONSOLIDATED STATEMENTS
(UNAUDITED)

Power

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


Related Party Transactions	Quarters Ended March 31,
Related Party Transactions	2009				2008
	(Millions)
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)		$	970			$	1,050
Billings to PSE&G through BGS (A)			344				272

Total Revenue from Affiliates		$	1,314			$	1,322

Expense Billings from Affiliates:
Administrative Billings from Services (B)		$	(40	)		$	(41	)

Total Expense Billings from Affiliates		$	(40	)		$	(41	)


Related Party Balances	March 31, 2009				December 31, 2008
	(Millions)
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)		$	399			$	319
Receivables from PSE&G through BGS and BGSS Contracts (A)			345				475
Administrative Billings Payable to Services (B)			(24	)			(26	)
Tax Sharing Payable to PSEG (C)			(230	)			(36	)
Amounts Payable to Energy Holdings			(3	)			—
Amounts PSEG Paid on Power’s Behalf			(1	)			—

Accounts Receivable—Affiliated Companies, net		$	486			$	732

Short-Term Loan to Affiliate (Demand Note Receivable from PSEG) (D)		$	951			$	—

Short-Term Loan from Affiliate (Demand Note Payable to PSEG) (D)		$	—			$	(3	)

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

Long-Term Accrued Taxes Payable (C)		$	(17	)		$	(16	)

PSE&G

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


Related Party Transactions	Quarters Ended March 31,
Related Party Transactions	2009				2008
	(Millions)
Expense Billings from Affiliates:
Billings from Power through BGSS (A)		$	(970	)		$	(1,050	)
Billings from Power through BGS (A)			(344	)			(272	)
Administrative Billings from Services (B)			(66	)			(65	)

Total Expense Billings from Affiliates		$	(1,380	)		$	(1,387	)

NOTES TO CONDENSED CONSOLIDATED STATEMENTS
(UNAUDITED)


Related Party Balances	March 31, 2009				December 31, 2008
	(Millions)
Payable to Power Related to Gas Supply Hedges for BGSS (A)		$	(399	)		$	(319	)
Payable to Power through BGS and BGSS Contracts (A)			(345	)			(475	)
Administrative Billings Payable to Services (B)			(41	)			(54	)
Tax Sharing Receivable from (Payable to) PSEG (C)			(49	)			21
Current Unrecognized Tax Receivable from PSEG (C)			59				55
Amounts Collected by PSEG on behalf of PSE&G			1				9

Accounts Payable—Affiliated Companies, net		$	(774	)		$	(763	)

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

Long-Term Accrued Taxes Payable (C)		$	(85	)		$	(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 FIN 48 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)

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

(E)

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

NOTES TO CONDENSED CONSOLIDATED STATEMENTS
(UNAUDITED)

Note 15. Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and revolving Letters of Credit 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)
Quarter Ended March 31, 2009
Operating Revenues		$	—			$	2,660			$	30			$	(316	)		$	2,374
Operating Expenses			3				2,050				30				(316	)			1,767

Operating Income			(3	)			610				—				—				607
Equity Earnings (Losses) of Subsidiaries			332				(6	)			—				(326	)			—
Other Income			23				82				—				(35	)			70
Other Deductions			—				(110	)			—				—				(110	)
Interest Expense			(53	)			(17	)			(8	)			35				(43	)
Income Tax Benefit (Expense)			19				(227	)			2				—				(206	)

Net Income (Loss)		$	318			$	332			$	(6	)		$	(326	)		$	318

Quarter Ended March 31, 2009
Net Cash Provided By (Used In) Operating Activities		$	415			$	1,267			$	(6	)		$	(413	)		$	1,263
Net Cash Provided By (Used In) Investing Activities		$	(91	)		$	(1,175	)		$	—			$	117			$	(1,149	)
Net Cash Provided By (Used In) Financing Activities		$	(325	)		$	(97	)		$	6			$	297			$	(119	)
Quarter Ended March 31, 2008
Operating Revenues		$	—			$	2,627			$	27			$	(279	)		$	2,375
Operating Expenses			2				2,117				27				(280	)			1,866

Operating Income (Loss)			(2	)			510				—				1				509
Equity Earnings (Losses) of Subsidiaries			281				(10	)			—				(271	)			—
Other Income			39				101				—				(54	)			86
Other Deductions			—				(91	)			—				—				(91	)
Interest Expense			(53	)			(28	)			(15	)			54				(42	)
Income Tax Benefit (Expense)			10				(201	)			5				(1	)			(187	)

Net Income (Loss)		$	275			$	281			$	(10	)		$	(271	)		$	275

Quarter Ended March 31, 2008
Net Cash Provided By (Used In) Operating Activities		$	(848	)		$	856			$	(26	)		$	956			$	938
Net Cash Provided By (Used In) Investing Activities		$	973			$	(806	)		$	(2	)		$	(742	)		$	(577	)
Net Cash Provided By (Used In) Financing Activities		$	(125	)		$	(52	)		$	28			$	(214	)		$	(363	)

NOTES TO CONDENSED CONSOLIDATED STATEMENTS
(UNAUDITED)


	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments				Consolidated Total
	(Millions)
March 31, 2009:
Current Assets		$	2,470		$	6,004		$	442		$	(6,098	)		$	2,818
Property, Plant and Equipment, net			50			4,599			916			(1	)			5,564
Investment in Subsidiaries			4,966			378			—			(5,344	)			—
Noncurrent Assets			243			1,175			53			(187	)			1,284

Total Assets		$	7,729		$	12,156		$	1,411		$	(11,630	)		$	9,666

Current Liabilities		$	391		$	6,154		$	920		$	(6,099	)		$	1,366
Noncurrent Liabilities			466			1,037			112			(186	)			1,429
Long-Term Debt			2,862			—			—			—				2,862
Member’s Equity			4,010			4,965			379			(5,345	)			4,009

Total Liabilities and Member’s Equity		$	7,729		$	12,156		$	1,411		$	(11,630	)		$	9,666


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

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

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

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

•

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

•

PSE&G, our public utility company which provides transmission and distribution of electricity and gas in New Jersey; and

•

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

OVERVIEW OF 2009 AND FUTURE OUTLOOK

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, focusing on operational excellence, financial strength and making disciplined investments. The following discussion 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 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.

Operational Excellence

Our generating assets continued to perform with strong operations in the first quarter of 2009. Our nuclear capacity factor for the first quarter 2009 was slightly higher than in the comparable period in 2008. Our fossil fleet also performed well in the first quarter 2009, although generation volumes were negatively impacted by lower electric prices than in the recent past, and the general economic slowdown. The largest reduction in volume was at our coal units which are burning higher-priced coal in 2009 than in 2008. Continued lower electric prices and recessionary conditions could prolong this trend for the foreseeable near-term future. Our hedging strategy has resulted in higher average prices than a year ago, thus largely offsetting our reduced generation. The increase in prices was due to comparably higher-priced contracts that replaced older, lower-priced contracts, such as the 2005 Basic Generation Service (BGS) auction contracts which expired in May 2008, that were replaced with higher priced contracts.

Our utility operations experienced a 2% decline in total electric volumes and 3% increase in total gas volumes in the first quarter of 2009 as compared to the same period in 2008. Residential sales contribute approximately 45% of our electric margin and 75% of our gas margin. In the Commercial and Industrial Segments, billings to customers are not based on total energy consumption as measured by kilowatt-hours or deka-therms, but are based on fixed, monthly demand charges that are set by the highest electric and gas 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. Therefore, any changes in energy usage over comparative periods may not impact sales margin.

During 2008 and the first quarter of 2009, we undertook a project to update our customer service system. In April 2009 our customer service system was fully integrated into our utility operations.

During the quarter there were also two significant regulatory developments that we believe have the potential to positively impact future operations.

•

On March 26, 2009, the Federal Energy Regulatory Commission (FERC) issued an order regarding PJM’s Reliability Pricing Model (RPM). The effect of this order upon our generation fleet in PJM is generally positive, particularly the increase in the cost of new entry value which more accurately reflects 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.

•

On April 1, 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 in that 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 5. Commitments and Contingent Liabilities.

There continue to be significant developments addressing the need to promote clean and renewable energy, energy efficiency and the reduction of greenhouse gases which may impact our operations in the future as new rules and regulations are adopted.

•

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

•

Legislation has been introduced in Congress to promote clean energy, energy efficiency, and reduce greenhouse gases. The bill sets forth major initiatives which include establishing a national renewable energy standard. This would provide for setting maximum pollution levels and creating a market mechanism for the sale and purchase of pollution allowances (cap-and-trade programs). While the proposed regulation would not eliminate individual state-level renewable portfolio standards, it could reduce or eliminate regional inconsistencies in environmental regulations.

Financial Strength

In 2009, we have continued to focus on managing costs while maintaining our safety and reliability standards and believe that our financial position remains strong.

Our businesses continue 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 in January and to date has issued $209 million under this program. We used these funds, cash from operations and cash on hand to:

•

contribute $257 million of the approximately $370 million we expect to contribute into our pension plans in 2009,

•

pay $250 million of Power’s 3.75% Senior Notes at maturity,

•

redeem $280 million of non-recourse debt at our Texas plants at the end of February and

•

repurchase $10 million of Energy Holdings remaining Senior Notes.

In addition, the Board of Directors has approved an increase in the quarterly dividends from $0.3225 per share to $0.3325 per share for the first and second quarters of 2009 with 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

During 2009, we expect to continue to pursue investments focusing on areas that complement our existing businesses and provide prudent growth opportunities. These areas include responding to climate change and continuing to improve environmental performance, upgrading critical energy infrastructure and providing new energy supplies. During 2009:

•

We were assigned construction and operating responsibility for two additional 500 kV transmission lines in New Jersey. The first line would run from Branchburg to Roseland and the second from Roseland to Hudson. These lines are still in the design phase.

•

We obtained incentive rate approval from FERC for our portion of a 500 kV transmission line that may extend to Lower Alloways Creek Township, New Jersey. We will be responsible for constructing and operating a portion of this line, known as the Mid-Atlantic Pathway Project (MAPP). Receipt of incentive rates is contingent upon our portion of the MAPP project being approved by PJM as a Regional Transmission Expansion Plan (RTEP) project.

•

We requested approval from the New Jersey Board of Public Utilities (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 the new program.

•

The BPU approved our Capital Economic Stimulus Program. Under this program, we anticipate accelerating $694 million of capital infrastructure investments through our utility for electric and gas programs in New Jersey over a 24-month period. The goal of the program is to help improve New Jersey’s economy through the creation of new jobs while enhancing our utility’s infrastructure. The program provides for a charge for immediate recovery of a return on the program expenditures plus depreciation of the assets which will be adjusted each January.

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

RESULTS OF OPERATIONS

The results for us and our subsidiaries for the quarters ended March 31, 2009 and 2008 are presented below:


Earnings (Losses)	Quarters Ended March 31,
Earnings (Losses)	2009				2008
	(Millions)
Power		$	318			$	275
PSE&G			124				137
Energy Holdings			7				29
Other			(5	)			(6	)

PSEG Income from Continuing Operations		$	444			$	435
Income from Discontinued Operations			—				13

PSEG Net Income		$	444			$	448


Earnings Per Share (Diluted)	Quarters Ended March 31,
	2009			2008
PSEG Income from Continuing Operations		$	0.88		$	0.85
Income from Discontinued Operations			—			0.03

PSEG Net Income		$	0.88		$	0.88

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


Non-Trading Mark-to-Market After Tax	Quarters Ended March 31,
Non-Trading Mark-to-Market After Tax	2009				2008
	(Millions)
Power		$	(18	)		$	3
Energy Holdings			3				2

Total		$	(15	)		$	5

The quarter-over-quarter increase in our Income from Continuing Operations reflects the following large drivers:

•

Improved earnings at Power due to higher prices realized under sales contracts partially offset by lower volumes and losses related to the Nuclear Decommissioning Trust (NDT) Funds, 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 changes related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, donations and general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 14. Related-Party Transactions. For an explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings that follow the table below.


	Quarters Ended March 31,								Increase/ (Decrease)
	2009				2008				2009 vs 2008
	(Millions)								(Millions)				%
Operating Revenues		$	3,921			$	3,792			$	129			3
Energy Costs			2,068				2,119				(51	)		(2	)
Operation and Maintenance			675				627				48			8
Depreciation and Amortization			207				192				15			8
Income from Equity Method Investments			10				12				(2	)		(17	)
Other Income and Deductions			(44	)			(2	)			42			N/A
Interest Expense			(145	)			(153	)			(8	)		(5	)
Income Tax Expense			(304	)			(233	)			71			30
Income from Discontinued Operations, net of tax			—				13				(13	)		(100	)

Power


	Quarters Ended March 31,						Increase/ (Decrease)
	2009			2008			2009 vs 2008
	(Millions)						(Millions)
Income from Continuing Operations		$	318		$	275		$	43
Net Income		$	318		$	275		$	43

For the quarter ended March 31, 2009, the primary reasons for the $43 million increase in Income from Continuing Operations were:

•

higher prices and sales volumes on BGS contracts supported by lower generation costs,

•

improved margins on a reduced sales volume under the BGSS contract, and

•

higher trading gains,

•

partially offset by higher maintenance costs and net losses on investments in the NDT Funds.

•

The increase also included the recognition of non-trading MTM losses of $18 million, after-tax, in 2009 as compared to $3 million of after-tax MTM gains in 2008.

The quarter-over-quarter details for these variances are discussed below:


	Quarters Ended March 31,								Increase/ (Decrease)
	2009				2008				2009 vs 2008
	(Millions)								(Millions)				%
Operating Revenues		$	2,374			$	2,375			$	(1	)		—
Energy Costs			1,462				1,589				(127	)		(8	)
Operation and Maintenance			258				239				19			8
Depreciation and Amortization			47				38				9			24
Other Income and Deductions			(40	)			(5	)			35			N/A
Interest Expense			(43	)			(42	)			1			2
Income Tax Expense			(206	)			(187	)			19			10

For the quarter ended March 31, 2009 as compared to 2008

Operating Revenues decreased $1 million due to:

•

Generation revenues increased $59 million due to

a net increase of $88 million from higher prices on a higher volume of BGS contracts modestly offset by the expiration of several contracts in May 2008, and

higher revenues of $19 million due to several new wholesale contracts that were entered into in late 2008 and early 2009,

partially offset by lower revenues of $41 million resulting from lower volumes of generation being sold at lower prices.

•

Gas Supply revenues decreased $76 million

including a net decrease of $8 million resulting from sales under the BGSS contract, comprised of $46 million from lower average gas prices in 2009 net of gains on financial hedging transactions, partly offset by higher sales volumes of $38 million due to colder winter temperatures in 2009, and

a net decrease of $68 million due to lower prices on a reduced sales volume to third party customers.

•

Trading revenues increased $16 million principally due to premiums received on the termination of certain trades and 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 $127 million due to:

Generation costs decreased by $39 million due to $98 million of lower fuel costs, primarily reflecting lower volumes of natural gas and coal purchases and lower average natural gas prices, partly offset by net losses of $51 million from financial hedging transactions.

Gas costs decreased $88 million, reflecting net decreases of $9 million and $75 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 increased $19 million primarily due to

a net increase of $8 million due to higher planned maintenance costs at our fossil stations, primarily Keystone, Bergen and Linden, and

an increase of $9 million primarily related to a planned outage at Hope Creek.

•

Depreciation and Amortization increased $9 million due to

an increase of $4 million resulting from a larger depreciable nuclear asset base in 2009, principally due to depreciation of the Salem 2 steam generator replacement being placed into service in May 2008, and a higher depreciable fossil asset base in 2009, and

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.

Other Income and Deductions decreased $35 million due to

•

higher charges of $22 million ($60 million in 2009 versus $38 million in 2008) for other-than-temporary impairments related to the NDT Fund securities,

•

net realized losses of $17 million on the NDT Fund securities, and

•

a $4 million write-off of obsolete pollution-control equipment,

•

partially offset by an increase of $7 million in net unrealized gains on NDT Fund derivative instruments.

Interest Expense experienced no material change.

Income Tax Expense increased $19 million in 2009 primarily due to

•

an increase of $25 million due to higher pre-tax income,

•

partially offset by a reduction of $3 million due to lower earnings from the NDT Funds, and

•

a reduction of $2 million due to increased benefits from a manufacturing deduction under the American Jobs Creation Act of 2004.

PSE&G


	Quarters Ended March 31,						Increase/ (Decrease)
	2009			2008			2009 vs 2008
	(Millions)
Income from Continuing Operations		$	124		$	137		$	(13	)
Net Income		$	124		$	137		$	(13	)

For the quarter ended March 31, 2009, the primary reasons for the $13 million decrease in Income from Continuing Operations were:

•

higher taxes as a result of tax benefits recorded in 2008 related to an IRS refund claim and other tax items, and

•

increased Operation and Maintenance expense and depreciation, offset by

•

higher margin revenues due to favorable weather and a Transmission formula rate increase.

The quarter-over-quarter details for these variances are discussed below.


	Quarters Ended March 31,								Increase/ (Decrease)
	2009				2008				2009 vs 2008
	(Millions)								(Millions)				%
Operating Revenues		$	2,735			$	2,618			$	117			4
Energy Costs			1,859				1,793				66			4
Operation and Maintenance			395				360				35			10
Depreciation and Amortization			149				143				6			4
Other Income and Deductions			—				4				(4	)		(100	)
Interest Expense			(79	)			(81	)			(2	)		(2	)
Income Tax Expense			(85	)			(65	)			20			31

For the quarter ended March 31, 2009 as compared to 2008

Operating Revenues increased $117 million primarily due to

•

Commodity related revenues increased $65 million due to

increased electric revenues of $75 million primarily due to $97 million in higher BGS and Non-Utility Generation (NGC) revenues (higher prices of $129 million offset by decreased sales of $32 million), offset by $22 million in lower non-utility generation (NUG) revenues, primarily due to lower prices, and

decreased gas revenues of $10 million due to $48 million in decreased BGSS prices offset by $38 million in higher sales due to weather.

•

Delivery revenues increased $52 million due to

increased gas revenues of $30 million due to $15 million of higher sales due to favorable weather and $15 million due to higher SBC revenues, and

increased electric revenues of $22 million due to $14 million for SBC revenues, $7 million for net transmission rate increases, $4 million for a securitization transition charge rate increase, offset by $3 million in decreased distribution sales and demands due to economic conditions. PSE&G retains no margins from SBC or STC collections as the revenues are offset in operating expenses below.

Operating Expenses

•

Energy Costs increased $66 million due to

increased electric costs of $75 million due to $120 million or 16% in higher prices for BGS and NUG purchases offset by $45 million or 6% in lower BGS and NUG volumes due to economic conditions, offset by

decreased gas costs of $10 million due to $48 million or 5% lower prices offset by $38 million or 4% in higher sales volumes due to favorable weather.

•

Operation and Maintenance increased $35 million primarily due to

increases in SBC expenses of $30 million, and

$11 million of higher labor and benefits, primarily increased pension expense,

partially offset by lower materials usage of $4 million, and

lower injuries and damages of $2 million.

•

Depreciation and Amortization increased $6 million due to

increases of $4 million due to additional plant in service, and

increases of $3 million for amortization of regulatory assets,

partially offset by $1 million in capitalized depreciation and software amortization.

Other Income and Deductions decreased $4 million due to

•

$3 million in lower investment income due to current market conditions, and

•

$1 million reduction in income tax gross-ups on contributions in aid of construction (CIAC). CIAC is taxable and PSE&G recognizes the gross-up as income when collected.

Interest Expense experienced no material change.

Income Tax Expense increased $20 million primarily due to

•

$3 million on higher pre-tax income, and

•

$18 million in tax benefits taken in 2008 related to an IRS refund claim.

Energy Holdings


	Quarters Ended March 31,						Increase/ (Decrease)
	2009			2008			2009 vs 2008
	(Millions)						(Millions)
Income from Continuing Operations		$	7		$	29		$	(22	)
Income from Discontinued Operations, net of tax			—			13			(13	)

Net Income		$	7		$	42		$	(35	)

For the quarter ended March 31, 2009, the primary reasons for the $22 million decrease in Income from Continuing Operations were:

•

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

•

lower generation revenues, and

•

lower leveraged lease revenues primarily due to the tax reserve taken in mid-2008 and the sale of leveraged lease assets,

•

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

•

lower interest expense due to debt retirement.

The quarter-over-quarter details for these variances are discussed below:


	Quarters Ended March 31,								Increase/ (Decrease)
	2009				2008				2009 vs 2008
	(Millions)								(Millions)				%
Operating Revenues		$	135			$	131			$	4			3
Energy Costs			69				68				1			1
Operation and Maintenance			30				35				(5	)		(14	)
Depreciation and Amortization			7				7				—			—
Income from Equity Method Investments			10				12				(2	)		(17	)
Other Income and Deductions			3				3				—			—
Interest Expense			(19	)			(23	)			(4	)		(17	)
Income Tax (Expense) Benefit			(16	)			16				32			N/A
Income from Discontinued Operations, net of Tax			—				13				(13	)		(100	)

For the quarters ended March 31, 2009 as compared to 2008

Operating Revenues increased $4 million due to

•

a gain of $23 million on the sales and terminations of leveraged lease assets in the first quarter,

•

partially offset by lower leveraged lease revenues of $13 million, primarily due to the tax reserve taken in mid-2008, and the sale of leveraged lease assets, and

•

a decrease of $6 million in generation revenues due to lower electricity prices, partially offset by an increase in electricity sales and higher unrealized MTM gains.

Operating Expenses

•

Energy Costs experienced no material change.

•

Operation and Maintenance decreased $5 million primarily due to

a decrease of $3 million in administrative costs due to the closure of our administrative office in Texas, and

a decrease of $2 million in outside service costs.

Income from Equity Method Investments decreased $2 million primarily due to lower income from GWF Energy Expansion due to the absence of the sale of water rights in 2008.

Interest Expense decreased $4 million primarily due to lower debt balances.

Income Tax Expense increased $32 million due to

•

an increase of $23 million due to the absence of tax benefits recorded in 2008 associated with an IRS claim, and

•

an increase of $11 million as a result of the sale of leveraged lease assets in 2009,

•

partially offset by a reduction of $2 million due to other credits.

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 quarter ended March 31, 2008 totaled $13 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 quarter ended March 31, 2009, our operating cash flow increased by $346 million as compared to the same quarter in 2008. The net change was due to net changes from our subsidiaries as discussed below.

Power

Power’s operating cash flow increased $325 million from $938 million to $1,263 million for the quarter ended March 31, 2009, as compared to the same period in 2008, primarily resulting from an increase of $223 million in net cash collateral receipts and an increase of $211 million from net collections of counterparty receivables, partially offset by contributions of $78 million to the employee pension plan in 2009.

PSE&G

PSE&G’s operating cash flow decreased $45 million from $261 million to $216 million for the quarter ended March 31, 2009, as compared to the same period in 2008, primarily due to $153 million in increased pension fund contributions. This was offset by $111 million in higher recovery of regulatory assets.

Energy Holdings

Energy Holdings’ operating cash flow increased $96 million from $(138) million to $(42) million for the quarter ended March 31, 2009, as compared to the same period in 2008. The increase was mainly attributable to tax payments made in 2008 related to the sales of 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 the facility to assume loan commitments of any financial institution that fails to meet its loan commitments. As of March 31, 2009, no single institution represents 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 March 31, 2009 were as follows:


Company/Facility	March 31, 2009											Primary Purpose
Company/Facility	Total Facility			Usage				Available Liquidity			Expiration Date	Primary Purpose
	(Millions)
PSEG:
5-year Credit Facility (A)		$	1,000		$	13	(B)		$	987	Dec 2012	CP Support/Funding/ Letters of Credit
Bilateral Credit Facility			100			—				100	June 2009	CP Support/Funding
Uncommitted Bilateral Agreement			N/A			—				N/A	N/A	Funding

Total PSEG		$	1,100		$	13			$	1,087

Power:
5-year Credit Facility (A)		$	1,600		$	192	(B)		$	1,408	Dec 2012	Funding/Letters of Credit
Bilateral Credit Facility			100			—				100	June 2009	Funding/Letters of Credit
Bilateral Credit Facility			100			24	(B)			76	March 2010	Funding/Letters of Credit
Bilateral Credit Facility			50			—				50	Sep 2009	Funding

Total Power		$	1,850		$	216			$	1,634

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

Total PSE&G		$	600		$	—			$	600

Energy Holdings
5-year Credit Facility		$	136		$	3	(B)		$	133	June 2010	Funding/Letters of Credit

Total		$	3,686		$	232			$	3,454

(A)

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

(B)

These amounts relate to letters of credit outstanding.

On April 3, 2009, Power executed a $150 million bilateral credit agreement to replace a $150 million credit agreement that expired during March 2009. The new credit agreement is available for funding and the issuance of letters of credit and expires on September 30, 2009.

In the second and third quarters of 2009, $250 million of bilateral credit facilities at PSEG and Power are scheduled to expire. While we expect to request renewal of each of these facilities, no assurances can be given that such facilities will be renewed or renewed on comparable terms.

Long-Term Debt Financing

In February 2009, Energy Holdings redeemed the remaining $280 million outstanding non-recourse project debt associated with the assets of PSEG Texas. The debt was scheduled to mature on December 31, 2009. PSEG and PSE&G have $249 million and $60 million, respectively, of debt maturities upcoming in 2009, excluding securitized and nonrecourse debt. These maturities will occur in late May 2009 for PSE&G and during the third and fourth quarters for PSEG. We believe that we will be able to refinance or retire these obligations assuming continued access to the capital markets. For a discussion of our long-term debt transactions during 2009, see Note 6. Changes in Capitalization.

Common Stock Dividends and Repurchases

Dividend payments on common stock for the quarter ended March 31, 2009 were $0.3325 per share and totaled $168 million. Dividend payments on common stock for the quarter ended March 31, 2008 were $0.3225 per share and totaled $164 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.

On April 21, 2009, our Board of Directors approved a common stock dividend of $0.3325 per share for the second quarter of 2009. This reflects an indicated annual dividend rate of $1.33 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our business, 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, PSE&G, Power and Energy Holdings.


	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	A3	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 $778 million as compared to amounts previously reported, primarily due to $694 million of spending accelerated from later years under the Capital Economic Stimulus Program approved by the BPU in April 2009. These expenditures will be financed by a combination of external capital and internally generated funds.

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 quarter ended March 31, 2009, Power made $162 million of capital expenditures (excluding $45 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 5. Commitments and Contingent Liabilities.

PSE&G

During the quarter ended March 31, 2009, PSE&G made $194 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $194 million does not include expenditures for cost of removal, net of salvage, of $9 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 gains or 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, load-serving contracts (both gas and electric), 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 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.

Increased trading activities during 2009 have led to a higher VaR as compared to December 31, 2008. As of March 31, 2009, trading VaR was $2 million. As of December 31, 2008, trading VaR was $1 million.


For the Quarter Ended March 31, 2009	Trading VaR				MTM VaR Non-Trading
	(Millions)
95% confidence level, Loss could exceed VaR one day in 20 days:
Period End		$	2			$	31
Average for the Period		$	1			$	33
High		$	2			$	49
Low		$	—	*		$	23
99% confidence level, Loss could exceed VaR one day in 200 days:
Period End		$	3			$	48
Average for the Period		$	1			$	52
High		$	3			$	77
Low		$	1			$	36

less than $1 million

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 March 31, 2009, 98% 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 exposure, net of collateral, as of March 31, 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 maturity of a company’s credit risk by credit rating of the counterparties.

Schedule of Credit Risk Exposure on Energy Contracts Net
Assets as of March 31, 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		$	1,543		$	402		$	1,366		2	(A)		$	935
Non-Investment Grade—External Rating			5			6			—		—				—
Investment Grade— No External Rating			7			1			7		—				—
Non-Investment Grade— No External Rating			22			22			9		—				—

Total		$	1,577		$	431		$	1,382		2			$	935

(A)

PSE&G is a counterparty with net exposure of $769 million. The remaining net exposure of $166 million is with a nonaffiliated power purchaser which is a regulated investment grade counterparty.

The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would 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 March 31, 2009, Power had 148 active counterparties.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Controls

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the first quarter of 2009 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the respective 2008 Annual Reports on Form 10-K of PSEG, Power and PSE&G, see Note 5. Commitments and Contingent Liabilities and Item 5. Other Information, Regulatory Issues.

RPM Model

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

2008 Form 10-K, Page 43. PJM submitted a filing at FERC seeking to implement certain prospective changes to the RPM model. Issues in this proceeding included:

•

the cost of new entry (CONE),

•

integration of transmission upgrades into RPM modeling,

•

recognition of locational capacity value,

•

participation in RPM by demand-side and energy efficiency resources, penalties for deficiencies and unavailability of capacity resources, and

•

the calculation of avoided cost and long-term contracting to encourage new entry.

On March 26, 2009, the FERC issued an order accepting various parts and rejecting others, including retaining CONE values and reducing RPM auction requirements to encourage participation. While we believe that the order is generally positive, we sought rehearing of this order for further adjustments to PJM’s filing.

ITEM 1A. RISK FACTORS

There are no additional Risk Factors to be added to those disclosed in Part I Item 1A of our 2008 Annual Reports on Form 10-K.

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 March 31, 2009, 2,382,200 shares were repurchased at a total price of $92 million.


2009	Total Number of Shares Purchased (A)		Average Price Per Share			Total Number of Shares Purchased as Part of Publicly Announced Plan		Approximate Dollar Value of Shares that May Yet be Purchased Under the Plan
								(Millions)
January 1–January 31		10,285		$	29.12		N/A		$	658
February 1–February 28		50,000		$	32.97		N/A		$	658
March 1–March 31		—		$	—		N/A		$	658

(A)

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Our Annual Meeting of Stockholders was held on April 21, 2009. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Act of 1934. There was no solicitation of proxies in opposition to management’s nominees as listed in the proxy statement and all of management’s nominees were elected to the Board of Directors. Details of the voting are provided below:


	Votes For				Votes Withheld
Proposal 1:
Election of Directors
Terms expiring in 2010
Albert R. Gamper, Jr.		425,996,198				9,094,619
Conrad K. Harper		426,808,991				8,281,826
Shirley Ann Jackson		414,567,330				20,523,487
David Lilley		430,440,419				4,650,398
Thomas A. Renyi		425,916,757				9,174,060
Hak Cheol Shin		430,216,359				4,874,458
	Votes For		Votes Against		Abstentions

Proposal 2:
Ratification of Appointment of Deloitte & Touche LLP as Independent Auditor		429,071,580		4,454,930		1,564,306

ITEM 5. OTHER INFORMATION

Certain information reported under the 2008 Annual Report on Form 10-K 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. References are to the related pages on the Form 10-K as printed and distributed.

FEDERAL REGULATION

Transmission Expansion

2008 Form 10-K, Page 19. PJM has approved the construction of a 500 kV transmission line running from Virginia through Maryland and Delaware and is still considering approval of the portion terminating in Lower Alloways Creek Township, New Jersey. We will be responsible for constructing and operating a portion of this line, known as the Mid-Atlantic Pathway Project (MAPP), if its portion of the line is approved. In March 2009, we obtained from FERC approval of a 150 basis point ROE adder for this project (yielding a ROE of 13.18%), 100% recovery of abandonment costs and the ability to transfer the project to an affiliate. Receipt of incentive rates is contingent upon our portion of the MAPP project being approved by PJM as a RTEP project.

In December 2008, PJM approved another transmission project, including two additional 500 kV transmission lines, and has assigned construction responsibility to PSE&G. The first line would run from Branchburg to Roseland, and the second from Roseland to Hudson. These lines are still in the design phase.

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. In October 2007, the DOE acted to designate transmission corridors within these 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 the 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. On February 18, 2009, the United States Court of Appeals for the Fourth Circuit narrowed the scope of the FERC’s back-stop siting authority. FERC has sought reconsideration of this Court of Appeals decision.

STATE REGULATION

Energy Supply

BGSS

2008 Form 10-K, Page 23. In May 2008, PSE&G requested an increase in annual BGSS revenue of $376 million, excluding Sales and Use Tax, to be effective October 1, 2008. Since that time, due to the significant downward trend in wholesale natural gas prices, we filed three revisions to the BGSS increase, a revised Stipulation (increase of 14% or $267 million), a BGSS self-implementing decrease (5% or approximately $108 million) and a second BGSS self-implementing decrease (7% or approximately $145 million). The increase in the BGSS-Residential Service Gas (RSG) rate became effective on October 3, 2008 and the decreases became effective on January 1, 2009 and March 1, 2009, respectively.

Energy Policy

Solar Initiatives

2008 Form 10-K, Page 23. 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 utility’s electric service area by providing loans to customers for the installation of solar photovoltaic (PV) systems on their premises. As of April 24, 2009, we have provided approximately $9 million in loans for approximately 2 MW of solar systems.

In February 2009, we filed a new solar initiative with the BPU called the Solar 4 All Program. Through this program, we would invest approximately $773 million to develop 120 MW of solar PV systems over a five-year horizon. The program consists of a centralized PV system (35MW), solar systems installed on distribution system poles (40MW), roof-mounted systems installed on local government buildings in our electric service territory (43MW) and roof-mounted solar systems installed in New Jersey Housing and Mortgage Finance Agency affordable housing communities (2MW). This program remains under review by the BPU.

On March 31, 2009, we also filed a new solar loan program, called “Solar Loan II”, with the BPU. This program is modeled on the original solar loan pilot program discussed above. Under Solar Loan II, we would help finance the installation of an additional 40 MW of solar systems in our electric service territory. Any remaining financing and capacity from the original solar loan program would be rolled into the new program.

Capital Economic Stimulus Infrastructure Program

2008 Form 10-K, Page 25. On January 21, 2009, we filed for approval of a capital economic stimulus infrastructure investment program. Under this initiative, we proposed to undertake $698 million of capital infrastructure investments for electric and gas programs over a 24 month period. The goal of these accelerated capital investments is to help improve the State’s economy through the creation of new jobs. This filing was made in response to the Governor of New Jersey’s proposal to help revive the economy through job growth and capital spending.

The BPU approved a settlement agreement on April 16, 2009 which identified 38 qualifying projects totaling $694 million. These projects are expected to create more than 900 new jobs. On April 28, 2009, we received the BPU’s written order which was effective May 1, 2009.

Under the program new Capital Adjustment Charges (CAC) will provide for immediate recovery of a return on program expenditures plus depreciation of the assets. The CAC’s will be adjusted each January based on forecasted program expenditures and will be subject to deferred accounting. The rates are subject to annual adjustments based on actual expenditures and actual general and economic market conditions.

Susquehanna-Roseland BPU Petition

2008 Form 10-K, Page 25. 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 of these municipalities do not apply to this line. A procedural schedule has been established, under which the BPU expects to issue a decision in December 2009. We are also in the process of seeking to obtain all necessary environmental permits for the project.

ITEM 6. EXHIBITS

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


a.	PSEG:
	Exhibit 10:	Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009
	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
b.	Power:
	Exhibit 10:	Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009
	Exhibit 12.1:	Computation of Ratios of Earnings to Fixed Charges
	Exhibit 31.2:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
	Exhibit 31.3:	Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
	Exhibit 32.2:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 32.3:	Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
c.	PSE&G:
	Exhibit 10:	Employment Agreement with Caroline Dorsa dated March 11, 2009, as amended April 24, 2009
	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: May 5, 2009

SIGNATURE

PSEG POWER LLC
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: May 5, 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: May 5, 2009