PSEG - 10-Q quarterly report FY

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

FORM 10-Q

(Mark One)

S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2008

£ 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
000-49614	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 each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


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

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No S

As of October 15, 2008, Public Service Enterprise Group Incorporated had outstanding 506,095,103 shares of its sole class of Common Stock, without par value.

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

As of October 15, 2008, 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, Dispositions and Impairments		16
	Note 4. Earnings Per Share		18
	Note 5. Commitments and Contingent Liabilities		19
	Note 6. Financial Risk Management Activities		30
	Note 7. Comprehensive Income (Loss), Net of Tax		33
	Note 8. Changes in Capitalization		34
	Note 9. Other Income and Deductions		35
	Note 10. Pension and Other Postretirement Benefits (OPEB)		36
	Note 11. Income Taxes		37
	Note 12. Financial Information by Business Segments		39
	Note 13. Fair Value Measurements		40
	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		49
	Overview of 2008		50
	Future Outlook		53
	Results of Operations		57
	Liquidity and Capital Resources		65
	Capital Requirements		70
	Accounting Matters		70
Item 3.	Qualitative and Quantitative Disclosures About Market Risk		71
Item 4.	Controls and Procedures		77
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		78
Item 1A.	Risk Factors		78
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		79
Item 5.	Other Information		79
Item 6.	Exhibits		87
	Signatures		88

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. 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 in other 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 rules, that may adversely affect our operating results.

•

Any inability of our energy transmission and distribution businesses to obtain adequate and timely rate relief and/or regulatory approvals from federal and/or 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 the capital and credit markets at reasonable pricing terms and the 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 capital market performance of our decommissioning and defined benefit plan trust funds.

•

Changes in technology and/or increased customer conservation.

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. Except as may be required by the federal securities laws, we expressly disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. 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


	For The Quarters Ended September 30,								For The Nine Months Ended September 30,
	2008				2007				2008				2007
	(Millions) (Unaudited)
OPERATING REVENUES		$	3,718			$	3,347			$	10,060			$	9,561
OPERATING EXPENSES
Energy Costs			1,899				1,588				5,552				4,885
Operation and Maintenance			610				559				1,857				1,727
Write-down of Assets			—				12				—				12
Depreciation and Amortization			214				209				597				587
Taxes Other Than Income Taxes			31				31				101				104

Total Operating Expenses			2,754				2,399				8,107				7,315

Income from Equity Method Investments			8				30				27				87

OPERATING INCOME			972				978				1,980				2,333
Other Income			95				61				285				187
Other Deductions			(107	)			(49	)			(288	)			(120	)
Interest Expense			(149	)			(184	)			(448	)			(549	)
Preferred Stock Dividends			(1	)			(1	)			(3	)			(3	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			810				805				1,526				1,848
Income Tax Expense			(334	)			(315	)			(780	)			(742	)

INCOME FROM CONTINUING OPERATIONS			476				490				746				1,106
Income from Discontinued Operations, including Gain on Disposal, net of tax expense of $160, $5, $174 and $27 for the quarters and nine months ended 2008 and 2007, respectively			180				16				208				4

NET INCOME		$	656			$	506			$	954			$	1,110

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC			507,724				508,543				508,233				507,206

DILUTED			508,326				509,090				508,890				507,966

EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS		$	0.94			$	0.96			$	1.47			$	2.18
NET INCOME		$	1.29			$	0.99			$	1.88			$	2.19

DILUTED
INCOME FROM CONTINUING OPERATIONS		$	0.94			$	0.96			$	1.47			$	2.18
NET INCOME		$	1.29			$	0.99			$	1.88			$	2.19

DIVIDENDS PAID PER SHARE OF COMMON STOCK		$	0.3225			$	0.2925			$	0.9675			$	0.8775

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2008				December 31, 2007
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	229			$	380
Accounts Receivable, net of allowances of $52 and $46 in 2008 and 2007, respectively			1,370				1,537
Unbilled Revenues			263				353
Fuel			1,077				791
Materials and Supplies			306				293
Prepayments			286				88
Restricted Funds			144				114
Derivative Contracts			143				65
Assets of Discontinued Operations			122				1,323
Deferred Income Taxes			71				—
Other			55				30

Total Current Assets			4,066				4,974

PROPERTY, PLANT AND EQUIPMENT			20,310				19,190
Less: Accumulated Depreciation and Amortization			(6,304	)			(5,994	)

Net Property, Plant and Equipment			14,006				13,196

NONCURRENT ASSETS
Regulatory Assets			5,654				5,165
Long-Term Investments			2,742				3,221
Nuclear Decommissioning Trust (NDT) Funds			1,100				1,276
Other Special Funds			144				164
Goodwill and Other Intangibles			59				51
Derivative Contracts			98				52
Other			185				200

Total Noncurrent Assets			9,982				10,129

TOTAL ASSETS		$	28,054			$	28,299

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2008				December 31, 2007
	(Millions) (Unaudited)
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	1,039			$	1,123
Commercial Paper and Loans			181				65
Accounts Payable			1,043				1,080
Derivative Contracts			307				324
Accrued Interest			160				113
Accrued Taxes			73				204
Deferred Income Taxes			—				106
Clean Energy Program			140				135
Obligation to Return Cash Collateral			181				79
Liabilities of Discontinued Operations			68				596
Other			435				450

Total Current Liabilities			3,627				4,275

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)			3,811				4,449
Regulatory Liabilities			380				419
Asset Retirement Obligations			568				542
Other Postretirement Benefit (OPEB) Costs			1,017				1,003
Accrued Pension Costs			145				203
Clean Energy Program			563				14
Environmental Costs			668				649
Derivative Contracts			173				198
Long-Term Accrued Taxes			1,200				423
Other			131				87

Total Noncurrent Liabilities			8,656				7,987

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt			6,315				6,782
Securitization Debt			1,396				1,530
Project Level, Non-Recourse Debt			301				346

Total Long-Term Debt			8,012				8,658

SUBSIDIARY’S PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2008 and 2007—795,234 shares			80				80

COMMON STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2008 and 2007—533,556,660 shares			4,753				4,732
Treasury Stock, at cost, 2008—27,461,557 shares; 2007—25,033,656 shares			(579	)			(478	)
Retained Earnings			3,701				3,261
Accumulated Other Comprehensive Loss			(196	)			(216	)

Total Common Stockholders’ Equity			7,679				7,299

Total Capitalization			15,771				16,037

TOTAL LIABILITIES AND CAPITALIZATION		$	28,054			$	28,299

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For The Nine Months Ended September 30,
	2008				2007
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	954			$	1,110
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
(Gain) Loss on Disposal of Discontinued Operations, net of tax			(187	)			—
Depreciation and Amortization			599				606
Amortization of Nuclear Fuel			75				73
Provision for Deferred Income Taxes (Other than Leases) and ITC			(71	)			45
Non-Cash Employee Benefit Plan Costs			126				138
Lease Transaction Reserves, Net of Taxes			490				—
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes			20				46
Undistributed Earnings from Affiliates			(32	)			(5	)
Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives			(77	)			16
Under Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs			(21	)			(38	)
Under Recovery of Societal Benefits Charge (SBC)			(42	)			(29	)
Cost of Removal			(33	)			(28	)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds			22				(37	)
Net Change in Certain Current Assets and Liabilities			(117	)			(326	)
Employee Benefit Plan Funding and Related Payments			(122	)			(76	)
Other			8				44

Net Cash Provided By Operating Activities			1,592				1,539

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(1,237	)			(973	)
Proceeds from Sale of Discontinued Operations			772				325
Proceeds from Sale of Property, Plant and Equipment			3				55
Proceeds from the Sale of Capital Leases and Investments			37				17
Proceeds from NDT Funds Sales			1,839				1,275
Investment in NDT Funds			(1,864	)			(1,295	)
Restricted Funds			(32	)			(4	)
NDT Funds Interest and Dividends			37				35
Other			(14	)			(24	)

Net Cash Used In Investing Activities			(459	)			(589	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans			116				(177	)
Issuance of Long-Term Debt			700				350
Issuance of Non-Recourse Debt			—				163
Issuance of Common Stock			—				82
Purchase of Common Treasury Stock			(92	)			—
Redemptions of Long-Term Debt			(1,263	)			(488	)
Repayment of Non-Recourse Debt			(38	)			(35	)
Redemption of Securitization Debt			(127	)			(121	)
Premium Paid on Early Extinguishment of Debt			(80	)			—
Cash Dividends Paid on Common Stock			(492	)			(445	)
Other			(8	)			2

Net Cash Used In Financing Activities			(1,284	)			(669	)

Effect of Exchange Rate Change			—				2

Net Increase (Decrease) in Cash and Cash Equivalents			(151	)			283
Cash and Cash Equivalents at Beginning of Period			380				100

Cash and Cash Equivalents at End of Period		$	229			$	383

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	865			$	460
Interest Paid, Net of Amounts Capitalized		$	375			$	478

See Notes to Condensed Consolidated Financial Statements.

PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For The Quarters Ended September 30,								For The Nine Months Ended September 30,
	2008				2007				2008				2007
	(Millions) (Unaudited)
OPERATING REVENUES		$	1,833			$	1,580			$	5,831			$	5,034
OPERATING EXPENSES
Energy Costs			904				712				3,360				2,894
Operation and Maintenance			282				232				796				711
Depreciation and Amortization			42				36				121				104

Total Operating Expenses			1,228				980				4,277				3,709

OPERATING INCOME			605				600				1,554				1,325
Other Income			88				56				267				162
Other Deductions			(104	)			(42	)			(282	)			(105	)
Interest Expense			(42	)			(43	)			(125	)			(119	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			547				571				1,414				1,263
Income Tax Expense			(219	)			(233	)			(571	)			(519	)

INCOME FROM CONTINUING OPERATIONS			328				338				843				744
Income (Loss) from Discontinued Operations, net of tax (expense) benefit of $(1) and $5 for the quarter and nine months ended 2007			—				1				—				(8	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	328			$	339			$	843			$	736

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

PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2008				December 31, 2007
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	22			$	11
Accounts Receivable			448				533
Accounts Receivable—Affiliated Companies, net			328				441
Fuel			1,077				791
Materials and Supplies			221				220
Derivative Contracts			124				46
Restricted Funds			28				50
Prepayments			36				26
Other			47				31

Total Current Assets			2,331				2,149

PROPERTY, PLANT AND EQUIPMENT			7,170				6,565
Less: Accumulated Depreciation and Amortization			(1,948	)			(1,814	)

Net Property, Plant and Equipment			5,222				4,751

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds			1,100				1,276
Goodwill			16				16
Other Intangibles			34				35
Other Special Funds			28				45
Derivative Contracts			65				7
Other			67				57

Total Noncurrent Assets			1,310				1,436

TOTAL ASSETS		$	8,863			$	8,336

LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	250			$	—
Accounts Payable			564				648
Short-Term Loan from Affiliate			168				238
Derivative Contracts			288				300
Accrued Interest			81				34
Other			165				118

Total Current Liabilities			1,516				1,338

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)			300				176
Asset Retirement Obligations			328				309
Other Postretirement Benefit (OPEB) Costs			138				129
Derivative Contracts			120				158
Accrued Pension Costs			54				70
Environmental Costs			55				55
Long-Term Accrued Taxes			15				26
Other			40				12

Total Noncurrent Liabilities			1,050				935

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
LONG-TERM DEBT
Total Long-Term Debt			2,653				2,902

MEMBER’S EQUITY
Contributed Capital			2,000				2,000
Basis Adjustment			(986	)			(986	)
Retained Earnings			2,806				2,438
Accumulated Other Comprehensive Loss			(176	)			(291	)

Total Member’s Equity			3,644				3,161

TOTAL LIABILITIES AND MEMBER’S EQUITY		$	8,863			$	8,336

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

PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For The Nine Months Ended September 30,
	2008				2007
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	843			$	736
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization			121				104
Amortization of Nuclear Fuel			75				73
Interest Accretion on Asset Retirement Obligations			19				17
Provision for Deferred Income Taxes and ITC			69				191
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives			(45	)			28
Non-Cash Employee Benefit Plan Costs			18				21
Net Realized (Gains) Losses and (Income) Expense from NDT Funds			22				(37	)
Net Change in Working Capital:
Fuel, Materials and Supplies			(287	)			(49	)
Margin Deposit Asset			146				(31	)
Margin Deposit Liability			18				(2	)
Accounts Receivable			45				(38	)
Accounts Payable			(118	)			(179	)
Accounts Receivable/Payable-Affiliated Companies, net			209				191
Accrued Interest Payable			47				46
Other Current Assets and Liabilities			5				(5	)
Employee Benefit Plan Funding and Related Payments			(20	)			(13	)
Other			42				(5	)

Net Cash Provided By Operating Activities			1,209				1,048

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(677	)			(501	)
Short-Term Loan—Affiliated Company, net			—				(37	)
Proceeds from Sale of Discontinued Operations			—				325
Sales of Property, Plant and Equipment			2				40
Proceeds from NDT Funds Sales			1,839				1,275
NDT Funds Interest and Dividends			37				35
Investment in NDT Funds			(1,864	)			(1,295	)
Restricted Funds			22				—
Other			(12	)			(15	)

Net Cash Used In Investing Activities			(653	)			(173	)

CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid			(475	)			(825	)
Short-Term Loan—Affiliated Company, net			(70	)			(54	)

Net Cash Used In Financing Activities			(545	)			(879	)

Net Increase (Decrease) in Cash and Cash Equivalents			11				(4	)
Cash and Cash Equivalents at Beginning of Period			11				13

Cash and Cash Equivalents at End of Period		$	22			$	9

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	458			$	266
Interest Paid, Net of Amounts Capitalized		$	84			$	89

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

[THIS PAGE INTENTIONALLY LEFT BLANK]

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For The Quarters Ended September 30,								For The Nine Months Ended September 30,
	2008				2007				2008				2007
	(Millions)
	(Unaudited)
OPERATING REVENUES		$	2,274			$	2,106			$	6,750			$	6,340
OPERATING EXPENSES
Energy Costs			1,521				1,341				4,527				4,083
Operation and Maintenance			313				308				993				947
Depreciation and Amortization			161				161				443				449
Taxes Other Than Income Taxes			31				31				101				104

Total Operating Expenses			2,026				1,841				6,064				5,583

OPERATING INCOME			248				265				686				757
Other Income			2				2				9				12
Other Deductions			(2	)			(1	)			(3	)			(3	)
Interest Expense			(82	)			(85	)			(244	)			(250	)

INCOME BEFORE INCOME TAXES			166				181				448				516
Income Tax Expense			(68	)			(74	)			(161	)			(214	)

NET INCOME			98				107				287				302
Preferred Stock Dividends			(1	)			(1	)			(3	)			(3	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	97			$	106			$	284			$	299

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


	September 30, 2008				December 31, 2007
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	42			$	32
Accounts Receivable, net of allowances of $51 in 2008 and $45 in 2007			886				995
Unbilled Revenues			263				353
Materials and Supplies			65				53
Prepayments			214				57
Restricted Funds			6				7
Derivative Contracts			—				1
Deferred Income Taxes			43				44

Total Current Assets			1,519				1,542

PROPERTY, PLANT AND EQUIPMENT			12,033				11,531
Less: Accumulated Depreciation and Amortization			(4,065	)			(3,920	)

Net Property, Plant and Equipment			7,968				7,611

NONCURRENT ASSETS
Regulatory Assets			5,654				5,165
Long-Term Investments			156				153
Other Special Funds			47				57
Other			105				109

Total Noncurrent Assets			5,962				5,484

TOTAL ASSETS		$	15,449			$	14,637

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


	September 30, 2008			December 31, 2007
	(Millions) (Unaudited)
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	495		$	429
Commercial Paper and Loans			181			65
Accounts Payable			365			325
Accounts Payable—Affiliated Companies, net			336			559
Accrued Interest			59			56
Accrued Taxes			3			29
Clean Energy Program			140			135
Derivative Contracts			21			20
Obligation to Return Cash Collateral			181			79
Other			204			239

Total Current Liabilities			1,985			1,936

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC			2,530			2,440
Other Postretirement Benefit (OPEB) Costs			821			821
Accrued Pension Costs			20			63
Regulatory Liabilities			380			419
Clean Energy Program			563			14
Environmental Costs			613			594
Asset Retirement Obligations			239			231
Derivative Contracts			57			36
Long-Term Accrued Taxes			75			75
Other			31			9

Total Noncurrent Liabilities			5,329			4,702

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt			3,088			3,102
Securitization Debt			1,396			1,530

Total Long-Term Debt			4,484			4,632

PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2008 and 2007—795,234 shares			80			80

COMMON STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2008 and 2007—132,450,344 shares			892			892
Contributed Capital			170			170
Basis Adjustment			986			986
Retained Earnings			1,521			1,237
Accumulated Other Comprehensive Income			2			2

Total Common Stockholder’s Equity			3,571			3,287

Total Capitalization			8,135			7,999

TOTAL LIABILITIES AND CAPITALIZATION		$	15,449		$	14,637

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


	For The Nine Months Ended September 30,
	2008				2007
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	287			$	302
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization			443				449
Provision for Deferred Income Taxes and ITC			33				(114	)
Non-Cash Employee Benefit Plan Costs			97				104
Non-Cash Interest Expense			11				9
Cost of Removal			(33	)			(28	)
Employee Benefit Plan Funding and Related Payments			(92	)			(53	)
Over Recovery of Electric Energy Costs (BGS and NTC)			32				1
Under Recovery of Gas Costs			(53	)			(39	)
Under Recovery of SBC			(42	)			(29	)
Other Non-Cash Charges			(3	)			(2	)
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues			198				9
Materials and Supplies			(12	)			(8	)
Prepayments			(157	)			(184	)
Accrued Taxes			(26	)			(1	)
Accrued Interest			3				(3	)
Accounts Payable			40				72
Accounts Receivable/Payable-Affiliated Companies, net			(264	)			(201	)
Obligation to Return Cash Collateral			102				12
Other Current Assets and Liabilities			(19	)			(47	)
Other			—				(5	)

Net Cash Provided By Operating Activities			545				244

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(534	)			(421	)
Proceeds from the Sale of Property, Plant and Equipment			1				3
Restricted Funds			(1	)			(1	)

Net Cash Used In Investing Activities			(534	)			(419	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt			116				173
Issuance of Long-Term Debt			700				350
Redemption of Long-Term Debt			(651	)			(113	)
Redemption of Securitization Debt			(127	)			(121	)
Deferred Issuance Costs			(4	)			(3	)
Premium Paid on Early Retirement of Debt			(32	)			—
Cash Dividends Paid on Common Stock			—				(100	)
Preferred Stock Dividends			(3	)			(3	)

Net Cash (Used In) Provided By Financing Activities			(1	)			183

Net Increase In Cash and Cash Equivalents			10				8
Cash and Cash Equivalents at Beginning of Period			32				28

Cash and Cash Equivalents at End of Period		$	42			$	36

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	109			$	301
Interest Paid, Net of Amounts Capitalized		$	235			$	241

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 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 as to any other company.

Note 1. Organization and Basis of Presentation

Organization

PSEG

PSEG has four principal direct wholly owned subsidiaries: Power, PSE&G, PSEG Energy Holdings L.L.C. (Energy Holdings) and PSEG Services Corporation (Services).

Power

Power 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: PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). Fossil and Nuclear own and operate generation and generation-related facilities. ER&T is responsible for day-to-day management of Power’s portfolio. Fossil, Nuclear and ER&T are subject to regulation by the Federal Energy Regulatory Commission (FERC) and Nuclear is also subject to regulation by the Nuclear Regulatory Commission (NRC).

PSE&G

PSE&G is an operating public utility engaged principally in the transmission of electric energy and distribution of electric energy and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC.

PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), are wholly owned, bankruptcy-remote subsidiaries of PSE&G that purchased certain transition properties from PSE&G and issued transition bonds secured by such properties. The transition properties consist principally of the statutory rights to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G’s transition costs related to deregulation, as approved by the BPU.

Energy Holdings

Energy Holdings has two principal direct wholly owned subsidiaries: PSEG Global L.L.C. (Global), which primarily develops, owns and operates domestic projects engaged in generation of energy and PSEG Resources L.L.C. (Resources), which has invested primarily in energy-related leveraged leases. Energy Holdings also owns Enterprise Group Development Corporation (EGDC), a commercial real estate property management business.

Global has reduced its international risk by monetizing the majority of its international investments. In July 2008, Global closed on the sale of its largest remaining international investment in the SAESA Group, and its sale of Bioenergie S.p.A. (Bioenergie), its investment in Italy, is pending. For additional information, see Note 3. Discontinued Operations, Dispositions and Impairments. Global’s remaining international investments in Venezuela and India had a total net book value of $52 million as of September 30, 2008.

Services

Services provides management and administrative and general services to PSEG and its subsidiaries. These include accounting, treasury, financial risk management, law, tax, planning, information technology, investor relations and certain other services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to intercompany service agreements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Basis of Presentation

PSEG, Power and PSE&G

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, 2007 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 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, 2007.

Reclassifications

PSEG and Power

Certain reclassifications have been made to the prior period financial statements to conform to the 2008 presentation. In accordance with a new policy established in the first quarter of 2008 resulting from the adoption of a new accounting standard, Power has adjusted its Condensed Consolidated Balance Sheet as of December 31, 2007 to net the fair value of cash collateral receivables and payables with the corresponding net derivative balances. See Note 2. Recent Accounting Standards for additional information. In addition, operating results for the SAESA Group and Bioenergie were reclassified to Income (Loss) from Discontinued Operations on the Condensed Consolidated Statements of Operations of PSEG for the quarter and nine months ended September 30, 2007. See Note 3. Discontinued Operations, Dispositions and Impairments.

Note 2. Recent Accounting Standards

The accounting standards discussed below were issued by the Financial Accounting Standards Board (FASB), but have not yet been adopted by PSEG, Power or PSE&G.

PSEG, Power and PSE&G will adopt the following new standards effective January 1, 2009 and do not anticipate a material impact to their respective financial statements upon adoption.

•

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

In December 2007, the FASB issued SFAS 141(R) which will change financial accounting and reporting of business combination transactions. It is based on the principle that all assets acquired and liabilities assumed in a business combination should be measured at their acquisition date fair values, with limited exceptions. This standard applies to all transactions and events in which an entity obtains control of one or more businesses of an acquiree. The standard also expands the definition of a business. A transaction formerly recorded as an asset acquisition may qualify as a business combination under SFAS 141(R). It also requires that acquisition-related costs and certain restructuring costs be recognized separately from the business combination.

Any business combinations for which the acquisition date is on or after January 1, 2009 will be accounted for under this new guidance.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

•

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

In December 2007, the FASB issued SFAS 160 which significantly changes the financial reporting relationship between a parent and non-controlling interests (i.e. minority interests). SFAS 160 requires all entities to report minority interests in subsidiaries as a separate component of equity in the consolidated financial statements. Accordingly, the amount of net income attributable to the noncontrolling interest is required to be included in consolidated net income on the face of the income statement. Further, SFAS 160 requires that transactions between a parent and noncontrolling interests should be treated as equity. However, if a subsidiary is deconsolidated, a parent is required to recognize a gain or loss.

SFAS 160 will be applied prospectively, except for presentation and disclosure requirements which are required to be applied retrospectively.

•

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

In March 2008, the FASB issued SFAS 161 which expands derivative disclosures by requiring an entity to disclose: i) an understanding of how and why an entity uses derivatives, ii) an understanding of how derivatives and related hedged items are accounted for and iii) transparency into the overall impact of derivatives on an entity’s financial statements.

•

FASB Staff Position (FSP) FAS 142-3, “Determination of the Useful Life of Intangible Assets” (FSP FAS 142-3)

In April 2008, the FASB issued FSP FAS 142-3 to amend the factors an entity should consider in determining the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The FSP would allow an entity to consider its own experience regarding renewals and extensions, as long as an entity’s own experience is consistent with the intended use of similar assets. If an entity lacks such experience, it would look to market participant information that is consistent with the highest and best use of the asset and make adjustments for other entity-specific factors.

•

Emerging Issues Task Force (EITF) Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Guarantee” (EITF 08-5)

In September 2008, the FASB ratified the EITF 08-5 consensus on fair valuing of liabilities that are recognized or disclosed at fair value and have third party guarantees or other third party credit enhancements. Under EITF 08-5, an issuer of a liability with third party guarantees or other third party credit enhancements would not include the effect of the third party guarantees (or credit enhancements) in the fair value measurement of the liability.

PSEG, Power and PSE&G will adopt the following new standard when effective. They do not anticipate a material impact to their respective financial statements upon adoption.

•

FSP FAS 133-1 and FASB Interpretation (FIN) 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (FSP FAS 133-1 and FIN 45-4)

In September 2008, the FASB issued FSP FAS 133-1 and FIN 45-4 to require enhanced disclosures for credit derivatives within the scope of SFAS 133 and all financial guarantees subject to FIN 45.

The FSP amends FAS 133 to require sellers of credit derivatives, including credit derivatives embedded in hybrid instruments, to disclose information that would enable users of the financial information to assess the potential effect of the instruments on the reporting company’s financial position. It also amends FIN 45 to require guarantors to disclose the current status of the payment / performance risk.

FSP FAS 133-1 and FIN 45-4 are effective for reporting periods ending after November 15, 2008. Earlier adoption is encouraged. PSEG, Power and PSE&G will include additional disclosures, as suggested by this FSP, in their annual financial statements for 2008 and subsequent interim and annual periods and do not anticipate a material impact to their respective financial statements upon adoption.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

FSP FAS 133-1 and FIN 45-4 also clarify the effective date for SFAS 161, stating that the disclosure requirements of SFAS 161 will be effective for quarterly periods beginning after November 15, 2008 and fiscal years that include those periods.

The following new accounting standards were adopted by PSEG, Power and PSE&G during 2008.

•

SFAS No. 157, “Fair Value Measurements” (SFAS 157)

PSEG, Power and PSE&G

In September 2006, the FASB issued SFAS 157 which provides a single definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Prior to SFAS 157, guidance for applying fair value was incorporated into several accounting pronouncements. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources (observable inputs) and those based on an entity’s own assumptions (unobservable inputs). Under SFAS 157, fair value measurements are disclosed by level within that hierarchy, with the highest priority being quoted prices in active markets.

PSEG, Power and PSE&G adopted SFAS 157 (except for certain non-financial assets and non-financial liabilities as described in FSP FAS 157-2) effective January 1, 2008. In accordance with the provisions of SFAS 157, PSEG recorded a cumulative effect adjustment of $22 million (after-tax) to January 1, 2008 Retained Earnings associated with the implementation of SFAS 157. In February 2008, the FASB issued FSP FAS 157-2 to partially defer the effective date of SFAS 157 for certain nonfinancial assets and nonfinancial liabilities. In February 2008, the FASB issued FSP FAS 157-1 to exclude leasing transactions from SFAS 157’s scope. In October 2008, the FASB also issued FSP FAS 157-3 to address entities’ concerns about lack of observable markets or observable inputs in determining the fair value of a financial asset when the market for that asset is not active.

For additional information, see Note 13. Fair Value Measurements.

•

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)

In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other items at fair value that would not otherwise be required to be measured at fair value. An entity would report unrealized gains and losses in earnings at each subsequent reporting date on items for which the fair value option has been elected. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The decision whether to elect the fair value option is applied instrument by instrument, with a few exceptions. The decision is irrevocable and it is required to be applied only to entire instruments and not to portions of instruments.

The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities; and (b) between assets and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS 159 was effective for financial statements issued for fiscal years beginning after November 15, 2007. Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative-effect adjustment to the opening balance of Retained Earnings.

PSEG, Power and PSE&G adopted SFAS 159 effective January 1, 2008; however, to date, PSEG, Power and PSE&G have not elected to measure any of their respective assets or liabilities at fair value under this standard.

•

FSP FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1)

PSEG and Power

In April 2007, the FASB issued FSP FIN 39-1, which amends FIN 39, “Offsetting of Amounts Related to Certain Contracts” to permit an entity to offset cash collateral paid or received against fair value amounts recognized for derivative instruments held with the same counterparty under the same master netting arrangement.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

PSEG and Power adopted the FSP effective January 1, 2008. In accordance with the provisions of FSP FIN 39-1, PSEG and Power established a policy of netting fair value cash collateral receivables and payables with the corresponding net derivative balances. The adoption of FSP FIN 39-1 resulted in PSEG and Power including cash collateral received of $16 million in their net derivative positions as of September 30, 2008. Amounts in prior period statements have been retroactively adjusted, as required under the FSP.

Note 3. Discontinued Operations, Dispositions and Impairments

Discontinued Operations

Power

Lawrenceburg Energy Center (Lawrenceburg)

In May 2007, Power completed the sale of Lawrenceburg, a 1,096-megawatt (MW), gas-fired combined cycle electric generating plant located in Lawrenceburg, Indiana, to AEP Generating Company, a subsidiary of American Electric Power Company, Inc. for a sale price of $325 million.

Lawrenceburg’s operating results for the quarter and nine months ended September 30, 2007, which are included in Discontinued Operations, are summarized below:


	Quarter Ended September 30, 2007			Nine Months Ended September 30, 2007
	(Millions)
Operating Revenues		$	—		$	—
Income (Loss) Before Income Taxes		$	2		$	(13	)
Net Income (Loss)		$	1		$	(8	)

Energy Holdings

Bioenergie

In August 2008, Global entered into an agreement to sell its 85% ownership interest in Bioenergie, which owns three biomass generation plants in Italy through its ownership of 100% of San Marco Bioenergie S.p.A. and 50% of Biomasse for $42 million. A $4 million down payment was made by the purchaser in conjunction with the execution of the agreement. The sale is pending.

Bioenergie’s operating results for the quarters and nine months ended September 30, 2008 and 2007, which are included in Discontinued Operations, are summarized below:


	Quarters Ended September 30,							Nine Months Ended September 30,
	2008				2007			2008				2007
	(Millions)
Operating Revenues		$	13			$	10		$	35			$	10
Income (Loss) Before Income Taxes		$	(29	)		$	1		$	(28	)		$	(10	)
Net Income (Loss)		$	(8	)		$	1		$	(9	)		$	(13	)

Bioenergie’s operating results for the quarter and nine months ended September 30, 2008 include a pre-tax impairment charge of $33 million and related tax benefits of $13 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The carrying amounts of Bioenergie’s assets as of September 30, 2008 and December 31, 2007 are summarized in the following table:


	As of September 30, 2008			As of December 31, 2007
	(Millions)
Current Assets		$	25		$	23
Noncurrent Assets			97			138

Total Assets of Discontinued Operations		$	122		$	161

Current Liabilities		$	21		$	21
Noncurrent Liabilities			47			55

Total Liabilities of Discontinued Operations		$	68		$	76

SAESA Group

In June 2008, Global signed an agreement to sell its investment in the SAESA Group, which consists of four distribution companies, one transmission company and a generation facility located in Chile. The sale was completed in July 2008 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, which is reported as Gain on Disposal of Discontinued Operations. Net cash proceeds, after Chilean and U.S. taxes of $269 million, were $612 million. A tax charge of $82 million was recognized in the fourth quarter of 2007 relating to the discontinuation of applying Accounting Principle Board No. 23, “Accounting for Income Taxes—Special Areas.”

SAESA Group’s operating results for the quarters and nine months ended September 30, 2008 and 2007, which are included in Discontinued Operations, are summarized below:


	Quarters Ended September 30,							Nine Months Ended September 30,
	2008				2007			2008			2007
	(Millions)
Operating Revenues		$	38			$	119		$	379		$	317
Income (Loss) Before Income Taxes		$	(5	)		$	11		$	36		$	40
Net Income		$	1			$	10		$	30		$	35

The carrying amounts of SAESA Group’s assets as of December 31, 2007 are summarized in the following table:


	As of December 31, 2007
	(Millions)
Current Assets		$	191
Noncurrent Assets			971

Total Assets of Discontinued Operations		$	1,162

Current Liabilities		$	130
Noncurrent Liabilities			390

Total Liabilities of Discontinued Operations		$	520

Electroandes S.A. (Electroandes)

On October 17, 2007, Global sold its investment in Electroandes, a hydro-electric generation and transmission company in Peru that owns and operates four hydro-generation plants with total capacity of 180 MW and 437 miles of electric transmission lines, for a total purchase price of $390 million, including the assumption of approximately $108 million of debt.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Electroandes’ operating results for the quarter and nine months ended September 30, 2007, which are included in Discontinued Operations, are summarized below:


	Quarter Ended September 30, 2007			Nine Months Ended September 30, 2007
	(Millions)
Operating Revenues		$	14		$	38
Income Before Income Taxes		$	7		$	14
Net Income (Loss)		$	4		$	(10	)

Dispositions

Power

In December 2006, Power recorded a pre-tax impairment loss of $44 million to write down four turbines to their estimated realizable value and reclassified them to Assets Held for Sale on Power’s Condensed Consolidated Balance Sheet. In April 2007, Power sold the four turbines to a third party and received proceeds of approximately $40 million, which approximated the recorded book value.

Energy Holdings

Chilquinta Energia S.A. (Chilquinta) and Luz del Sur S.A.A. (LDS)

In December 2007, Global closed on the sales of its ownership interest in the Chilean electric distributor, Chilquinta and its affiliates, and in the Peruvian electric distributor, LDS and its affiliates, for $685 million. Net cash proceeds after taxes were approximately $480 million, which resulted in an after-tax loss of $23 million.

Thermal Energy Development Partnership, L.P. (Tracy Biomass)

In January 2007, Global sold its interest in Tracy Biomass for approximately $7 million, resulting in a 2007 pre-tax gain of approximately $7 million ($6 million after-tax).

Impairments

Energy Holdings

Venezuela

PSEG has indirect ownership interests in two generating facilities in Maracay and Cagua, Venezuela that have a total capacity of 120 MW. The projects are owned and operated by Turboven Company Inc. (Turboven), an entity which is jointly-owned by Global (50%) and Corporacion Industrial de Energia (CIE). Global also has a 9% indirect interest in Turbogeneradores de Maracay through a partnership with CIE.

During 2007, the Venezuelan government announced its intention to nationalize certain sectors of Venezuelan industry and commerce, including Turboven. Global entered into valuation discussions with the government of Venezuela as part of the nationalization efforts and, based upon a review of the circumstances in September 2007, recorded an impairment charge of $11 million ($7 million, after-tax), reflecting Global’s estimated market valuation of the project.

Note 4. Earnings Per Share (EPS)

PSEG

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:


	Quarters Ended September 30,												Nine Months Ended September 30,
	2008						2007						2008						2007
	Basic			Diluted			Basic			Diluted			Basic			Diluted			Basic			Diluted
EPS Numerator: Earnings (Millions)
Continuing Operations		$	476		$	476		$	490		$	490		$	746		$	746		$	1,106		$	1,106
Discontinued Operations			180			180			16			16			208			208			4			4

Net Income		$	656		$	656		$	506		$	506		$	954		$	954		$	1,110		$	1,110

EPS Denominator: (Thousands)
Weighted Average Common Shares Outstanding			507,724			507,724			508,543			508,543			508,233			508,233			507,206			507,206
Effect of Stock Options			—			369			—			547			—			435			—			711
Effect of Stock Performance Units			—			176			—			—			—			153			—			49
Effect of Restricted Stock			—			57			—			—			—			69			—			—

Total Shares			507,724			508,326			508,543			509,090			508,233			508,890			507,206			507,966

EPS:
Continuing Operations		$	0.94		$	0.94		$	0.96		$	0.96		$	1.47		$	1.47		$	2.18		$	2.18
Discontinued Operations			0.35			0.35			0.03			0.03			0.41			0.41			0.01			0.01

Net Income		$	1.29		$	1.29		$	0.99		$	0.99		$	1.88		$	1.88		$	2.19		$	2.19

Note 5. Commitments and Contingent Liabilities

Guaranteed Obligations

Power

Power contracts for electricity, natural gas, oil, coal, pipeline capacity, transportation and emission allowances and engages in risk management activities through ER&T. These activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are executed with numerous counterparties and brokers. Counterparties and brokers may require guarantees, cash or cash-related instruments to be deposited on these transactions as described below.

Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York), in commodity-related transactions to support current exposure, interest and other costs on sums due and payable in the ordinary course of business. These payment 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. The face value of the guarantees outstanding as of September 30, 2008 and December 31, 2007 was $1.8 billion and $1.5 billion, respectively.

In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T and Power New York would have to fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee and all of ER&T’s and Power New York’s contracts would have to be “out-of- the-money” (if the contracts are terminated, Power would owe money to the counterparties). The probability of all contracts at ER&T and Power New York being simultaneously “out-of-the-money” 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 to Power under these guarantees if ER&T and/or

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Power New York were to default. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $412 million and $521 million as of September 30, 2008 and December 31, 2007, respectively.

Power is subject to counterparty collateral calls related to commodity contracts and is subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s agreements. Changes in commodity prices, including fuel, emissions allowances and electricity, 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. Generally, such futures contracts require a deposit of cash margin with brokers, the amount of which is subject to change based on market movement and in accordance with exchange rules. These margins decreased significantly in the third quarter of 2008 due to decreasing commodity prices. As of September 30, 2008 and December 31, 2007, Power had the following margin posted and received no additional demands to satisfy collateral obligations:


	As of September 30, 2008			As of December 31, 2007
	(Millions)
Letters of Credit Margin Posted		$	258		$	186
Letters of Credit Margin Received		$	109		$	42
Net Cash Margin Deposited		$	2		$	166

Power has established a policy of netting fair value cash collateral receivables and payables with the corresponding net energy contract balances. As a result, Power has included net cash collateral received of $16 million and net cash collateral paid of $86 million in its corresponding net energy contract positions as of September 30, 2008 and December 31, 2007, respectively. The remaining balance of net cash margin deposited shown above is primarily included in Accounts Receivable on Power’s Condensed Consolidated Balance Sheets.

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 that ER&T provide further performance assurance. As of September 30, 2008, if Power were to lose its investment grade rating, ER&T could be required to post additional collateral of approximately $825 million. Power has sufficient liquidity to post such collateral. As of September 30, 2008, there was $2.8 billion of available liquidity under PSEG and Power’s credit facilities that could be used to post collateral.

In addition to amounts discussed above, Power had posted $52 million in letters of credit as of September 30, 2008 and $39 million in letters of credit as of December 31, 2007 to support various other contractual and environmental obligations.

Environmental Matters

PSEG, Power and PSE&G

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).

PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the Passaic River facility. The operations included one operating electric generating station (Essex Site), one former generating station and four former manufactured gas plants (MGPs). PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the Societal Benefits Clause (SBC). PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilities arising out of the site in connection with the sale. The Essex Site was transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Essex Site.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

In 2003, the EPA notified 41 potentially responsible parties (PRPs), including Power and PSE&G, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances had been released from the Essex Site and a former MGP located in Harrison, New Jersey (Harrison Site), which also includes facilities for PSE&G’s ongoing gas operations. The EPA estimated that its study would require five to eight years to complete and would cost $20 million, of which it would seek to recover $10 million from the PRPs, including Power and PSE&G.

In 2006, the EPA notified the PRPs that the cost of its study will greatly exceed the $20 million initially estimated and after discussion, 73 PRPs, including Power and PSE&G, have agreed to assume responsibility for the study pursuant to an Administrative Order on Consent 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 allocable to Power and PSE&G varies depending on the number of PRPs who have agreed to divide the costs but it currently approximates 6%, approximately 80% of which is attributable to PSE&G’s former MGPs and approximately 20% to Power’s generating station. Power has provided notice to insurers concerning this potential claim.

In June 2007, the EPA announced a draft Focused Feasibility Study (FFS) that proposes six options with estimated costs ranging from $900 million to $2.3 billion to address contamination cleanup in the lower eight miles of the Passaic River in addition to a “No Action” alternative. The work contemplated by the FFS is not subject to the Administrative Order on Consent or the cost sharing agreement. The EPA is reviewing comments received on the draft FFS.

In 2005, the 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 related to the PRP’s former dioxin operations and its effects on the Passaic River. In September 2008, the Court issued a case management order permitting the defendants to file third party complaints for contribution. The PRP and the other defendants have stated that they intend to join over 200 additional parties, including PSEG, Power and PSE&G.

CERCLA and the New Jersey Spill Compensation and Control Act (Spill Act) authorize federal and state trustees for natural resources to assess damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the New Jersey Department of Environmental Protection (NJDEP) requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP has regulations in effect concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. In 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that directed the 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 in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP announced that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million. In August 2007, the National Oceanic and Atmospheric Administration of the United States Department of Commerce sent a letter to PSE&G and other companies identified as PRPs notifying them that it intended to perform an assessment of injuries to natural resources and inviting the PRPs to participate. The PRPs have not agreed to participate in either of these natural resource damage initiatives.

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 PSEG.

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 the Newark Bay Study Area. The notice letter requested that the PRPs participate and fund the EPA-approved

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 (RI/FS) that OCC is conducting in the Newark Bay Study Area. The EPA considers the Newark Bay Study Area, along with the Passaic River Study Area, to be part of the Diamond Alkali Superfund Site. The notice states the EPA’s belief that hazardous substances were released from sites owned by PSEG and located on the Hackensack River. Currently five of the entities, including PSEG, are participating and partially funding the RI/FS study. The sites included two operating electric generating stations (Hudson and Kearny sites) and one former MGP. PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. The Hudson and Kearny sites were transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Hudson and Kearny sites. Power has provided notice to insurers concerning this potential claim.

Other

In June 2007, the State of New Jersey filed multiple lawsuits in New Jersey Superior Court against parties, including PSE&G, who were alleged to be responsible for injuries to natural resources in New Jersey. Included in these lawsuits was a claim against PSE&G and others arising out of PSE&G’s former Camden Coke facility, and a claim against PSE&G and others arising out of the cleanup of the Global Landfill Superfund site in Old Bridge, New Jersey. PSE&G has responded to the complaint in the natural resource damages case arising out of the former Camden Coke site and is in the process of remediating that site under its MGP program, discussed below. In March 2008, Power executed an Amended Consent Decree, which obligates the settling parties (including PSE&G) to implement remediation of the Global Landfill site and resolves the natural resource damages claim. The Amended Consent Decree was entered by the court in September 2008.

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.

PSE&G

MGP Remediation Program

PSE&G is working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites (Remediation Program). To date, 38 sites have been identified as sites requiring some level of remedial action. In addition, the NJDEP has 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 is PSE&G’s former Camden Coke facility located in Camden. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based on regulatory requirements, experience with the program and available remediation technologies.

As of December 31, 2007, PSE&G’s estimate to remediate all MGP sites to completion, as well as the anticipated costs to address MGP-related material discovered in three rivers adjacent to two former MGP sites, resulted in a range between $639 million and $812 million through 2021. In the third quarter of 2008, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined it could range between $644 million and $841 million from September 30, 2008 through 2021. Since no amount within the range was considered to be most likely, PSE&G recorded a liability of $644 million as of September 30, 2008. Of this amount, $31 million was recorded in Other Current Liabilities and $613 million was reflected in Environmental Costs in Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, PSE&G has recorded a $644 million Regulatory Asset.

Power

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

The PSD/NSR regulations, promulgated under the Clean Air Act, require major sources of certain air pollutants to obtain permits, install pollution-control technology and obtain offsets, in some circumstances,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties of up to $27,500 for each day of continued violation.

In November 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets consistent with an earlier consent decree that resolved allegations of non-compliance with PSD/NSR programs at Power’s Mercer, Hudson and Bergen generating stations. Under this agreement and the consent decree, 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.

Pursuant to this program, Power has installed selective catalytic reduction equipment at Mercer at a cost of $122 million. The cost of implementing the balance of the agreement is estimated at $475 million to $525 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. Fossil also purchased and retired emissions allowances by July 31, 2007, paid a $6 million civil penalty and has agreed to contribute $3 million for programs to reduce particulate emissions from diesel engines in New Jersey. Two particulate emissions reduction projects are in development to meet the agreement criteria. In May 2007, Mercer Units 1 and 2 commenced construction of the emission control projects. In February 2008, Hudson Unit 2 commenced construction of the emission control projects.

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 do not rely on a cap-and-trade program. In October 2008, EPA filed a petition with the U.S. Supreme Court to review the lower court’s decision. Opposition briefs and reply briefs are permitted to be filed prior to the Supreme Court deciding whether it will review the case. The full impact, if any, of this development is uncertain. Compliance with the new mercury standards is not expected to have a material impact on Power’s operations in New Jersey and Connecticut given the stringent mercury-control requirements applicable in those states, 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 Connecticut, 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. The costs for Mercer and Hudson are included in the cost estimates referred to in the PSD/NSR discussion above.

New Jersey

The regulations in New Jersey required coal-fired electric generating units to meet certain emissions limits or reduce emissions by approximately 90% by December 15, 2007, unless a one-year extension was granted by NJDEP. Companies that are parties to multi-pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012.

Power’s New Jersey facilities expected to achieve the remaining December 15, 2007 requirements through the installation of carbon injection technology at both Mercer Units. This was completed in January 2007; however, because there is some uncertainty as to whether the system can consistently achieve the required reductions, Power applied for and received from NJDEP approval of a one-year extension through a facility-specific control plan that includes the installation of baghouses at the Mercer Units in 2008. Installation is scheduled to be completed by the end of 2008.

With respect to the reductions required by December 15, 2012, Power anticipates compliance will be achieved through the installation of a baghouse at its Hudson Plant by the end of 2010.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The mercury-control technologies are also part of Power’s multi-pollutant reduction agreement, which resulted from earlier agreements that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

Connecticut

Mercury emissions control standards effective in July 2008 in Connecticut require coal-fired power plants to achieve either an emissions limit or 90% mercury removal efficiency through technology installed to control mercury emissions. Power has demonstrated compliance at its Bridgeport Harbor Station resulting from the installation of a baghouse which was placed in operation in January 2008. The total costs for the installation were approximately $157 million.

Pennsylvania

In February 2007, Pennsylvania finalized its “state-specific” requirements to reduce mercury emissions from coal-fired electric generating units. The Keystone and Conemaugh generating stations will be positioned by 2010 to meet Phase I of the Pennsylvania mercury rule by benefiting from reductions realized from the installation of controls for compliance with SO₂ and NO_x reductions. Phase II of the mercury rule will be addressed after a full evaluation of Phase I reductions.

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 as part of the one-hour standard for ozone attainment implementation. Power operates electric generation stations, major stationary sources, in the New Jersey-Connecticut severe non-attainment area that failed to meet the required NAAQS. Neither the EPA nor the states in the non-attainment areas in which Power operates have initiated the process for imposing fees in compliance with the court ruling; however, preliminary analysis suggests that penalty fees will be approximately $6 million annually. 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 below the statutory threshold through the installation of control technologies at one or more of Power’s generation stations.

NO_x Reduction

In August 2008, the NJDEP proposed revisions to NO_x emission control regulations that would impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel fired electric generation units. Although this rule is proposed but not final, as written it could have significant impact on the generation fleet, including the necessity to retire a significant portion of the peaking units by 2015 or 2016. If adopted as proposed, the rule could necessitate the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW).

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to subsurface contamination 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 each of September 30, 2008 and December 31, 2007 related to these obligations, which is included in Environmental Costs on 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 January 2006, 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 was filed with

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

the NJDEP. This allows Salem to continue operating under its existing NJPDES permit until a new permit is issued.

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.

Prior to this decision, Power had 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.

In May 2007, Power and other industry petitioners filed with the Second Circuit Court a request for a rehearing, which was denied. The parties, including Power, requested U.S. Supreme Court review of the matter. In April 2008, the U.S. Supreme Court granted the request of industry petitioners, including Power, to review the question of whether Section 316(b) of the FWPCA allows EPA to compare costs with benefits in determining the “best technology available” for minimizing adverse environmental impact at cooling water intake structures. An Oral argument is currently scheduled for December 2, 2008. It is anticipated that the U.S. Supreme Court will render a decision before the end of the 2008-2009 term.

Although the rule applies to all of Power’s electric generating units that use surface waters for once-through cooling purposes, the impact of the rule and the decision of the Second Circuit Court cannot be determined for all of Power’s facilities. Depending on the final decision of the U.S. Supreme Court, and subsequent actions by the EPA to promulgate a revised rule, the Second Circuit’s decision could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants in New Jersey and Connecticut, including Salem, Hudson, Mercer, Bridgeport and, possibly, Sewaren and New Haven, without making significant upgrades to their existing intake structures and cooling systems.

If the NJDEP and the Connecticut Department of Environmental Protection were to require installation of closed-cycle cooling or its equivalent at these once-through cooled facilities, the related costs and impacts would be material to Power and would require economic review to determine whether to continue operations at these facilities.

For example, Power’s application to renew its Salem permit, filed in February 2006 with the NJDEP, estimated the costs associated with adding cooling towers for Salem to be approximately $1 billion, of which Power’s share would be approximately $575 million. Potential costs associated with any closed-cycle cooling requirements are not included in Power’s forecasted capital expenditures.

New Generation and Development

Power

Nuclear

Power increased its generating capacity at Hope Creek and Salem Unit 2 in 2008. Phase I of the Hope Creek turbine replacement project increased the nominal capacity of the unit by 10 MW in 2005. Phase II added approximately 150 MW of nominal capacity in the second quarter of 2008. Phase I of the Salem Unit 2 turbine upgrade increased Power’s share of the nominal capacity by 14 MW in 2003. Phase II was completed and put in operation in the second quarter of 2008, concurrent with steam generator replacement and increased Power’s share of the nominal capacity by approximately 23 MW. Power’s total expenditures for these projects were $215 million (including Interest Capitalized During Construction of $24 million).

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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 32 MW nominal (14 MW at Unit 3 in 2011 and 18 MW at Unit 2 in 2012). Expenditures for this project will begin in the fourth quarter of 2008 and continue through 2013.

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 approximately $11 million which are included in Other Noncurrent Assets on Power’s and PSEG’s Condensed Consolidated Balance Sheets.

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

Power and PSE&G

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 within three business days 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 are responsible for fulfilling all the requirements of a PJM Interconnection L.L.C. (PJM) Load Serving Entity including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all 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
	2005			2006			2007			2008
36 Month Terms Ending			May 2008			May 2009			May 2010			May 2011	(a)
Load (MW)			2,840			2,882			2,758			2,840
$per kWh		$	0.06541		$	0.10251		$	0.09888		$	0.1115

(a)

Prices set in the February 2008 BGS Auction became effective on June 1, 2008 when the 2005 Auction Year agreements expired.

PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or approximately 80% of its residential gas supply annual requirements through the BGSS tariff. For additional information, see Note 14. Related-Party Transactions.

The BPU has conducted an audit of the gas procurement practices of all four New Jersey gas utilities, including PSE&G. A final report on the audit is forthcoming. The outcome of this proceeding cannot be predicted.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Minimum Fuel Purchase Requirements

Power

Power has fuel purchase commitments for coal and oil for certain of its fossil generation stations through various long-term commitments, 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 at Salem, Hope Creek and Peach Bottom.

As of September 30, 2008, the total minimum purchase requirements included in these commitments are as follows:


Fuel Type	Commitments through 2012			Power’s share
Nuclear Fuel
Uranium		$	594		$	372
Enrichment		$	397		$	245
Fabrication		$	199		$	126
Natural Gas		$	829		$	829
Coal/Oil		$	1,001		$	1,001

Energy Holdings

The generation facilities of PSEG Texas, LP (PSEG Texas), a wholly owned subsidiary of Global, have entered into gas supply agreements for its anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of September 30, 2008, PSEG Texas’ fuel purchase commitments were $45 million which support its contracted energy sales.

Regulatory Proceedings

PSEG and PSE&G

Electric Discount and Energy Competition Act (Competition Act)

In April 2007, PSE&G and 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. Notice of the filing of the Complaint was also provided to New Jersey’s Attorney General. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

In July 2007, the same 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. Briefing of the appeal has been completed.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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. PSE&G’s motion to dismiss the BPU petition is pending.

Investment Tax Credits (ITC)

The Internal Revenue Service (IRS) has issued several private letter rulings (PLRs) that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets’ regulatory lives, which for PSE&G, was terminated upon New Jersey’s electric industry deregulation in 1999. Based on this fact, in 1999, PSE&G reversed the deferred tax and ITC liability relating to the generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge due to such restructuring of the industry in New Jersey. In May 2006, the IRS issued a PLR to PSE&G, which concluded that none of the generation ITC could be passed to utility customers without violating the IRS’ normalization rules. In March 2008, the U.S. Treasury Department issued final regulations that confirmed that none of the generation-related ITC could be passed to utility customers without violating the normalization rules. PSE&G has advised the BPU of these regulations and awaits the BPU’s determination on this matter. While the issuance of the regulations is a favorable development for PSE&G, no assurance can be given as to final outcome of this issue.

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. The draft report addresses the SBC, Market Transition Charge (MTC) and Non-Utility Generation deferred balances. The BPU released the report in May 2005.

While the consultant to the BPU found that the Phase II deferral balances complied in all material respects with the BPU Orders regarding such deferrals, the consultant 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 amount in dispute is $114 million, which if required to be refunded to customers with interest through September 2008, would be $129 million.

At PSE&G’s request, the matter was transmitted to the Office of Administrative Law for the development of an evidentiary record and an initial decision. The BPU granted the request in February 2007. In May 2007, PSE&G filed a motion for Summary Judgment requesting dismissal of the matter. In September 2007, the Administrative Law Judge issued an initial decision denying PSE&G’s motion to dismiss the matter and ordering the filing of testimony and evidentiary hearings. Hearings were held in July 2008 and briefs were filed in September 2008. The BPU Staff and New Jersey Division of Rate Counsel have both asserted in briefs that the disputed amount should be refunded to customers.

While PSE&G believes the MTC methodology it used was fully litigated and resolved by the prior BPU Orders in its previous electric base rate case, deferral audit and deferral proceedings, PSE&G cannot predict the 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, bringing the total liability through 2012 to $748 million. PSE&G has recorded a discounted liability of $703 million as of September 30, 2008. Of this amount, $140 million was recorded as a current liability and $563 million as a noncurrent liability. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the SBC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Energy Holdings

Leveraged Lease Investments

In November 2006, the IRS issued its Revenue Agent’s Report 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 Report proposed a 20% penalty for substantial 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 September 30, 2008 and December 31, 2007, Resources’ total gross investment in such transactions was $1 billion and $1.5 billion, respectively.

PSEG has been in discussions with the Office of Appeals of the IRS concerning the deductions that have been disallowed. PSEG believes that its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken.

There are several 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

As a result of the recent court decisions regarding these types of leveraged lease transactions, PSEG evaluated its unrecognized tax benefits under FIN 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48), and recorded an after-tax increase to the interest reserve of $135 million in the second quarter of 2008. This charge is recorded in Income Tax Expense in PSEG’s Condensed Consolidated Statements of Operations. The after-tax increase to the interest reserve charged to income in the third quarter was $10 million.

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 is 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 will be recognized as income over the remaining term of the affected leases. In the third quarter, the additional reduction of operating revenues was $10 million with a partially offsetting reduction in income tax expense of $2 million, resulting in a net after-tax income reduction of $8 million.

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 $110 million to $130 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Cash Impact

As of September 30, 2008, an aggregate $1.2 billion would become currently payable if PSEG conceded 100% of deductions taken through that date. In December 2007, PSEG deposited $100 million with the IRS to defray potential interest costs associated with this disputed tax liability. In September 2008, PSEG deposited an additional $80 million bringing to $180 million the total cash deposited with the IRS. 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 approximately $1 billion. As of September 30, 2008, penalties of $151 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 $15 million per quarter. 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 September 30, 2008.

Based on the status of discussions with the IRS, and considering developments in other cases, PSEG currently anticipates that it will pay between $230 million and $360 million in tax, interest and penalties for the tax years 1997-2000 during the first 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 2001-2003 followed by further litigation to recover those taxes. Theses amounts are in addition to tax deposits made to date for the years referenced above.

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. Financial Risk Management

The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their results of operations and financial conditions. PSEG, Power and PSE&G manage exposure to these market risks through their regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, Power and PSE&G use the term ‘hedge’ to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the gains or losses on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, Power and PSE&G uses derivative instruments as risk management tools consistent with its respective business plan and prudent business practices.

Derivative Instruments and Hedging Activities

Energy Contracts

Power

Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil and emission allowances in the spot, forward and futures markets, primarily in PJM, New York and New Jersey and natural gas in the producing region.

Power maintains a strategy of entering into positions to optimize the value of its portfolio and reduce earnings volatility of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy seeking to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options and futures. For contracts not qualifying for hedge accounting, Power marks its derivative energy contracts to market in accordance with SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) with changes in fair value charged to the Consolidated Statements of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.

The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale contracts, swaps, options, futures and FTRs.

Cash Flow Hedges

Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of September 30, 2008, the fair value of these hedges was $(88) million. These hedges resulted in a $(69) million after-tax impact on Accumulated Other Comprehensive Loss. As of December 31, 2007, the fair value of these hedges was $(427) million. These hedges, along with realized losses on hedges of $(4) million retained in Accumulated Other Comprehensive Loss, resulted in a $(250) million after-tax impact on Accumulated Other Comprehensive Loss. During the 12 months ending September 30, 2009, $(23) million of after-tax unrealized losses on these commodity derivatives is expected to be reclassified to earnings with another $(48) million of after-tax unrealized losses to be reclassified to earnings for the 12 months ending September 30, 2010. Ineffectiveness associated with these hedges, as defined in SFAS 133, was a gain of $11 million, pre-tax, at September 30, 2008. The expiration date of the longest-dated cash flow hedge is in 2011.

Other Derivatives

Power also enters into certain other contracts that are derivatives, but do not qualify for cash flow hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations and a portion is used in Power’s Nuclear Decommissioning Trust Funds (NDT). Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs, Operating Revenues, Other Income or Other Deductions, as appropriate, on the Consolidated Statements of Operations. The net fair value of these instruments was $5 million and $(10) million as of September 30, 2008 and December 31, 2007, respectively.

Energy Holdings

Cash Flow Hedges

Energy Holdings uses forward sale and purchase contracts and swaps to hedge forecasted energy sales from one of the generation stations of its subsidiary, PSEG Texas. Energy Holdings also enters into swap transactions to hedge the price of fuel. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of September 30, 2008, the fair value of these hedges was $4 million. During the 12 months ending September 30, 2009, substantially all of the after-tax unrealized gains on these commodity derivatives are expected to be reclassified to earnings. There was no ineffectiveness associated with these hedges, as defined in SFAS 133. These hedges resulted in an after-tax impact of $2 million on Accumulated Other Comprehensive Loss. The expiration date of the longest-dated cash flow hedge is in 2009.

Other Derivatives

The generation facilities of PSEG Texas enter into electricity forward and capacity sales contracts to sell a portion of their 2,000 MW capacity with the balance sold into the daily spot market. They also enter into gas purchase contracts to specifically match the generation requirements to support the electricity forward sales contracts. Although these contracts fix the amount of revenue, fuel costs and cash flows, and thereby provide financial stability to PSEG Texas, these contracts are, based on their terms, derivatives that do not meet the specific accounting criteria in SFAS 133 to qualify for the normal purchases and normal sales exception, or to be designated as a hedge for accounting purposes. As a result, these contracts must be

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

recorded at fair value through the Consolidated Statements of Operations. The net fair value of the open positions was $60 million as of September 30, 2008 and $63 million as of December 31, 2007.

Interest Rates

PSEG, Power and PSE&G

PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed and floating rate debt and interest rate derivatives.

Fair Value Hedges

PSEG and Power

PSEG uses an interest rate swap to convert Power’s fixed-rate debt of $250 million of 3.75% Senior Notes due April 2009 into variable-rate debt. The interest rate swap is designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of September 30, 2008 and December 31, 2007, the fair value of the hedge was $(1) million and $(2) million, respectively.

Cash Flow Hedges

PSE&G

PSE&G uses interest rate swaps and other interest rate derivatives to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives used are designated and effective as cash flow hedges. As of September 30, 2008 the fair value of these cash flow hedges was $(2) million and $(4) million, respectively. The $(2) million and $(4) million as of September 30, 2008 and December 31, 2007 are deferred as Regulatory Assets and are expected to be recovered from PSE&G’s customers. As of September 30, 2008, there was no hedge ineffectiveness associated with these hedges.

Other Derivatives

Energy Holdings

Energy Holdings uses interest rate swaps at PSEG Texas to manage its exposure to variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives were previously effective as cash flow hedges; however as of September 30, 2008 they were de-designated due to a change in their underlying interest basis. The fair value of these swaps recorded in Accumulated Other Comprehensive Loss as of September 30, 2008 was ($6) million and will be amortized to earnings over the remaining life of the underlying debt. The fair value changes of the swap beginning October 2008 will be marked to market through earnings.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 7. Comprehensive Income (Loss), Net of Tax


	Power (A)				PSE&G			Other (B)				Consolidated Total
	(Millions)
For the Quarter Ended September 30, 2008:
Net Income		$	328			$	98		$	230			$	656
Other Comprehensive Income (Loss)			775				—			(75	)			700

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

For the Quarter Ended September 30, 2007:
Net Income		$	339			$	107		$	60			$	506
Other Comprehensive Income			52				—			34				86

Comprehensive Income		$	391			$	107		$	94			$	592

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

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

For the Nine Months Ended September 30, 2007:
Net Income		$	736			$	302		$	72			$	1,110
Other Comprehensive Income (Loss)			(73	)			—			54				(19	)

Comprehensive Income		$	663			$	302		$	126			$	1,091

(A)

Changes at Power primarily relate to changes in SFAS 133 unrealized gains and losses on derivative contracts that qualify for hedge accounting in 2008 and 2007, as detailed below.

(B)

Other consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations. Changes for 2008 and 2007 primarily relate to the sale of Global’s investment in SAESA Group. Refer to Note 3. Discontinued Operations, Dispositions and Impairments.

Accumulated Other Comprehensive Income (Loss)


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

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


	Balance as of December 31, 2006				Power				PSE&G			Other				Balance as of September 30, 2007
	(Millions)
For the Nine Months Ended September 30, 2007:
Derivative Contracts		$	(114	)		$	(92	)		$	—		$	(1	)		$	(207	)
Pension and OPEB Plans			(214	)			8				—			2				(204	)
Currency Translation Adjustment			110				—				—			52				162
NDT Funds			108				11				—			—				119
Other			2				—				—			1				3

		$	(108	)		$	(73	)		$	—		$	54			$	(127	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 8. Changes in Capitalization

PSEG

In October 2008, PSEG paid $49 million of its 6.89% Senior Notes.

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

Power

In September 2008, Power paid a cash dividend to PSEG of $225 million and in each of June 2008 and March 2008, Power paid a cash dividend to PSEG of $125 million.

PSE&G

In May 2008, PSE&G redeemed its outstanding $157 million of 6.375% First and Refunding Mortgage Bonds Remarketable Series YY Due 2023 Mandatorily Tendered 2008. PSE&G paid approximately $32 million in cash to settle the remarketing option held by the remarketing dealer.

In April 2008, PSE&G issued $400 million of 5.30% Medium-Term Notes, Series E due May 1, 2018.

In March 2008, PSE&G issued $300 million of Floating Rate (3-month Libor + 0.875%) Bonds due 2010.

As of December 31, 2007, PSE&G had $494 million of variable rate pollution control bonds outstanding which serviced and secured a like amount of insured tax-exempt variable rate bonds of the Pollution Control Authority of Salem County (Salem County Authority). Through April 2008, PSE&G purchased $494 million of the Salem County Authority bonds which were either being held by the broker/dealer or tendered by bondholders upon conversion of the bonds to a weekly interest rate mode. These purchases were recorded as a reduction to PSE&G’s Long-Term Debt included in its Condensed Consolidated Balance Sheets. PSE&G intends to hold these bonds until they can be remarketed or refinanced.

In September 2008, June 2008 and March 2008, Transition Funding repaid $45 million, $37 million and $40 million, respectively, of its transition bonds.

In June 2008, PSE&G Transition Funding II LLC repaid $5 million of its transition bonds.

Energy Holdings

In March 2008, Energy Holdings repurchased $5 million of its $530 million then outstanding 8.50% Senior Notes due 2011.

In February 2008, Energy Holdings repaid at maturity $207 million of its 8.625% Senior Notes.

In January 2008, Energy Holdings redeemed its outstanding $400 million of 10% Senior Notes due 2009.

During the first nine months of 2008, Energy Holdings paid $48 million in premiums related to the early redemption of its outstanding debt.

During the first nine months of 2008, Energy Holdings’ subsidiaries repaid $38 million of non-recourse debt, primarily related to the PSEG Texas generation facilities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9. Other Income and Deductions


	Power			PSE&G			Other (A)				Consolidated Total
	(Millions)
Other Income:
For the Quarter Ended September 30, 2008:
Interest and Dividend Income		$	1		$	1		$	4			$	6
NDT Fund Realized Gains			74			—			—				74
NDT Interest and Dividend Income			12			—			—				12
Other			1			1			1				3

Total Other Income		$	88		$	2		$	5			$	95

For the Quarter Ended September 30, 2007:
Interest and Dividend Income		$	5		$	2		$	(1	)		$	6
NDT Fund Realized Gains			37			—			—				37
NDT Interest and Dividend Income			12			—			—				12
Change in Derivative Fair Value			—			—			4				4
Other			2			—			—				2

Total Other Income		$	56		$	2		$	3			$	61

For the Nine Months Ended September 30, 2008:
Interest and Dividend Income		$	5		$	5		$	7			$	17
NDT Fund Realized Gains			221			—			—				221
NDT Interest and Dividend Income			37			—			—				37
Other			4			4			2				10

Total Other Income		$	267		$	9		$	9			$	285

For the Nine Months Ended September 30, 2007:
Interest and Dividend Income		$	20		$	8		$	(1	)		$	27
NDT Fund Realized Gains			102			—			—				102
NDT Interest and Dividend Income			37			—			—				37
Change in Derivative Fair Value			—			—			3				3
Arbitration Award (Konya-Ilgin)			—			—			9				9
Other			3			4			2				9

Total Other Income		$	162		$	12		$	13			$	187

(A)

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power			PSE&G			Other (A)			Consolidated Total
	(Millions)
Other Deductions:
For the Quarter Ended September 30, 2008:
NDT Fund Realized Losses and Expenses		$	39		$	—		$	—		$	39
Other-Than-Temporary Impairment of Investments			65			—			—			65
Donations			—			2			1			3

Total Other Deductions		$	104		$	2		$	1		$	107

For the Quarter Ended September 30, 2007:
NDT Fund Realized Losses and Expenses		$	26		$	—		$	—		$	26
Other-Than-Temporary Impairment of Investments			16			—			—			16
Change in Derivative Fair Value			—			—			5			5
Donations			—			1			1			2

Total Other Deductions		$	42		$	1		$	6		$	49

For the Nine Months Ended September 30, 2008:
NDT Fund Realized Losses and Expenses		$	145		$	—		$	—		$	145
NDT Fund Unrealized Losses.			1			—			—			1
Other-Than-Temporary Impairment of Investments			135			—			—			135
Donations			—			3			1			4
Loss on Early Extinguishment of Debt.			—			—			2			2
Other			1			—			—			1

Total Other Deductions		$	282		$	3		$	3		$	288

For the Nine Months Ended September 30, 2007:
NDT Fund Realized Losses and Expenses		$	62		$	—		$	—		$	62
Other-Than-Temporary Impairment of Investments			40			—			—			40
Change in Derivative Fair Value			—			—			5			5
Donations			—			2			6			8
Other			3			1			1			5

Total Other Deductions		$	105		$	3		$	12		$	120

(A)

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

Note 10. Pension and Other Postretirement Benefits (OPEB)

PSEG

PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis. OPEB costs are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Pension Benefits								OPEB								Pension Benefits								OPEB
																	Nine Months Ended September 30,								Nine Months Ended September 30,
	Quarters Ended September 30,								Quarters Ended September 30,
	2008				2007				2008				2007				2008				2007				2008				2007
	(Millions)
Components of Net Periodic Benefit Costs:
Service Cost		$	19			$	20			$	4			$	4			$	58			$	62			$	11			$	12
Interest Cost			56				55				18				18				170				163				54				54
Expected Return on Plan Assets			(72	)			(72	)			(4	)			(3	)			(217	)			(216	)			(11	)			(10	)
Amortization of Net
Transition Obligation			—				—				7				7				—				—				21				21
Prior Service Cost			2				2				4				3				7				8				10				9
Loss (Gain)			4				5				—				2				10				15				(1	)			6

Net Periodic Benefit Costs			9				10				29				31				28				32				84				92
Effect of Regulatory Asset			—				—				4				4				—				—				14				14

Total Benefit Costs.		$	9			$	10			$	33			$	35			$	28			$	32			$	98			$	106

PSEG, Power and PSE&G

Pension costs and OPEB costs for PSEG and its subsidiaries are detailed as follows:


	Pension Benefits						OPEB						Pension Benefits						OPEB
													Nine Months Ended September 30,						Nine Months Ended September 30,
	Quarters Ended September 30,						Quarters Ended September 30,
	2008			2007			2008			2007			2008			2007			2008			2007
	(Millions)
Power		$	2		$	3		$	4		$	4		$	8		$	9		$	10		$	12
PSE&G			4			4			28			30			12			14			85			90
Energy Holdings			—			—			—			—			1			1			—			—
Services			3			3			1			1			7			8			3			4

Total PSEG Consolidated Benefit Costs		$	9		$	10		$	33		$	35		$	28		$	32		$	98		$	106

PSEG contributed $75 million into its qualified pension plans and postretirement healthcare plan in 2008.

Note 11. Income Taxes

An analysis of the tax provision expense is as follows:


	Power				PSE&G				Other (A)				Consolidated Total
	(Millions)
For the Quarter Ended September 30, 2008:
Income Before Income Taxes		$	547			$	166			$	97			$	810
Tax Computed at the Statutory Rate			191				58				34				283
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit			34				11				—				45
Uncertain Tax Positions			(1	)			—				12				11
Other			(5	)			(1	)			1				(5	)

Total Income Tax Expense		$	219			$	68			$	47			$	334

Effective Income Tax Rate			40.0	%			41.0	%			48.5	%			41.2	%

For the Quarter Ended September 30, 2007:
Income Before Income Taxes		$	571			$	181			$	53			$	805

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power				PSE&G				Other (A)				Consolidated Total
	(Millions)
Tax Computed at the Statutory Rate			200				63				19				282
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit			35				12				(2	)			45
Foreign Operations			—				—				(13	)			(13	)
Uncertain Tax Positions			1				—				5				6
Other			(3	)			(1	)			(1	)			(5	)

Total Income Tax Expense		$	233			$	74			$	8			$	315

Effective Income Tax Rate			40.8	%			40.9	%			15.1	%			39.1	%

For the Nine Months Ended September 30, 2008:
Income (Loss) Before Income Taxes		$	1,414			$	448			$	(336	)		$	1,526
Tax Computed at the Statutory Rate			495				157				(117	)			535
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit			89				32				34				155
Uncertain Tax Positions			—				(22	)			131				109
Other			(13	)			(6	)			—				(19	)

Total Income Tax Expense		$	571			$	161			$	48			$	780

Effective Income Tax Rate			40.4	%			35.9	%			N/A				51.1	%

For the Nine Months Ended September 30, 2007:
Income Before Income Taxes		$	1,263			$	516			$	69			$	1,848
Tax Computed at the Statutory Rate			442				181				24				647
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit			76				36				(7	)			105
Foreign Operations			—				—				(19	)			(19	)
Uncertain Tax Positions			4				—				11				15
Other			(3	)			(3	)			—				(6	)

Total Income Tax Expense		$	519			$	214			$	9			$	742

Effective Income Tax Rate			41.1	%			41.5	%			13.0	%			40.2	%

(A)

PSEG’s other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs and amounts applicable to Energy Holdings that reflect interim period distortion due to asset sales and other one-time adjustments.

Each of PSEG, Power and PSE&G provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from PSE&G’s customers in the future. Accordingly, an offsetting Regulatory Asset was established. As of September 30, 2008, PSE&G had a Regulatory Asset of $418 million representing the tax costs expected to be recovered through rates based upon established regulatory practices, which permit recovery of current taxes payable. This amount was determined using the enacted federal income tax rate of 35% and state income tax rate of 9%.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

On December 17, 2007 and September 15, 2008, PSEG made tax deposits with the IRS in the amount of $100 million and $80 million, respectively, to defray interest costs associated with disputed tax assessments associated with certain lease investments (see Note 5. Commitments and Contingent Liabilities). The $180 million of deposits are fully refundable and are recorded as a reduction to the Unrecognized Tax Benefit liability on PSEG’s Condensed Consolidated Balance Sheets.

It is reasonably possible that the total unrecognized tax benefits (including interest) at PSEG will decrease by approximately $29 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 $9 decrease for Power, a $22 million increase for PSE&G, a $24 million decrease for Services, a $23 million decrease for Energy Holdings and a $5 million increase for PSEG parent.

As a result of a change in accounting method for the capitalization of indirect costs, during the first nine months of 2008, PSEG reduced the net amount of its unrecognized tax benefits (including interest) by $86 million, approximately $45 million of which related to PSE&G. Because the IRS agreed with PSE&G’s change in accounting method, it is reasonably possible that PSE&G’s claim related to this matter will be settled with the IRS in the next 12 months, resulting in an increase in the unrecognized tax benefits.

Note 12. Financial Information by Business Segments

Information related to the segments of PSEG and its subsidiaries is detailed below:


	Power			PSE&G				Resources				Global				Other (A)				Consolidated
	(Millions)
For the Quarter Ended September 30, 2008:
Total Operating Revenues		$	1,833		$	2,274			$	18			$	332			$	(739	)		$	3,718
Income (Loss) From Continuing Operations			328			98				(11	)			67				(6	)			476
Loss from Discontinued Operations, net of tax			—			—				—				(7	)			—				(7	)
Gain on Disposal of Discontinued Operations, net of tax			—			—				—				187				—				187
Net Income (Loss)			328			98				(11	)			247				(6	)			656
Preferred Securities Dividends			—			(1	)			—				—				1				—
Segment Earnings (Loss)			328			97				(11	)			247				(5	)			656
Gross Additions to Long-Lived Assets			293			189				1				1				14				498
For the Quarter Ended September 30, 2007:
Total Operating Revenues		$	1,580		$	2,106			$	40			$	209			$	(588	)		$	3,347
Income (Loss) From Continuing Operations			338			107				15				41				(11	)			490
Income from Discontinued Operations, net of tax			1			—				—				15				—				16
Net Income (Loss)			339			107				15				56				(11	)			506
Preferred Securities Dividends			—			(1	)			—				—				1				—
Segment Earnings (Loss)			339			106				15				56				(10	)			506
Gross Additions to Long-Lived Assets			178			125				—				5				6				314
For the Nine Months Ended September 30, 2008:
Total Operating Revenues		$	5,831		$	6,750			$	(408	)		$	645			$	(2,758	)		$	10,060
Income (Loss) From Continuing Operations			843			287				(466	)			101				(19	)			746
Income from Discontinued Operations, net of tax			—			—				—				21				—				21
Gain on Disposal of Discontinued Operations, net of tax			—			—				—				187				—				187
Net Income (Loss)			843			287				(466	)			309				(19	)			954
Preferred Securities Dividends			—			(3	)			—				—				3				—
Segment Earnings (Loss)			843			284				(466	)			309				(16	)			954
Gross Additions to Long-Lived Assets			677			534				2				4				20				1,237
For the Nine Months Ended September 30, 2007:
Total Operating Revenues		$	5,034		$	6,340			$	119			$	510			$	(2,442	)		$	9,561

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power				PSE&G				Resources			Global			Other (A)				Consolidated
	(Millions)
Income (Loss) From Continuing Operations			744				302				46			62			(48	)			1,106
Income (Loss) from Discontinued Operations, net of tax			(8	)			—				—			12			—				4
Net Income (Loss)			736				302				46			74			(48	)			1,110
Preferred Securities Dividends			—				(3	)			—			—			3				—
Segment Earnings (Loss)			736				299				46			74			(45	)			1,110
Gross Additions to Long-Lived Assets			501				421				1			33			17				973
As of September 30, 2008:
Total Assets		$	8,863			$	15,449			$	2,475		$	1,652		$	(385	)		$	28,054
Investments in Equity Method Subsidiaries		$	28			$	—			$	—		$	195		$	—			$	223
As of December 31, 2007:
Total Assets		$	8,336			$	14,637			$	2,992		$	2,340		$	(6	)		$	28,299
Investments in Equity Method Subsidiaries		$	14			$	—			$	—		$	208		$	—			$	222

(A)

PSEG’s other activities include amounts applicable to PSEG (as parent corporation) and Energy Holdings (as parent company) and EGDC 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 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 at PSEG, as parent corporation.

Note 13. Fair Value Measurements

PSEG, Power and PSE&G

Effective January 1, 2008, PSEG, Power and PSE&G adopted SFAS 157 except for non-financial assets and liabilities as described in FSP FAS 157-2 and discussed in Note 2. Recent Accounting Standards. 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, are based on the best information available and might include an entity’s own data. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist mainly of various FTRs, other longer term capacity and transportation contracts and certain commingled securities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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. Under EITF 02-3, PSEG Texas had a deferred inception loss of $34 million, pre-tax, as of December 31, 2007 related to a five-year capacity contract at its generation facilities, which was being amortized at $11 million per year through 2010. In accordance with the provisions of SFAS 157, PSEG Texas recorded a cumulative effect adjustment of $22 million after-tax to January 1, 2008 Retained Earnings in its Condensed Consolidated Balance Sheet associated with the implementation of SFAS 157.

The following table presents information about PSEG’s, Power’s, and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis at September 30, 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 September 30, 2008
Description	Total as of September 30, 2008				Cash Collateral Netting (F)				Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
	(Millions)
PSEG
*Assets:*
Derivative Contracts:
Energy Contracts (A)		$	162			$	(40	)		$	—		$	115			$	87
Other Commodity Contracts (B)		$	81			$	—			$	—		$	18			$	63
NDT Funds (D)		$	1,182			$	—			$	525		$	634			$	23
Rabbi Trusts (D)		$	137			$	—			$	12		$	111			$	14
Other Long-Term Investments (E)		$	1			$	—			$	1		$	—			$	—
*Liabilities:*
Derivative Contracts:
Energy Contracts (A)		$	(381	)		$	24			$	—		$	(428	)		$	23
Other Commodity Contracts (B)		$	(92	)		$	—			$	—		$	(15	)		$	(77	)
Interest Rate Swaps (C)		$	(8	)		$	—			$	—		$	(8	)		$	—
Power
*Assets:*
Derivative Contracts:
Energy Contracts (A)		$	189			$	(40	)		$	—		$	142			$	87
NDT Funds (D)		$	1,182			$	—			$	525		$	634			$	23
Rabbi Trusts (D)		$	28			$	—			$	2		$	23			$	3
*Liabilities:*
Derivative Contracts:
Energy Contracts (A)		$	(408	)		$	24			$	—		$	(455	)		$	23
PSE&G
*Assets:*
Derivative Contracts:
Other Commodity Contracts (B)		$	2			$	—			$	—		$	—			$	2
Rabbi Trusts (D)		$	47			$	—			$	4		$	38			$	5
*Liabilities:*
Other Commodity Contracts (B)		$	(77	)		$	—			$	—		$	—			$	(77	)
Interest Rate Swaps (C)		$	(1	)		$	—			$	—		$	(1	)		$	—

(A)

Whenever possible, fair values for energy 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. For contracts where no observable market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(B)

Other commodity contracts primarily include more complex agreements for which limited pricing information is available. These contracts are valued using modeling techniques and assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.

(C)

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.

(D)

The NDT Funds and the Rabbi Trusts maintain investments in various equity and fixed income securities classified as “available for sale” under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” These securities are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Most equity securities are priced utilizing the principal market close price or in some cases midpoint, bid or ask price (primarily Level 1). Fixed income securities are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). Short-term investments are valued based upon internal matrices using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3). The NDT Funds exclude net receivables/payables of $82 million related to pending security sales/purchases.

(E)

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

(F)

Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under FIN 39-1. For further discussion, see Note 2. Recent Accounting Standards.

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 Ending September 30, 2008


	Balance as of July 1, 2008				Total Gains or (Losses) Realized/Unrealized								Purchases and (Sales)				Balance as of September 30, 2008
	Balance as of July 1, 2008				Included in Income (A)				Included in Regulatory Assets/ Liabilities (B)				Purchases and (Sales)				Balance as of September 30, 2008
	(Millions)
PSEG Derivative Assets		$	133			$	15			$	(1	)		$	3			$	150
PSEG Derivative Liabilities		$	(69	)		$	—			$	15			$	—			$	(54	)
PSEG NDT Funds		$	32			$	(2	)		$	—			$	(7	)		$	23
PSEG Rabbi Trust Funds		$	14			$	—			$	—			$	—			$	14
Power Derivative Assets		$	83			$	1			$	—			$	3			$	87
Power Derivative Liabilities		$	23			$	—			$	—			$	—			$	23
Power NDT Funds		$	32			$	(2	)		$	—			$	(7	)		$	23
Power Rabbi Trust Funds		$	3			$	—			$	—			$	—			$	3
PSE&G Derivative Assets		$	3			$	—			$	(1	)		$	—			$	2
PSE&G Derivative Liabilities		$	(92	)		$	—			$	15			$	—			$	(77	)
PSE&G Rabbi Trust Funds		$	5			$	—			$	—			$	—			$	5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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


	Balance as of January 1, 2008				Total Gains or (Losses) Realized/Unrealized								Purchases and (Sales)				Balance as of September 30, 2008
	Balance as of January 1, 2008				Included in Income (C)				Included in Regulatory Assets/ Liabilities (B)				Purchases and (Sales)				Balance as of September 30, 2008
	(Millions)
PSEG Derivative Assets		$	44			$	53			$	(1	)		$	54			$	150
PSEG Derivative Liabilities		$	(49	)		$	20			$	(25	)		$	—			$	(54	)
PSEG NDT Funds		$	27			$	(3	)		$	—			$	(1	)		$	23
PSEG Rabbi Trust Funds		$	16			$	—			$	—			$	(2	)		$	14
Power Derivative Assets		$	13			$	20			$	—			$	54			$	87
Power Derivative Liabilities		$	3			$	20			$	—			$	—			$	23
Power NDT Funds		$	27			$	(3	)		$	—			$	(1	)		$	23
Power Rabbi Trust Funds		$	3			$	—			$	—			$	—			$	3
PSE&G Derivative Assets		$	3			$	—			$	(1	)		$	—			$	2
PSE&G Derivative Liabilities		$	(52	)		$	—			$	(25	)		$	—			$	(77	)
PSE&G Rabbi Trust Funds		$	6			$	—			$	—			$	(1	)		$	5

(A)

PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $26 million is included in Operating Revenues and $(11) million is included in Other Comprehensive Income. Of the $26 million in Operating Revenues, $14 million (unrealized) is at PSEG Texas and $12 million (unrealized) is at Power. The $(11) 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.

(C)

PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $76 million is included in Operating Revenues and $(3) million is included in Other Comprehensive Income. Of the $76 million in Operating Revenues, $33 million (unrealized) is at PSEG Texas and $43 million (unrealized) is at Power. The $(3) million included in Other Comprehensive Income is at Power.

As of September 30, 2008, PSEG carried approximately $1.1 billion of net assets that are measured at fair value on a recurring basis, of which approximately $130 million were measured using unobservable inputs and classified as level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no significant transfers in or out of Level 3 during the nine months ended September 30, 2008.

Note 14. Related-Party Transactions

The majority of the following discussion relates to intercompany transactions. These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated during the consolidation process in accordance with GAAP when preparing PSEG’s Condensed Consolidated Financial Statements.

BGS and BGSS Contracts

Power and PSE&G

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 2012 and year-to-year thereafter.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.

The amounts which Power charged to PSE&G for BGS and BGSS are presented below:


	Power’s Billings for the
	Quarters Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(Millions)
BGS		$	506		$	408		$	1,113		$	889
BGSS		$	210		$	173		$	1,606		$	1,537

As of September 30, 2008 and December 31, 2007, Power had net receivables from PSE&G of $215 million and $451 million, respectively, primarily related to the BGS and BGSS contracts.

In addition, as of September 30, 2008 and December 31, 2007, PSE&G had a payable to Power of $164 million and $55 million, respectively, related to gas supply hedges Power entered into for BGSS.

Services

Power and PSE&G

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.

The billings for administrative services and payables are presented below:


	Services’ Billings for the												Payable to Services as of
	Quarters Ended September 30,						Nine Months Ended September 30,
													September 30, 2008			December 31, 2007
	2008			2007			2008			2007
	(Millions)
Power		$	41		$	34		$	122		$	101		$	23		$	24
PSE&G		$	61		$	58		$	194		$	165		$	40		$	57

PSEG, Power and PSE&G believe that the costs of services provided by Services approximate market value for such services.

Tax Sharing Agreements

PSEG, Power and PSE&G

PSE&G and Power had payables to or receivables from PSEG related to taxes as follows:


	Receivable/(Payable) to PSEG as of
	September 30, 2008				December 31, 2007
	(Millions)
Power		$	(32	)		$	(43	)
PSE&G		$	17			$	(5	)

As a result of the adoption of FIN 48, PSE&G and Power each recorded current and non-current payables to or receivables from PSEG related to uncertain tax positions. Such amounts are as follows:


	Current Receivable/(Payable) to PSEG as of
	September 30, 2008			December 31, 2007
	(Millions)
Power		$	4		$	8
PSE&G		$	64		$	(3	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Non-Current Receivable/(Payable) to PSEG as of
	September 30, 2008				December 31, 2007
	(Millions)
Power		$	(15	)		$	(26	)
PSE&G		$	(75	)		$	(75	)

Affiliate Loans and Advances

PSEG and Power

As of September 30, 2008 and December 31, 2007, Power had a demand note payable of $168 million and $238 million, respectively, to PSEG for short-term funding needs.

PSE&G and Services

As of each of September 30, 2008 and December 31, 2007, PSE&G had advanced working capital to Services of $33 million. This amount is included in Other Noncurrent Assets on PSE&G’s Condensed Consolidated Balance Sheets.

Power and Services

As of each of September 30, 2008 and December 31, 2007, Power had advanced working capital to Services of $17 million. This amount is included in Other Noncurrent Assets on Power’s Condensed Consolidated Balance Sheets.

Other

PSEG and Power

As of September 30, 2008, Power had a net payable to PSEG of less than $1 million. As of December 31, 2007, Power had a net payable to PSEG of $5 million related to amounts that PSEG had paid to suppliers on Power’s behalf.

PSEG and PSE&G

As of September 30, 2008 and December 31, 2007, PSE&G had net receivables from PSEG of $2 million and $11 million, respectively, related to amounts that PSEG had collected on PSE&G’s behalf.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 15. Guarantees of Debt

Power

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 Fossil, Nuclear and 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)
For the Quarter Ended September 30, 2008:
Operating Revenues		$	—			$	2,129			$	31			$	(327	)		$	1,833
Operating Expenses			3				1,522				31				(328	)			1,228

Operating Income			(3	)			607				—				1				605
Equity Earnings (Losses) of Subsidiaries			328				(10	)			—				(318	)			—
Other Income			38				110				—				(60	)			88
Other Deductions			—				(104	)			—				—				(104	)
Interest Expense			(44	)			(43	)			(15	)			60				(42	)
Income Tax Benefit (Expense)			9				(232	)			5				(1	)			(219	)

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

For the Quarter Ended September 30, 2007:
Operating Revenues		$	—			$	1,830			$	23			$	(273	)		$	1,580
Operating Expenses			—				1,227				25				(272	)			980

Operating Income (Loss)			—				603				(2	)			(1	)			600
Equity Earnings (Losses) of Subsidiaries			339				(8	)			—				(331	)			—
Other Income			48				71				—				(63	)			56
Other Deductions			—				(42	)			—				—				(42	)
Interest Expense			(47	)			(46	)			(13	)			63				(43	)
Income Tax Benefit (Expense)			—				(239	)			5				2				(233	)
Income (Loss) from Discontinued Operations, net of tax			(1	)			—				2				(1	)			1

Net Income (Loss)		$	339			$	339			$	(8	)		$	(331	)		$	339

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

Operating Income (Loss)			(8	)			1,561				—				1				1,554
Equity Earnings (Losses) of Subsidiaries			858				(30	)			—				(828	)			—
Other Income			111				317				—				(161	)			267
Other Deductions			—				(282	)			—				—				(282	)
Interest Expense			(150	)			(92	)			(43	)			160				(125	)
Income Tax Benefit (Expense)			32				(616	)			13				—				(571	)

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power				Guarantor Subsidiaries				Other Subsidiaries				Consolidating Adjustments				Consolidated Total
	(Millions)
For the Nine Months Ended September 30, 2007:
Operating Revenues		$	—			$	5,789			$	77			$	(832	)		$	5,034
Operating Expenses			—				4,464				77				(832	)			3,709

Operating Income			—				1,325				—				—				1,325
Equity Earnings (Losses) of Subsidiaries			744				(30	)			—				(714	)			—
Other Income			148				202				—				(188	)			162
Other Deductions			—				(105	)			—				—				(105	)
Interest Expense			(156	)			(114	)			(36	)			187				(119	)
Income Tax Benefit (Expense)			—				(534	)			14				1				(519	)
Loss from Discontinued Operations, net of tax			—				—				(7	)			(1	)			(8	)

Net Income (Loss)		$	736			$	744			$	(29	)		$	(715	)		$	736

For the Nine Months Ended September 30, 2008:
Net Cash Provided By (Used In) Operating Activities		$	(297	)		$	1,692			$	(104	)		$	(82	)		$	1,209
Net Cash Provided By (Used In) Investing Activities		$	774			$	(1,926	)		$	(20	)		$	519			$	(653	)
Net Cash Provided By (Used In) Financing Activities		$	(475	)		$	244			$	124			$	(438	)		$	(545	)
For the Nine Months Ended September 30, 2007:
Net Cash Provided By (Used In) Operating Activities		$	1,175			$	1,393			$	(45	)		$	(1,475	)		$	1,048
Net Cash Provided By (Used In) Investing Activities		$	(335	)		$	(648	)		$	(55	)		$	865			$	(173	)
Net Cash Provided By (Used In) financing Activities		$	(840	)		$	(749	)		$	100			$	610			$	(879	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments				Consolidated Total
	(Millions)
As of September 30, 2008:
Current Assets		$	2,419		$	5,191		$	435		$	(5,714	)		$	2,331
Property, Plant and Equipment, net			39			4,252			931			—				5,222
Investment in Subsidiaries			4,321			138			—			(4,459	)			—
Noncurrent Assets			131			1,250			44			(115	)			1,310

Total Assets		$	6,910		$	10,831		$	1,410		$	(10,288	)		$	8,863

Current Liabilities		$	387		$	5,678		$	1,166		$	(5,715	)		$	1,516
Noncurrent Liabilities			226			833			105			(114	)			1,050
Long-Term Debt			2,653			—			—			—				2,653
Member’s Equity			3,644			4,320			139			(4,459	)			3,644

Total Liabilities and Member’s Equity		$	6,910		$	10,831		$	1,410		$	(10,288	)		$	8,863

As of December 31, 2007:
Current Assets		$	2,553		$	3,541		$	360		$	(4,305	)		$	2,149
Property, Plant and Equipment, net			149			3,669			934			(1	)			4,751
Investment in Subsidiaries			3,538			168			—			(3,706	)			—
Noncurrent Assets			156			1,506			30			(256	)			1,436

Total Assets		$	6,396		$	8,884		$	1,324		$	(8,268	)		$	8,336

Current Liabilities		$	99		$	4,489		$	1,057		$	(4,307	)		$	1,338
Noncurrent Liabilities			234			858			98			(255	)			935
Long-Term Debt			2,902			—			—			—				2,902
Member’s Equity			3,161			3,537			169			(3,706	)			3,161

Total Liabilities and Member’s Equity		$	6,396		$	8,884		$	1,324		$	(8,268	)		$	8,336

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

PSEG, Power and PSE&G

This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (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.

The following discussion relates to the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets, significant events that have occurred during 2008 and the future outlook for Power, PSE&G and PSEG Energy Holdings L.L.C. (Energy Holdings), as well as the key factors that will drive the future performance of these businesses. This discussion includes significant changes in or additions to information reported in the 2007 Annual Report on Form 10-K and 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 2007 Annual Report on Form 10-K.

PSEG’s business consists of four reportable segments, which are Power, PSE&G and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C. (Resources).

Power

Power is an electric generation and wholesale energy marketing and trading company that is focused on generation markets in the Northeast and Mid Atlantic U.S. Through its subsidiaries, Power seeks to produce low-cost energy through efficient operations of its nuclear, coal and gas-fired generation facilities. Power seeks to balance this generation production with its fuel requirements and supply obligations through energy portfolio management. In addition to the electric generation business, Power’s revenues also include gas supply sales under the Basic Gas Supply Service (BGSS) contract with PSE&G and to other customers.

PSE&G

PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and under regulation by the Federal Energy Regulatory Commission (FERC) for its electric transmission and wholesale sales operations. Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies.

Global

Domestically, Global owns two 1,000 MW combined cycle generation facilities in the Electric Reliability Council of Texas (ERCOT) market, and has investments in power producers that own and operate electric generation in California and Hawaii, with smaller investments in New Hampshire and Pennsylvania. Global has reduced its international risk by monetizing most of its international investments. Global is also pursuing the development of renewable energy projects.

Resources

Resources primarily has invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments.

Overview of 2008

Financial Results

PSEG, Power and PSE&G

The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and nine months ended September 30, 2008 and 2007 are presented below:


	Earnings (Losses)
	Quarters Ended September 30,								Nine Months Ended September 30,
	2008				2007				2008				2007
	(Millions)
Power		$	328			$	338			$	843			$	744
PSE&G			98				107				287				302
Global			67				41				101				62
Resources (A)			(11	)			15				(466	)			46
Other (B)			(6	)			(11	)			(19	)			(48	)

PSEG Income from Continuing Operations			476				490				746				1,106
Income from Discontinued Operations			180				16				208				4

PSEG Net Income		$	656			$	506			$	954			$	1,110


	Earnings (Loss) Per Share (Diluted)
	Quarters Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
PSEG Income from Continuing Operations		$	0.94		$	0.96		$	1.47		$	2.18
Income from Discontinued Operations			0.35			0.03			0.41			0.01

PSEG Net Income		$	1.29		$	0.99		$	1.88		$	2.19

(A)

In the second quarter of 2008, Resources recorded after-tax charges of $490 million related to the disallowance of deductions taken in prior years’ tax filings associated with certain types of leveraged lease transactions. See Note 5. Commitments and Contingent Liabilities for additional information.

(B)

Other activities include non-segment amounts of PSEG (as parent company) and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain administrative and general expenses at PSEG and Energy Holdings (as parent companies).

The quarter-over-quarter decrease in PSEG’s Income from Continuing Operations principally reflected decreases at Power and PSE&G. Power’s Operating Revenues increased due to higher sales prices on re-contracted BGS contracts and in PJM, exceeding the increase in its generation costs that primarily resulted from increased prices for natural gas purchases. However, these favorable results were more than offset by higher losses recognized in 2008 on certain securities in the Nuclear Decommissioning Trust (NDT) Funds and higher Operation and Maintenance Costs related to outages at certain facilities of PSEG Fossil LLC (Fossil) and PSEG Nuclear LLC (Nuclear). PSE&G’s decrease was principally due to lower sales and higher depreciation. The quarter-over-quarter increase in PSEG’s Net Income was primarily due to the gain of $187 million recognized in 2008 on the sale of the SAESA Group, which was included in Income from Discontinued Operations.

The nine month over nine month decrease in PSEG’s Income from Continuing Operations reflected a significant decrease at Resources, largely due to after-tax charges of $490 million recorded in June 2008 associated with deductions taken for tax purposes on certain types of leveraged lease transactions that are being challenged by the IRS. See Note 5. Commitments and Contingent Liabilities for additional information. Earnings were also slightly lower at PSE&G due to lower sales and higher depreciation. These decreases were somewhat offset by improved earnings at Power and to a lesser degree at Global. Power’s Operating Revenues increased due to higher prices and higher sales volumes, partially offset by higher generation costs as well as higher losses in the NDT Fund and Operation and Maintenance Costs. Global’s earnings increased primarily due to improved operations and higher mark to market (MTM) gains at its Texas generation facilities.

Business Developments

PSEG, Power and PSE&G

First Quarter

PSEG’s Board of Directors approved a two-for-one stock split of PSEG’s outstanding shares of common stock.

The BPU approved the results of New Jersey’s annual BGS-Fixed Price (FP) and BGS-Commercial and Industrial Energy Price auctions and PSE&G successfully secured contracts to provide the anticipated electricity requirements for its customers. As a result of the February 2008 auction, new BGS-FP rates increased the average residential customer’s bill by approximately 12% effective June 2008.

FERC approved the classification of new 69 kV facilities as transmission rather than distribution which PSE&G expects to result in improvements in reliability and more expeditious rate treatment for these facilities.

The U.S. Department of Treasury issued final regulations regarding Investment Tax Credit (ITC) normalization, referring to deferred tax balances that were to be refunded to utility customers but were terminated upon New Jersey’s electric industry deregulation in 1999. The ruling confirmed that none of the generation-related ITC could be passed to utility customers without violating the normalization rules.

Second Quarter

The U.S. Supreme Court granted the request of industry petitioners, including Power, to review the question of whether Section 316(b) of the Federal Water Pollution Control Act allows the U.S. Environmental Protection Agency (EPA) to compare costs with benefits in determining the “best technology available” for minimizing adverse environmental impact at cooling water intake structures. This matter could have a material impact on Power’s ability to renew Clean Water Act permits at a number of its larger plants without making significant equipment upgrades involving material expenditures.

The BPU approved a settlement agreement allowing PSE&G to invest approximately $105 million in a solar energy pilot program designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. PSE&G will provide loans to customers in its electric service territory for the installation of solar photovoltaic systems on the customers’ premises. The program is open to commercial, industrial and residential customers. As of September 30, 2008, PSE&G has received applications for approximately 34% of the 30 MW program.

FERC approved incentive rate treatment for PSE&G’s Susquehanna-Roseland transmission line project, which will enable PSE&G to earn an adequate return on investment, full recovery of construction costs and the authority to transfer certain incentives to affiliates that are members of Regional Transmission Organizations (RTOs).

A complaint was filed with FERC with respect to PJM’s Reliability Pricing Model (RPM) on the grounds that the capacity prices set in the first three RPM auctions were not just and reasonable. In September 2008, the FERC issued an order dismissing this complaint. If upheld on rehearing and on appeal, this order eliminates the potential for the payment of refunds with respect to transitional auction payments made to generators in PJM, including Power.

PSE&G submitted a request to the BPU for an increase in annual BGSS revenues of $376 million to be effective October 1, 2008, representing approximately a 20% increase on a typical residential gas customer’s bill. This request was revised to $267 million on August 27, 2008 and approved by the BPU on October 3, 2008.

Power completed turbine replacement projects at Hope Creek and Salem Unit 2, increasing its nuclear generating capacity at those facilities.

•

Hope Creek—Phase I increased the nominal capacity of the unit by 10 MW in 2005. Phase II added approximately 150 MW of nominal capacity in the second quarter of 2008.

•

Salem Unit 2—Phase I increased Power’s share of the nominal capacity by 14 MW in 2003. Phase II was completed and put in operation in the second quarter of 2008, concurrent with steam generator replacement and increased Power’s share of the nominal capacity by approximately 23 MW.

In June 2008, as a result of the recent court decisions regarding certain types of leveraged lease transactions, PSEG evaluated its unrecognized tax benefits under FIN 48, “Accounting for Uncertainty in

Income Taxes—an Interpretation of FASB Statement 109” (FIN 48), and recorded an after-tax increase to the interest reserve of $135 million in the second quarter of 2008. This charge is recorded in Income Tax Expense in PSEG’s Condensed Consolidated Statement of Operations. PSEG also recorded a charge of $355 million under 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.” This charge is 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. As the tax benefits associated with these lease transactions are timing differences, total cash flows and net income in a leveraged lease transaction remain the same after a change in the timing of the cash flows. The charges related to FSP 13-2 will therefore be recognized as income over the remaining terms of the affected leases.

Third Quarter

In July 2008, PSE&G filed a petition with FERC to implement a cost-of-service formula rate for its existing and future transmission investment. On September 30, 2008, the FERC approved PSE&G’s request for formula transmission rates, effective October 1, 2008. Under this formula, PSE&G will put rates into effect in January of each year based upon its internal forecast of annual expenses and capital expenditures, and rates will be trued up to reflect actual annual expenses/capital expenditures in the following year. The order provides for an ROE of 11.68% on existing and new transmission investment.

The Clean Air Interstate Rule (CAIR), enacted by the EPA in 2005, would have required 28 eastern states to reduce nitrogen oxide (NO_x) and sulfur dioxide (SO₂) in the 2009, 2010 and 2015 timeframe. In July 2008, CAIR was vacated by the United States Court of Appeals for the District of Columbia Circuit. Subsequent to that ruling, market prices for SO₂ allowances have declined significantly, and a decline in electricity prices in certain states has occurred. In September 2008, the EPA, certain industry groups and certain environmental groups filed a petition for rehearing with the Court. By order dated October 21, 2008 the Court requested additional briefings from various aligned petitioners, by November 5, 2008, directing them to address:

•

whether any party is seeking the repeal of CAIR, and

•

whether the Court should stay its mandate to vacate CAIR until EPA promulgates a revised rule.

Any significant decrease in electricity prices could adversely affect Power’s revenues. PSEG and Power cannot predict the ultimate resolution of CAIR, nor the ultimate effect on their results of operations. Power foresees no change in its existing construction response to controlling NO_x and SO₂.

The Board of Directors of PSEG authorized the repurchase of up to $750 million of PSEG Common Stock to be executed over 18 months beginning August 1, 2008. PSEG is not obligated to acquire any specific number of shares and may suspend or terminate its share repurchases at any time. The amount and timing of any stock repurchases would be based on various factors such as management’s assessment of PSEG’s capital structure and liquidity, the market price of PSEG’s common stock and the opportunity to grow the business if investments are available. As of September 30, 2008, approximately two million common shares were repurchased at a cost of $92 million. See Liquidity and Capital Resources for more information.

Global closed on the sale of 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 $275 million, were $600 million.

In August 2008, Global entered into an agreement to sell its 85% ownership interest in Bioenergie, which consists of generation facilities in Italy. The sale is pending. Bioenergie’s operating results for the quarter and nine months ended September 30, 2008 include a pre-tax impairment charge of $33 million and related tax benefits of $22 million which are included in Discontinued Operations.

The Emergency Economic Stabilization Act of 2008, which was passed in October 2008, provides for:

•

an eight year extension of the tax credits for solar and other renewable energy sources

•

removal of the $2,000 limit on residential solar credits

•

utility eligibility for the 30% solar credit

•

10 year accelerated tax depreciation of smart metering and smart grids

PSEG, Power and PSE&G believe that the Emergency Economic Stabilization Act of 2008 will ease their ability to reach New Jersey’s aggressive Energy Master Plan goals and spur additional development of

renewables. PSE&G believes that it will also provide company-owned solar installations with the same economic advantage as private development and support the expected upgrade of its distribution and metering systems.

PSE&G, PSEG Energy Resources & Trade LLC (ER&T), Power Connecticut, Fossil and Nuclear submitted market-based rate (MBR) filings to FERC in which they asserted that they either lack market power or, that market power is being effectively mitigated in various markets. On September 2, 2008, PSE&G, ER&T, Power Connecticut, Fossil and Nuclear filed a revised MBR analysis based on recent FERC orders. On October 16, 2008, the FERC accepted the updated market power analysis of PSE&G, ER&T and Power Connecticut, concluding that they had satisfied the standards for MBR authority. The FERC also granted MBR authorization to Fossil and Nuclear.

The final New Jersey Energy Master Plan (EMP) rule was issued in October 2008. The final plan identifies a number of actions to improve energy efficiency, increase the use of renewable resources, ensure a reliable supply of energy and stimulate investment in clean energy technologies.

For additional information, see Item 5. Other Information and Note 5. Commitments and Contingent Liabilities.

Future Outlook

PSEG, Power and PSE&G

PSEG’s future success will depend on the ability of Power, PSE&G and Energy Holdings to achieve their respective objectives and earnings expectations, as well as the successful completion of various construction projects and their respective growth initiatives, discussed below.

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

In general, PSEG believes it has growth opportunities in the following three key areas:

•

responding to climate change and continuing to improve environmental performance through investments in energy efficiency, renewables and clean central station power;

•

upgrading critical energy infrastructure; and

•

providing new energy supplies.

There are challenges for 2009 resulting from the turmoil in the capital and credit markets and volatility in the commodity markets which could place downward pressure on earnings resulting from:

•

increasing pension expense due to significantly lower pension asset values;

•

increasing cost of borrowing due to tightening capital and credit markets and higher risk premiums sought by investors and lenders; and

•

increasing coal costs resulting from a potential renegotiation with a key supplier.

Power

As a merchant generator, Power’s primary profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, and a series of energy-related products used to optimize the operation of the energy grid. A key factor for success is Power’s ability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to satisfy its obligations. Historically, Power’s nuclear and coal-fired facilities have produced over 50% and 25% of Power’s production, respectively. Power seeks to sell a portion of this anticipated low-cost nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of two to four years. With the vast majority of its power sourced from these lower-cost units, rising electric prices have yielded higher margins for Power. Recent market prices for electricity, fuels and other commodities related to Power’s business have been increasingly volatile, dramatically increasing during the second quarter of 2008, and falling sharply in the third quarter. The prices of various commodities that affect Power’s business, including natural gas, coal and electricity, have also changed relative to one another during this volatile period, which also can impact Power’s business results positively or negatively, especially if sustained over the long term (beyond the two to four year contracted period).

In addition, the recent financial crisis may have a negative effect on economic growth in our markets which also may have a negative effect on Power’s results, including demand reduction and depressed equity markets which would lower the market value of Power’s NDT Funds. Decreases in the market value below the cost of investments in the NDT Funds result in losses that are reflected in Power’s results of operations. These developments and general economic conditions have increased Power’s cost of borrowing.

In view of changes such as these, as well as strong competition, market complexity and constantly changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While higher forward prices may have a potentially significant beneficial impact on margins, they could also raise any replacement power costs that Power may incur in the event of unanticipated outages, and could also further increase liquidity requirements as a result of contract obligations. For additional information on liquidity requirements, see Liquidity and Capital Resources.

Power contracts for the future delivery of nuclear fuel and coal to support its contracted sales. Power’s estimated fuel needs are subject to change based upon the level of its operations as well as upon market demands for and on the price of coal, both of which have increased recently. Earlier in the year, Power revised the pricing for one of its coal supply agreements for the Mercer station through 2008. A second supplier for about 15% of Mercer’s coal requirements declared a force majeure and reduced shipments of coal. A settlement was reached with this supplier pursuant to which shipments were reinstated at the contract volumes with no net increase in price over the terms of the coal supply agreement. An Indonesian supplier of coal for the Bridgeport and Hudson generating units has notified PSEG that it has received a letter from the Indonesian government, as the rights holder for coal resources in Indonesia, requesting that the supplier renegotiate its contracts with PSEG to reflect currently effective market prices based on certain coal indexes. The letter states that in the event that no agreement is reached for the renegotiation of the contracts, the supplier should temporarily discontinue deliveries of coal until agreement is reached. The agreement currently provides for approximately 2.7 million tons for 2009 and 2010 and about half of that annual amount in 2011. Power is currently in negotiations with the supplier. Resolution of this issue cannot be predicted, but any renegotiation of the Indonesian coal contracts would likely result in a material increase in coal costs. Power believes it can continue to manage its fuel sourcing needs in this dynamic market but changes in prices and demand could impact its future operations or financial results.

Power could be impacted by a number of events, including regulatory or legislative actions favoring non-competitive markets, energy efficiency/demand response initiatives and regulatory policies favoring generation that may be subject to less stringent environmental regulation. Further, some of the market- based mechanisms in which Power participates, including BGS auctions and the RPM capacity payments, are at times the subject of review or discussion by some of the participants in the New Jersey and federal regulatory and political arenas, including FERC and the BPU, and the PJM market monitor. Accordingly, Power can provide no assurance that any or all of these mechanisms will continue to exist in their current form. For additional information, see Item 5. Other Information—Regulatory Issues.

In addition, Power must be able to effectively manage its construction projects and continue to economically operate its generation facilities under increasingly stringent environmental requirements, including legislation, regulation and voluntary restrictions that address:

•

the control of carbon dioxide (CO₂) emissions to reduce the effects of global climate change and greenhouse gas, and the cost of complying with the Regional Greenhouse Gas Initiative (RGGI), including the cost of CO₂ emission allowances;

•

The first auction related to CO₂ allowances for the RGGI region was conducted in September 2008. Future auctions are anticipated on a quarterly basis.

•

other emissions such as NO_x, SO₂ and mercury; and

•

the potential need for significant upgrades to existing water intake structures and cooling systems at its larger once-through cooled plants, including Salem, Hudson, Mercer, Sewaren, New Haven and Bridgeport.

Power recently completed two projects to increase the generating capacity of its Hope Creek and Salem Unit 2 facilities and has several other projects included in its forecasted capital expenditures.

Power has two large environmental back-end technology projects underway at its Mercer and Hudson coal plants scheduled to be completed by the end of 2010. Power is focused on completing these projects on schedule and within the established budgets, but faces many risks typically involved in managing large construction projects.

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. Power estimates the cost of these generating units to be $130 million to $140 million. Construction is expected to commence in June 2011.

Power has initiated planning activities with respect to the construction of new gas-fired peaking capacity. Power’s final decision whether or not to proceed with construction of these units would depend on numerous items, including estimated capital and interconnection costs, available siting and Power’s ability to meet environmental permitting requirements. Power is also currently exploring the potential to build new nuclear generation and in addition may also seek growth from acquisition opportunities.

PSE&G

PSE&G’s results primarily depend on the treatment of the various rate and other issues by the BPU and FERC, as well as other state and federal regulatory agencies. Therefore, PSE&G’s success will depend on its ability to:

•

attain an adequate return on the investments it plans to make in its electric and gas transmission and distribution system;

•

continue cost containment initiatives;

•

maintain system reliability and safety levels, and

•

continue recovery of the regulatory assets it has deferred.

Under the terms of the settlement of PSE&G’s most recent electric and gas base rate cases, PSE&G is required to file joint electric and gas petitions for future base rate increases and no base rate changes may become effective before November 15, 2009. PSE&G expects to file a joint electric and gas rate case in 2009 with rates effective in 2010.

As noted previously, the FERC has recently approved PSE&G’s petition to implement a cost of service formula rate for its existing and future transmission investments. This forward-looking formula rate mechanism allows PSE&G to update its transmission rates annually based on forecasted Operation and Maintenance Expense and capital expenditures for the coming year, with no lag of recovery, and will provide for a true-up to actual expenditures in the subsequent year. PSE&G’s results will also be impacted by the level of recovery of distribution revenues in light of customer demand and conservation efforts.

PSE&G has noticed a decline in the electric sales growth by its customers in response to a decline in economic activity. PSE&G does not expect this decline to have a material impact on its results during the remainder of 2008. However, PSE&G has reduced its forecasted long term sales growth rate from 1% down to 0.5% per year.

In order to meet the growing demand for electricity in the region in a safe, reliable and economically efficient manner, PJM has identified the need for several transmission projects as part of its Regional Transmission Expansion Plan (RTEP). One project is the Susquehanna-Roseland 500 kV transmission project that was approved by PJM and is currently in the permitting and siting phase with construction expected to begin in the spring of 2009 to meet the 2012 in-service date. PSE&G has the responsibility to build and own a portion of this transmission line and has been granted incentive rate treatment for this project. PSE&G will also be responsible for constructing and owning a portion of the Mid-Atlantic Pathway Project (MAPP), another 500 kV transmission line, when approved. The in-service date has not been finalized. There are several other 500 kV transmission projects, as well as 230 kV transmission project options, actively under consideration by PJM to address future reliability criteria violations in the PJM region. These projects have not yet been approved by PJM. For additional information, see Item 5. Other Information.

PSE&G has proposed various initiatives to meet energy goals under the EMP. As discussed above, PSE&G has received BPU approval allowing PSE&G to invest approximately $105 million over two years to help finance the installation of solar energy systems throughout its service area. PSE&G will be allowed to earn a return on and of its investment and partially recover its administrative costs to implement the Solar Energy Program through regulated rates. The program will support 30 MW of solar power in the next two years, fulfilling approximately 50% of the BPU’s Renewal Portfolio Standard requirements of 57 MW in PSE&G’s service area by May 2009 and May 2010.

Energy Holdings

Energy Holdings’ earnings are primarily comprised of the results of operations at Global and Resources.

Global’s largest investment is in two 1,000 MW generating facilities in Texas, and, as such, its success will be largely driven by the operation of those plants and by changes in market conditions, particularly projected market prices and weather.

A large deployment of new renewable (wind) generating facilities in west Texas, coupled with limited transmission capacity and the intermittent nature of the resource, has created congestion and is believed to be a primary driver for lower forward energy prices in ERCOT’s west zone where one of Global’s facilities is located.

Global’s results from its investments in Texas are also impacted by the recognition of unrealized mark-to-market (MTM) gains and losses on its fixed-price capacity option covering 350 MW of the west Texas facility’s generating output. The lower forward prices and increased volatility, discussed above, have resulted in an increase to the fair value of the capacity option which was $61 million as of September 30, 2008. Future earnings will be reduced as this amount is reversed to earnings over the remaining life of the contract, which expires in December 2010.

Global is also pursuing the potential development of wind, biomass, solar and other renewable projects, primarily in PSEG’s core markets.

In August 2008, Global invested in a joint venture to further develop compressed air energy storage (CAES). CAES technology stores energy in the form of compressed air by injection into underground caverns which can then be released to generate electricity through specialized turbine equipment. This technology could be used to optimize an intermittent energy source, such as wind, by storing energy at night and releasing this stored energy during the day when customers need power. Global expects to use the technology and expertise to develop and design CAES power plants and sell licenses to third parties to implement CAES technology.

In October 2008, the New Jersey Office of Clean Energy (OCE) awarded a $4 million grant to a joint venture owned equally by a subsidiary of Global and an unaffiliated private developer, to advance the development of a 350 MW wind farm approximately 16 miles off the shore of southern New Jersey. An offshore wind farm has not yet been developed and constructed in the United States. Numerous issues, including federal and state permitting, environmental impacts, power output sale arrangements, construction approach and expected maintenance costs, will need to be worked through in order to successfully develop such a project. If these issues are satisfactorily addressed and the joint venture decides to proceed, the wind farm could be fully operational in 2013.

Resources maintains a portfolio of investments which is designed to provide a fixed rate of return. However, its future performance is subject to tax risks, such as the impacts of changes to uncertain tax positions as determined by changes in substantive tax law and tax audit results, including resolution of significant tax audit claims associated with its leveraged lease transactions. See Note 5. Commitments and Contingent Liabilities for further discussion.

PSEG, Power and PSE&G

As PSEG and its subsidiaries go through their annual planning process, considering the recent market turmoil, they are reviewing projected capital expenditures. As a result PSE&G anticipates decreasing planned capital spending for 2009 by approximately $125 million as compared to the amounts reflected in the 2007 Form 10-K. PSEG and Power do not anticipate any material change to planned capital spending for 2009.

PSEG expects that continued strong cash from operations, when combined with cash on hand and other available liquidity, will be sufficient to:

•

support the projected capital expenditure program,

•

fund shareholder dividends,

•

fund additional contributions to the pension funds, and

•

provide for potential payments to address significant income tax claims related to certain leveraged lease transactions at Energy Holdings, discussed in Note 5. Commitments and Contingent Liabilities.

Any funds remaining after satisfying these obligations, when combined with potential additional financing capacity, would be discretionary cash that could be used to pursue growth and the stock repurchase program.

During this period of market turmoil, any additional financing would be dependent on the availability of the capital markets at reasonable pricing terms to PSEG and its subsidiaries. For additional information see Liquidity and Capital Resources.

RESULTS OF OPERATIONS

PSEG


	For the Quarters Ended September 30,								Increase (Decrease)				%			For the Nine Months Ended September 30,								Increase (Decrease)				%
	2008				2007				Increase (Decrease)				%			2008				2007				Increase (Decrease)				%
	(Millions)															(Millions)
Operating Revenues		$	3,718			$	3,347			$	371			11			$	10,060			$	9,561			$	499			5
Energy Costs		$	1,899			$	1,588			$	311			20			$	5,552			$	4,885			$	667			14
Operation and Maintenance		$	610			$	559			$	51			9			$	1,857			$	1,727			$	130			7
Depreciation and Amortization		$	214			$	209			$	5			2			$	597			$	587			$	10			2
Income from Equity Method Investments		$	8			$	30			$	(22	)		(73	)		$	27			$	87			$	(60	)		(69	)
Other Income and Deductions		$	(12	)		$	12			$	(24	)		N/A			$	(3	)		$	67			$	(70	)		N/A
Interest Expense		$	(149	)		$	(184	)		$	(35	)		(19	)		$	(448	)		$	(549	)		$	(101	)		(18	)
Income Tax Expense		$	(334	)		$	(315	)		$	19			6			$	(780	)		$	(742	)		$	38			5
Income from Discontinued Operations, including Gain on Disposal, net of Tax Expense		$	180			$	16			$	164			N/A			$	208			$	4			$	204			N/A
Net Income		$	656			$	506			$	150			30			$	954			$	1,110			$	(156	)		(14	)

PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, Power, PSE&G and Energy Holdings, excluding changes related to intercompany transactions, which are eliminated in consolidation, and certain financing costs at the parent company. For additional information on intercompany transactions, see Note 14. Related-Party Transactions. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for Power, PSE&G and Energy Holdings that follow.

Power

For the quarter ended September 30, 2008, Power had Net Income of $328 million, a decrease of $11 million as compared to the same period in the prior year. For the nine months ended September 30, 2008, Power had Net Income of $843 million, an increase of $107 million as compared to the same period in the prior year.

The primary reasons for the decrease in the three months ended September 30, 2008, as compared to the same period in 2007, were higher Operations and Maintenance costs and lower Other Income and Deductions related to net losses on investments in NDT Funds, partially offset by higher margins. Margins were driven by sales prices realized on re-contracted BGS contracts, and prices realized in PJM, partially reduced by higher generation costs primarily due to higher prices for natural gas. Operation and Maintenance Costs increased largely due to outages at certain of Fossil’s and Nuclear’s facilities. Investments in NDT Funds resulted in net losses of $18 million compared with net gains of $7 million in the same period in 2007.

The primary reasons for the increase for the nine month period ended September 30, 2008, as compared to the same period in 2007, were higher net Margins, partially offset by higher Operations and Maintenance costs and Other Income and Deductions related to net losses on investments in NDT Funds. Net Margins were driven by higher prices on higher sales volumes in PJM and from recontracted BGS contracts. Operation and Maintenance Costs increased due to outages at certain of Fossil’s and Nuclear’s facilities. Investments in NDT Funds resulted in an increase in net losses of $60 million compared with the same period in 2007.

Net Income for the three month periods included the effects of MTM losses of $20 million, after-tax, in 2008 as compared to $4 million of gains, after-tax, in 2007. Net Income for the nine month periods included

the effects of MTM gains of $10 million, after-tax, in 2008 as compared to losses of $6 million, after-tax, in 2007.


	For the Quarters Ended September 30,								Increase (Decrease)				%			For the Nine Months Ended September 30,								Increase (Decrease)				%
	2008				2007				Increase (Decrease)				%			2008				2007				Increase (Decrease)				%
	(Millions)															(Millions)
Operating Revenues		$	1,833			$	1,580			$	253			16			$	5,831			$	5,034			$	797			16
Energy Costs		$	904			$	712			$	192			27			$	3,360			$	2,894			$	466			16
Operation and Maintenance		$	282			$	232			$	50			22			$	796			$	711			$	85			12
Depreciation and Amortization		$	42			$	36			$	6			17			$	121			$	104			$	17			16
Other Income and Deductions		$	(16	)		$	14			$	(30	)		N/A			$	(15	)		$	57			$	(72	)		N/A
Interest Expense		$	(42	)		$	(43	)		$	(1	)		(2	)		$	(125	)		$	(119	)		$	6			5
Income Tax Expense		$	(219	)		$	(233	)		$	(14	)		(6	)		$	(571	)		$	(519	)		$	52			10
Income (Loss) from Discontinued Operations, net of Tax Benefit (Expense)		$	—			$	1			$	(1	)		(100	)		$	—			$	(8	)		$	8			(100	)
Net Income		$	328			$	339			$	(11	)		(3	)		$	843			$	736			$	107			15

Variances are all related to the same period in the prior year. The detail is discussed below:

Operating Revenues

The $253 million increase for the quarter ended September 30, 2008 was due to increases of $171 million in generation revenues, $77 million in gas revenues and $5 million in trading revenues.

The $797 million increase for the nine months ended September 30, 2008 was due to increases of $675 million in generation revenues, $97 million in gas supply revenues and $25 million in trading revenues.

Generation

Generation revenues increased $171 million for the quarter ended September 30, 2008 due to an increase of $126 million resulting from higher prices on a higher volume of BGS-FP contracts and an increase of $79 million due to higher prices on generation being sold into the PJM and the New York energy pools. These increases were partially offset by decreases of $13 million due to the expiration of certain wholesale power contracts and $10 million due to lower RPM pricing in PJM for the 2008/2009 delivery year and $7 million of net losses on financial hedging transactions.

Generation revenues increased $675 million for the nine months ended September 30, 2008 due to an increase of $367 million resulting from a higher volume of generation being sold at higher prices into PJM and $44 million from higher prices in the New York power pool. The increase was also due to $280 million from higher prices on a higher volume of BGS contracts. Also contributing to the increase was $80 million from higher capacity prices mainly due to the Reliability Pricing Model, which also resulted in $10 million of lower Reliability-Must-Run revenues. The increases were also partially offset by net losses of $63 million on financial hedging transactions and a decrease of $18 million due to the roll off of certain wholesale power contracts.

Gas Supply

Gas supply revenues increased $77 million for the quarter ended September 30, 2008 principally due to a net increase of $51 million from sales under the BGSS contract, comprised of $62 million from higher prices partly offset by lower sales volumes of $11 million resulting from customer conservation in 2008. The increase was also due to $18 million from sales to third party customers and $8 million of higher net gains on financial hedging transactions in 2008 as compared to the same period in 2007.

Gas supply revenues increased $97 million for the nine months ended September 30, 2008 principally due to a net increase of $85 million from sales under the BGSS contract, comprised of $168 million from higher prices partly offset by lower sales volumes of $83 million due to customer conservation and milder average temperatures in 2008. Higher prices on sales to third party customers partly offset by reduced sales volumes also contributed $54 million to the increase. These increases were partially offset by $42 million in lower net gains on financial hedging transactions in 2008 as compared to the first nine months of 2007.

Trading Revenues

Trading revenues increased $5 million for the quarter ended September 30, 2008 due mainly to gains on electric-related contracts.

Trading revenues increased $25 million for the nine months ended September 30, 2008 due primarily to gains on electric-related and firm transmission rights contracts.

Operating Expenses

Energy Costs

Energy Costs increased $192 million for the quarter ended September 30, 2008. Generation costs increased $132 million, of which $153 million was primarily due to higher prices on modestly reduced volumes of natural gas and coal used for fuel. The increase was also attributable to $11 million of higher transmission costs and $10 million in net losses on financial hedging transactions mainly related to contracts to purchase gas. The increase in generation costs was partly offset by a $26 million reduction in energy purchases at PJM due to lower load being served as a result of the roll off of certain wholesale contracts and $15 million in lower congestion costs. Gas costs for BGSS increased $60 million, reflecting a net increase of $41 million due to higher inventory costs of $52 million partly offset by $11 million due to a reduced volume of gas sold to satisfy Power’s obligations under the BGSS contract and a net increase of $18 million on sales to third party customers due primarily to higher inventory costs.

Energy Costs increased $466 million for the nine months ended September 30, 2008. Generation costs increased $360 million, of which $459 million was mainly due to higher fuel costs related to higher prices and higher volumes of natural gas and coal. This increase was partly offset by net gains of $67 million from financial hedging transactions, mainly related to contracts to purchase gas, and $27 million of lower congestion and transmission costs. Gas costs increased $106 million, reflecting net increases of $60 million and $59 million related to Power’s obligations under the BGSS contract and sales to third party customers, respectively, reflecting higher inventory costs partially offset by reduced volumes. These increases were partially offset by a reduction of $13 million in losses on financial hedging transactions in 2008 as compared to the same period in 2007.

Operation and Maintenance

Operation and Maintenance expense increased $50 million for the quarter ended September 30, 2008 due to an increase at Fossil of $25 million, primarily related to planned outages at its Linden, Mercer, Bergen and Bridgeport facilities and an increase at Nuclear of $19 million related to planned outages at the Peach Bottom and Salem stations. Labor costs increased $6 million mainly due to filling staff positions that had been open in 2007.

Operation and Maintenance expense increased $85 million for the nine months ended September 30, 2008 primarily due to a net increase at Fossil of $45 million due to planned outages in 2008 at the Hudson, Linden and Bridgeport facilities partially offset by the absence of maintenance costs incurred in 2007 for planned outages at certain other fossil stations. There was an increase of $26 million at Nuclear related to the aforementioned planned outages in 2008. Labor costs increased $14 million mainly due to filling staff positions that had been open in 2007.

Depreciation and Amortization

The $6 million and $17 million increases for the quarter and nine month periods ended September 30, 2008, respectively, were primarily due to a larger depreciable nuclear and fossil asset base in 2008. Increases of $2 million for the third quarter and $7 million for the first nine months of 2008 were attributable to depreciation of pollution-control equipment being placed into service on January 1, 2008 at Power’s coal-fired Bridgeport, Connecticut generating facility and $2 million for the third quarter and $3 million for the first nine months of 2008 were due to depreciation of the Salem 2 steam generator replacement being placed into service in May 2008.

Other Income and Deductions

Other Income and Deductions decreased $30 million for the quarter ended September 30, 2008. OTTI recognized on certain securities in the NDT Funds increased $49 million from $16 million in the third quarter of 2007 to $65 million in the third quarter of 2008, reflecting difficult market conditions in 2008. Interest income received from PSEG decreased by $4 million due to a change in the short-term funding positions.

These decreases were partially offset by an increase of $23 million from net realized gains related to the NDT Funds.

Other Income and Deductions decreased $72 million for the nine months ended September 30, 2008 as a result of an increase in OTTI of $95 million and lower interest income of $15 million from PSEG partially offset by a net increase of $35 million from net realized gains related to the NDT Funds.

Interest Expense

Interest Expense increased $6 million for the nine months ended September 30, 2008 due primarily to the reclassification in 2007 of $13 million of Interest Expense to Discontinued Operations of the Lawrenceburg facility, which was sold in May 2007, partially offset by higher capitalized interest costs of $8 million in 2008 related to various fossil and nuclear capital projects in process.

Income Taxes

Income Taxes decreased $14 million for the quarter ended September 30, 2008 due primarily due to lower pre-tax income.

Income Taxes increased $52 million for the nine months ended September 30, 2008 due primarily to higher pre-tax income.

Loss from Discontinued Operations, net of tax

In May 2007, Power completed the sale of its Lawrenceburg generation facility. The sale price for the facility and inventory was $325 million. The transaction resulted in an after-tax charge to Power’s earnings of $208 million and was reflected as a charge to Discontinued Operations in the fourth quarter of 2006. Income from Discontinued Operations of Lawrenceburg was $1 million in the third quarter of 2007 and the Loss from Discontinued Operations of Lawrenceburg was $8 million for the nine months ended September 30, 2007.

PSE&G

For the quarter ended September 30, 2008, PSE&G had Net Income of $98 million, a decrease of $9 million as compared to the same period in 2007. For the nine months ended September 30, 2008, PSE&G had Net Income of $287 million, a decrease of $15 million as compared to the same period in 2007.


	For the Quarters Ended September 30,								Increase (Decrease)				%			For the Nine Months Ended September 30,								Increase (Decrease)				%
	2008				2007				Increase (Decrease)				%			2008				2007				Increase (Decrease)				%
	(Millions)															(Millions)
Operating Revenues		$	2,274			$	2,106			$	168			8			$	6,750			$	6,340			$	410			6
Energy Costs		$	1,521			$	1,341			$	180			13			$	4,527			$	4,083			$	444			11
Operation and Maintenance		$	313			$	308			$	5			2			$	993			$	947			$	46			5
Depreciation and Amortization		$	161			$	161			$	—			—			$	443			$	449			$	(6	)		(1	)
Other Income and Deductions		$	—			$	1			$	(1	)		(100	)		$	6			$	9			$	(3	)		(25	)
Interest Expense		$	(82	)		$	(85	)		$	(3	)		(4	)		$	(244	)		$	(250	)		$	(6	)		(2	)
Income Tax Expense		$	(68	)		$	(74	)		$	(6	)		(8	)		$	(161	)		$	(214	)		$	(53	)		(25	)
Net Income			98			$	107			$	(9	)		(8	)		$	287			$	302			$	(15	)		(5	)

Variances are all related to the same period in the prior year. The detail is discussed below:

Operating Revenues

PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM spot market; delivery revenues from the transmission and distribution of energy through its system; and other operating revenues from the provision of various services.

PSE&G makes no margin on gas commodity sales as the costs are passed through to customers. The difference between the gas costs paid under the requirements contract for residential customers and the revenues received from residential customers is deferred and collected from or returned to customers in future periods. Gas commodity prices fluctuate monthly for commercial and industrial (C&I) customers and annually through the BGSS tariff for residential customers. In addition, for residential gas customers,

PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual BGSS proceedings.

PSE&G makes no margin on electric commodity sales as the costs are passed through to customers. PSE&G secures its electric commodity through the annual BGS auction. Electric commodity supply prices are set based on the results of these auctions for residential and smaller C&I customers, and are translated into seasonally-adjusted fixed rates. Electric supply for larger C&I customers is provided at a rate principally based on the hourly PJM real-time energy price. Customers may obtain their electric supply through either the BGS default electric supply service or through competitive third-party electric suppliers, and the majority of the customers subject to hourly pricing are currently receiving electric supply from third-party suppliers. Any differences between amounts paid by PSE&G to BGS suppliers for electric commodity, and the amounts of electric commodity revenue collected from customers is deferred and collected or returned to customers in subsequent months.

The $168 million increase in operating revenues for the quarter ended September 30, 2008 was due to an increase of $180 million in commodity revenues offset by decreases of $11 million in delivery revenues and $1 million in other operating revenues, primarily related to appliance service contracts.

The $410 million increase for the nine months ended September 30, 2008 was due to increases of $443 million in commodity revenues offset by decreases of $28 million in delivery revenues, described below and $5 million in other operating revenues, primarily related to appliance service contracts.

Commodity

The $180 million increase in commodity-related revenues for the quarter ended September 30, 2008 was due to increases of $148 million and $32 million in electric and gas revenues, respectively. The electric increase was due to $122 million in higher BGS revenues (higher auction prices of $148 million offset by decreased volumes of $26 million) and $26 million in higher non-utility generation (NUG) revenues (higher prices of $30 million offset by $4 million in lower volumes). The gas increase was primarily due to $38 million in price variances for C&I customers offset by $6 million in lower volumes due to weather. Prices charged to C&I customers are market-based.

The $443 million increase in commodity related revenues for the nine months ended September 30, 2008 was due to increases in electric revenues of $378 million and gas revenues of $65 million. The increase in electric revenues was primarily due to $313 million in higher BGS revenues (higher auction prices of $373 million offset by decreased sales of $60 million) and $82 million in higher NUG revenues, due to higher prices, offset by $17 million in lower non-utility generation clause (NGC) revenues, due to lower prices. The increase in gas revenues was primarily due to $163 million in higher BGSS prices offset by $98 million in lower volumes due to weather.

Delivery

The $11 million decrease in delivery revenues for the quarter ended September 30, 2008 was due to decreases of $8 million in electric revenues and $3 million in gas revenues. The electric decrease was due primarily to $11 million in decreased volumes due to weather offset by $3 million in higher prices. The gas decrease was due to $3 million in lower volumes primarily due to weather.

The $29 million decrease in delivery revenues for the nine months ended September 30, 2008 was due to a $37 million decrease in gas revenues offset by a $9 million increase in electric revenues. The gas decrease was due to $15 million in decreased sales primarily due to weather and $22 million due to the Societal Benefits Clause (SBC) rate decrease in March 2007. The electric increase was due primarily to $29 million for increased SBC rates offset by $21 million in decreased volumes due to weather. PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses.

Operating Expenses

Energy Costs

The $180 million increase for the quarter ended September 30, 2008 was comprised of increases of $147 million and $33 million in electric and gas costs, respectively. The electric increase was due to $179 million in higher prices for BGS and NUG purchases offset by $32 million in lower volumes due to weather. The gas increase was caused by $39 million in higher BGSS prices offset by $6 million in lower volumes, primarily due to weather.

The $444 million increase for the nine months ended September 30, 2008 was comprised of increases of $378 million in electric costs and $66 million in gas costs. The increase in electric costs was primarily due to $438 million in higher prices for BGS and NUG purchases offset by $60 million in lower BGS volumes due to weather. The increase in gas costs was caused by a $164 million increase in prices offset by $98 million in lower volumes due to weather.

Operation and Maintenance

The $5 million increase for the quarter ended September 30, 2008 was primarily due to increased amortization of deferred expenses, resulting from a $6 million increase in the SBC in March 2007.

The $46 million increase for the nine months ended September 30, 2008 was due primarily to $27 million in increased amortization of deferred expenses, including a $23 million increase in the SBC in March 2007. Gas bad debt expenses have increased $2 million or about 8%. Injuries and damages decreased by $3 million. The remaining $20 million represents a 3% increase as a result of wage increases, the impact of higher commodity costs on materials and increased use of contract labor.

Depreciation and Amortization

The $6 million decrease for the nine months ended September 30, 2008 was due primarily to a $6 million decrease in Regulatory Asset amortization, a $5 million reduction in software amortization and a $4 million decrease in the amortization of DOE enrichment facility decommissioning costs. These decreases were offset by an $8 million increase due to increased plant in service and $1 million due to transmission general plant rate changes approved by FERC.

Other Income and Deductions

The $3 million decrease for the nine months ended September 30, 2008 was due to a $3 million decrease in investment interest income and a $2 million decrease in gains on the sale of property, plant and equipment. Offsetting these decreases was a $2 million increase in income tax gross-up on contributions in aid of construction (CIAC). CIAC are taxable and PSE&G recognizes the gross-up as income when collected.

Interest Expense

The $6 million decrease for the nine months ended September 30, 2008 was due primarily to decreases of $7 million resulting from lower short-term average interest rates and average debt balances outstanding and $2 million in lower interest on regulatory clauses. This was offset by $2 million resulting from higher long-term debt balances outstanding.

Income Taxes

The $6 million decrease for the quarter ended September 30, 2008 was primarily due to lower pre-tax income.

The $53 million decrease for the nine months ended September 30, 2008 was primarily due to decreased taxes of $28 million on lower pre-tax income, a $22 million decrease related to a one-time remeasurement of the FIN 48 reserves resulting from an IRS approved refund claim at PSEG for earlier tax years and $3 million in various tax adjustments.

Energy Holdings

For the quarter ended September 30, 2008, Energy Holdings had Net Income of $236 million, an increase of $165 million as compared to the same period in the prior year. For the nine months ended September 30, 2008, Energy Holdings had a Net Loss of ($159) million, a decrease of ($277) million as compared to the same period in the prior year.

The primary reason for the increase for the quarter was the net gain of $187 million on the sale of the SAESA Group included in Income from Discontinued Operations, partially offset by a $7 million Loss from Discontinued Operations in 2008, compared to $15 million of Income from Discontinued Operations in the same quarter of 2007.

The primary reason for the decrease for the nine months ended September 30, 2008, as compared to the same period in 2007, was the recognition of a charge of $490 million (after-tax) in the second quarter of 2008 associated with certain types of leveraged lease transactions at Resources. See Note 5. Commitments and

Contingent Liabilities. Also contributing to the decrease was a decrease in Income from Equity Method Investments. The decreases were partially offset by the net gain of $187 million on the sale of the SAESA Group included in Income from Discontinued Operations, $9 million of additional Income from Discontinued Operations, increased earnings from the Texas generation facilities, primarily due to an increase in spark spread (the difference between the market price of electricity and the costs of natural gas fuel) of $52 million ($34 million, after-tax) and the recognition of MTM gains of $15 million ($10 million, after-tax).


	For the Quarters Ended September 30,								Increase (Decrease)				%			For the Nine Months Ended September 30,								Increase (Decrease)				%
	2008				2007				Increase (Decrease)				%			2008				2007				Increase (Decrease)				%
	(Millions)															(Millions)
Operating Revenues		$	354			$	251			$	103			41			$	245			$	635			$	(390	)		(61	)
Energy Costs		$	214			$	127			$	87			69			$	427			$	354			$	73			21
Operation and Maintenance		$	28			$	27			$	1			4			$	95			$	90			$	5			6
Write-down of Assets		$	—			$	12			$	(12	)		(100	)		$	—			$	12			$	(12	)		(100	)
Depreciation and Amortization		$	7			$	7			$	—			N/A			$	22			$	23			$	(1	)		(4	)
Income from Equity Method Investments		$	8			$	30			$	(22	)		(73	)		$	27			$	87			$	(60	)		(69	)
Other Income and Deductions		$	7			$	—			$	7			100			$	14			$	16			$	(2	)		(13	)
Interest Expense		$	(18	)		$	(37	)		$	(19	)		(51	)		$	(60	)		$	(113	)		$	(53	)		(47	)
Income Tax Expense		$	(46	)		$	(15	)		$	31			N/A			$	(49	)		$	(40	)		$	9			23
Income from Discontinued Operations, net of Tax Expense		$	180			$	15			$	165			N/A			$	208			$	12			$	196			N/A
Net Income (Loss)		$	236			$	71			$	165			N/A			$	(159	)		$	118			$	(277	)		N/A

Variances are all related to the same period in the prior year. The detail is discussed below:

Operating Revenues

Operating Revenues were higher for the quarter ended September 30, 2008 by $103 million due to an increase in generation revenue at Global of $123 million, partially offset by lower lease revenue at Resources. The higher generation revenue was due to increases at the PSEG Texas facilities of $77 million from unrealized MTM gains, $37 million from higher electricity prices and $9 million from higher sales volumes.

Operating Revenues were lower for the nine months ended September 30, 2008 by $390 million mainly due to a $485 million pre-tax charge in June 2008. This charge related to the IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions at Resources. See Note 5. Commitments and Contingent Liabilities.

Excluding the lease transaction charge, Operating Revenues increased by $95 million for the nine months ended September 30, 2008. The increase was largely due to higher generation revenues of $142 million for Global operations at PSEG Texas’ facilities, resulting from a $181 million increase in electricity prices, higher unrealized MTM gains of $16 million and higher gas sales of $3 million, partially offset by $58 million of lower electricity sales volumes. The increase in generation revenues was partially offset by lower lease revenue and lower gains on investments of $40 million at Resources, and the absence of a $7 million gain on the sale of Global’s interest in Tracy Biomass in January 2007.

Operating Expenses

Energy Costs

Costs were higher in the quarter ended September 30, 2008 by $87 million due to increases at the Texas generation facilities. This resulted from increases in unrealized MTM losses of $48 million, fuel prices of $33 million and volume due to higher dispatch of $6 million.

Costs were higher for the nine months ended September 30, 2008 by $73 million due to increases at the Texas generation facilities. This resulted from increases in fuel prices of $106 million, and higher gas resale and power purchase of $6 million, partially offset by lower fuel consumption due to lower generation of $40 million.

Operation and Maintenance

Costs were higher for the nine months ended September 30, 2008 by $5 million primarily due to an increase at the Texas generation facilities for a scheduled maintenance outage as well as higher general and administrative expenses relating primarily to outside services at Global and additional severance and retention accruals.

Write-down of Assets

The amounts recorded for the quarter and nine months ended September 30, 2008 are for Global’s write-down of its investment in Turboven in September 2007. See Note 3. Discontinued Operations, Dispositions and Impairments for additional information.

Depreciation and Amortization

Costs were lower for the nine months ended September 30, 2008, by $1 million due to lower depreciation at the Texas Generation facilities.

Income from Equity Method Investments

Income decreased for the quarter and nine months ended September 30, 2008 by $22 million and $60 million, respectively, primarily due to the absence of income from Global’s 50% ownership interest in the Chilean electric distributor, Chilquinta and Global’s 37.9% ownership interest in the Peruvian electric distributor, Luz Del Sur (LDS). These assets were sold in December 2007. Income from Chilquinta was $10 million and $28 million for the quarter and nine months ended September 30, 2007, respectively. Income from LDS was $6 million and $19 million for the quarter and nine months ended September 30, 2007, respectively. In addition, there was lower income from other equity investments for the quarter and nine months ended September 30, 2008 of $6 million and $11 million, respectively, primarily due to higher fuel costs and lower generation.

Other Income and Deductions

The $7 million increase for the quarter ended September 30, 2008 was primarily due to an increase in interest and dividend income of $5 million in 2008 and an MTM loss adjustment taken in 2007 for a Chilquinta loan.

The $2 million decrease for the nine months ended September 30, 2008 was primarily due to the absence of a $9 million pre-tax gain in the first quarter of 2007 relating to the receipt of an arbitration award regarding the construction of a power plant in the Konya-Ilgin region of Turkey, partially offset by an increase in interest and dividend income of $7 million.

Interest Expense

The $19 million and $53 million decreases for the quarter and the nine months ended September 30, 2008, respectively, were primarily due to lower debt balances. See Note 8. Changes in Capitalization for more information.

Income Taxes

Taxes were higher for the quarter ended September 30, 2008 by $31 million due to a $30 million increase in taxes at Global resulting from a higher pre-tax income, combined with FIN 48 adjustments, and a $1 million increase in taxes at Resources.

Taxes were higher for the nine months ended September 30, 2008 by $9 million due to a $29 million increase at Global and a $20 million decrease at Resources. The increase at Global was due to a higher pre-tax income, adjustments to 2007 federal and state taxes, partially offset by a lower FIN 48 expense in 2008. The decrease at Resources was primarily due to an increase of $126 million relating to the leverage lease transactions, which was more than offset by a $130 million reduction in taxes due to a charge against revenues related to such leases and a $16 million decrease attributable to lower pre-tax income.

Income from Discontinued Operations, net of tax

Bioenergie

In August 2008, Energy Holdings entered into an agreement to sell its 85% ownership interest in Bioenergie, which consists of generation facilities in Italy. The Loss from Discontinued Operations related to Bioenergie for the quarter ended September 30, 2008 was $8 million as compared to Income from Discontinued Operations in 2007 of $1 million. The Losses from Discontinued Operations related to Bioenergie for the nine months ended September 30, 2008 and 2007 were $9 million and $13 million, respectively. See Note 3. Discontinued Operations, Dispositions and Impairments for additional information.

SAESA Group

In December 2007, Energy Holdings reclassified its investment in the SAESA Group of companies to Discontinued Operations. Income from Discontinued Operations related to the SAESA Group for each of the quarters ended September 30, 2008 and 2007 were $1 million and $10 million, respectively. Income from Discontinued Operations related to the SAESA Group for the nine months ended September 30, 2008 and 2007 were $30 million and $35 million, respectively. The sale was completed in July 2008 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, which is reported as Gain on Disposal of Discontinued Operations. See Note 3. Discontinued Operations, Dispositions and Impairments for additional information.

Electroandes

In June 2007, Energy Holdings reclassified its investment in Electroandes to Discontinued Operations. This resulted in a $19 million income tax expense at Global in the second quarter of 2007 related to the discontinuation of applying APB 23, because the income generated by Electroandes was no longer expected to be indefinitely reinvested.

Income from Discontinued Operations for the quarter ended September 30, 2007 was $4 million and Loss from Discontinued Operations for the nine months ended September 30, 2007 was $10 million. On October 17, 2007, Global completed the sale of Electroandes for a total purchase price of $390 million, including the assumption of approximately $108 million of debt. See Note 3. Discontinued Operations, Dispositions and Impairments for additional information.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, Power, PSE&G and Energy Holdings.

Operating Cash Flows

PSEG

For the nine months ended September 30, 2008, PSEG’s operating cash flow increased by $53 million from $1,539 million to $1,592 million, as compared to the same period in 2007, due to changes from its subsidiaries as discussed below.

Power

Power’s operating cash flow increased $161 million from $1,048 million to $1,209 million for the nine months ended September 30, 2008, as compared to the same period in 2007, primarily resulting from a decrease of $197 million in cash collateral requirements, an increase of $83 million from net collections of customer receivables and an increase in accounts payable of $61 million generally reflecting higher commodity costs in the first nine months of 2008 as compared to the same period in 2007, partially offset by $238 million of buildup of gas and coal inventories in anticipation of the winter heating season at higher 2008 prices, and other miscellaneous items.

PSE&G

PSE&G’s operating cash flow increased $301 million from $244 million to $545 million for the nine months ended September 30, 2008, as compared to the same period in 2007. The increase was primarily due

to a $90 million increase in cash collateral held by PSE&G, primarily under BGS contracts, a $189 million improvement in customer accounts receivable, and a $132 million increase in cash flow from income taxes. Through the first nine months of 2008, PSE&G experienced a normal seasonal decline in the accounts receivable balance while in the comparable period in 2007 the cash collections from customers were lower due to very mild weather in December 2006. The increase in cash flow from income taxes was a combination of bonus accelerated depreciation on 2008 property and the absence of a tax adjustment paid in 2007.

Offsetting the increase were higher outflows of $73 million for higher gas and electric commodity costs in 2008 due to higher prices and a $39 million in increased pension fund payments.

Energy Holdings

Energy Holdings’ operating cash flow decreased $458 million from $251 million to $(207) million for the nine months ended September 30, 2008, as compared to the same period in 2007. The decrease was mainly attributable to increased tax payments in 2008 related to asset sales, lower distributions from Global’s equity method investments in 2008, and an $80 million tax deposit made with the IRS in September 2008 associated with disputed tax assessments on certain lease investments. See Note 5. Commitments and Contingent Liabilities for additional information.

Common Stock Dividends

Dividend payments on common stock for the quarters ended September 30, 2008 and 2007 were $0.3225 and $0.2925 per share, respectively, and totaled $164 million and $149 million, respectively. Dividend payments on common stock for the nine months ended September 30, 2008 and 2007 were $0.9675 and $0.8775 per share, respectively, and totaled $492 million and $445 million, respectively. On July 15, 2008, PSEG’s Board of Directors approved a common stock dividend of $0.3225 per share for the third quarter of 2008, reflecting an indicated annual dividend rate of $1.29 per share. PSEG expects to continue to pay cash dividends on its common stock; however, the declaration and payment of future dividends to holders of PSEG common stock will be at the discretion of the Board of Directors and will depend upon many factors, including PSEG’s financial condition, earnings, cash flows, capital and credit requirements of its business, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.

Financial Markets Update

Due to the failures and weakening financial condition of several major institutions in the financial sector since late in the third quarter of 2008, the global financial markets have experienced unprecedented volatility. Liquidity in the capital markets has eroded as a result of tightening credit capacity by lenders and significantly higher risk premiums sought by investors. This recent crisis has been severe in nature and has resulted in government intervention in an attempt to create sustainability of the financial markets.

Although PSE&G anticipates accessing the capital markets, PSEG and Power do not expect to need to access the capital markets in the near term as they believe that their current level of projected operating cash flows and liquidity available under their credit facilities will be sufficient to:

•

fund necessary capital expenditures;

•

pay upcoming debt maturities;

•

provide any additional funding for the pension or NDT funds; and

•

maintain dividend payments.

However, if long-term capital is economically available and depending on their cash and liquidity positions, PSEG and its subsidiaries would issue longer term securities to meet some of these capital needs.

Liquidity

PSEG, Power, PSE&G and their subsidiaries have been managing their liquidity situations to assure that they have sufficient access to cash to operate their businesses in the event the capital markets do not allow for near term financing at reasonable terms. They are also closely monitoring the financial condition and concentration of lenders in their respective 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. No single institution is committing more than 9% of the total.

Recently, margin posting requirements have decreased due to a drop in commodity prices relative to where Power and Energy Holdings hedged their energy and fuel purchases. As a result, there is significant liquidity available under the credit facilities. As shown in the table below, PSEG, Power, PSE&G and Energy Holdings had available liquidity of $1.1 billion, $1.7 billion, $447 million and $115 million, respectively, as of September 30, 2008. Each of the 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 Power’s liquidity needs. PSEG, Power and PSE&G continually monitor their liquidity and seek to add capacity as needed to meet their liquidity requirements. During 2008, PSEG, Power and PSE&G added capacity of $147 million, $225 million and $28 million, respectively.


Company	Expiration Date	Total Facility			Primary Purpose	Usage as of September 30, 2008				Available Liquidity as of September 30, 2008
	(Millions)
PSEG:
5-year Credit Facility (A)	Dec 2012		$	1,000	CP Support/ Funding/Letters of Credit		$	—			$	1,000
Bilateral Credit Facility (B)	June 2009		$	100	CP Support/ Funding		$	—			$	100
Uncommitted Bilateral Agreement	N/A			N/A	Funding		$	—				N/A

Total for PSEG			$	1,100							$	1,100
Power:
5-year Credit Facility (A)	Dec 2012		$	1,600	Funding/Letters of Credit		$	225	(C)		$	1,375
Bilateral Credit Facility (D)	March 2009		$	150	Funding/Letters of Credit		$	59	(C)		$	91
Bilateral Credit Facility (B)	June 2009		$	100	Funding/Letters of Credit		$	—			$	100
Bilateral Credit Facility	March 2010		$	100	Funding/Letters of Credit		$	25	(C)		$	75
Bilateral Credit Facility (E)	Sept 2009		$	50	Funding			—			$	50

Total for Power			$	2,000							$	1,691
PSE&G:
5-year Credit Facility (A)	June 2012		$	600	CP Support/ Funding/Letters of Credit		$	153			$	447
Uncommitted Bilateral Agreement	N/A			N/A	Funding		$	28				N/A

Total for PSE&G			$	600							$	447
Energy Holdings:
5-year Credit Facility	June 2010		$	136	Funding/Letters of Credit		$	21			$	115

Total All Companies			$	3,836							$	3,353

(A)

During June 2008, the credit facilities for PSEG, Power and PSE&G were increased by $47 million, $75 million and $28 million, respectively, when a new counterparty made a commitment to all three credit facilities. In 2012, the facilities will be reduced by these same incremental amounts.

(B)

During June 2008, PSEG and Power each entered into these bilateral credit facilities.

(C)

These amounts relate to letters of credit outstanding.

(D)

Power had a $200 million bilateral credit facility that expired in March 2008. In April 2008, Power entered into a new facility of $150 million with the same counterparty on similar terms.

(E)

During September 2008, Power entered into this bilateral credit facility.

Power

As of September 30, 2008, PSEG had loaned $168 million to Power.

As discussed previously, Power’s required margin postings for sales contracts entered into in the normal course of business decreased significantly during the quarter ended September 30, 2008. The required margin postings will fluctuate based on volatility in commodity prices. Should commodity prices rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract obligations are fulfilled, liquidity requirements are reduced.

In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit rating to below investment grade, which represents at least a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide performance assurance, generally in the form of a letter of credit or cash. Providing this support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset portfolio.

As of September 30, 2008, Power believes it has sufficient liquidity required to meet its potential collateral requirements. See Note 5. Commitments and Contingent Liabilities for further information.

Financing

Following PSEG’s principal repayment of $49 million on its 6.89% senior notes due 2009 on October 29, 2008, there is one remaining maturity in 2008 of $250 million at PSE&G in November. PSEG, Power and PSE&G also have $249 million, $250 million and $60 million, respectively, of debt maturities upcoming in 2009, excluding securitized and non-recourse debt. The maturities are during the second quarter of 2009 for Power and PSE&G and during the third and fourth quarters for PSEG. Power also has $44 million of Pollution Control Bonds due 2042 that are subject to a mandatory tender on January 15, 2009, which it plans to remarket on that date.

PSEG and Power anticipate that they will be able to fund these maturities with expected cash generation and their current credit facilities based on current market and business conditions. If the capital market financing is available on economical terms, PSEG and Power would seek to refinance these obligations using longer term financial vehicles. Over the longer term, PSEG and its subsidiaries will need to access the capital markets to fund their construction programs and to provide capital for new development opportunities.

Pension and NDT Trust Assets

The weakening financial markets have resulted in significant year-to-date losses in both PSEG’s pension and NDT trust funds.

PSEG had previously anticipated funding its pension trust with approximately $75 million in 2009. Due to the recent volatility and weakening of the financial markets, PSEG will likely make additional cash contribution of $55 million in 2009. PSEG believes that this incremental amount is manageable given projected sources of cash flow from its businesses. The reduction in value of the pension trust fund in 2008 will also likely result in an increase to pension expense in 2009. The amount of the increment will depend on market performance and interest rates over the remainder of 2008.

It is also possible that Power may be required to provide additional decommissioning assurance in 2009 to the NDT Funds as mandated by minimum fund performance requirements. This additional decommissioning assurance may be up to $100 million and could be in the form of a cash contribution, a letter of credit or a parental guarantee.

External Financings

For information related to External Financings, see Note 8. Changes in Capitalization.

Debt Covenants

PSEG’s, Power’s and PSE&G’s respective credit agreements may contain maximum debt to total capitalization ratios and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon the respective future financial position, level of earnings and cash flows of PSEG, Power and PSE&G, as to which no assurances can be given. The ratios presented below are for the

benefit of the investors of the related securities to which the covenants apply. They are not intended as financial performance or liquidity measures.

PSEG

Financial covenants contained in PSEG’s note purchase agreements related to the private placement of debt include a ratio of total debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans and certain letters of credit) to total capitalization (including preferred securities outstanding) covenant. This covenant requires that such ratio not be more than 70.0%. As of September 30, 2008, PSEG’s ratio of debt to capitalization (as defined above) was 49.6%.

PSEG’s credit facilities contain a similar but less restrictive financial covenant where total debt excludes letters of credit related to collateral postings and total capitalization excludes any impacts for Accumulated Other Comprehensive Income/Loss adjustments related to marking energy contracts to market and equity reductions from the funded status of pensions or benefit plans associated with Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This covenant requires that such ratio not be more than 70.0%. As of September 30, 2008, PSEG’s ratio of debt to capitalization (as defined above) was 48.1%.

Power

Financial covenants contained in Power’s credit facilities include a ratio of debt to total capitalization covenant. The Power ratio is the same debt to total capitalization calculation as set forth above for PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets). This covenant requires that such ratio will not exceed 65.0%. As of September 30, 2008, Power’s ratio of debt to total capitalization (as defined above) was 39.3%.

PSE&G

Financial covenants contained in PSE&G’s credit facility include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total capitalization covenant. This covenant requires that such ratio will not be more than 65.0%. As of September 30, 2008, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 45.8%.

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of September 30, 2008, PSE&G’s Mortgage coverage ratio was 3.9 to 1 and the Mortgage would permit up to $2.2 billion aggregate principal amount of new Mortgage Bonds to be issued against previous bondable additions and improvements to its property.

Credit Ratings

PSEG, Power and PSE&G

If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, Power’s and PSE&G’s securities and serve to materially increase those companies’ cost of capital and limit their 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 June 2008, Moody’s affirmed the rating of Energy Holdings and changed the ratings outlook to Stable from Negative. In July 2008, Moody’s affirmed the ratings of PSEG and PSE&G and changed the ratings outlook of both companies to Stable from Negative. The rating and outlook of Power remained unchanged.


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

Other Comprehensive Income

PSEG, Power and PSE&G

For information related to Other Comprehensive Income/Loss, see Note 7. Comprehensive Income (Loss), Net of Tax.

CAPITAL REQUIREMENTS

PSEG, Power and PSE&G

As noted previously, PSE&G has revised its anticipated capital expenditures as compared to amounts presented in the 2007 Form 10-K. PSE&G anticipates decreasing its planned capital spending for 2009 by approximately $125 million. The decrease at PSE&G is comprised of an increase in spending in transmission of $100 million on approved capital projects, partially offset by a reduction in spending in electric and gas distribution and other areas of approximately $225 million.

It is expected that the majority of funding for capital requirements of PSEG, Power and PSE&G will come from their respective internally generated funds. As discussed above under Liquidity and Capital Resources, depending on market conditions and the cash and liquidity position of each business, the balance is expected to be provided by the issuance of debt at the respective subsidiary or project level and by equity contributions from PSEG.

Power

During the nine months ended September 30, 2008, Power made $598 million of capital expenditures (excluding $79 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 nine months ended September 30, 2008, PSE&G made $534 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $534 million does not include expenditures for cost of removal, net of salvage, of $33 million, which are included in operating cash flows.

ACCOUNTING MATTERS

PSEG, Power and PSE&G

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

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES
ABOUT MARKET RISK

PSEG, Power and PSE&G

The market risk inherent in PSEG’s, Power’s and PSE&G’s market-risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements (Notes). It is the policy of each entity to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, Power and PSE&G have a Risk Management Committee comprised of executive officers who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.

Additionally, PSEG, Power and PSE&G are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG’s and its subsidiaries’ Condensed Consolidated Financial Statements.

Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, Power and PSE&G for the year ended December 31, 2007 or Quarterly Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008.

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, Power enters 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.

Normal Operations and Hedging Activities

Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to reduce risk associated with volatile commodity prices. Commodity price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors.

Under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), changes in the fair value of qualifying cash flow hedge transactions are recorded in Accumulated Other Comprehensive Loss, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings.

Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and are accounted for upon settlement.

Trading

Power maintains a strategy of entering into positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. In addition, Power has non-asset based trading activities. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to market in accordance with SFAS 133 with gains and losses recognized in earnings.

Value-at-Risk (VaR) Models

Power

Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR model for Power includes its 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. Power estimates VaR across its commodity businesses.

Power manages its exposure at the portfolio level. Its portfolio 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 Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and its hedges. Non-trading 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 by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for the MTM trading and non-trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively manages its portfolio.

Higher market prices and volatilities have lead to a higher non-trading VaR as compared to September 30, 2007 and December 31, 2007. As of September 30, 2008, trading VaR was $3 million and as of December 31, 2007, trading VaR was less than $1 million.


	Trading VaR				Non-Trading MTM VaR
	(Millions)
For the Quarter Ended September 30, 2008
95% Confidence Level, One-Day Holding Period, One-Tailed:
Period End		$	3			$	67
Average for the Period		$	1			$	80
High		$	3			$	117
Low		$	—	*		$	60
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End		$	5			$	104
Average for the Period		$	1			$	126
High		$	5			$	183
Low		$	—	*		$	93

less than $1 million

Other Supplemental Information Regarding Market Risk

Power

The following tables describe the drivers of Power’s energy trading and marketing activities and Operating Revenues included in its Condensed Consolidated Statement of Operations for the quarter and nine months ended September 30, 2008. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale market. As the information in these tables highlight, MTM activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices. For additional information, see Note 6. Financial Risk Management Activities.

Operating Revenues
For the Quarter Ended September 30, 2008


	Normal Operations and Hedging (A)				Trading				Total
	(Millions)
MTM Activities:
Unrealized MTM Gains (Losses)
Changes in Fair Value of Open Position		$	23			$	2			$	25
Realization at Settlement of Contracts			(1	)			3				2

Total Change in Unrealized Fair Value			22				5				27
Realized Net Settlement of Transactions Subject to MTM			1				(3	)			(2	)

Net MTM Gains			23				2				25
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			1,808				—				1,808

Total Operating Revenues		$	1,831			$	2			$	1,833

Operating Revenues
For the Nine Months Ended September 30, 2008


	Normal Operations and Hedging (A)				Trading				Total
	(Millions)
MTM Activities:
Unrealized MTM Gains (Losses)
Changes in Fair Value of Open Position		$	28			$	22			$	50
Realization at Settlement of Contracts			(2	)			(12	)			(14	)

Total Change in Unrealized Fair Value			26				10				36
Realized Net Settlement of Transactions Subject to MTM			2				12				14

Net MTM Gains			28				22				50
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			5,781				—				5,781

Total Operating Revenues		$	5,809			$	22			$	5,831

(A)

Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset-backed transactions (ABT) and hedging activities, but excludes owned and contracted generation assets.

The following table indicates Power’s energy contracts, including Power’s hedging activity related to ABT and derivative instruments that qualify for hedge accounting under SFAS 133. This table and the one that follows present amounts segregated by portfolio that are then netted for those counterparties with whom Power has the right to offset and therefore, are not necessarily indicative of amounts presented on the Condensed Consolidated Balance Sheets. The balances with counterparties with whom Power has master netting agreements may also be offset against collateral amounts with those counterparties. As of September 30, 2008, $16 million of net cash collateral received included in a Net Derivative Contract Liability of $203 million resulted in a Net Derivative Contract Liability of $219 million as presented on the Condensed Consolidated Balance Sheet.

Energy Contract Net Assets/Liabilities
As of September 30, 2008


	Normal Operations and Hedging				Trading				Total
	(Millions)
MTM Energy Assets
Current Assets		$	134			$	84			$	218
Noncurrent Assets			6				25				31

Total MTM Energy Assets			140				109				249

MTM Energy Liabilities
Current Liabilities		$	(361	)		$	(34	)		$	(395	)
Noncurrent Liabilities			(35	)			(22	)			(57	)

Total MTM Energy Liabilities			(396	)			(56	)			(452	)

Total MTM Energy Contract Net Assets (Liabilities)		$	(256	)		$	53			$	(203	)

The following table presents the maturity of net fair value of MTM energy contracts.

Maturity of Net Fair Value of MTM Energy Trading Contracts
As of September 30, 2008


	Maturities within
	2008				2009				2010-2012				Total
	(Millions)
Trading		$	30			$	39			$	(15	)		$	54
Normal Operations and Hedging			(17	)			(161	)			(79	)			(257	)

Total Net Unrealized Gains (Losses) on MTM Contracts		$	13			$	(122	)		$	(94	)		$	(203	)

Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.

Global

The following table describes the drivers of Global’s marketing activities and Operating Revenues included in PSEG’s Condensed Consolidated Statement of Operations for the quarter and nine months ended September 30, 2008. Normal operations and hedging activities represent the marketing of electricity available from Global’s owned generation sold into the market. Activities accounted for under the accrual method account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices.

Operating Revenues
For the Quarter Ended September 30, 2008


	Normal Operations and Hedging (A)
	(Millions)
MTM Activities:
Unrealized MTM Gains
Changes in Fair Value of Open Position		$	48
Realization at Settlement of Contracts			—

Total Change in Unrealized Fair Value			48
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			284

Total Operating Revenues		$	332

Operating Revenues
For the Nine Months Ended September 30, 2008


	Normal Operations and Hedging (A)
	(Millions)
MTM Activities:
Unrealized MTM Gains
Changes in Fair Value of Open Position		$	31
Realization at Settlement of Contracts			—

Total Change in Unrealized Fair Value			31
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			614

Total Operating Revenues		$	645

(A)

Includes derivative contracts that Global enters into to hedge anticipated exposures related to its owned and contracted generation supply.

The following table indicates Global’s energy contract net assets.

Energy Contract Net Assets/Liabilities
As of September 30, 2008


	Normal Operations and Hedging
	(Millions)
MTM Energy Assets
Current Assets		$	28
Noncurrent Assets			35

Total MTM Energy Assets			63

MTM Energy Liabilities
Current Liabilities		$	3
Noncurrent Liabilities			—

Total MTM Energy Liabilities			3

Total MTM Energy Contract Net Assets		$	60

The following table presents the maturity of net fair value of MTM energy contracts.

Maturity of Net Fair Value of MTM Energy Contracts
As of September 30, 2008


	Maturities within
	2008			2009			2010-2012			Total
	(Millions)
Total Net Unrealized Gains on MTM Contracts		$	5		$	28		$	27		$	60

PSEG and Power

The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG and Power are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. The table also provides an estimate of the losses, net of taxes that are expected to be reclassified out of Accumulated Other Comprehensive Loss and into earnings over the next twelve months.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
As of September 30, 2008


	Accumulated Other Comprehensive Loss				Portion Expected to be Reclassified in next 12 months
	(Millions)
Commodities		$	(66	)		$	(21	)
Interest Rates			(7	)			3

Net Cash Flow Hedge Loss Included in Accumulated Other Comprehensive Loss		$	(73	)		$	(18	)

Power

Credit Risk

The following table provides information on Power’s credit exposure, net of collateral, as of September 30, 2008. 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 September 30, 2008


Rating	Current Exposure			Securities Held as Collateral			Net Exposure			Number of Counterparties >10%			Net Exposure of Counterparties >10%
				(Millions)									(Millions)
Investment Grade—External Rating		$	339		$	32		$	316		1	(A)		$	204
Non-Investment Grade—External Rating			405			—			405		1	(B)			363
Investment Grade—No External Rating			2			—			2		—				—
Non-Investment Grade—No External Rating			38			1			37		—				—

Total		$	784		$	33		$	760		2			$	567

(A)

PSE&G is a counterparty with net exposure of $204 million.

(B)

Credit exposure is with a non-investment grade counterparty that is a coal supplier to Power. Therefore, this exposure relates to the risk of the counterparty’s non-performance under its obligations rather than payment risk. Coal prices have risen sharply since the beginning of 2008.

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 collateral than the outstanding exposure, in which case there would not be exposure. As of September 30, 2008, Power had 127 active counterparties.

ITEM 4. CONTROLS AND PROCEDURES

PSEG, Power and PSE&G

Disclosure Controls and Procedures

PSEG, Power and PSE&G 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) to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Securities Exchange Act of 1934 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. PSEG, Power and PSE&G 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

PSEG, Power and PSE&G continually review their respective disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting. There have been no changes in internal control over financial reporting that occurred during the third quarter of 2008 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

PSEG, Power and PSE&G

PSEG, Power and PSE&G are parties 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 2007 Annual Reports on Form 10-K of PSEG, Power and PSE&G and Item 1 of Part II of the respective Quarterly Reports on Form 10-Q of PSEG, Power and PSE&G for the quarters ended March 31, 2008 and June 30, 2008, see Note 5. Commitments and Contingent Liabilities and Item 5. Other Information, Regulatory Issues.

ITEM 1A. RISK FACTORS

The risk factors discussed below should be read in conjunction with, and update and supplement the risk factors discussed in PSEG’s, Power’s and PSE&G’s respective Annual Reports on Form 10-K for the year ended December 31, 2007 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008.

2007 Form 10-K, Page 35 and March 31, 2008 and June 30, 2008 Quarterly Reports on Form 10-Q. We may be adversely affected by changes in energy deregulation policies, including market design rules. The energy industry continues to experience significant change. Our business has been impacted by rules established that create locational capacity markets in each of PJM, New England and New York. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. While the existence of these rules has had a positive impact on Power’s revenues, as its generation in PJM and New England is located in constrained areas, both PJM’s and New England’s locational capacity market design rules have been challenged in court. Any changes to these rules may have an adverse impact on our financial condition, results of operations and cash flows.

In May 2008, several state commissions, customer groups and certain federal agencies filed a complaint with FERC against PJM with respect to its RPM, which was recently dismissed by the FERC. PJM, however, is in the process of conducting a stakeholder proceeding with an aggressive time schedule to develop prospective changes and enhancements to RPM. PJM is expected to make a filing at FERC in the fourth quarter of 2008 to propose these prospective changes.

In July 2008, Power and PSE&G filed a brief with the United States Court of Appeals for the District of Columbia Circuit due to concerns regarding the manner in which the Cost of New Entry (CONE) under RPM is calculated. Other petitioners, including the BPU, also filed briefs. PSE&G filed a reply brief in this proceeding on October 30, 2008.

For additional information on Capacity Market Issues see Item 5. Other Information.

2007 Form 10-K, Page 37 and March 31, 2008 and June30, 2008 Quarterly Reports on Form 10-Q. Certain of our leveraged lease transactions at Resources may be successfully challenged by the IRS, which would have a material adverse effect on our taxes, operating results and cash flows. The IRS has disallowed all deductions associated with certain lease transactions that are similar to a type that the IRS publicly announced its intention to challenge, for tax years 1997 through 2000, and 2001 through 2003. As of September 30, 2008 and December 31, 2007, Resources’ total gross investment in such transactions was $1 billion and $1.5 billion, respectively.

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.

As of September 30, 2008, $1.2 billion in the aggregate, would become currently payable if PSEG conceded 100% of deductions taken through that date. In December 2007, PSEG deposited $100 million with

the IRS to defray potential interest costs associated with this disputed tax liability. In September 2008, PSEG deposited an additional $80 million bringing to $180 million the total cash deposited with the IRS. 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 approximately $1 billion. As of September 30, 2008, penalties of $151 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. We have not established a reserve for penalties because we believe we have strong defenses to the assertion of penalties under applicable law. Interest and penalties grow at the rate of $15 million per quarter. 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 September 30, 2008.

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

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


2008	Total Number of Shares Purchased (A)		Average Price Paid 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 (in millions)
July 1–July 31		8,000		$	46.57		N/A			N/A
August 1–August 31 (A)		1,137,500		$	40.14		1,129,500		$	704
September 1–September 30 (A)		1,256,700		$	37.06		1,252,700		$	658

(A)

Includes repurchases of shares in the open market to satisfy the exercise of stock option awards.

ITEM 5. OTHER INFORMATION

Certain information reported under the 2007 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarters ended March 31, 2008 and June 30, 2008 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2007 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 and June 30, 2008. References are to the related pages on the Form 10-K, and Form 10-Q as printed and distributed.

REGULATORY ISSUES

Federal Regulation

FERC

PSEG, Power and PSE&G

Regulation of Wholesale Sales—Generation/Market Issues

2007 Form 10-K, Page 15 and March 31, 2008 Form 10-Q, page 65 and June 30, 2008 Form 10-Q, page 74. Under FERC regulations, public utilities must receive FERC authorization to sell power in interstate commerce. Public utilities may sell power at cost-based rates or may apply to FERC for authority

to sell power at market-based rates (MBR). In order to obtain approval to sell power at MBR, FERC must first make a determination that the requesting company lacks market power in the relevant markets. Once this determination is made, and MBR authority is granted, the public utility’s individual sales made under the MBR authority are not reviewed or approved by FERC but are reported to FERC in quarterly reports.

PSE&G, ER&T, Power Connecticut, Fossil and Nuclear submitted MBR filings in January 2008 to FERC in which they asserted that they either lack any generation market power or, if they do possess any market power, that market power is being effectively mitigated. They further asserted that, to the extent that FERC analyzes market power held in the small sub-market of Northern PSEG, PJM mitigation rules (including price capping for bids) eliminate the potential for the exercise of market power in this sub-market.

On October 16, 2008, the FERC accepted the updated market power filing of PSE&G, ER&T and Power Connecticut concluding that the applicants had satisfied the FERC’s standards for market-based rate authority. In addition, the FERC granted market-based rate authorization to Fossil and Nuclear.

Capacity Market Issues

2007 Form 10-K, Page 16 and March 31, 2008 Form 10-Q, page 66 and June 30, 2008 Form 10-Q, page 74. RPM is a locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under RPM, generators located in constrained areas within PJM are paid more for their capacity so that they are incented to locate in those areas where generation capacity is most needed. Four PJM capacity auctions covering commitment periods extending from June 1, 2007 through May 31, 2011 have been held to date.

Cost of New Entry (CONE)

On July 21, 2008, Power and PSE&G filed a brief with the United States Court of Appeals for the District of Columbia Circuit due to concerns regarding the manner in which the CONE is calculated. Other petitioners’ briefs, including the BPU, were also filed. Reply briefs will be filed by the end of October.

Power and PSE&G strongly support the RPM design but believe that certain components of the design, particularly the CONE mechanism, should be modified.

If the CONE is set too low, generators in the PJM markets may not be adequately compensated for existing capacity and may not have sufficient incentives to construct new generating units.

RPM Auction

On May 30, 2008, several state commissions, including the BPU and consumer advocate agencies, as well as customer groups and certain federal agencies (RPM Buyers) filed a complaint with FERC against PJM with respect to RPM.

The complaint challenged the results of the RPM capacity auctions held for the 2008/2009, 2009/2010 and 2010/2011 delivery years. The RPM Buyers asserted that various RPM rules permitted suppliers to reduce the amount of capacity offered into the auctions, thereby increasing prices, and that PJM’s mitigation measures were inadequate to restrain the exercise of market power in the capacity auctions. The RPM Buyers requested that FERC find that the clearing prices produced are unlawful and thus should not be charged to capacity buyers or paid to capacity sellers such as Power, and requested refunds, with a refund effective date of May 30, 2008.

On September 18, 2008, the FERC issued an order dismissing the RPM Buyers complaint. In dismissing the complaint, the FERC concluded that:

•

The RPM Buyers had failed to allege or prove that any party violated PJM’s Tariff and market rules;

•

There was no showing of market power, and mitigation rules exist to address any potential violations; and

•

The prices determined for the transition period were set in accordance with PJM’s FERC-approved Tariff.

FERC’s dismissal of the complaint, if upheld on rehearing and on appeal, eliminates the potential for the payment of refunds with respect to transitional auction payments made to generators in PJM, including Power. In October 2008, the RPM Buyers sought rehearing of this dismissal order at the FERC.

RPM Model

PJM is evaluating ways to improve RPM. PJM retained the Brattle Group, an outside consultant, to prepare a report evaluating the efficacy of the RPM model. This report, which was issued on June 30, 2008, recommends maintaining the basic design elements of RPM but also proposes changes to RPM that would, among other things:

•

increase the pool of resources that can be bid into RPM, e.g. enhancing the ability of efficiency and demand response resources to bid in;

•

revise the penalty structure for deficiencies and unavailability of capacity resources, perhaps increasing the penalties levied on demand resources;

•

redesign the incremental auction process by creating a single type of incremental auction; and

•

evaluate and refine the process for calculating the net CONE.

PJM has initiated a stakeholder process to address some or all of the recommendations proposed in the Brattle Group report, and has been directed by the FERC to file proposed changes in certain areas with the FERC by December 15, 2008. The FERC has also directed its Staff to convene a technical conference in February 2009 on the issues raised in the RPM Buyers’ complaint and related issues raised by PJM stakeholders, with the objective of implementing any necessary changes to RPM in time for the May 2009 auction.

Reactive Power

June 30, 2008 Form 10-Q, page 75. Reactive power encompasses certain ancillary services necessary to maintain voltage support and operate the system. In May 2008, ER&T filed with FERC to increase its annual fixed revenues by $18 million to reflect its provision of reactive power support in PJM. No protests were filed regarding the filing, though PJM filed to challenge the proposed effective date. PJM filed comments asking FERC not to make the rates effective in May, due to concerns with retroactive billing adjustments, but rather to make the rates effective the first day of the month that FERC approves the filing. As requested by FERC, ER&T provided additional support for its filing in July 2008. No protests were filed by the comment date. In September 2008, ER&T made a supplemental filing as directed by the FERC. The FERC is expected to act in November 2008 on the filing.

FERC Transmission Regulation

PSE&G Transmission Rate Case Filing

In July 2008, PSE&G filed a petition with FERC to implement a cost of service formula rate for PSE&G’s existing and future transmission investment.

Formula-type rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula which takes O&M expenditures and capital investments and applies an approved Return on Equity (ROE). PSE&G proposed a forward-looking formula rate mechanism, which would allow PSE&G to update its transmission rates annually based on forecasted O&M and capital expenditures for the coming year, with no lag of recovery, and would provide for a true-up to actual expenditures in the subsequent year. PSE&G also proposed an ROE of 11.68%. While PSE&G did not request approval in this petition of any incentive rates, the formula rate mechanism would provide for recovery of previously-approved transmission rate incentives as well as a mechanism for recovery of any transmission incentives authorized in the future.

On September 30, 2008, the FERC approved PSE&G’s request for formula transmission rates, effective October 1, 2008. Under this formula, PSE&G will put rates into effect each January for that year based upon its internal forecast of annual expenses and capital expenditures. Rates will be trued up to reflect the actual annual expense/capital expenditures the following year. The order provides for an ROE of 11.68% on existing and new transmission investment as requested. The approved formula also provides a mechanism to flow through incentives to transmission customers; the incentive rates, however, are separately approved by the FERC on a project-by-project basis. Thus, since PSE&G has already obtained FERC approval for incentive transmission rates for its Susquehanna-Roseland project, the authorized incentives will be added to the approved base ROE, yielding an ROE of 12.93% for this particular project.

Transmission Rates and Cost Allocation

2007 Form 10-K, Page 17 and June 30, 2008 Form 10-Q, page 76. In 2007, PJM and its members reached a settlement regarding how to allocate costs for new lower voltage (below 500 kilovolts (kV)) transmission expansion. Specifically, PJM will use a “beneficiary pays” methodology, identifying the beneficiaries of a particular expansion and allocating costs to those beneficiaries. On July 29, 2008, FERC issued an order approving this settlement. While the settlement is quite comprehensive in establishing how to determine the beneficiaries of a particular transmission expansion and allocating the costs to those beneficiaries, the parties did not reach agreement on certain issues related to whether and how merchant transmission facilities that have firm rights to export power out of PJM to another region should be included in the beneficiary pays analysis and be responsible for a share of the costs of the transmission upgrades. These issues were set for hearing before FERC.

On September 18, 2008, following the conclusion of a hearing, a FERC Administrative Law Judge (ALJ) issued an initial decision agreeing with PSEG’s position that merchant transmission facilities should be required to pay a load ratio share of all future transmission projects in PJM, such as PSE&G’s Susquehanna-Roseland project. Thus, merchant transmission facilities holding a firm right to withdraw power from PJM will be treated like load in PJM for purposes of future cost allocations. On October 20, 2008, the merchant transmission projects filed exceptions to this decision with the FERC, thereby ensuring review of the ALJ decision by the FERC.

Transmission Expansion

2007 Form 10-K, Page 17 and March 31, 2008 Form 10-Q, page 67 and June 30, 2008 Form 10-Q, page 76. In June 2007, PSE&G endorsed the construction of three new 500 kV transmission lines intended to address reliability issues of the electrical grid serving New Jersey customers. Also in June 2007, PJM approved construction of one of the proposed lines (Susquehanna-Roseland line) and in April 2008, FERC approved incentive rate treatment for the line.

In May 2008, seven state consumer advocates, including the New Jersey Division of Rate Counsel (Rate Counsel), sought rehearing of FERC’s April 2008 order approving the incentive rate treatment. In June 2008, PSE&G and PPL Corporation (PPL) filed an answer to this rehearing request, urging FERC to deny the request for rehearing. On September 5, 2008, the FERC denied the rehearing request and confirmed the rate incentives it granted PSE&G and PPL for the Susquehanna-Roseland project.

Through the RTEP process, PJM has identified the need for the construction of a 500kV transmission line running from Virginia through Maryland and Delaware and terminating in Salem Township. PSE&G will be responsible for constructing and operating a portion of this line, known as the Mid-Atlantic Pathway Project (MAPP), when approved.

Consolidated Edison Company of New York, Inc (Con Ed)

June 30, 2008 Form 10-Q, page 76. In November 2001, Con Ed filed a complaint with FERC against PSE&G, PJM and NYISO asserting a failure to comply with agreements between PSE&G and Con Ed covering 1,000 MW of transmission. Both PSE&G and Con Ed have sought judicial review of FERC orders addressing these contracts before the U.S. Court of Appeals for the District of Columbia Circuit. The matter remains pending.

The agreements expire in May 2012. On April 22, 2008, pursuant to FERC rules that permit holders of long-term transmission rights to extend their entitlements, PJM filed contracts with FERC which would extend until 2017 the transmission service that is the subject of the disputed agreements between PSE&G and Con Ed. PSE&G has protested PJM’s filing.

On August 26, 2008, FERC issued an order setting for hearing and settlement procedures most of the issues raised by PSE&G in its protest. A settlement conference was held on October 29, 2008. If the parties are unable to settle, the matter will proceed to hearing.

PSE&G is unable to predict the outcome of these proceedings.

Compliance

Reliability Standards

One of FERC’s tasks in the compliance area is to ensure compliance with reliability standards developed by the North American Electric Reliability Corporation (NERC) and approved by the FERC. Congress has required FERC to put in place, through NERC, national and regional reliability standards to ensure the reliability of the U.S. electric transmission grid and to prevent major system blackouts. NERC has developed, and FERC has approved, many reliability standards, compliance with which is mandatory by all those entities (including transmission owners, generation owners and generation operators) that have the ability to impact upon the reliability of the bulk electric transmission system (100 kV and above). PSEG, PSE&G, Power and Energy Holdings (or their operating subsidiaries) are obligated to comply with the standards and to ensure continuing compliance. FERC has the ability to impose penalties of up to $1 million per day per violation for any violation of NERC Reliability Standards.

In August 2008, Energy Holdings’ Texas generating plants were audited for NERC Reliability Standards compliance by the Texas Regional Entity (TRE), NERC’s regional arm in Texas. On October 27, 2008, TRE issued its final audit report for the plants, concluding that both plants were in compliance with the NERC Reliability Standards for which they were audited. In November 2008, PSE&G will be audited by ReliabilityFirst Corporation, NERC’s regional arm in PJM.

Standards of Conduct

In March 2008, FERC initiated a rulemaking proceeding, seeking industry comment on whether FERC’s then-existing Standards of Conduct regulations–governing the interaction between Transmission Provider employees and wholesale merchant employees–should be revised to make them clearer, less restrictive and easier to follow. PSEG, along with many other industry participants, filed comments in this proceeding. On October 16, 2008, FERC issued a Final Rule in this proceeding, which revises FERC’s Standards of Conduct by abandoning the “corporate” separation approach to regulating these interactions and instead adopting an “employee function” approach, which focuses on an individual employee’s job functions in determining how the rules will apply. PSEG is presently analyzing the Final Rule to determine all of its impacts, and will then take all necessary steps to ensure compliance with these new rules.

State Regulation

PSE&G

SBC Filing

2007 Form 10-K, Page 20 and June 30, 2008 Form 10-Q, page 77. The SBC is a mechanism designed to insure recovery of costs associated with activities required to be accomplished to achieve specific government mandated public policy determinations. The programs that are covered by the SBC (gas and electric) are energy efficiency and renewable energy programs, Manufactured Gas Plant RAC and the USF. In addition, the electric SBC includes a Social Programs component. All components include interest on both over and under recoveries.

In May 2007, PSE&G filed a motion with the BPU seeking approval of changes in its electric and gas SBC rates and its electric non-utility generation charge (NGC) rates. A revised motion was filed in October 2007. In June 2008 PSE&G received the ALJ’s Initial Decision disallowing a portion of its claimed lost revenues. The ALJ granted an electric increase of $89.7 million compared to $89.8 million requested and a gas increase of $15.2 million compared to PSE&G’s request of $16.7 million. Exceptions and reply exceptions were filed in July 2008.

In September 2008, the BPU voted to modify the ALJ’s initial decision, which had recommended a total rate increase of $105 million. This BPU ruling affirms the disallowance of $1.4 million of lost revenues. As of October 22, 2008, the BPU had not issued its written Order. Upon reviewing the BPU’s Order, PSE&G will determine what actions to take in regard to the decision.

RAC Filing

2007 Form 10-K, Page 20. In December 2007, PSE&G submitted its RAC 15 filing with the BPU, seeking recovery of $36 million of RAC program costs incurred during the twelve-month period from

August 1, 2006 through July 31, 2007 and a determination that these costs were reasonable and available for recovery.

On October 3, 2008, the BPU issued an Order approving the settlement of the matter and affirming recovery of PSE&G’s RAC 15 costs of $36 million. Amortization of the program costs is equal to revenues with no impact on Net Income.

Power and PSE&G

BGSS

2007 Form 10-K, Page 21 and March 31, 2008 Form 10-Q, page 68 and June 30, 2008 Form 10-Q, page 77.. BGSS is the mechanism approved by the BPU designed to recover all gas costs related to the supply for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. Revenues are matched with costs using deferred accounting, with the goal of achieving a zero cumulative balance by September 30 of each year.

In May 2008, PSE&G requested an increase in annual BGSS revenues of $376 million, excluding Sales and Use Tax, to be effective October 1, 2008. This represents an approximate 20% increase on a typical residential gas customer’s bill. Based on discussions with the BPU Staff, PSE&G submitted a proposed Stipulation of the Parties that would place the filed rate into effect on October 1, 2008 on a provisional basis, subject to refund.

In August 2008, due to the significant downward trend in wholesale natural gas prices, PSE&G proposed a revised stipulation to the BPU reducing the requested BGSS increase from the filed $376 million or 20% to approximately $267 million or 14.3%. The BPU approved it on October 3, 2008 and the new BGSS rates became effective immediately.

Solar Initiative

2007 Form 10-K, Page 22 and March 31, 2008 Form 10-Q, page 68 and June 30, 2008 Form 10-Q, page 77. In April 2007, PSE&G filed a plan with the BPU designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. This program received final BPU approval and a written BPU order in April 2008. Under the plan, PSE&G will invest approximately $105 million over two years in a pilot program to help finance the installation of 30 MW of solar systems throughout its electric service area. PSE&G will provide loans to customers in its electric service territory for the installation of solar photovoltaic systems on the customers’ premises. The borrowers can repay the loans over a period of either 10 years (for residential customer loans) or 15 years (for all other loans) by providing PSE&G with solar renewable energy certificates (SRECs). Borrowers will also have the option to repay the loans with cash.

The program will support 30 MW of solar power, fulfilling approximately 50% of the BPU’s Renewal Portfolio Standard requirements in PSE&G’s service area in May 2009 and May 2010.

PSE&G will be allowed a return of 11.11% on invested capital, including income tax effects. The program was opened up to non-residential customers on April 17, 2008. As of September 30, 2008, applications have been received for approximately 34% of the 30 MW program. Beginning July 2008, the program became available to residential customers. The BPU, through a stakeholder working group, also spent several months considering whether additional measures are needed to stimulate solar development in New Jersey. In August 2008, the BPU issued an order directing PSE&G to commence discussions with BPU Staff and the Division of Rate Counsel regarding the development of an SREC-based financing plan. Thus, PSE&G is currently working to modify its existing solar loan program for the Energy Years ending May 31, 2011 and May 31, 2012 in a manner that will stimulate a competitive market for SRECs, and plans to make a filing with the BPU in January 2009. The August order does not change the terms of PSE&G’s existing pilot solar loan program.

New Jersey Energy Master Plan (EMP)

2007 Form 10-K, Page 22 and March 31, 2008 Form 10-Q, page 68 and June 30, 2008 Form 10-Q, page 78. State law in New Jersey requires that an EMP be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. A final EMP was released in October 2008. The final plan identifies a number of

the actions to improve energy efficiency, increase the use of renewable resources, ensure a reliable supply of energy and stimulate investment in clean energy technologies, including to:

•

maximize energy conservation and energy efficiency to reduce New Jersey’s projected energy use by 20% by the year 2020;

•

reduce prices by decreasing peak demand by 5,700 MW by 2020;

•

strive to achieve 30% of the state’s electricity needs from renewable sources by 2020;

•

develop at least 3000 MW of off-shore wind by 2020,

•

develop new low carbon emitting, efficient power plants to help close the gap between the supply and demand of electricity;

•

invest in innovative clean energy technologies and businesses to stimulate the industry’s growth and green job development in New Jersey;

•

work with electric and gas utilities to develop individual utility master plans through 2020 to evaluate options to modernize the electrical grid

•

establish a state energy council;

•

conduct a complete review of the BGS auction process;

Consistent with the EMP, PSE&G has proposed several programs in filings with the BPU addressing different components of the EMP goals, has submitted a number of strategies designed to improve efficiencies in customer use and increase the level of renewable generation. PSEG and PSE&G participated in the EMP roundtable discussions and outreach sessions conducted by the State of New Jersey from June through August 2008 to review the conclusions and recommendations of the EMP.

Advanced Metering Infrastructure (AMI) Technologies

2007 Form 10-K, Page 22 and June 30, 2008 Form 10-Q, page 78. In December 2007, PSE&G filed a petition with the BPU requesting expedited approval to deploy and test AMI technologies, to enable customers to monitor energy use, conserve energy, reduce costs during peak periods and reduce CO2 emissions that contribute to global climate change. In June 2008, the BPU approved a pilot program. PSE&G is in the initial design stages.

Carbon Abatement Program

2007 Form 10-K, Page 22 and June 30, 2008 Form 10-Q, page 78. In December 2007, PSE&G filed a petition with the BPU seeking expedited approval of a carbon abatement pilot program. This filing was withdrawn on May 1, 2008.

A petition for approval for a small scale carbon abatement program was filed with the BPU in June 2008 seeking approval under the Regional Greenhouse Gas Initiative (RGGI) legislation which was signed into law in January 2008. The filing was found deficient by the BPU in July 2008. PSE&G supplemented its filing to correct deficiencies on July 28, 2008. A discovery settlement conference was held on October 10, 2008. PSE&G proposes to invest up to $46 million over four years in programs across specific customer segments. The program is designed to support New Jersey’s EMP goals and promote energy efficiency. PSE&G has requested a return on this investment at its established rate. The matter is currently pending. This amount is not included in PSE&G’s projected capital expenditures.

Demand Response

In July 2008, the BPU directed that demand response (DR) programs be implemented by each of New Jersey’s electric utilities beginning in June 2009. In its order, the BPU established target goals to increase DR by 300 MW for the first year of the program and a total increase of 600 MW of DR by the end of the third year and stated that 55% of the target would be the responsibility of PSE&G. In response, PSE&G filed its program proposal in August and identified $93.4 million of investment in DR. PSE&G’s filing sought full recovery the costs of its DR program, including a return on its investment, through rates.

In September 2008, the BPU voted to defer action on PSE&G’s DR program (and the proposed DR programs of the other New Jersey electric utilities) and to reconvene its Demand Response Working Group (DRWG), which will focus on enrolling, with additional incentives, more New Jersey-based DR in already-existing DR programs of PJM, in which PSE&G’s role would be limited. It is not yet clear what impact the BPU’s action in reconvening the DRWG will have on PSE&G’s pending DR filing. It is possible that the

BPU may still act to approve all, or at least a portion, of PSE&G’s DR filing by the end of 2008, but the exact outcome of this proceeding cannot be predicted.

Universal Service Fund (USF) Filing

The USF is an energy assistance program mandated by the BPU under the Competition Act to provide payment assistance to low-income customers. The Lifeline program is a separately mandated energy assistance program to provide payment assistance to elderly and disabled customers. On June 30, 2008, the State’s electric and gas public utilities filed to reset statewide rates for the Permanent Universal Service Fund (USF) and the Lifeline program. The filed rates were set to recover $248 million on a statewide basis. Of this amount, the revised statewide electric rates will recover $151 million while the revised statewide gas rates will recover $97 million. As part of this filing, the rates for the Lifeline program will recover a total of $77 million, $51 million for the electric program and $26 million for the gas program. PSE&G’s USF rates will recover $85 million and $61 million for electric and gas respectively. PSE&G’s Lifeline rates will recover $28 million and $16 million for electric and gas respectively. PSE&G earns no margin on the collection of the USF and Lifeline programs, resulting in no impact on Net Income. PSE&G received a Written Order dated October 21, 2008 and the new rates were effective October 24, 2008.

ITEM 6. EXHIBITS

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


a.	PSEG:
	Exhibit 10:	Senior Management Incentive Compensation Plan, effective January 1, 2009
	Exhibit 10.1:	Management Incentive Compensation Plan, effective January 1, 2009
	Exhibit 10.2:	Key Executive Severance Plan, amended effective September 22, 2008
	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 Thomas M. O’Flynn 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 Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
b.	Power:
	Exhibit 10:	Senior Management Incentive Compensation Plan, effective January 1, 2009
	Exhibit 10.1:	Management Incentive Compensation Plan, effective January 1, 2009
	Exhibit 10.2:	Key Executive Severance Plan, amended effective September 22, 2008
	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 Thomas M. O’Flynn 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 Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
c.	PSE&G:
	Exhibit 10:	Senior Management Incentive Compensation Plan, effective January 1, 2009
	Exhibit 10.1:	Management Incentive Compensation Plan, effective January 1, 2009
	Exhibit 10.2:	Key Executive Severance Plan, amended effective September 22, 2008
	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 Thomas M. O’Flynn 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 Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

SIGNATURE

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

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: October 31, 2008

SIGNATURE

PSEG POWER LLC
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: October 31, 2008

SIGNATURE

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: October 31, 2008

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