10-Q

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 JUNE 30, 2006

OR

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

FOR THE TRANSITION PERIOD FROM                  TO                 

Commission File Number		Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
	001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza, P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com		22-2625848
	001-00973	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
	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
	000-32503	PSEG ENERGY HOLDINGS L.L.C. (A New Jersey Limited Liability Company) 80 Park Plaza—T20 Newark, New Jersey 07102-4194 973 456-3581 http://www.pseg.com		42-1544079

      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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Public Service Enterprise Group Incorporated	Large accelerated filer S	Accelerated filer £	Non-accelerated filer £
Public Service Electric and Gas Company	Large accelerated filer £	Accelerated filer £	Non-accelerated filer S
PSEG Power LLC	Large accelerated filer £	Accelerated filer £	Non-accelerated filer S
PSEG Energy Holdings L.L.C.	Large accelerated filer £	Accelerated filer £	Non-accelerated filer S

      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 July 31, 2006, Public Service Enterprise Group Incorporated had outstanding 251,722,921 shares of its sole class of Common Stock, without par value.

      As of July 31, 2006, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.

      PSEG Power LLC and PSEG Energy Holdings L.L.C. are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q and are filing their respective Quarterly Reports on Form 10-Q with the reduced disclosure format authorized by General Instruction H.

TABLE OF CONTENTS

		Page
FORWARD-LOOKING STATEMENTS			ii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated		1
	Public Service Electric and Gas Company		5
	PSEG Power LLC		9
	PSEG Energy Holdings L.L.C.		13
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation		17
	Note 2. Recent Accounting Standards		19
	Note 3. Discontinued Operations, Dispositions and Acquisitions		22
	Note 4. Earnings Per Share (EPS)		25
	Note 5. Commitments and Contingent Liabilities		26
	Note 6. Risk Management		38
	Note 7. Comprehensive Income (Loss), Net of Tax		42
	Note 8. Changes in Capitalization		43
	Note 9. Other Income and Deductions		44
	Note 10. Income Taxes		46
	Note 11. Financial Information by Business Segments		47
	Note 12. Stock-Based Compensation		48
	Note 13. Related-Party Transactions		52
	Note 14. Guarantees of Debt		54
Item 2.	Management's Discussion and Analysis of Financial Condition and       Results of Operations (MD&A)		57
	Pending Merger		57
	Overview of 2006 and Future Outlook		58
	Results of Operations		63
	Liquidity and Capital Resources		71
	Capital Requirements		77
	Accounting Matters		77
Item 3.	Qualitative and Quantitative Disclosures About Market Risk		77
Item 4.	Controls and Procedures		83
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		84
Item 5.	Other Information		85
Item 6.	Exhibits		93
Signatures			94

i

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. Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings) undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The following review should not be construed as a complete list of factors that could affect forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• business conditions, financial market, credit rating, regulatory and other risks resulting from the pending merger with Exelon Corporation or the failure to close the merger;

• regulatory issues that significantly impact operations;

• ability to maintain satisfactory regulatory results;

• operating performance or cash flow from investments falling below projected levels;

• credit, commodity, interest rate, counterparty and other financial market risks;

• liquidity and the ability to access capital and maintain adequate credit ratings;

• adverse or unanticipated weather conditions that significantly impact costs and/or operations, including generation;

• inability to attract and retain management and other key employees, particularly in view of the pending merger with Exelon Corporation;

• changes in the electric industry, including changes to power pools;

• changes in demand;

• changes in the number of market participants and the risk profiles of such participants;

• availability of power transmission facilities that impact the ability to deliver output to customers;

• growth in costs and expenses;

• environmental regulations that significantly impact operations;

• changes in rates of return on overall debt and equity markets that could adversely impact the value of pension and other postretirement benefits assets and liabilities and the Nuclear Decommissioning Trust Funds;

• changes in political conditions, recession, acts of war or terrorism;

• changes in technology that make generation, transmission and/or distribution assets less competitive;

• continued availability of insurance coverage at commercially reasonable rates;

• involvement in lawsuits, including liability claims and commercial disputes;

• acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG's, PSE&G's, Power's and Energy Holdings' strategy or structure;

• business combinations among competitors and major customers;

• general economic conditions, including inflation or deflation;

• changes in tax laws and regulations;

• changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements;

ii

• ability to recover investments or service debt as a result of any of the risks or uncertainties mentioned herein;

PSEG, PSE&G and Energy Holdings

• ability to obtain adequate and timely rate relief;

PSEG, Power and Energy Holdings

• inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations;

• inability to meet generation operating performance expectations;

• energy transmission constraints or lack thereof;

• adverse changes in the market for energy, capacity, natural gas, emissions credits, congestion credits and other commodity prices, especially during significant price movements for natural gas and power;

• surplus of energy capacity and excess supply;

• substantial competition in the worldwide energy markets;

• margin posting requirements, especially during significant price movements for natural gas and power;

• availability of fuel and timely transportation at reasonable prices;

• effects on competitive position of actions involving competitors or major customers;

• changes in product or sourcing mix;

• delays, cost escalations or unsuccessful construction and development;

PSEG and Power

• changes in regulation and safety and security measures at nuclear facilities;

• ability to maintain nuclear operating performance at projected levels, particularly if the operating services contract with Exelon is not extended in the event the merger does not close;

PSEG and Energy Holdings

• changes in foreign currency exchange rates;

• deterioration in the credit of lessees and their ability to adequately service lease rentals;

• ability to realize tax benefits;

• changes in political regimes in foreign countries; and

• international developments negatively impacting business.

      Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings 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, PSEG, PSE&G, Power and Energy Holdings or their respective business prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and Energy Holdings expressly disclaims 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. In making any investment decision regarding PSEG's, PSE&G's, Power's and Energy Holdings' securities, PSEG, PSE&G, Power and Energy Holdings are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

iii

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Quarters Ended June 30,						For the Six Months Ended June 30,
	2006			2005			2006			2005
	(Millions) (Unaudited)
OPERATING REVENUES	$	2,606		$	2,377		$	6,124		$	5,616
OPERATING EXPENSES
Energy Costs		1,387			1,316			3,591			3,165
Operation and Maintenance		583			553			1,164			1,124
Write-down of Project Investments		263			—			263			—
Depreciation and Amortization		207			174			411			358
Taxes Other Than Income Taxes		27			28			68			71
Total Operating Expenses		2,467			2,071			5,497			4,718
Income from Equity Method Investments		30			29			63			60
OPERATING INCOME		169			335			690			958
Other Income		52			34			106			77
Other Deductions		(20	)		(21	)		(51	)		(35	)
Interest Expense		(207	)		(198	)		(408	)		(398	)
Preferred Stock Dividends		(1	)		(1	)		(2	)		(2	)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(7	)		149			335			600
Income Tax Expense		(7	)		(58	)		(150	)		(229	)
(LOSS) INCOME FROM CONTINUING OPERATIONS		(14	)		91			185			371
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax expense (benefit) of $141, ($127), $142 and ($130) for the quarter and six months ended 2006 and 2005, respectively		223			(173	)		227			(168	)
NET INCOME (LOSS)	$	209		$	(82	)	$	412		$	203
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC		251,474			238,732			251,331			238,524
DILUTED		252,084			243,019			252,075			242,632
EARNINGS PER SHARE:
BASIC
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.05	)	$	0.38		$	0.74		$	1.56
NET INCOME (LOSS)	$	0.83		$	(0.34	)	$	1.64		$	0.85
DILUTED
(LOSS) INCOME FROM CONTINUING OPERATIONS	$	(0.05	)	$	0.38		$	0.74		$	1.53
NET INCOME (LOSS)	$	0.83		$	(0.34	)	$	1.64		$	0.84
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.57		$	0.56		$	1.14		$	1.12

See Notes to Condensed Consolidated Financial Statements.

1

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2006			December 31, 2005
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	136		$	288
Accounts Receivable, net of allowances of $49 and $44 in 2006 and 2005, respectively		1,455			1,936
Unbilled Revenues		239			394
Fuel		644			812
Materials and Supplies		292			277
Energy Trading Contracts		72			327
Prepayments		365			129
Restricted Funds		75			76
Derivative Contracts		11			50
Assets of Discontinued Operations		—			498
Assets Held for Sale		23			—
Other		35			41
Total Current Assets		3,347			4,828
PROPERTY, PLANT AND EQUIPMENT		19,388			18,896
Less: Accumulated Depreciation and Amortization		(5,817	)		(5,560	)
Net Property, Plant and Equipment		13,571			13,336
NONCURRENT ASSETS
Regulatory Assets		4,979			5,053
Long-Term Investments		3,858			4,077
Nuclear Decommissioning Trust (NDT) Funds		1,159			1,133
Other Special Funds		538			559
Goodwill and Other Intangibles		590			608
Energy Trading Contracts		19			42
Derivative Contracts		10			—
Other		188			177
Total Noncurrent Assets		11,341			11,649
TOTAL ASSETS	$	28,259		$	29,813

See Notes to Condensed Consolidated Financial Statements.

2

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2006			December 31, 2005
	(Millions) (Unaudited)
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	369		$	1,536
Commercial Paper and Loans		570			100
Accounts Payable		877			1,154
Derivative Contracts		338			425
Energy Trading Contracts		143			200
Accrued Interest		133			152
Accrued Taxes		107			141
Clean Energy Program		108			96
Liabilities of Discontinued Operations		—			436
Other		412			515
Total Current Liabilities		3,057			4,755
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		4,436			4,248
Regulatory Liabilities		614			720
Asset Retirement Obligations		607			585
Other Postretirement Benefit (OPEB) Costs		627			597
Clean Energy Program		187			233
Environmental Costs		407			420
Derivative Contracts		370			637
Energy Trading Contracts		18			19
Other		266			218
Total Noncurrent Liabilities		7,532			7,677
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		7,731			7,849
Securitization Debt		1,801			1,879
Project Level, Non-Recourse Debt		866			891
Debt Supporting Trust Preferred Securities		660			660
Total Long-Term Debt		11,058			11,279
SUBSIDIARIES' PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2006 and 2005—795,234 shares		80			80
COMMON STOCKHOLDERS' EQUITY
Common Stock, no par, authorized 500,000,000 shares; issued; 2006—265,855,786 shares; 2005—265,332,746 shares		4,632			4,618
Treasury Stock, at cost; 2006—14,144,970 shares; 2005—14,169,560 shares		(532	)		(532	)
Retained Earnings		2,671			2,545
Accumulated Other Comprehensive Loss		(239	)		(609	)
Total Common Stockholders' Equity		6,532			6,022
Total Capitalization		17,670			17,381
TOTAL LIABILITIES AND CAPITALIZATION	$	28,259		$	29,813

See Notes to Condensed Consolidated Financial Statements.

3

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	For The Six Months Ended June 30,
	2006			2005
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	412		$	203
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
(Gain) Loss on Disposal of Discontinued Operations, net of tax		(228	)		177
Depreciation and Amortization		411			365
Amortization of Nuclear Fuel		48			45
Provision for Deferred Income Taxes (Other than Leases) and ITC		(11	)		16
Non-Cash Employee Benefit Plan Costs		116			114
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes		(3	)		(19	)
Loss (Gain) on Sale of Investments		255			(27	)
Undistributed Earnings from Affiliates		(36	)		(28	)
Foreign Currency Transaction Loss (Gain)		2			(5	)
Unrealized Gains on Energy Contracts and Other Derivatives		(23	)		(3	)
Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		45			9
Under Recovery of Societal Benefits Charge (SBC)		(50	)		(49	)
Net Realized Gains and Income from NDT Funds		(36	)		(37	)
Other Non-Cash Charges		9			29
Net Change in Certain Current Assets and Liabilities		18			(70	)
Employee Benefit Plan Funding and Related Payments		(49	)		(121	)
Proceeds from the Withdrawal of Partnership Interests and Other Distributions		7			63
Other		(82	)		(99	)
Net Cash Provided By Operating Activities		805			563
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(473	)		(480	)
Proceeds from the Sale of Investments and Return of Capital from Partnerships		681			27
Proceeds from NDT Funds Sales		720			1,949
Investment in NDT Funds		(726	)		(1,962	)
NDT Funds Interest and Dividends		19			17
Other		11			142
Net Cash Provided By (Used In) Investing Activities		232			(307	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans		470			93
Issuance of Non-Recourse Debt		—			7
Issuance of Common Stock		34			37
Redemptions of Long-Term Debt		(1,205	)		(66	)
Repayment of Non-Recourse Debt		(25	)		(12	)
Redemption of Debt Underlying Trust Securities		(154	)		—
Cash Dividends Paid on Common Stock		(286	)		(267	)
Other		(21	)		(28	)
Net Cash Used In Financing Activities		(1,187	)		(236	)
Effect of Exchange Rate Change		(2	)		(2	)
Net (Decrease) Increase in Cash and Cash Equivalents		(152	)		18
Cash and Cash Equivalents at Beginning of Period		288			263
Cash and Cash Equivalents at End of Period	$	136		$	281
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	196		$	101
Interest Paid, Net of Amounts Capitalized	$	370		$	431

See Notes to Condensed Consolidated Financial Statements.

4

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	For The Quarters Ended June 30,						For The Six Months Ended June 30,
	2006			2005			2006			2005
	(Millions) (Unaudited)
OPERATING REVENUES	$	1,534		$	1,441		$	3,884		$	3,625
OPERATING EXPENSES
Energy Costs		945			853			2,576			2,277
Operation and Maintenance		276			268			577			563
Depreciation and Amortization		150			128			302			263
Taxes Other Than Income Taxes		27			28			68			71
Total Operating Expenses		1,398			1,277			3,523			3,174
OPERATING INCOME		136			164			361			451
Other Income		8			2			12			4
Other Deductions		(1	)		—			(2	)		(1	)
Interest Expense		(83	)		(86	)		(168	)		(170	)
INCOME BEFORE INCOME TAXES		60			80			203			284
Income Tax Expense		(26	)		(31	)		(91	)		(117	)
NET INCOME		34			49			112			167
Preferred Stock Dividends		(1	)		(1	)		(2	)		(2	)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	33		$	48		$	110		$	165

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

5

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2006			December 31, 2005
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	25		$	159
Accounts Receivable, net of allowances of $45 in 2006 and $41 in 2005		746			959
Unbilled Revenues		239			394
Materials and Supplies		53			49
Prepayments		295			49
Restricted Funds		11			14
Derivative Contracts		1			—
Other		34			32
Total Current Assets		1,404			1,656
PROPERTY, PLANT AND EQUIPMENT		10,890			10,636
Less: Accumulated Depreciation and Amortization		(3,759	)		(3,627	)
Net Property, Plant and Equipment		7,131			7,009
NONCURRENT ASSETS
Regulatory Assets		4,979			5,053
Long-Term Investments		146			144
Other Special Funds		293			315
Other		115			114
Total Noncurrent Assets		5,533			5,626
TOTAL ASSETS	$	14,068		$	14,291

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

6

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2006			December 31, 2005
	(Millions) (Unaudited)
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	280		$	485
Commercial Paper and Loans		391			—
Accounts Payable		325			286
Accounts Payable—Affiliated Companies, net		283			391
Accrued Interest		54			59
Clean Energy Program		108			96
Derivative Contracts		11			6
Other		270			370
Total Current Liabilities		1,722			1,693
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC		2,560			2,608
Other Postretirement Benefit (OPEB) Costs		585			561
Regulatory Liabilities		614			720
Clean Energy Program		187			233
Environmental Costs		352			365
Asset Retirement Obligations		215			210
Derivative Contracts		19			6
Other		27			27
Total Noncurrent Liabilities		4,559			4,730
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		2,753			2,866
Securitization Debt		1,801			1,879
Total Long-Term Debt		4,554			4,745
PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2006 and 2005—795,234 shares		80			80
COMMON STOCKHOLDER'S EQUITY
Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding		892			892
Contributed Capital		170			170
Basis Adjustment		986			986
Retained Earnings		1,110			1,000
Accumulated Other Comprehensive Loss		(5	)		(5	)
Total Common Stockholder's Equity		3,153			3,043
Total Capitalization		7,787			7,868
TOTAL LIABILITIES AND CAPITALIZATION	$	14,068		$	14,291

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

7

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Six Months Ended June 30,
	2006			2005
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	112		$	167
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		302			263
Provision for Deferred Income Taxes and ITC		(39	)		(57	)
Non-Cash Employee Benefit Plan Costs		83			81
Non-Cash Interest Expense		1			4
Employee Benefit Plan Funding and Related Payments		(27	)		(73	)
Over Recovery of Electric Energy Costs (BGS and NTC)		—			16
Over (Under) Recovery of Gas Costs		45			(7	)
Under Recovery of SBC		(50	)		(49	)
Other Non-Cash Charges		4			3
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		368			142
Materials and Supplies		(4	)		(5	)
Prepayments		(246	)		(214	)
Accrued Taxes		(25	)		(25	)
Accrued Interest		(5	)		—
Accounts Payable		39			67
Accounts Receivable/Payable-Affiliated Companies, net		(315	)		(197	)
Other Current Assets and Liabilities		(79	)		27
Other		(35	)		(87	)
Net Cash Provided By Operating Activities		129			56
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(259	)		(239	)
Restricted Funds		3			2
Net Cash Used In Investing Activities		(256	)		(237	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt		391			265
Redemption of Securitization Debt		(74	)		(66	)
Redemption of Long-Term Debt		(322	)		—
Preferred Stock Dividends		(2	)		(2	)
Net Cash (Used In) Provided by Financing Activities		(7	)		197
Net (Decrease) Increase In Cash and Cash Equivalents		(134	)		16
Cash and Cash Equivalents at Beginning of Period		159			6
Cash and Cash Equivalents at End of Period	$	25		$	22
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	112		$	197
Interest Paid, Net of Amounts Capitalized	$	159		$	158

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

8

PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Quarters Ended June 30,						For The Six Months Ended June 30,
	2006			2005			2006			2005
				(Millions) (Unaudited)
OPERATING REVENUES	$	1,135		$	1,060		$	3,102		$	2,790
OPERATING EXPENSES
Energy Costs		675			688			2,162			1,958
Operation and Maintenance		264			235			499			462
Depreciation and Amortization		40			32			75			62
Total Operating Expenses		979			955			2,736			2,482
OPERATING INCOME		156			105			366			308
Other Income		34			30			75			61
Other Deductions		(14	)		(12	)		(33	)		(20	)
Interest Expense		(44	)		(26	)		(84	)		(54	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		132			97			324			295
Income Tax Expense		(55	)		(41	)		(135	)		(124	)
INCOME FROM CONTINUING OPERATIONS		77			56			189			171
Loss from Discontinued Operations, net of tax benefit of $4 and $9 for the quarter and six months ended 2005, respectively		—			(6	)		—			(13	)
Loss on Disposal of Discontinued Operations, net of tax benefit of $123 for the quarter and six months ended 2005, respectively		—			(177	)		—			(177	)
EARNINGS (LOSS) AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	77		$	(127	)	$	189		$	(19	)

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

9

PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2006			December 31, 2005
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	5		$	8
Accounts Receivable		583			862
Accounts Receivable—Affiliated Companies, net		206			288
Fuel		642			812
Materials and Supplies		207			201
Energy Trading Contracts		72			327
Derivative Contracts		6			50
Other		20			27
Total Current Assets		1,741			2,575
PROPERTY, PLANT AND EQUIPMENT		6,598			6,457
Less: Accumulated Depreciation and Amortization		(1,646	)		(1,577	)
Net Property, Plant and Equipment		4,952			4,880
NONCURRENT ASSETS
Deferred Income Taxes and Investment Tax Credits (ITC)		—			70
Nuclear Decommissioning Trust (NDT) Funds		1,159			1,133
Goodwill and Other Intangibles		62			63
Other Special Funds		147			143
Energy Trading Contracts		19			42
Derivative Contracts		1			—
Other		54			39
Total Noncurrent Assets		1,442			1,490
TOTAL ASSETS	$	8,135		$	8,945
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	—		$	500
Accounts Payable		440			745
Short-Term Loan from Affiliate		145			202
Energy Trading Contracts		143			200
Derivative Contracts		316			403
Accrued Interest		34			41
Other		82			86
Total Current Liabilities		1,160			2,177
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		93			—
Asset Retirement Obligations		389			373
Energy Trading Contracts		18			19
Derivative Contracts		326			597
Environmental Costs		55			55
Other		72			70
Total Noncurrent Liabilities		953			1,114
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
LONG-TERM DEBT
Total Long-Term Debt		2,817			2,817
MEMBER'S EQUITY
Contributed Capital		2,000			2,000
Basis Adjustment		(986	)		(986	)
Retained Earnings		2,499			2,310
Accumulated Other Comprehensive Loss		(308	)		(487	)
Total Member's Equity		3,205			2,837
TOTAL LIABILITIES AND MEMBER'S EQUITY	$	8,135		$	8,945

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

10

PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	For The Six Months Ended June 30,
	2006			2005
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	189		$	(19	)
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Loss on Disposal of Discontinued operations, net of tax		—			177
Depreciation and Amortization		75			62
Amortization of Nuclear Fuel		48			45
Interest Accretion on Asset Retirement Obligations		16			14
Provision for Deferred Income Taxes and ITC		38			77
Unrealized Gains on Energy Contracts and Other Derivatives		(23	)		(4	)
Non-Cash Employee Benefit Plan Costs		22			22
Net Realized Gains and Income from NDT Funds		(36	)		(37	)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies		164			102
Accounts Receivable		279			240
Accounts Payable		(301	)		(465	)
Accounts Receivable/Payable-Affiliated Companies, net		290			247
Accrued Interest Payable		(7	)		—
Other Current Assets and Liabilities		47			(19	)
Employee Benefit Plan Funding and Related Payments		(18	)		(32	)
Other		(62	)		6
Net Cash Provided By Operating Activities		721			416
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(193	)		(227	)
Proceeds from NDT Funds Sales		720			1,949
NDT Funds Interest and Dividends		19			17
Investment in NDT Funds		(726	)		(1,962	)
Short-Term Loan-Affiliated Company, net		—			(93	)
Other		13			8
Net Cash Used In Investing Activities		(167	)		(308	)
CASH FLOWS FROM FINANCING ACTIVITIES
Redemption of Long-Term Debt		(500	)		—
Short-Term Loan-Affiliated Company, net		(57	)		(98	)
Net Cash Used In Financing Activities		(557	)		(98	)
Net (Decrease) Increase in Cash and Cash Equivalents		(3	)		10
Cash and Cash Equivalents at Beginning of Period		8			10
Cash and Cash Equivalents at End of Period	$	5		$	20
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	79		$	10
Interest Paid, Net of Amounts Capitalized	$	83		$	57

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

11

[THIS PAGE INTENTIONALLY LEFT BLANK]

PSEG ENERGY HOLDINGS L.L.C.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	For The Quarters Ended June 30,						For The Six Months Ended June 30,
	2006			2005			2006			2005
	(Millions) (Unaudited)
OPERATING REVENUES
Electric Generation and Distribution Revenues	$	318		$	235		$	581		$	448
Income from Leveraged and Operating Leases		38			45			77			92
Other		11			(10	)		21			43
Total Operating Revenues		367			270			679			583
OPERATING EXPENSES
Energy Costs		194			162			388			300
Operation and Maintenance		52			53			101			110
Write-down of Project Investments		263			—			263			—
Depreciation and Amortization		12			11			24			25
Total Operating Expenses		521			226			776			435
Income from Equity Method Investments		30			29			63			60
OPERATING (LOSS) INCOME		(124	)		73			(34	)		208
Other Income		13			3			23			13
Other Deductions		(5	)		(8	)		(15	)		(14	)
Interest Expense		(51	)		(54	)		(101	)		(112	)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST		(167	)		14			(127	)		95
Income Tax Benefit (Expense)		63			(1	)		51			(15	)
Minority Interests in Earnings of Subsidiaries		(1	)		(1	)		(1	)		(1	)
(LOSS) INCOME FROM CONTINUING OPERATIONS		(105	)		12			(77	)		79
(Loss) Income from Discontinued Operations, net of tax benefit (expense) of $1, $0, $0 and ($2) for the quarter and six months ended 2006 and 2005, respectively		(5	)		10			(1	)		22
Gain on Disposal of Discontinued Operations, net of tax expense of $142 for the quarter and six months ended 2006		228			—			228			—
NET INCOME		118			22			150			101
Preference Units Distributions		—			(1	)		—			(3	)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	118		$	21		$	150		$	98

See disclosures regarding PSEG Energy Holdings L.L.C.
included in the Notes to Condensed Consolidated Financial Statements.

13

PSEG ENERGY HOLDINGS L.L.C.
CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2006			December 31, 2005
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	101		$	68
Accounts Receivable:
Trade—net of allowances of $4 and $3 in 2006 and 2005, respectively		107			101
Other Accounts Receivable		18			14
Notes Receivable:
Affiliated Companies		708			409
Other		—			5
Inventory		33			27
Restricted Funds		65			62
Assets of Discontinued Operations		—			498
Assets Held for Sale		23			—
Derivative Contracts		4			—
Other		6			7
Total Current Assets		1,065			1,191
PROPERTY, PLANT AND EQUIPMENT		1,658			1,560
Less: Accumulated Depreciation and Amortization		(282	)		(237	)
Net Property, Plant and Equipment		1,376			1,323
NONCURRENT ASSETS
Leveraged Leases, net		2,751			2,720
Corporate Joint Ventures and Partnership Interests		915			1,180
Goodwill and Other Intangibles		524			540
Derivative Contracts		9			3
Other		111			98
Total Noncurrent Assets		4,310			4,541
TOTAL ASSETS	$	6,751		$	7,055

See disclosures regarding PSEG Energy Holdings L.L.C.
included in the Notes to Condensed Consolidated Financial Statements.

14

PSEG ENERGY HOLDINGS L.L.C.
CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2006		December 31, 2005
	(Millions) (Unaudited)
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	40	$	348
Accounts Payable:
Trade		59		50
Affiliated Companies		54		11
Derivative Contracts		6		13
Accrued Interest		36		42
Liabilities of Discontinued Operations		—		436
Other		57		83
Total Current Liabilities		252		983
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment and Energy Tax Credits		1,777		1,705
Derivative Contracts		18		27
Other		107		66
Total Noncurrent Liabilities		1,902		1,798
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
MINORITY INTERESTS		21		15
LONG-TERM DEBT
Project Level, Non-Recourse Debt		866		891
Senior Notes		1,449		1,448
Total Long-Term Debt		2,315		2,339
MEMBER'S EQUITY
Ordinary Unit		1,713		1,713
Retained Earnings		467		317
Accumulated Other Comprehensive Income (Loss)		81		(110	)
Total Member's Equity		2,261		1,920
TOTAL LIABILITIES AND MEMBER'S EQUITY	$	6,751	$	7,055

See disclosures regarding PSEG Energy Holdings L.L.C.
included in the Notes to Condensed Consolidated Financial Statements.

15

PSEG ENERGY HOLDINGS L.L.C.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	For The Six Months Ended June 30,
	2006			2005
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	150		$	101
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		24			31
Demand Side Management Amortization		2			3
Investment Write-off		—			22
Deferred Income Taxes (Other than Leases)		(9	)		(4	)
Leveraged Lease Income, Adjusted for Rents Received and Deferred Income Taxes		(3	)		(19	)
Undistributed Earnings from Affiliates		(36	)		(28	)
Loss (Gain) on Sale of Investments		255			(49	)
Gain on Sale of Discontinued Operations		(228	)		—
Unrealized Gain on Investments		(1	)		(1	)
Foreign Currency Transaction Loss (Gain)		2			(5	)
Change in Fair Value of Derivative Financial Instruments		1			1
Other Non-Cash Charges		2			5
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable		(29	)		1
Inventory		(3	)		6
Accounts Payable		(90	)		47
Other Current Assets and Liabilities		(28	)		(23	)
Proceeds from Withdrawal of Partnership Interests and Other Distributions		7			63
Other		2			1
Net Cash Provided By Operating Activities		18			152
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(20	)		(18	)
Proceeds from Sale of Discontinued Operations		494			—
Proceeds from Sale of Property		1			—
Proceeds from the Sale of Investments		187			27
Short-Term Loan Receivable—Affiliated Company, net		(299	)		58
Restricted Funds		(3	)		(2	)
Proceeds from Collection of Notes Receivable		—			132
Other		(8	)		—
Net Cash Provided By Investing Activities		352			197
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Non-Recourse Long-Term Debt		—			7
Repayment of Non-Recourse Long-Term Debt		(25	)		(12	)
Repayment of Senior Notes		(309	)		—
Return of Capital Contributed		—			(100	)
Redemptions of Preference Units		—			(184	)
Cash Distributions Paid on Preference Units		—			(3	)
Other		(1	)		(6	)
Net Cash Used In Financing Activities		(335	)		(298	)
Effect of Exchange Rate Change		(2	)		(2	)
Net Increase In Cash and Cash Equivalents		33			49
Cash and Cash Equivalents at Beginning of Period		68			183
Cash and Cash Equivalents at End of Period	$	101		$	232
Supplemental Disclosure of Cash Flow Information:
Income Taxes (Received) Paid	$	(14	)	$	26
Interest Paid, Net of Amounts Capitalized	$	78		$	145

See disclosures regarding PSEG Energy Holdings L.L.C.
included in the Notes to Condensed Consolidated Financial Statements.

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

      This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings 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: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services).

      As previously disclosed, on December 20, 2004, PSEG entered into an agreement and plan of merger (Merger Agreement) with Exelon Corporation (Exelon), a public utility holding company headquartered in Chicago, Illinois, whereby PSEG will be merged with and into Exelon (Merger). Pursuant to the terms of the Merger Agreement, upon closing of the Merger, each share of PSEG Common Stock will be converted into 1.225 shares of Exelon Common Stock.

      The Merger Agreement has been unanimously approved by both companies' Boards of Directors. On July 19, 2005, shareholders of PSEG voted to approve the Merger and on July 22, 2005, shareholders of Exelon voted to approve the issuance of common shares to PSEG shareholders to effect the Merger.

      The Merger Agreement provides that if the Merger was not consummated by June 20, 2006, either party can terminate the Merger Agreement. Exelon and PSEG are continuing to seek the final required regulatory approval from the New Jersey Board of Public Utilities (BPU) and neither party has taken any action to terminate the Merger Agreement or extend the June 20, 2006 date in the Merger Agreement.

      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 BPU and the Federal Energy Regulatory Commission (FERC).

      PSE&G also owns PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), bankruptcy-remote entities that purchased certain transition property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the right to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G electric distribution customers, which represents the irrevocable right to receive amounts sufficient to recover certain of PSE&G's transition costs related to deregulation, as approved by the BPU.

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

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

      Energy Holdings

      Energy Holdings has two principal direct wholly owned subsidiaries: PSEG Global L.L.C. (Global), which owns and operates international and domestic projects engaged in the generation and distribution of energy, including power production facilities and electric distribution companies, 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.

      Services

      Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial services, investor relations, stockholder services, real estate, environmental, health and safety, insurance, risk management, tax, library, records and information services, security, corporate secretarial and certain planning, budgeting and forecasting services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements.

Basis of Presentation

      PSEG, PSE&G, Power and Energy Holdings

      The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for 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, PSE&G's, Power's and Energy Holdings' respective Annual Reports on Form 10-K for the year ended December 31, 2005 and Quarterly Reports on Form 10-Q for the quarter ended March 31, 2006.

      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, 2005. Certain reclassifications of prior period data have been made to conform with the current presentation.

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

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003.

	Pension Benefits						OPEB						Pension Benefits						OPEB
	Quarters Ended June 30,						Quarters Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005			2006			2005			2006			2005
	(Millions)
Components of Net Periodic Benefit Costs:
Service Cost	$	22		$	22		$	4		$	4		$	43		$	45		$	9		$	9
Interest Cost		52			51			17			16			105			103			34			30
Expected Return on Plan Assets		(67	)		(62	)		(3	)		(3	)		(134	)		(125	)		(6	)		(5	)
Amortization of Net
Transition Obligation		—			—			7			7			—			—			14			14
Prior Service Cost		2			4			3			3			5			8			6			3
Loss		14			12			2			1			27			23			4			2
Net Periodic Benefit Costs		23			27			30			28			46			54			61			53
Effect of Regulatory Asset		—			—			5			5			—			—			10			10
Total Benefit Costs	$	23		$	27		$	35		$	33		$	46		$	54		$	71		$	63

      PSE&G, Power, Energy Holdings and Services

      Pension costs and OPEB costs for PSE&G, Power, Energy Holdings and Services are detailed as follows:

	Pension Benefits				OPEB				Pension Benefits				OPEB
	Quarters Ended June 30,				Quarters Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005		2006		2005		2006		2005
	(Millions)
PSE&G	$	11	$	13	$	30	$	29	$	23	$	27	$	60	$	55
Power		7		8		4		3		14		16		8		6
Energy Holdings		1		1		—		—		1		1		—		—
Services		4		5		1		1		8		10		3		2
Total Benefit Costs	$	23	$	27	$	35	$	33	$	46	$	54	$	71	$	63

Note 2. Recent Accounting Standards

The following accounting standards were issued by the Financial Accounting Standards Board (FASB), but have not yet been adopted by PSEG.

FASB Staff Position (FSP) No. FIN 46(R)-6, “Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)” (FIN 46(R)-6)

      PSEG, PSE&G, Power and Energy Holdings

      In April 2006, the FASB issued FSP No. FIN 46(R)-6, which introduces a “by-design” approach to determine the variability to consider when applying FASB Interpretation No. (FIN) 46(R), “Consolidation of Variable Interest Entities.” The FSP provided guidance on how companies should go about evaluating “variability” which would impact whether an entity is a variable interest entity (VIE), which interests are variable interests, how expected losses and residual returns are calculated and which party is the primary beneficiary of the VIE. This guidance is to be applied prospectively in the first

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

reporting period beginning after July 15, 2006. Since this guidance will be applied prospectively, it will have no impact on PSEG's, PSE&G's, Power's or Energy Holdings' financial statements upon adoption.

FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement 109” (FIN 48)

      PSEG, PSE&G, Power and Energy Holdings

      In July 2006, the FASB issued FIN 48, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return. Under FIN 48, the financial statements will reflect expected future tax consequences of such positions presuming the tax authorities' full knowledge of the position and all relevant facts. FIN 48 would require an entity to recognize the benefit of tax positions when it is “more likely-than-not” that the position is sustainable based on the merits of the position. FIN 48 also addresses the accrual of interest and penalties related to tax uncertainties and the classification of liabilities on the balance sheet.

      FIN 48 is effective as of the beginning of fiscal years that start after December 15, 2006. A company would record the change in net assets that result from the application of FIN 48 as an adjustment to retained earnings. PSEG, PSE&G, Power and Energy Holdings are evaluating this guidance, which could have a material impact on their respective earnings and financial position.

FSP No. FAS 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” (FSP 13-2)

      PSEG and Energy Holdings

      In July 2006, the FASB issued FSP No. 13-2, which addresses how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the accounting by a lessor for that lease. The FSP amends FASB Statement No. 13, “Accounting for Leases,” stating that a change in the timing of the above referenced cash flows must be reviewed at least annually. If a change in timing has occurred, or is projected to occur, the rate of return and the allocation of income to positive investment years must be recalculated from the inception of the lease.

      The guidance in this FSP shall be applied to fiscal years beginning after December 15, 2006. The cumulative effect of applying the provisions of this FSP shall be reported as an adjustment to the beginning balance of retained earnings as of the beginning of the period in which this FSP is adopted. PSEG and Energy Holdings are evaluating this guidance, which could have a material impact on their respective earnings and financial positions.

The following accounting standard has been proposed by the FASB.

      PSEG, PSE&G, Power and Energy Holdings

      On March 31, 2006, the FASB issued an exposure draft (ED) that would require companies to record the under or over funded positions of defined benefit pension and OPEB plans on the balance sheet. For under funded plans, the amount to record as a liability would be equal to the difference between the plan's projected benefit obligation (PBO) and the fair value of plan assets. In addition, the ED would require that the total of unrecognized costs for defined benefit and OPEB plans be recorded as an after-tax charge to equity. The unrecognized costs represent actuarial gains or losses, prior service costs and transition obligations arising from the adoption of the current pension and OPEB accounting standards, which have not been expensed.

      Current accounting guidance requires that unrecognized costs be presented in a footnote to the financial statements as part of a reconciliation of a plan's funded status with amounts recorded in the financial statements. The unrecognized costs are amortized as a component of net periodic pension or

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

OPEB expense. With the adoption of this standard, the unrecognized costs would be amortized out of equity through the Statement of Operations.

      As of December 31, 2005, PSEG had about $1.6 billion of unrecognized pension and OPEB costs. Presently, PSEG's PBOs are lower reflecting the change in long-term interest rates; thus, the amount of unrecognized costs is significantly lower than at December 31, 2005. More than 60% of the unrecognized costs relate to current and retired employees of PSE&G. If this standard is adopted, management believes that these costs would be recorded as a regulatory asset rather than a charge to equity because the amortization of these costs is reflected in current rates.

      If issued in its present form, this standard would become effective for fiscal periods ending after December 15, 2006. PSEG, PSE&G, Power and Energy Holdings are currently evaluating the impact of this ED, which could have a material impact on their respective financial positions.

The following new accounting standards were adopted by PSEG during 2006.

Statement of Financial Accounting Standard (SFAS) No. 123R, “Share-Based Payment, revised 2004” (SFAS 123R)

      PSEG

      Effective January 1, 2006, PSEG adopted SFAS No. 123R, which replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25). SFAS 123R focuses primarily on accounting for share-based awards to employees in exchange for services, and it requires entities to recognize compensation expense for these awards. The cost for equity-based awards is expensed based on their grant date fair value, and liability awards are expensed based on their fair value, which is re-measured each reporting period. The pro forma disclosure previously permitted under SFAS 123 is no longer an alternative to financial statement recognition.

      Prior to January 1, 2006, PSEG accounted for stock-based awards under the intrinsic value method of APB 25. In accordance with APB 25, PSEG did not record compensation expense related to its stock option grants because the strike price was equal to the fair value of the underlying stock on the grant date; however, it did record compensation expense over the requisite service period for restricted stock grants and performance unit awards.

      SFAS 123R is applicable to all of PSEG's outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective method. Accordingly, the financial results for prior periods were not retroactively adjusted to reflect the effects of SFAS 123R. The compensation expense recorded as a result of adopting SFAS 123R was not material. For additional information, see Note 12. Stock-Based Compensation.

SFAS No. 151, “Inventory Costs” (SFAS 151)

      PSEG, PSE&G, Power and Energy Holdings

      In November 2004, the FASB issued SFAS 151, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. This statement requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be recognized as current-period charges. In addition, this statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 was effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The adoption of SFAS 151 did not have a material impact on the respective financial statements of PSEG, PSE&G, Power and Energy Holdings.

21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

FSP 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments” (FSP 115-1 and 124-1)

      PSEG, PSE&G, Power and Energy Holdings

      This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary and the measurement of the impairment loss. It also requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. This guidance applies to equity securities that have a readily determinable fair value and all debt securities. It does not apply to investments accounted for under the equity method. An investment is impaired if its fair value is less than its cost, as assessed at the individual security level. When an investment is impaired, the investor is required to evaluate whether the impairment is other-than-temporary. If other-than-temporary, the unrealized loss must be recognized. For all investments in an unrealized loss position for which other-than-temporary impairments have not been recognized, the investor should disclose by category of investment the amount of unrealized losses and the fair value of investments with unrealized losses and related narrative disclosures. FSP 115-1 and 124-1 was effective for reporting periods beginning after December 15, 2005. The adoption of this FSP did not have a material effect on PSEG's, PSE&G's, Power's or Energy Holdings' respective financial statements.

Emerging Issues Task Force (EITF) Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13)

      PSEG, PSE&G, Power and Energy Holdings

      EITF 04-13 concludes that inventory purchases and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined and treated as nonmonetary exchanges involving inventory. The consensus includes indicators that should be considered in determining whether transactions were entered into in contemplation of one another. The EITF also concludes that exchanges of finished goods for raw materials or work-in-process within the same line of business should be recognized at fair value if the transaction has commercial substance and fair value is determinable within reasonable limits. All other inventory exchanges should be recognized at carrying value. The provisions of EITF 04-13 are effective for new inventory arrangements entered into, or modifications or renewals of existing inventory arrangements occurring in financial periods beginning after March 15, 2006. The adoption of EITF 04-13 did not have a material effect on the respective financial statements of PSEG, PSE&G, Power and Energy Holdings.

Note 3. Discontinued Operations, Dispositions and Acquisitions

Discontinued Operations

      Power

      Waterford Generation Facility (Waterford)

      In September 2005, Power completed the sale of its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. In May 2005, Power recognized an estimated loss on disposal of $177 million, net of tax benefit of $123 million. In the third quarter 2005, Power completed the sale of Waterford and recognized an additional loss on disposal of $1 million, net of tax. The proceeds of the sale, together with the anticipated reduction in tax liability, were approximately $320 million, which were used to retire debt at Power.

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

      Waterford's operating results for the quarter and six months ended June 30, 2005, which were reclassified to Discontinued Operations, are summarized below:

	Quarter Ended June 30, 2005		Six Months Ended June 30, 2005
	(Millions)
Operating Revenues	$	5	$	5
Loss Before Income Taxes	$	10	$	22
Net Loss	$	6	$	13

      Energy Holdings

      Elektrocieplownia Chorzow Elcho Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina)

      On January 31, 2006, Global entered into an agreement with CEZ a.s. to sell its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale was completed on May 29, 2006. Proceeds, net of transaction costs, were $476 million, resulting in a gain of $228 million net of tax expense of $142 million. This gain is included in Discontinued Operations. The 2006 operating results for Global's assets in Poland have been reclassified to Discontinued Operations.

      Elcho's and Skawina's operating results for the quarters and six months ended June 30, 2006 and 2005 are summarized below:

	Quarters Ended June 30,									Six Months Ended June 30,
	2006					2005				2006					2005
	Elcho			Skawina		Elcho		Skawina		Elcho			Skawina		Elcho		Skawina
	(Millions)
Operating Revenues	$	9		$	11	$	28	$	30	$	39		$	44	$	57	$	66
(Loss) Income Before Income Taxes	$	(6	)	$	—	$	10	$	—	$	(3	)	$	2	$	21	$	3
Net (Loss) Income	$	(5	)	$	—	$	10	$	—	$	(2	)	$	1	$	20	$	2

      The carrying amounts of the assets of Elcho and Skawina as of December 31, 2005 are summarized in the following table:

	As of December 31, 2005
	Elcho		Skawina
	(Millions)
Current Assets	$	41	$	27
Noncurrent Assets		319		111
Total Assets of Discontinued Operations	$	360	$	138
Current Liabilities	$	27	$	24
Noncurrent Liabilities		336		49
Total Liabilities of Discontinued Operations	$	363	$	73

      Elcho's and Skawina's total non-recourse debt amounted to $287 million and $26 million, respectively, as of December 31, 2005.

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Dispositions

      Energy Holdings

      Rio Grande Energia (RGE)

      On May 10, 2006, Global entered into an agreement with Companhia Paulista de Force Luz (CPFL) to sell its 32% ownership interest in RGE, a Brazilian electric distribution company. The transaction closed on June 23, 2006 and gross proceeds of $185 million were received. The transaction resulted in an after-tax loss of $177 million, primarily related to the devaluation of the Brazilian Real subsequent to Global's acquisition of its interests in RGE in 1997.

      Solar Electric Generating Systems (SEGS) Projects

      In January 2005, Resources and Global sold their minority limited partner interests in three SEGS projects for proceeds of approximately $7 million, resulting in an after-tax gain of $4 million.

      Dhofar Power Company S.A.O.C. (Dhofar Power)

      In April 2005, Global sold a 35% interest in Dhofar Power through a public offering on the Omani stock exchange, as required under the Concession Agreement, reducing Global's ownership in Dhofar Power from 81% to 46%. Net proceeds from the sale approximated $25 million, resulting in an after-tax gain of approximately $1 million. Following the sale, Global's investment in Dhofar Power has been accounted for under the equity method.

      On May 15, 2006, Global signed an agreement to sell Dhofar Power to Oman Technical Partners Ltd., a consortium formed by The GCC Energy Fund of Dubai, Darbat Power of Oman and Malakoff Berhad of Malaysia; therefore, Global reclassified the investment to Assets Held for Sale on the Condensed Consolidated Balance Sheets. The sale, which is contingent upon obtaining consents from Dhofar Power's lenders, is expected to close later in 2006 and generate proceeds of approximately $33 million resulting in an immaterial after-tax gain. As a result of the pending sale of this investment, a deferred tax expense of approximately $1 million was recorded. This represents the difference in the book basis and tax basis of the investment.

      Meiya Power Company Limited (MPC)

      In January and April 2005, Global received payments of approximately $38 million and $99 million, respectively, representing the full payment of the receivable relating to the sale of its 50% equity interest in MPC in December 2004.

      Resources

      In January 2005, a KKR Fund, in which Resources had invested, sold its investment in KinderCare Learning Centers, Inc. and Resources received proceeds of approximately $17 million, resulting in an after-tax gain of approximately $1 million.

Acquisitions

      Energy Holdings

      Prisma 2000 S.p.A. (Prisma)

      In May 2006, Global forgave the guarantees of its partner in the Prisma investment of certain loans Global had made to Prisma and converted such loans totaling $38 million into additional equity in Prisma, thereby increasing its ownership interest from 50% to 85%. As a result of this increased ownership interest, Global now has voting control of the project and Energy Holdings began

24

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

consolidating this investment in its financial statements as of May 2006. Therefore, the investment balance was reclassified from Long-Term Investments to various balance sheet accounts, primarily Property, Plant and Equipment of approximately $62 million, Long-Term Investments of approximately $13 million, Capital Lease Obligations of approximately $40 million and certain other assets and liabilities. Although the purchase price allocation has not been adjusted due to the recent acquisition, Energy Holdings recorded certain immaterial purchase accounting adjustments to reflect the plant, contracts and investment in Biomasse Italia S.p.A. (Biomasse) at fair value. Energy Holdings expects to update the purchase price allocation to reflect market factors that existed at the date of the acquisition and finalize its assessment of potential legal and tax contingencies in the third quarter of 2006. The consolidation of Prisma is expected to add approximately $45 million of revenue to Energy Holdings' financial statements, and the additional ownership interest is expected to result in a modest increase to Energy Holdings' earnings.

      Prisma indirectly owns and operates three biomass generation plants in Italy through its ownership of 100% of San Marco Bioenergie S.p.A., which owns a 20 MW plant, and 50% of Biomasse, a partnership with Api Holding S.p.A., which owns two plants totaling 60 MW. Global records Prisma's investment in Biomasse as an equity method investment due to Global's approximate 43% indirect ownership in Biomasse. The output of the plants is sold under power purchase agreements with the Italian national grid (CIP contracts), which include a premium for the renewable energy output. These contracts expire from 2009 through 2012.

Note 4. Earnings Per Share (EPS)

PSEG

      Diluted EPS is calculated by dividing Net Income (Loss) by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under PSEG's stock option plans, upon payment of performance units and upon conversion of Participating Units.

      The following table shows the effect of these stock options, performance units and Participating Units on the weighted average number of shares outstanding used in calculating diluted EPS:

	Quarters Ended June 30,												Six Months Ended June 30,
	2006						2005						2006				2005
	Basic			Diluted			Basic			Diluted			Basic		Diluted		Basic			Diluted
EPS Numerator:
Earnings (Millions)
Continuing Operations	$	(14	)	$	(14	)	$	91		$	91		$	185	$	185	$	371		$	371
Discontinued Operations		223			223			(173	)		(173	)		227		227		(168	)		(168	)
Net Income (Loss)	$	209		$	209		$	(82	)	$	(82	)	$	412	$	412	$	203		$	203
EPS Denominator (Thousands):
Weighted Average Common Shares Outstanding		251,474			251,474			238,732			238,732			251,331		251,331		238,524			238,524
Effect of Stock Options		—			519			—			934			—		653		—			994
Effect of Stock Performance Units		—			91			—			110			—		91		—			110
Effect of Participating Units		—			—			—			3,243			—		—		—			3,004
Total Shares		251,474			252,084			238,732			243,019			251,331		252,075		238,524			242,632
Earnings Per Share:
Continuing Operations	$	(0.05	)	$	(0.05	)	$	0.38		$	0.38		$	0.74	$	0.74	$	1.56		$	1.53
Discontinued Operations		0.88			0.88			(0.72	)		(0.72	)		0.90		0.90		(0.71	)		(0.69	)
Net Income (Loss)	$	0.83		$	0.83		$	(0.34	)	$	(0.34	)	$	1.64	$	1.64	$	0.85		$	0.84

      No stock options had an antidilutive effect for the quarters and six months ended June 30, 2006 and 2005.

      Dividend payments on common stock for the quarters ended June 30, 2006 and 2005 were $0.57 and $0.56 per share, respectively, and totaled approximately $143 million and $133 million,

25

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

respectively. Dividend payments on common stock for the six months ended June 30, 2006 and 2005 were $1.14 and $1.12 per share, respectively, and totaled approximately $286 million and $267 million, respectively.

Note 5. Commitments and Contingent Liabilities

Guaranteed Obligations

      Power

      Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York) in commodity-related transactions in the ordinary course of business. These payment guarantees are provided to counterparties in order to obtain credit under physical and financial agreements for gas, power, pipeline capacity, transportation, oil, electricity and related commodities and services. These payment guarantees support the current exposure, interest and other costs on sums due and payable by ER&T and Power New York. Under these agreements, guarantees offered for trading and marketing 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 June 30, 2006 and December 31, 2005 was approximately $1.6 billion. 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 it 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. The 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 $595 million and $549 million as of June 30, 2006 and December 31, 2005, respectively.

      Power is subject to collateral calls related to commodity contracts that are bilateral and are subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T's agreements. Changes in commodity prices, including fuel, emission allowances and electricity, can have a material impact on margin requirements under such contracts that are entered into in the normal course of business. As of June 30, 2006, Power had posted margin of approximately $299 million, primarily in the form of letters of credit, and received margin of approximately $4 million to satisfy collateral obligations and support various contractual and environmental obligations. Collateral obligations may be posted in the form of cash or letters of credit. Assuming no changes in forward energy prices and positions, Power's collateral requirements can be expected to decline over time as its contracts expire.

      In the event of a deterioration of Power's credit rating to below investment grade, which represents a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide further performance assurance, generally in the form of a letter of credit or cash. As of June 30, 2006, if Power were to lose its investment grade rating and, assuming all counterparties to which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to approximately $684 million. Power believes that it has sufficient liquidity to post such collateral, if necessary.

      Due to a decrease in commodity prices and a roll off of positions between March 31, 2006 and June 30, 2006, the amount of collateral posting requirements decreased by approximately 60%.

26

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

      Energy Holdings

      Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects. The guaranteed obligations as of June 30, 2006 and December 31, 2005 are as follows:

				As of
Subsidiaries/Affiliates	Location	Description	Expiration Date	June 30, 2006		December 31, 2005
				(Millions)
Skawina (a)	Poland	Equity commitment	August 2007	$	6	$	9
PSEG Global Funding II LLC	Delaware	Contingent guarantee related to debt service obligations associated with Chilquinta	April 2011		25		25
Prisma	Italy	Leasing agreement guarantee	N/A		19		20
TIE - Guadalupe	Guadalupe	Interest Rate Swap Guarantee	December 2009		21		33
Elcho (b)	Poland	Debt Service Reserve Backup	October 2006		—		32
PSEG Energy Technologies Asset Management Company LLC	New Jersey	Performance guarantee	N/A		3		6
Other	Various	Various	N/A		13		13
Total Contingent Obligations				$	87	$	138

(a)	Sold in May 2006. The guaranteed amount has been indemnified by the purchaser, CEZ a.s. For further information, see Note 3. Discontinued Operations, Dispositions and Acquisitions.
(b)	Global's obligation was terminated as a result of the sale.

      In September 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies) and nearly all of its assets. However, Energy Holdings retained certain outstanding construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance companies for which exposure is adequately supported by the outstanding letters of credit shown in the table above for PSEG Energy Technologies Asset Management Company LLC. As of June 30, 2006, there were $14 million of such bonds outstanding related to uncompleted construction projects and other obligations. These performance bonds are not included in the $87 million of guaranteed obligations above.

      In addition to the amounts discussed above, certain subsidiaries of Energy Holdings may also have contingent obligations related to their respective projects, which are non-recourse to Energy Holdings.

Environmental Matters

      PSEG, PSE&G and Power

      Hazardous Substances

      The New Jersey Department of Environmental Protection (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. These regulations may substantially increase the costs of environmental investigations and necessary remediation, particularly at sites situated on surface water bodies. PSE&G, Power and respective predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations is not currently estimable. However, neither PSE&G nor Power anticipates that compliance with these regulations will have a material adverse effect on their respective financial positions, results of operations or net cash flows.

27

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

      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.

      In 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G and Power, 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 approximately $20 million, of which it would seek to recover $10 million from the PRPs, including PSE&G and Power. Power is evaluating recoverability of any disbursed amounts from its insurance carriers.

      Also, 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 New Jersey Spill Compensation and Control 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.

      PSE&G and Power have indicated to both the EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their respective claims and, along with approximately 51 other PRPs, have entered into an agreement with the EPA or have indicated their intention to enter an agreement that provides for sharing the costs of the $20 million study between the government organizations and the PRPs. The EPA recently has notified the PRPs that the cost of the study will greatly exceed the $20 million initially estimated and offered to the PRPs the opportunity to conduct the study themselves rather than reimburse the government for the additional costs it incurs. The PRP group is considering the offer and has engaged in discussions with the EPA. Whether the PRP group, or some number of the PRPs, agree to assume responsibility for the study will depend upon many factors, including a revised estimated cost of the study, the number of parties who agree to participate and the manner in which the parties divide the costs among themselves. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River or natural resource damages. However, such costs could be material.

      PSE&G

      MGP Remediation Program

      PSE&G is currently 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 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. Specifically, in 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the 10 most

28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

significant sites for cleanup. One of the sites identified is a former MGP facility located in Camden, New Jersey. 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. Since the inception of the Remediation Program in 1988 through June 30, 2006, PSE&G had expenditures of approximately $356 million.

      During the fourth quarter of 2005, PSE&G refined the detailed site estimates. The cost of remediating all sites to completion, as well as the anticipated costs to address MGP-related material discovered in two rivers adjacent to former MGP sites, could range between $751 million and $796 million. No amount within the range was considered to be most likely. Therefore, $395 million was accrued as of June 30, 2006, which represents the difference between the low end of the total program cost estimate of $751 million and the total incurred costs through June 30, 2006 of $356 million. Of this amount, approximately $43 million was recorded in Other Current Liabilities and $352 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $395 million Regulatory Asset was recorded. PSE&G anticipates spending $44 million in 2006, $45 million in 2007 and an average of $36 million per year through 2016 to remediate MGP-related environmental conditions.

      New Jersey Clean Energy Program

      The BPU has approved a funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The liability for the funding requirement has been recorded at the discounted present value. The costs associated with this program will be recovered from PSE&G ratepayers over the four years and, therefore, a Regulatory Asset was also recorded. The liability for the funding requirement as of June 30, 2006 and December 31, 2005 was $296 million and $329 million, respectively.

      Power

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

      The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The Federal government may order companies allegedly 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 approximately $27,500 for each day of continued violation.

      The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-burning units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to requests for information and, in January 2002, reached an agreement with the NJDEP and the EPA to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur Dioxide (SO₂), Nitrogen Oxide (NOx), particulate matter and mercury from the coal-burning units at the Mercer and Hudson generating stations. The cost of the program was approximately $111 million for installation of selective catalytic reduction systems (SCRs) at Mercer, as well as additional expenditures of approximately $400 million to $500 million at Hudson and $150 million to $250 million at Mercer for other pollution control equipment to be installed by December 31, 2006 and December 31, 2012, respectively. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over Bergen 2 regarding the

29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

applicability of PSD requirements and allowed construction of the unit to be completed and operations to commence.

      Power has notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution control equipment and other necessary modifications to the unit. Power will be unable to complete the installation of the pollution control equipment at Hudson by the December 31, 2006 deadline. Power has proposed to the NJDEP and the EPA an alternative pollution reduction plan to permit Hudson to continue to operate on coal beyond December 31, 2006. Discussions relating to this issue are ongoing. Power believes that the unit may continue to operate after December 31, 2006; however no assurances can be given. Power cannot accurately determine all costs, including any penalties and limitations on operations, related to the Hudson unit beyond December 31, 2006, but such costs could be material. The costs associated with the pollution control modifications for the Hudson unit have not been included in Power's forecasted capital expenditures.

      Mercury Legislation

      New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The Connecticut legislation requires coal-fired power plants in Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions effective in July 2008. The regulations in New Jersey require coal-fired electric generating units in New Jersey to meet certain emission limits or reduce emissions by 90% by December 15, 2007. 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 has a multi-pollutant reduction agreement with the NJDEP as a result of a consent decree that resolved issues arising out of the PSD and the NSR air pollution control programs at the Hudson, Mercer and Bergen facilities. Substantial uncertainty exists regarding the feasibility of achieving the reductions in mercury emissions required by the New Jersey regulations and Connecticut statute; however, the estimated costs of technology believed to be capable of meeting these emissions limits at Power's coal-fired unit in Connecticut and at its Mercer Station are included in Power's capital expenditure forecast. Total estimated costs for the project are between $150 million and $200 million each.

      New Jersey Industrial Site Recovery Act (ISRA)

      In the second quarter of 1999, a study was conducted pursuant to ISRA and potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. Power had a $51 million liability as of June 30, 2006 and December 31, 2005 related to these obligations, which is included in Other Noncurrent Liabilities on Power's Condensed Consolidated Balance Sheets and Environmental Costs on 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 Nuclear Generating Station (Salem), which expired in July 2006, allowing for the continued operation of Salem with its existing cooling water system. A renewal application prepared in accordance with the new Phase II 316(b) rule was filed with the NJDEP that allows the station to continue operating under its existing NJPDES permit until a new permit is issued. Power believes that its application to renew Salem's NJPDES permit demonstrates that the station meets the Phase II 316(b) rule's performance standards for reduction of impingement mortality and entrainment through the station's existing cooling water intake technology and operations plus implemented restoration measures. Power believes that the application further demonstrates that the station meets the Phase II 316(b) rule's site-specific determination standards without the benefits of restoration. If the

30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

NJDEP were to require the installation of technologies at the Salem facility to reduce cooling water intake flow commensurate with closed-cycle cooling as a result of an unfavorable decision in the Phase II litigation or otherwise, Power estimates that the costs associated with cooling towers for Salem are approximately $1 billion, of which Power's share would be approximately $575 million. These costs are not included in Power's currently forecasted capital expenditures.

New Generation and Development

      Power

      Power also has contracts with outside parties to purchase upgraded turbines for Salem Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek to modestly increase its generating capacity. Phase II of the Salem Unit 2 turbine replacement is currently scheduled for 2008 concurrent with steam generator replacement and is anticipated to increase capacity by 26 MW. Phase II of the Hope Creek turbine replacement is expected to be completed in 2007 along with the thermal power uprate and is expected to add approximately 120 MW. Power's expenditures to date approximate $215 million (including Interest Capitalized During Construction (IDC) of $19 million) with an aggregate estimated share of total costs for these projects of $244 million (including IDC of $24 million). Timing, costs and results of these projects are dependent on timely completion of work, timely approval from the NRC and various other factors.

      Completion of the projects discussed above within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes in the operational dates or ultimate costs to complete.

      Energy Holdings

      Electroandes S.A. (Electroandes)

      A 35 MW expansion project of an existing hydro station at Electroandes, a generating facility in Peru, is under review. Construction has been indefinitely postponed as the project is being re-evaluated. No construction funds have been disbursed on the project thus far and capital expenditures related to this project have been removed from Energy Holdings' cash forecast.

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

      Power

      Power seeks to mitigate volatility in its results by contracting in advance for 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 below. In addition to the BGS-related contracts, Power has entered into firm supply contracts with EDCs in Pennsylvania and Connecticut, as well as other firm sales and trading positions and commitments.

      PSE&G and Power

      PSE&G is required to obtain all electric supply requirements for customers that do not purchase electric supply from third-party suppliers through the annual New Jersey BGS auctions. The BGS auction process is a statewide process in which all of the New Jersey EDCs participate. The BGS auctions are “declining clock” auctions, where the EDCs accept offers for the amount of electric supply bidders are willing to offer with higher prices at the beginning of the auction. The auction proceeds when the amount of supply bid exceeds what is needed. The offer price is subsequently lowered and the

31

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

process continues in a series of steps. When the amount of supply bid by the prospective suppliers matches an EDC's electric supply needs, the auction ends. The BPU renders a decision whether or not to accept the auction results within two business days of its conclusion.

      PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions within three business days of the BPU's approval. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G's anticipated load requirements. The winners of the auction are responsible for fulfilling all the requirements of a PJM Load Serving Entity (LSE) including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume any migration risk and must satisfy New Jersey's renewable portfolio standards.

      Through the BGS auctions, PSE&G has contracted for its anticipated BGS-Fixed Price load, as follows:

	Term Ending
	May 2006(a)		May 2007(b)		May 2008(c)		May 2009(d)
Term	34 months		36 months		36 months		36 months
Load (MW)		2,900		2,840		2,840		2,882
$ per kWh	$	0.05560	$	0.05515	$	0.06541	$	0.10251

(a)	Prices set in the February 2003 BGS auction.
(b)	Prices set in the February 2004 BGS auction.
(c)	Prices set in the February 2005 BGS auction.
(d)	Prices set in the February 2006 BGS auction, which became effective on June 1, 2006.

      PSE&G entered into a full requirements contract through 2007 with Power to meet the supply requirements of PSE&G's gas customers. Power has entered into hedges for a portion of its anticipated BGSS obligations, as permitted by the BPU. The BPU permits recovery of the cost of gas hedging up to 115 billion cubic feet or approximately 80% of PSE&G's residential gas supply annually through the BGSS tariff. For additional information, see Note 13. Related-Party Transactions.

Minimum Fuel Purchase Requirements

      Power

      Power purchases coal for certain of its fossil generation stations through various long-term commitments. The total minimum purchase requirements included in these commitments amount to approximately $718 million through 2012.

      Power has various multi-year requirements-based purchase commitments that average approximately $89 million per year to meet Salem's and Hope Creek's nuclear fuel needs, of which Power's share is approximately $64 million per year through 2010. Power has been advised by the co-owner and operator of Peach Bottom, Exelon Generation LLC (Exelon Generation), that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom through 2010, of which Power's share is approximately $31 million per year.

      In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G. As of June 30, 2006, the total minimum requirements under these contracts were approximately $1.2 billion through 2016.

      These purchase obligations are aligned with Power's strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

      Energy Holdings

      The Guadalupe and Odessa plants of Texas Independent Energy, L.P. (TIE), an indirect, wholly owned subsidiary of Energy Holdings, have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of June 30, 2006, the Guadalupe and Odessa plants, which total approximately 2,000 MW of capacity, had forward energy sales contracts in place which support the majority of margin expectations for the balance of 2006. The plants had fuel purchase commitments totaling $82 million to fully support such contracts.TIE has also entered into an agreement to sell approximately 18% of its aggregate capacity for 2007 through 2010.

Operating Services Contract (OSC)

      Power

      Nuclear has entered into an OSC with Exelon Generation, which commenced on January 17, 2005, relating to the operation of the Hope Creek and Salem nuclear generating stations. The OSC requires Exelon Generation to provide a chief nuclear officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon Generation operating model, which defines practices that Exelon Generation has used to manage the operations of its own nuclear facilities. Nuclear continues as the license holder with exclusive legal authority to operate and maintain the plants, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities. Exelon Generation is entitled to receive reimbursement of its costs in discharging its obligations, an annual operating services fee of $3 million and incentive fees up to $12 million annually based on attainment of goals relating to safety, capacity factor and operation and maintenance expenses. The OSC has a term of two years, subject to earlier termination in certain circumstances. In the event of termination, Exelon Generation will continue to provide services under the OSC for a transition period of at least 180 days and up to two years at the election of Nuclear. This period may be further extended by Nuclear for up to an additional 12 months if Nuclear determines that additional time is necessary to complete required activities during the transition period.

Maintenance Agreement

      Power

      Power entered into a long-term contractual services agreement with a vendor in September 2003 to provide the outage and service needs for certain of Power's fossil generating units at market rates. The contract covers approximately 25 years and could result in annual payments ranging from approximately $10 million to $50 million for services, parts and materials rendered.

Nuclear Fuel Disposal

      Power

      Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per kWh of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility for such purpose to be available earlier than 2017.

      Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from-reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). Adequate spent fuel storage capacity is estimated to be available through

33

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power has commenced construction of an on-site storage facility that will satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of their current respective license lives. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach Bottom's spent fuel storage requirements until at least 2014.

      Exelon Generation had previously advised Power that it had signed an agreement with the DOE, applicable to Peach Bottom, under which Exelon Generation would be reimbursed for costs incurred resulting from the DOE's delay in accepting spent nuclear fuel for permanent storage. Under this agreement, Power's portion of Peach Bottom's Nuclear Waste Fund fees was reduced by approximately $18 million through August 31, 2002, at which point credits were fully utilized and covered the cost of Exelon Generation's on-site storage facility. In September 2002, the U.S. Court of Appeals for the Eleventh Circuit issued an opinion upholding a petition seeking to set aside the receipt of these credits by Exelon Generation. On August 14, 2003, Exelon Generation received a letter from the DOE demanding repayment of previously received credits from the Nuclear Waste Fund. The letter also demanded a total of approximately $1.5 million of accrued interest. In August 2004, Exelon Generation advised Nuclear that it reached a settlement with the U.S. Department of Justice, under which Exelon Generation would be reimbursed for costs associated with the storage of spent nuclear fuel at the Peach Bottom facility, a portion of which would be paid to Nuclear as a co-owner of Peach Bottom. Future costs incurred resulting from the DOE delays in accepting spent fuel will be reimbursed annually until the DOE fulfills its obligation to accept spent nuclear fuel. In addition, Exelon Generation and Nuclear are required to reimburse the DOE for the previously received credits from the Nuclear Waste Fund, plus lost earnings. Under this settlement, Power received approximately $27 million for its share of previously incurred storage costs for Peach Bottom, $22 million of which was used for the required reimbursement to the Nuclear Waste Fund. Exelon Generation paid Power approximately $5.4 million for its portion of the spent fuel storage costs reimbursed by the DOE in 2005 for costs incurred between October 1, 2003 and June 30, 2005.

      In September 2001, Power filed a complaint in the U.S. Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. On October 14, 2004, an order to show cause was issued regarding whether the U.S. Court of Federal Claims has jurisdiction over the matter. Power responded to this order in November 2004. On January 31, 2005, the Judge dismissed the breach-of-contract claims of Power and three other utilities. Power moved for reconsideration in the U.S. Court of Federal Claims and jointly petitioned for permission to appeal the January 31, 2005 order to the U.S. Court of Appeals for the Federal Circuit. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.

Spent Fuel Pool

      Power

      The spent fuel pool at each Salem unit has an installed leakage collection system. This system was found to be obstructed at Salem Unit 1. Power developed a solution to maintain the design function of the leakage collection system at Salem Unit 1 and investigated the existence of any structural degradation that might have been caused by the obstruction. The concrete and reinforcing steel laboratory tests results were completed in March 2006. Test results that have been collected as part of the ongoing testing indicate that no repairs are anticipated. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Power cannot predict what further actions the NRC may take on this matter.

      Elevated concentrations of tritium in the shallow groundwater at Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Power conducted a comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power is conducting remedial actions to address the contamination in accordance with a remedial action workplan approved by the NJDEP in November

34

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2004. The remedial actions are expected to be ongoing for several years. The costs necessary to address this on-site groundwater contamination issue are not expected to be material.

Investment Tax Credits (ITC)

      PSEG and PSE&G

      As of June 1999, the Internal Revenue Service (IRS) had 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 were terminated upon New Jersey's electric industry deregulation. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC liability relating to PSE&G's generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry in New Jersey. PSE&G was directed by the BPU to seek a PLR from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the tax normalization rules of the Internal Revenue Code. PSE&G filed a PLR request with the IRS in 2002.

      On December 21, 2005, the Treasury proposed new regulations for comment addressing the normalization of ITC, replacing regulations originally proposed in 2003. The new proposed regulations, if finalized, would not permit retroactive application. Accordingly, the IRS's conclusions in the above referenced PLRs would continue to remain in effect for all industry deregulations prior to December 21, 2005.

      On April 26, 2006, the BPU issued an order to PSE&G revoking its previous instruction and directing PSE&G to withdraw its request for a PLR by April 27, 2006. The BPU asserted that the Treasury's proposed regulation project was the more appropriate authority to rely upon in deciding the ITC issue.

      On May 1, 2006, PSE&G filed a motion for reconsideration with the BPU requesting that it modify its April 26, 2006 order to PSE&G to withdraw the PLR request. On May 5, 2006, the BPU denied PSE&G's motion for reconsideration and reiterated its order to withdraw the PLR request. On May 8, 2006, PSE&G filed a petition with the Appellate Court of New Jersey challenging the BPU's order to withdraw the PLR. The appeal is still pending. On May 11, 2006, the IRS issued a private letter ruling to PSE&G. The PLR concluded that none of the generation ITC could be passed to utility customers without violating the normalization rules. While the holding in the PLR is a favorable development for PSE&G, the outstanding Treasury regulation project could overturn the holding in the PLR if the Treasury were to alter the position set out in the December 21, 2005 proposed regulations. The issue cannot be fully resolved until the final Treasury regulations are issued.

      On May 16, 2006, the BPU voted in favor of a special investigation and hearing before the BPU concerning PSE&G's actions leading up to receiving the PLR, specifically its failure to abide by the BPU order to withdraw the request. An order detailing such special investigation has not yet been issued and no investigation has begun. PSE&G cannot predict the outcome of this special investigation.

      While PSE&G cannot predict the outcome of these matters, a requirement to refund such amounts to customers would have a material adverse impact on PSEG's and PSE&G's financial condition, results of operations and net cash flows.

BPU Deferral Audit

      PSEG and PSE&G

      The BPU Energy and Audit Division conducts periodic audits of utilities' deferred balances. A draft Deferral Audit—Phase II report relating to PSE&G for the 12-month period ended July 31, 2003 was released by the consultant to the BPU in April 2005. The draft report addresses PSE&G's SBC, Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances. The BPU released the report on May 13, 2005.

35

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

      While the consultant to the BPU found that PSE&G's 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 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 approximately $114 million. PSE&G and the BPU Staff are continuing discussions to resolve these questions and, if a resolution cannot be achieved, a BPU proceeding may be instituted to consider the issues raised. While PSE&G believes the MTC methodology it used was fully litigated and resolved, without exception, by the BPU and other intervening parties in its previous electric base rate case, deferral audit and deferral proceeding that were approved by the BPU in its order on April 22, 2004, and that such order is non-appealable, PSE&G cannot predict the impact of the outcome of any such proceeding.

Leveraged Lease Investments

      PSEG and Energy Holdings

      Resources faces risks with regard to the creditworthiness of certain lessees that collectively comprise a substantial portion of its investment portfolio. Resources also faces risks related to potential changes in the current accounting and tax treatment of certain investments in leveraged leases.

      From 1996 through 2002, PSEG, through its indirect wholly owned subsidiary, Resources, entered into a number of leveraged lease transactions in the ordinary course of business. Certain of those transactions are similar to a type that the IRS subsequently announced its intention to challenge, and PSEG understands that similar transactions entered into by other companies have been the subject of review and challenge by the IRS. As of each of June 30, 2006 and December 31, 2005, Resources' total gross investment in such transactions was approximately $1.4 billion. The IRS is presently reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2000, when Resources entered into some of these transactions.

      On September 27, 2005, the IRS proposed to disallow PSEG's deductions associated with certain of these leveraged leases which have been designated by the IRS as “listed transactions.” On July 8, 2006, the IRS proposed to disallow deductions associated with another group of these leveraged leases. Other lease transactions within the audit period are still under IRS review. The IRS may propose additional disallowances in the future. If deductions associated with these lease transactions entered into by PSEG are successfully challenged by the IRS, it could have a material adverse impact on PSEG's and Energy Holdings' financial position, results of operations and net cash flows and could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law and believes that it should prevail with respect to any IRS challenge, although no assurances can be given.

      If the tax benefits associated with all of the listed lease transactions were completely disallowed by the IRS, approximately $717 million of PSEG's deferred tax liabilities that have been recorded under leveraged lease accounting through June 30, 2006 could become currently payable. In addition, interest expense of approximately $106 million, after-tax, and penalties could be assessed. Management assessed the probability of various outcomes to this matter and recorded appropriate reserves in accordance with SFAS No. 5 “Accounting for Contingencies.” Energy Holdings believes that such an outcome is unlikely. However, in the event that such a payment is required, Energy Holdings believes that, assuming certain asset monetizations of its investment portfolio, it has the financial capacity to meet this potential obligation.

      The FASB recently issued additional guidance for leveraged leases. See Note 2. Recent Accounting Standards for additional information.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Restructuring Charge

      Power

      In June 2005, Power implemented a plan to reduce its Nuclear workforce by approximately 200 positions. The plan included voluntary and involuntary separations offered to both represented and non-represented employees. The major cost associated with the restructuring relates to payments to the employees who were terminated. Power's $14 million share of the estimated total cost was recorded in 2005, approximately $11 million of which had been paid as of June 30, 2006.

Retention Program

      PSEG, PSE&G, Power and Energy Holdings

      The Retention Program, effective as of December 20, 2004, provides for payments to be made to certain key employees of PSEG who remain employed from the date of execution of the Merger Agreement through the date that is 90 days after the consummation of the Merger. The amount of a participant's retention payment may not be less than 40% or more than 150% of the participant's annual base salary. Retention payments under the Retention Program were not to exceed $10 million in the aggregate.

      PSEG paid the first installment, equal to half of a participant's total retention payment, in December 2005, the first anniversary of the date of execution of the Merger Agreement. The merged company will pay the participants' remaining retention payments within 90 days after the consummation of the Merger. In April 2006, the Retention Program was amended to change maximum aggregate payments from $10 million to $15 million. Awards granted after March 31, 2006 are to be paid in one installment. No participant whose employment terminates prior to 90 days after the consummation of the Merger, for any reason other than involuntary termination without “cause”, will receive any retention payment. A participant whose employment is terminated without “cause”, on or prior to the payment of the final installment of the retention payment will be treated as if he or she remained employed through the date that is 90 days after consummation of the Merger for all purposes under the Retention Program.

Severance Plan

      PSEG, PSE&G, Power and Energy Holdings

      The Severance Plan provides change in control severance benefits to certain elected officers of PSEG whose employment is terminated without “cause” or who resign their employment for “good reason” within two years after a change in control, which would include the consummation of the Merger. Under the Severance Plan, the majority of the participants, if they are terminated without “cause” or resign employment for “good reason,” under the terms of the plan, will receive (1) a pro rata bonus based on the participant's target annual incentive compensation, (2) two times the sum of the participant's salary and target incentive bonus, (3) accelerated vesting of equity-based awards, (4) a lump sum payment equal to the actuarial equivalent of the participant's benefits under all of PSEG's retirement plans in which the participant participates calculated as though the participant remained employed for two years beyond the date his or her employment terminates less the actuarial equivalent of such benefits on the date his or her employment terminates, (5) two years continued welfare benefits (the first 18 months of which will be provided through PSEG-paid COBRA continuation coverage), (6) one year of PSEG-paid outplacement services and (7) vesting of any compensation previously deferred. Under the Severance Plan, five participants will receive the same benefits as the other participants, except that the applicable multiplier for salary and target incentive bonus, retirement plan accruals and continuation of welfare benefits is three years instead of two.

37

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Other

      Energy Holdings

      Electroandes

      In July 2005, Electroandes received a notice from Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, claiming past due taxes for 2002 totaling approximately $2 million related to certain interest deductions. Electroandes has taken similar interest deductions subsequent to 2002. The total cumulative estimated potential amount for past due taxes, including associated interest and penalties, is approximately $8 million through June 30, 2006. Electroandes believes it has valid legal defenses to these claims, and has filed for an appeal with SUNAT to which it has not yet received a response; however, no assurances can be given regarding the outcome of this matter.

      Dhofar Power

      Since commencing operations in Oman in May 2003, Dhofar Power has experienced a number of unplanned service interruptions, including four in the first half of 2004, which resulted from a combination of force majeure events and breaches of general warranties of the contractors that installed equipment at Dhofar Power. Dhofar Power and the Government of Oman have been in a dispute regarding the applicability and extent of any penalties under Dhofar Power's Concession Agreement arising from these service interruptions. On July 14, 2005, the expert engaged by the parties recommended no penalties be assessed for the 2003 service interruptions and agreed with Dhofar Power's interpretation of the Concession Agreement with respect to the criteria to be utilized in assessing penalties. The Government of Oman has exercised its right to appeal the expert's determination to a full arbitration panel. While Dhofar Power believes this matter will be favorably resolved in 2006, no assurances can be given.

      Dhofar Power and the Government of Oman are also in disagreement on the basis of the calculation of certain monthly allowances to be paid to compensate Dhofar Power for the capital investment costs associated with the enhancements and extensions of the transmission and distribution system in Salalah. On August 24, 2005, the expert engaged by the parties found in favor of Dhofar Power with respect to the criteria to be used in determining the monthly allowances. In the view of Dhofar Power, the Government of Oman has failed to timely exercise its right to appeal the expert's determination to a full arbitration panel. The Government of Oman has now paid all sums previously due and is continuing to make payments on the basis of Dhofar Power's calculations, but has not agreed that it is obligated to continue to pay Dhofar Power on the basis recognized by the expert. Dhofar Power will seek to enforce the expert's determination that it is entitled to approximately $1 million annually through December 2018 and believes that this matter will be favorably resolved in 2006, although no assurances can be given.

Note 6. Risk Management

PSEG, PSE&G, Power and Energy Holdings

      The operations of PSEG, PSE&G, Power and Energy Holdings 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, PSE&G, Power and Energy Holdings 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, PSE&G, Power and Energy Holdings 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

38

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

market risks. Each of PSEG, PSE&G, Power and Energy Holdings uses derivative instruments as risk management tools consistent with its respective business plan and prudent business practices.

Derivative Instruments and Hedging Activities

      Power

      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.

      Energy Trading Contracts (ETCs)

      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, but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana, and natural gas in the producing region.

      Power marks to market its derivative ETCs in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), with changes in fair value charged to the Condensed Consolidated Statements of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market 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.

      Power routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, such future contracts require a deposit of cash margin, the amount of which is subject to change based on market movement and in accordance with exchange rules. As of June 30, 2006, Power had deposited margin of approximately $258 million related to exchange-traded transactions which are margined and monitored separately from physical trading activity.

      Commodity Contracts

      Power

      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 June 30, 2006, the fair value of these hedges was $(634) million. These hedges, along with realized losses on hedges of $15 million retained in Accumulated Other Comprehensive Loss (OCL), resulted in a $(379) million after-tax impact on OCL. As of December 31, 2005, the fair value of these hedges was $(951)

39

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

million. These hedges, along with realized gains on hedges of $11 million retained in OCL, resulted in a $(558) million after-tax impact on OCL. During the next 12 months, $189 million (after-tax) of net unrealized and realized losses on these commodity derivatives is expected to be reclassified to earnings. Approximately $140 million of after-tax unrealized losses on these commodity derivatives in OCL is expected to be reclassified to earnings for the 12 months ended June 30, 2008. Ineffectiveness associated with these hedges, as defined in SFAS 133, was $(8) million at June 30, 2006. The expiration date of the longest-dated cash flow hedge is in 2009.

      Other Derivatives

      Power also enters into certain other contracts that are derivatives, but do not qualify for 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. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs or Operating Revenues, as appropriate, on the Condensed Consolidated Statements of Operations. The net fair value of these instruments as of June 30, 2006 was $(16) million. The net fair value of these instruments as of December 31, 2005 was not material.

      Energy Holdings

      Other Derivatives

      TIE enters into electricity forward and capacity sale contracts to sell its 2,000 MW capacity for portions of the current calendar year and into the daily spot market. TIE also enters 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 TIE, 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 recorded at fair value. The net fair value of the open positions was approximately $8 million and $(7) million as of June 30, 2006 and December 31, 2005, respectively.

Interest Rates

      PSEG, PSE&G, Power and Energy Holdings

      PSEG, PSE&G, Power and Energy Holdings 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

      In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009. PSEG used an interest rate swap to convert Power's fixed-rate debt 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 June 30, 2006 and December 31, 2005, the fair value of the hedge was $(13) million and $(10) million, respectively.

      Cash Flow Hedges

      PSEG, PSE&G and Energy Holdings

      PSEG, PSE&G and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures 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. Except

40

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

for PSE&G's cash flow hedges, the fair value changes of these derivatives are initially recorded in OCL. As of June 30, 2006, the fair value of these cash flow hedges was $2 million, including $(3) million and $5 million at PSE&G and Energy Holdings, respectively. As of December 31, 2005, the fair value of these cash flow hedges was $(17) million, including $(11) million and $(6) million at PSE&G and Energy Holdings, respectively. The $(3) million and $(11) million at PSE&G as of June 30, 2006 and December 31, 2005, respectively, is not included in OCL, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G's customers. During the next twelve months, $1 million of unrealized losses (net of taxes) on interest rate derivatives in OCL is expected to be reclassified to earnings at PSEG, PSE&G and Energy Holdings. As of June 30, 2006, there was essentially no hedge ineffectiveness associated with these hedges. The fair value amounts above as of December 31, 2005 do not include approximately $(60) million for the cash flow hedges at Elcho, which had been reclassified into Discontinued Operations.

      Other Derivatives

      Energy Holdings

      As of June 30, 2006, Energy Holdings had no cross-currency interest rate swaps where changes in fair value of such swaps are recorded in Income from Equity Method Investments on the Condensed Consolidated Statements of Operations. The fair value of these swaps at December 31, 2005 was approximately $(2) million.

Foreign Currencies

      Energy Holdings

      Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of its risks is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, Global and certain of its foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to changes in the Euro, the Peruvian Nuevo Sol and the Chilean Peso. Changes in valuation of these currencies can impact the value of Global's investments. Global has attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations.

      As of June 30, 2006, the net cumulative foreign currency revaluations have increased the total amount of Global's Member's Equity by $109 million.

      In November and December 2005, Energy Holdings purchased foreign currency options in order to hedge the majority of its 2006 expected earnings denominated in Brazilian Real, Chilean Pesos and Peruvian Nuevo Soles. These options are not considered hedges for accounting purposes under SFAS 133 and, as a result, changes in their fair value are recorded directly to earnings. Energy Holdings terminated its remaining Brazilian Real options on June 28, 2006. The fair value of the options outstanding at June 30, 2006 and December 31, 2005 was approximately $1 million and $2 million, respectively.

Hedges of Net Investments in Foreign Operations

      Energy Holdings

      In March 2004 and April 2004, Energy Holdings entered into four cross-currency interest rate swap agreements. The swaps are designed to hedge the net investment in a foreign subsidiary associated with the exposure to the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross-currency swaps was $(24) million and $(33) million as of June 30, 2006 and December 31, 2005, respectively. The

41

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

change in fair value is recorded net of tax in Cumulative Translation Adjustment within OCL. As a result, Energy Holdings' Member's Equity was reduced by $21 million as of June 30, 2006.

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

	PSE&G		Power (A)			Energy Holdings (B)			Other (C)			Consolidated Total
	(Millions)
For the Quarter Ended June 30, 2006:
Net Income (Loss)	$	34	$	77		$	118		$	(20	)	$	209
Other Comprehensive Income (Loss)		—		46			189			(1	)		234
Comprehensive Income (Loss)	$	34	$	123		$	307		$	(21	)	$	443
For the Quarter Ended June 30, 2005:
Net Income (Loss)	$	49	$	(127	)	$	22		$	(26	)	$	(82	)
Other Comprehensive Income		—		6			31			3			40
Comprehensive Income (Loss)	$	49	$	(121	)	$	53		$	(23	)	$	(42	)
For the Six Months Ended June 30, 2006:
Net Income (Loss)	$	112	$	189		$	150		$	(39	)	$	412
Other Comprehensive Income		—		179			191			—			370
Comprehensive Income (Loss)	$	112	$	368		$	341		$	(39	)	$	782
For the Six Months Ended June 30, 2005:
Net Income (Loss)	$	167	$	(19	)	$	101		$	(46	)	$	203
Other Comprehensive Income (Loss)		—		(104	)		(20	)		5			(119	)
Comprehensive Income (Loss)	$	167	$	(123	)	$	81		$	(41	)	$	84

(A)	Changes at Power primarily relate to SFAS 133 unrealized losses on derivative contracts that qualify for hedge accounting and unrealized gains and losses on Nuclear Decommissioning Trust (NDT) Funds.
(B)	Changes at Energy Holdings primarily relate to the realization of losses on Brazilian currency as a result of the sale of RGE and unrealized gains and losses on various derivative transactions.
(C)	Other primarily consists of activity at PSEG (as parent company), Services and intercompany eliminations.

42

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 8. Changes in Capitalization

PSEG

      During the six months ended June 30, 2006, PSEG issued approximately 523,000 shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Program for approximately $34 million.

      In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity investment in the trust.

PSE&G

      On June 23, 2006, PSE&G repaid at maturity $174 million of its Floating Rate Series A First and Refunding Mortgage Bonds.

      On March 1, 2006, PSE&G repaid at maturity $148 million of its 6.75% Series UU First and Refunding Mortgage Bonds.

      In June 2006 and March 2006, Transition Funding repaid approximately $35 million and $36 million, respectively, of its transition bonds

      In June 2006, PSE&G Transition Funding II LLC (Transition Funding II) repaid approximately $3 million of its transition bonds.

Power

      In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes.

Energy Holdings

      In January 2006, Energy Holdings redeemed $309 million of its 7.75% Senior Notes due in 2007.

      On February 17, 2006, the maturity of the Odessa–Ector Power Partners, L.P (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above LIBOR. On September 29, 2006, an interest rate swap will take effect which will convert the floating LIBOR interest rate on approximately 80% of Odessa's debt to a fixed rate of 5.4275% through December 31, 2009.

43

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9. Other Income and Deductions

	PSE&G		Power		Energy Holdings		Other (A)			Consolidated Total
	(Millions)
Other Income:
For the Quarter Ended June 30, 2006:
Interest and Dividend Income	$	3	$	3	$	7	$	(3	)	$	10
NDT Fund Realized Gains		—		21		—		—			21
NDT Interest and Dividend Income		—		10		—		—			10
Other		5		—		6		—			11
Total Other Income	$	8	$	34	$	13	$	(3	)	$	52
For the Quarter Ended June 30, 2005:
Interest and Dividend Income	$	2	$	2	$	2	$	(1	)	$	5
NDT Fund Realized Gains		—		17		—		—			17
NDT Interest and Dividend Income		—		10		—		—			10
Foreign Currency Gains		—		—		1		—			1
Other		—		1		—		—			1
Total Other Income	$	2	$	30	$	3	$	(1	)	$	34
For the Six Months Ended June 30, 2006:
Interest and Dividend Income	$	6	$	7	$	9	$	(4	)	$	18
NDT Fund Realized Gains		—		49		—		—			49
NDT Interest and Dividend Income		—		19		—		—			19
Foreign Currency Gains		—		—		5		—			5
Change in Derivative Fair Value		—		—		1		—			1
Other		6		—		8		—			14
Total Other Income	$	12	$	75	$	23	$	(4	)	$	106
For the Six Months Ended June 30, 2005:
Interest and Dividend Income	$	4	$	3	$	9	$	(1	)	$	15
Gain on Sale of Investments		—		—		1		—			1
NDT Fund Realized Gains		—		39		—		—			39
NDT Interest and Dividend Income		—		17		—		—			17
Foreign Currency Gains		—		—		1		—			1
Change in Derivative Fair Value		—		—		1		—			1
Other		—		2		1		—			3
Total Other Income	$	4	$	61	$	13	$	(1	)	$	77

44

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

	PSE&G		Power		Energy Holdings		Other (A)			Consolidated Total
	(Millions)
Other Deductions:
For the Quarter Ended June 30, 2006:
Donations	$	1	$	—	$	—	$	—		$	1
Foreign Currency Losses		—		—		3		—			3
Change in Derivative Fair Value		—		—		1		—			1
NDT Fund Realized Losses and Expenses		—		13		—		—			13
Minority Interest		—		—		—		1			1
Other		—		1		1		(1	)		1
Total Other Deductions	$	1	$	14	$	5	$	—		$	20
For the Quarter Ended June 30, 2005:
Donations	$	—	$	1	$	—	$	—		$	1
Foreign Currency Losses		—		—		6		—			6
Change in Derivative Fair Value		—		—		2		—			2
NDT Fund Realized Losses and Expenses		—		11		—		—			11
Minority Interest		—		—		—		1			1
Total Other Deductions	$	—	$	12	$	8	$	1		$	21
For the Six Months Ended June 30, 2006:
Donations	$	2	$	—	$	—	$	—		$	2
Foreign Currency Losses		—		—		7		—			7
Change in Derivative Fair Value		—		—		3		—			3
NDT Fund Realized Losses and Expenses		—		32		—		—			32
Minority Interest		—		—		—		1			1
Other		—		1		5		—			6
Total Other Deductions	$	2	$	33	$	15	$	1		$	51
For the Six Months Ended June 30, 2005:
Donations	$	1	$	1	$	—	$	—		$	2
Foreign Currency Losses		—		—		10		—			10
Change in Derivative Fair Value		—		—		3		—			3
NDT Fund Realized Losses and Expenses		—		19		—		—			19
Minority Interest		—		—		—		1			1
Other		—		—		1		(1	)		—
Total Other Deductions	$	1	$	20	$	14	$	—		$	35

(A) Other consists of reclassifications for minority interests in PSEG's consolidated results of operations and intercompany eliminations at PSEG (as parent company).

45

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 10. Income Taxes

      An analysis of the tax provision expense is as follows:

	PSE&G			Power			Energy Holdings			Other (A)			Consolidated Total
	(Millions)
For the Quarter Ended June 30, 2006:
Income (Loss) from Continuing Operations before Income Taxes	$	60		$	132		$	(167	)	$	(32	)	$	(7	)
Tax Computed at the Statutory Rate		21			46			(58	)		(11	)		(2	)
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit		5			8			(3	)		(2	)		8
Rate Differential of Foreign Operations		—			—			(4	)		—			(4	)
Plant Related Items		5			—			—			—			5
Other		(5	)		1			2			2			—
Total Income Tax Expense (Benefit)	$	26		$	55		$	(63	)	$	(11	)	$	7
Effective Income Tax Rate		43.3	%		41.7	%		37.7	%		34.4	%		(100.0	)%
For the Quarter Ended June 30, 2005:
Income (Loss) from Continuing Operations before Income Taxes	$	80		$	97		$	14		$	(42	)	$	149
Tax Computed at the Statutory Rate		28			34			5			(15	)		52
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit		6			5			5			—			16
Rate Differential of Foreign Operations		—			—			(16	)		—			(16	)
Lease Rate Differential		—			—			2			—			2
Other		(3	)		2			5			—			4
Total Income Tax Expense (Benefit)	$	31		$	41		$	1		$	(15	)	$	58
Effective Income Tax Rate		38.8	%		42.3	%		7.1	%		35.7	%		38.9	%
For the Six Months Ended June 30, 2006:
Income (Loss) from Continuing Operations before Income Taxes	$	203		$	324		$	(127	)	$	(65	)	$	335
Tax Computed at the Statutory Rate		71			113			(44	)		(23	)		117
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit		15			19			(5	)		(3	)		26
Rate Differential of Foreign Operations		—			—			(4	)		—			(4	)
Plant Related Items		8			—			—			—			8
Other		(3	)		3			2			1			3
Total Income Tax Expense (Benefit)	$	91		$	135		$	(51	)	$	(25	)	$	150
Effective Income Tax Rate		44.8	%		41.7	%		40.2	%		38.5	%		44.8	%
For the Six Months Ended June 30, 2005:
Income (Loss) from Continuing Operations before Income Taxes	$	284		$	295		$	95		$	(74	)	$	600
Tax Computed at the Statutory Rate		99			103			33			(26	)		209
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit		20			17			(2	)		(1	)		34
Rate Differential of Foreign Operations		—			—			(28	)		—			(28	)
Plant Related Items		1			—			—			—			1
Lease Rate Differential		—			—			2			—			2
Other		(3	)		4			10			—			11
Total Income Tax Expense (Benefit)	$	117		$	124		$	15		$	(27	)	$	229
Effective Income Tax Rate		41.2	%		42.0	%		15.8	%		36.5	%		38.2	%

(A) PSEG's other activities include amounts applicable to PSEG (as parent company) that primarily relate to financing and certain administrative and general costs.

46

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 11. Financial Information by Business Segments

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

							Energy Holdings
	PSE&G			Power			Resources			Global			Other (A)			Other (B)			Consolidated Total
	(Millions)
For the Quarter Ended June 30, 2006:
Total Operating Revenues	$	1,534		$	1,135		$	46		$	319		$	2		$	(430	)	$	2,606
Income (Loss) from Continuing Operations		34			77			19			(122	)		(2	)		(20	)		(14	)
Loss from Discontinued Operations, net of tax		—			—			—			(5	)		—			—			(5	)
Income on Disposal of Discontinued operations, net of tax		—			—			—			228			—			—			228
Net Income (Loss)		34			77			19			100			(1	)		(20	)		209
Preferred Securities Dividends/Preference Unit Distributions		(1	)		—			—			—			—			1			—
Segment Earnings (Loss)		33			77			19			100			(1	)		(19	)		209
Gross Additions to Long-Lived Assets		151			75			—			6			—			1			233
For the Quarter Ended June 30, 2005:
Total Operating Revenues	$	1,441		$	1,060		$	28		$	239		$	3		$	(394	)	$	2,377
Income (Loss) from Continuing Operations		49			56			(1	)		15			(2	)		(26	)		91
(Loss) Income from Discontinued Operations, net of tax		—			(6	)		—			10			—			—			4
Loss on Disposal of Discontinued Operations, net of tax		—			(177	)		—			—			—			—			(177	)
Net Income (Loss)		49			(127	)		(1	)		25			(2	)		(26	)		(82	)
Preferred Securities Dividends/Preference Unit Distributions		(1	)		—			—			(1	)		—			2			—
Segment Earnings (Loss)		48			(127	)		(1	)		24			(2	)		(24	)		(82	)
Gross Additions to Long-Lived Assets		146			138			1			5			(1	)		(6	)		283
For the Six Months Ended June 30, 2006:
Total Operating Revenues	$	3,884		$	3,102		$	93		$	581		$	5		$	(1,541	)	$	6,124
Income (Loss) from Continuing Operations		112			189			38			(113	)		(2	)		(39	)		185
Loss from Discontinued Operations, net of tax		—			—			—			(1	)		—			—			(1	)
Income on Disposal of discontinued operations, net of tax		—			—			—			228			—			—			228
Net Income (Loss)		112			189			38			114			(2	)		(39	)		412
Preferred Securities Dividends/Preference Unit Distributions		(2	)		—			—			—			—			2			—
Segment Earnings (Loss)		110			189			38			114			(2	)		(37	)		412
Gross Additions to Long Lived Assets		259			193			—			19			1			1			473
For the Six Months Ended June 30, 2005:
Total Operating Revenues	$	3,625		$	2,790		$	89		$	488		$	6		$	(1,382	)	$	5,616
Income (Loss) from Continuing Operations		167			171			22			60			(3	)		(46	)		371
(Loss) Income from Discontinued Operations, net of tax		—			(13	)		—			22			—			—			9
Loss on Disposal of Discontinued Operations, net of tax		—			(177	)		—			—			—			—			(177	)
Net Income (Loss)		167			(19	)		22			82			(3	)		(46	)		203
Preferred Securities Dividends/Preference Unit Distributions		(2	)		—			—			(3	)		—			5			—
Segment Earnings (Loss)		165			(19	)		22			79			(3	)		(41	)		203
Gross Additions to Long-Lived Assets		239			227			2			17			(1	)		(4	)		480

47

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

					Energy Holdings
	PSE&G		Power		Resources		Global		Other (A)		Other (B)			Consolidated Total
	(Millions)
As of June 30, 2006:
Total Assets	$	14,068	$	8,135	$	2,959	$	3,058	$	734	$	(695	)	$	28,259
Investments in Equity Method Subsidiaries	$	—	$	—	$	10	$	826	$	—	$	—		$	836
As of December 31, 2005:
Total Assets	$	14,291	$	8,945	$	2,871	$	3,799	$	385	$	(478	)	$	29,813
Investments in Equity Method Subsidiaries	$	—	$	—	$	10	$	1,128	$	—	$	—		$	1,138

(A)

Energy Holdings' other activities include amounts applicable to Energy Holdings (as parent company) and EGDC. The net losses primarily relate to financing and certain administrative and general costs of Energy Holdings.

(B)

PSEG's other activities include amounts applicable to PSEG (as parent company), 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 13. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at PSEG, as parent company.

Note 12. Stock-Based Compensation

PSEG

      As approved at the Annual Meeting of Stockholders in 2004, PSEG's 2004 Long-Term Incentive Plan (2004 LTIP) replaced prior Long-Term Incentive Plans (the 1989 LTIP and 2001 LTIP). The 2004 LTIP is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance shares, restricted stock, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIPs are non-qualified options to purchase shares of PSEG's common stock, restricted stock awards and performance unit awards. However, since 2004, only restricted stock has been granted.

      The 2004 LTIP currently provides for the issuance of equity awards with respect to approximately 13.0 million shares of common stock. As of June 30, 2006, there were 11.8 million shares available for future awards under the 2004 LTIP.

      Stock Options

      Under the 2004 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees of PSEG and its subsidiaries selected by the Organization and Compensation Committee of PSEG's Board of Directors, the plan's administrative committee (Committee). Option awards are granted with an exercise price equal to the market price of PSEG's common stock at the grant date. The options generally vest based on three to five years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control, retirement, death or disability. Options are exercisable over a period of time designated by the Committee (but not prior to one year or longer than 10 years from the date of grant) and are subject to such other terms and conditions as the Committee determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering previously acquired shares of PSEG common stock.

      PSEG purchases shares on the open market to meet the exercise requirements of stock options.

48

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

      Restricted Stock

      Under the 2004 LTIP, PSEG has granted restricted stock awards to officers and other key employees. These shares are subject to risk of forfeiture until vested by continued employment. Restricted stock generally vests annually over three years, but are considered outstanding at the time of grant, as the recipients are entitled to dividends and voting rights. Vesting may be accelerated upon certain events, such as change in control (unless substituted with an equity award of equal value), retirement, death or disability.

      In addition, from 1998 to 2001, PSEG granted 210,000 shares of restricted stock to a key executive, which are subject to risk of forfeiture until vested by continued employment. The shares vest on a staggered schedule through March 2007.

      PSEG issues restricted stock from treasury stock.

      Performance Units

      Under the 2004 LTIP, performance units were granted to certain key executives, which provide for payment in shares of PSEG common stock based on achievement of certain financial goals over the three-year period from 2004 through 2006. The payout varies from 0% to 200% of the number of performance units granted depending on PSEG's performance compared to the performance of other companies in the Dow Jones Utilities Index. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG common stock up until January 1, 2007. Vesting may be accelerated upon certain events such as change in control, retirement, death or disability.

      Stock-Based Compensation

      Effective January 1, 2006, PSEG adopted SFAS 123R. See Note 2. Recent Accounting Standards for a description of the adoption of SFAS 123R. As a result, all outstanding unvested stock options as of January 1, 2006 are being expensed based on their grant date fair values, which were determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.

      Prior to the adoption of SFAS 123R, PSEG recognized compensation expense for restricted stock over the vesting period based on the grant date fair market value of the shares. PSEG will continue to recognize compensation expense over the vesting term.

      Also prior to the adoption of SFAS 123R, PSEG recognized compensation expense for performance units. The fair value of each performance unit was based on the grant date fair value of PSEG stock. The accrual of compensation cost was based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. The current accrual is estimated at 100% of the original grant. The accrual is adjusted for subsequent changes in the estimated or actual outcome.

      Compensation cost from options, restricted stock and performance units is included in Operation and Maintenance Expense in PSEG's Condensed Consolidated Statements of Operations and amounted to approximately $3.3 million and $1.9 million for the quarters ended June 30, 2006 and 2005, respectively, and approximately $6.6 million and $3.5 million for the six months ended June 30, 2006 and 2005, respectively. The total income tax benefit recognized in PSEG's Condensed Consolidated Statements of Operations was approximately $1.4 million and $0.8 million for the quarters ended June 30, 2006 and 2005, respectively, and approximately $2.7 million and $1.4 million for the six months ended June 30, 2006 and 2005, respectively. Compensation cost capitalized as part of property, plant and equipment was less than $0.1 million for each of the quarters ended June 30, 2006 and 2005 and approximately $0.1 million for each of the six months ended June 30, 2006 and 2005. Of the total compensation cost for the six months ended June 30, 2006, approximately $0.6 million, or $0.3 million after-tax, related to the adoption of SFAS 123R, which was primarily due to expensing stock options for

49

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

the first time. There was no impact on basic and diluted earnings per share from the implementation of SFAS 123R because there were a relatively small number of outstanding unvested stock options as of the implementation date.

      Prior to the adoption of SFAS 123R, PSEG presented all tax benefits for deductions resulting from the exercise of share-based compensation as operating cash flows in the Condensed Consolidated Statement of Cash Flows. SFAS 123R requires the benefits of tax deductions in excess of the taxes expensed on recognized compensation cost to be reported as financing cash flows. There was approximately $18 million of excess tax benefits included as a financing cash inflow in the June 30, 2006 Condensed Consolidated Statements of Cash Flow. Total cash flow will remain unchanged from what would have been reported under prior accounting rules.

      The following table illustrates the effect on net income and earnings per share if PSEG had applied the fair value recognition provisions of SFAS 123R for the quarter and six months ended June 30, 2005.

	Quarter Ended June 30,			Six Months Ended June 30,
	2005			2005
	(Millions, except Share Data)			(Millions, except Share Data)
Net (Loss) Income, as reported	$	(82	)	$	203
Add: Total stock-based compensation expensed during the period, net of tax		1			2
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2	)		(3	)
Pro forma Net (Loss) Income	$	(83	)	$	202
(Loss) Earnings per share:
Basic—as reported	$	(0.34	)	$	0.85
Basic—pro forma	$	(0.35	)	$	0.85
Diluted—as reported	$	(0.34	)	$	0.84
Diluted—pro forma	$	(0.34	)	$	0.83

      Prior to the adoption of SFAS 123R, PSEG recognized the compensation cost of stock based awards issued to retirement eligible employees that fully or partially vest upon an employee's retirement over the nominal vesting period of performance, and recognized any remaining compensation cost at the date of retirement. In accordance with SFAS 123R, PSEG recognizes compensation cost of awards issued after January 1, 2006 over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is retirement eligible and the award vests.

      There were no options granted during 2005 or 2006. Changes in stock options for the six months ended June 30, 2006 are summarized as follows:

Options	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 2006		3,981,555		$	41.07
Granted		—			—
Exercised		(1,633,822	)		39.78
Canceled		(1,867	)		42.75
Outstanding at June 30, 2006		2,345,866		$	41.97		5.7 years	$	56,652,645
Exercisable at June 30, 2006		1,911,952		$	41.79		5.3 years	$	46,509,807

      The intrinsic value of options is the difference between the current market price and the exercise price. The total intrinsic value of options exercised during the six months ended June 30, 2006 and 2005

50

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

was approximately $43.1 million and $36.2 million, respectively. During the six months ended June 30, 2006 and 2005, cash received from stock options exercised was approximately $65.0 million and $82.5 million, respectively. The tax benefit realized from stock options exercised during the six months ended June 30, 2006 and 2005 was approximately $17.6 million and $14.8 million, respectively.

      As of June 30, 2006, there was approximately $0.7 million of unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted average period of seven months.

      Restricted Stock Information

      Changes in restricted stock for the six months ended June 30, 2006 are summarized as follows:

Options	Shares			Weighted Average Grant Date Fair Value		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 2006		466,744		$	56.69
Granted		43,800			66.53
Vested		(87,047	)		51.90
Canceled		(8,086	)		59.49
Outstanding at June 30, 2006		415,411		$	58.67		2.0 years	$	27,466,975

      The weighted average grant date fair value per share was $51.91 for restricted stock awards granted during the six months ended June 30, 2005.

      The total intrinsic value of restricted stock vested during the six months ended June 30, 2006 was approximately $6.1 million. No restricted shares vested during the six months ended June 30, 2005.

      As of June 30, 2006, there was approximately $19.1 million of unrecognized compensation cost related to restricted stock, which is expected to be recognized over a weighted average period of 2.1 years.

      Performance Units Information

      As of June 30, 2006, 82,700 performance units were outstanding and unvested, net of 900 units forfeited in the six-month period then ended. Approximately 7,900 dividend equivalents had accrued on these performance units. The grant date fair value of the performance units is $42.75 per unit.

      Assuming performance units are paid out at the 100% performance level, the total intrinsic value of performance units outstanding at June 30, 2006 is approximately $6.0 million.

      As of June 30, 2006, there was approximately $0.7 million of unrecognized compensation cost related to performance units, which is expected to be recognized over the next six months.

      Outside Directors

      During 2006, each director who was not an officer of PSEG or its subsidiaries and affiliates will be paid an annual retainer of $50,000. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently 50%, of the annual retainer is paid in PSEG common stock.

      PSEG also maintains a Stock Plan for Outside Directors (Stock Plan) pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive a restricted stock award, currently 1,000 shares per year, for each year of service as a director. The restrictions on the stock granted under the Stock Plan provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director's service were terminated after a “change in control” as defined in the Stock Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director who has the right to vote the shares. The fair value of these shares is recorded as

51

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

compensation expense in the Condensed Consolidated Statements of Operations. Compensation expense for the Stock Plan was less than $0.2 million for each of the quarters ended June 30, 2006 and 2005 and approximately $0.3 million for each of the six months ended June 30, 2006 and 2005.

      Employee Stock Purchase Plan

      PSEG maintains an employee stock purchase plan for all eligible employees of PSEG and its subsidiaries. Under the plan, shares of PSEG common stock may be purchased at 95% of the fair market value through payroll deductions. Employees may purchase shares having a value not exceeding 10% of their base pay. During the six months ended June 30, 2006 and 2005, employees purchased 21,794 and 27,772 shares at an average price of $60.77 and $51.90 per share, respectively. As of June 30, 2006, 1.9 million shares were available for future issuance under this plan.

Note 13. Related-Party Transactions

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

BGS and BGSS Contracts

      PSE&G and Power

      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 2007. 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 June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(Millions)
BGS	$	163	$	110	$	264	$	223
BGSS	$	257	$	260	$	1,260	$	1,122

      As of June 30, 2006 and December 31, 2005, Power had net receivables from PSE&G of approximately $164 million and $454 million, respectively, primarily related to the BGS and BGSS contracts. These transactions were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's Condensed Consolidated Financial Statements.

      In addition, as of June 30, 2006 and December 31, 2005, PSE&G had a payable to Power of approximately $55 million and a receivable of approximately $152 million, respectively, related to gas supply hedges Power entered into for BGSS.

Services

      PSE&G, Power and Energy Holdings

      Services provides and bills administrative services to PSE&G, Power and Energy Holdings. In addition, PSE&G, Power and Energy Holdings have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of

52

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

each of the operating companies. The billings for administrative services and payables are presented below:

	Services' Billings for the
	Quarters Ended June 30,				Six Months Ended June 30,				Payable to Services as of
	2006		2005		2006		2005		June 30, 2006		December 31, 2005
							(Millions)
PSE&G	$	53	$	53	$	108	$	103	$	33	$	34
Power	$	33	$	37	$	70	$	75	$	16	$	21
Energy Holdings	$	4	$	5	$	9	$	9	$	2	$	2

      These transactions were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's Condensed Consolidated Financial Statements. PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximate market value for such services.

Tax Sharing Agreements

      PSEG, PSE&G, Power and Energy Holdings

      PSE&G, Power and Energy Holdings had (payables to) receivables from PSEG related to taxes as follows:

	(Payable to) Receivable from PSEG As of
	June 30, 2006			December 31, 2005
	(Millions)
PSE&G	$	(36	)	$	(59	)
Power	$	3		$	4
Energy Holdings	$	(56	)	$	(12	)

Affiliate Loans and Advances

      PSEG and Power

      As of June 30, 2006 and December 31, 2005, Power had a demand note payable to PSEG of approximately $145 million and $202 million, respectively, for short-term funding needs.

      PSEG and Energy Holdings

      As of June 30, 2006, Energy Holdings had a demand note receivable of $258 million due from PSEG and a term note receivable of $450 million due on September 30, 2006 from PSEG. As of December 31, 2005, Energy Holdings had a demand note receivable due from PSEG of $409 million. These notes reflect the investment of Energy Holdings' excess cash with PSEG.

      PSE&G and Services

      As of each of June 30, 2006 and December 31, 2005, PSE&G had advanced working capital to Services of approximately $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 June 30, 2006 and December 31, 2005, Power had advanced working capital to Services of approximately $17 million. This amount is included in Other Noncurrent Assets on Power's Condensed Consolidated Balance Sheets.

53

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Other

      PSEG and PSE&G

      As of June 30, 2006 and December 31, 2005, PSE&G had net receivables from PSEG of approximately $6 million related to amounts that PSEG had collected on PSE&G's behalf.

      PSEG and Power

      As of June 30, 2006 and December 31, 2005, Power had net receivables from PSEG of approximately $1 million related to amounts that PSEG had collected on Power's behalf.

      PSEG and Energy Holdings

      As of June 30, 2006 and December 31, 2005, Energy Holdings had net receivables from PSEG of approximately $2 million and $1 million, respectively, primarily for interest due on the demand note receivable from PSEG.

      Energy Holdings and PSE&G

      As of June 30, 2006 and December 31, 2005, Energy Holdings had a receivable of approximately $2 million and $3 million, respectively, related to efficiency incentive initiatives performed for PSE&G's customers. Energy Holdings recorded revenues for such services of approximately $3 million and $6 million for the quarters ended June 30, 2006 and 2005, respectively, and approximately $7 million and $11 million for the six months ended June 30, 2006 and 2005, respectively.

Note 14. Guarantees of Debt

Power

      Each series of Power's Senior Notes and Pollution Control Notes is 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 June 30, 2006
Revenues	$	—		$	1,395		$	37		$	(297	)	$	1,135
Operating Expenses		1			1,239			38			(299	)		979
Operating (Loss) Income		(1	)		156			(1	)		2			156
Equity Earnings (Losses) of Subsidiaries		85			(12	)		—			(73	)		—
Other Income		42			44			1			(53	)		34
Other Deductions		—			(13	)		(1	)		—			(14	)
Interest Expense		(54	)		(24	)		(19	)		53			(44	)
Income Taxes		5			(67	)		8			(1	)		(55	)
Net Income (Loss)	$	77		$	84		$	(12	)	$	(72	)	$	77

54

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated Total
	(millions)
For the Quarter ended June 30, 2005
Revenues	$	—		$	1,278		$	37		$	(255	)	$	1,060
Operating Expenses		—			1,182			28			(255	)		955
Operating Income		—			96			9			—			105
Equity (Losses) Earnings of Subsidiaries		(127	)		(182	)		—			309			—
Other Income		36			30			1			(37	)		30
Other Deductions		—			(12	)		—			—			(12	)
Interest Expense		(38	)		(17	)		(6	)		35			(26	)
Income Taxes		2			(41	)		—			(2	)		(41	)
Loss on Discontinued Operations, Including Loss on Disposal, net of Tax Benefit		—			—			(183	)		—			(183	)
Net (Loss) Income	$	(127	)	$	(126	)	$	(179	)	$	305		$	(127	)
For the Six Months ended June 30, 2006
Revenues	$	—		$	3,589		$	70		$	(557	)	$	3,102
Operating Expenses		1			3,223			71			(559	)		2,736
Operating (Loss) Income		(1	)		366			(1	)		2			366
Equity Earnings (Losses) of Subsidiaries		198			(23	)		—			(175	)		—
Other Income		82			89			1			(97	)		75
Other Deductions		—			(32	)		(1	)		—			(33	)
Interest Expense		(97	)		(46	)		(38	)		97			(84	)
Income Taxes		7			(156	)		15			(1	)		(135	)
Net Income (Loss)	$	189		$	198		$	(24	)	$	(174	)	$	189
For the Six Months ended June 30, 2005
Revenues	$	—		$	3,227		$	71		$	(508	)	$	2,790
Operating Expenses		—			2,935			54			(507	)		2,482
Operating Income		—			292			17			(1	)		308
Equity (Losses) Earnings of Subsidiaries		(19	)		(191	)		—			210			—
Other Income		67			61			1			(68	)		61
Other Deductions		—			(20	)		—			—			(20	)
Interest Expense		(70	)		(34	)		(17	)		67			(54	)
Income Taxes		3			(126	)		1			(2	)		(124	)
Loss on Discontinued Operations, Including Loss on Disposal, net of Tax Benefit		—			—			(190	)		—			(190	)
Net Income (Loss)	$	(19	)	$	(18	)	$	(188	)	$	206		$	(19	)
For the Six Months ended June 30, 2006
Net Cash Provided By (Used In) Operating Activities	$	1,841		$	(767	)	$	(7	)	$	(346	)	$	721
Net Cash (Used In) Provided By Investing Activities	$	(1,341	)	$	747		$	7		$	420		$	(167	)
Net Cash (Used In) Provided By Financing Activities	$	(500	)	$	17		$	—		$	(74	)	$	(557	)

55

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated Total
	(millions)
For the Six Months ended June 30, 2005
Net Cash (Used In) Provided By Operating Activities	$	(1,306	)	$	238		$	1,103		$	381		$	416
Net Cash (Used In) Provided By Investing Activities	$	208		$	42		$	(48	)	$	(510	)	$	(308	)
Net Cash (Used In) Provided By Financing Activities	$	1,100		$	(273	)	$	(1,054	)	$	129		$	(98	)
As of June 30, 2006
Current Assets	$	3,539		$	3,143		$	258		$	(5,199	)	$	1,741
Property, Plant and Equipment, net		151			3,329			1,472			—			4,952
Investment in Subsidiaries		3,883			430			—			(4,313	)		—
Noncurrent Assets		199			1,494			16			(267	)		1,442
Total Assets	$	7,772		$	8,396		$	1,746		$	(9,779	)	$	8,135
Current Liabilities	$	1,672		$	3,508		$	1,177		$	(5,197	)	$	1,160
Noncurrent Liabilities		77			1,043			101			(268	)		953
Long-Term Debt		2,817			—			—			—			2,817
Member's Equity		3,206			3,845			468			(4,314	)		3,205
Total Liabilities and Member's Equity	$	7,772		$	8,396		$	1,746		$	(9,779	)	$	8,135
As of December 31, 2005
Current Assets	$	2,584		$	2,616		$	251		$	(2,876	)	$	2,575
Property, Plant and Equipment, net		143			3,271			1,466			—			4,880
Investment in Subsidiaries		3,507			453			—			(3,960	)		—
Noncurrent Assets		179			1,609			17			(315	)		1,490
Total Assets	$	6,413		$	7,949		$	1,734		$	(7,151	)	$	8,945
Current Liabilities	$	695		$	3,213		$	1,146		$	(2,877	)	$	2,177
Noncurrent Liabilities		63			1,268			96			(313	)		1,114
Long-Term Debt		2,817			—			—			—			2,817
Member's Equity		2,838			3,468			492			(3,961	)		2,837
Total Liabilities and Member's Equity	$	6,413		$	7,949		$	1,734		$	(7,151	)	$	8,945

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

      Following are the significant changes in or additions to information reported in the 2005 Annual Report on Form 10-K affecting the consolidated financial condition and the results of operations. This discussion refers to the Condensed Consolidated Financial Statements (Statements) and the related Notes to Condensed Consolidated Financial Statements (Notes) and should be read in conjunction with such Statements and Notes.

      This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), and PSEG Energy Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no representations as to any other company.

PENDING MERGER

PSEG, PSE&G, Power and Energy Holdings

      On December 20, 2004, PSEG entered into an agreement and plan of merger (Merger Agreement) with Exelon Corporation (Exelon), a public utility holding company headquartered in Chicago, Illinois, whereby PSEG will be merged with and into Exelon (Merger). Under the terms of the Merger Agreement, upon closing of the Merger, each share of PSEG Common Stock will be converted into 1.225 shares of Exelon Common Stock.

      The Merger Agreement has been unanimously approved by both companies' Boards of Directors. On July 19, 2005, shareholders of PSEG voted to approve the Merger and on July 22, 2005, shareholders of Exelon voted to approve the issuance of common shares to PSEG shareholders to effect the Merger.

      PSEG and Exelon have obtained all regulatory approvals from the principal governmental authorities involved to complete the Merger, except the New Jersey Board of Public Utilities (BPU).

      On June 1, 2006, the Nuclear Regulatory Commission approved the Merger.

      On June 22, 2006, Exelon and PSEG reached an agreement with the U.S. Department of Justice (DOJ), which resolved all competition issues reviewed by the DOJ in connection with the Merger. The terms of the DOJ agreement require the merged company to enter into agreements within 150 days after the Merger closes to sell the following six fossil fuel-fired electric generating stations with a total capacity of approximately 5,600 megawatts (MW) and gives the DOJ approval rights over the buyers to assure a competitive market after the divestiture:

Owned by PSEG
•	Linden, a 1,544 MW combined cycle natural gas and peaking (gas/oil) facility in Linden, New Jersey
•	Mercer, a 777 MW coal-and natural gas/oil-fired facility in Hamilton, New Jersey
•	Hudson, a 991 MW coal-and natural gas-fired facility in Woodbridge, New Jersey
•	Sewaren Units 1-4, a 452 MW natural gas/oil steam facility in Woodbridge, New Jersey
Owned by Exelon
•	Eddystone, a 1,408 MW coal-fired, mid-merit (oil/gas) and peaking (oil) facility in Eddystone, Pennsylvania
•	Cromby, a 345 MW coal-and natural gas/oil-fired facility in Phoenixville, Pennsylvania

      Also under the terms of the DOJ agreement, for a period of 10 years following the Merger, the merged company will be required to obtain DOJ's prior approval before acquiring or obtaining control of any existing power plants in the mid-Atlantic region. The proposed settlement and the DOJ's competitive impact statement are subject to public written comment for a period of 60 days and approval of the U.S. District Court, but closing of the Merger is not contingent upon such approval.

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      The fossil power plant divestiture required by the settlement with the DOJ will satisfy the requirements imposed by the Federal Energy Regulatory Commission (FERC) in its June 2005 order approving the Merger to divest fossil generation. The virtual nuclear divestiture approved by FERC continues to be an obligation of the merged company, even though it is not required by the DOJ settlement. The divestitures will be required only if the Merger closes.

      In New Jersey, the BPU issued an order on June 20, 2005, requiring Exelon and PSEG to prove that positive benefits flow to PSE&G's customers and the State of New Jersey as a result of the Merger, and that, at a minimum, there would be no adverse impact to competition, employees or reliability due to the Merger. Exelon and PSE&G are negotiating with the BPU Staff and other interested parties in an effort to reach a settlement of the Merger proceeding. Exelon and PSE&G recently made a materially enhanced settlement offer in the ongoing discussions, which they believe provides substantial positive benefits to customers and the State of New Jersey. The comprehensive offer provides cash to be used for a variety of customer and state benefits, primarily immediate rate reductions, rate concessions and other terms that are significantly greater than originally offered. As a result of this offer, PSE&G's earnings and cash flow would be materially reduced in the near term. PSEG and Exelon have also indicated that it is essential to reach a settlement promptly in order to complete the transaction. If a settlement is reached, it would need to be reviewed by the Administrative Law Judge (ALJ) and would need to be approved by the BPU. Although PSEG believes that this process can be completed in time to allow the merger to close in the third quarter of 2006, there is currently no established timetable for BPU action on the merger. As a result, it is possible that the closing could slip into the fourth quarter.

      The regulatory and political developments in Illinois pertaining to Exelon's rates and operations could also have an effect on the timing or closing conditions of the Merger.

      The final decision on whether to proceed with the Merger will rest with the Boards of both PSEG and Exelon after the terms and conditions of all regulatory requirements are known. The Merger Agreement provides that if the Merger was not consummated by June 20, 2006, either party can terminate the Merger Agreement without penalty. Neither Exelon nor PSEG has taken any action to terminate the Merger Agreement or extend the June 20, 2006 date in the Merger Agreement.

      Although PSEG and Exelon believe that the expectations as to timing for the closing of the Merger described above are reasonable, no assurances can be given as to the timing of the receipt of the BPU approval, that the approval will be received or that potential conditions required by the BPU will be acceptable to the parties or not have materially adverse conditions.

      PSEG is committed to maintaining a viable stand-alone business strategy in the event the Merger does not close. In the event that the Merger Agreement is terminated prior to closing, Management believes PSEG will continue to operate successfully on a stand-alone basis; however, inability to close the Merger could have an adverse impact on PSEG's stock price, PSEG's, PSE&G's and Power's credit ratings and the markets for their respective securities and could materially and adversely impact the financial condition, results of operations and cash flows of PSEG, PSE&G and Power. As a condition of maintaining existing credit ratings, it could be necessary for PSEG, PSE&G and Power to reduce debt and/or obtain additional equity. It is not possible to predict whether the market prices for PSEG common stock may be adversely affected by the dilutive effect of any such additional equity. It is also not possible to predict the impact on any of the securities of PSEG, PSE&G, Power and Energy Holdings of investor perception of the respective near-term prospects of those companies, including Power's ability to maintain the current level of nuclear operating performance if PSEG is unable to extend the current Nuclear Operating Services Contract with Exelon (see Note 5. Commitments and Contingent Liabilities), and the effect on operations of PSEG's current significantly reduced staffing.

OVERVIEW OF 2006 AND FUTURE OUTLOOK

PSEG

      PSEG's business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C. (Resources). The following is a discussion of 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 the first half of 2006 and expectations for the full year 2006 and beyond.

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      For the six months ended June 30, 2006, PSEG had Net Income of $412 million, or $1.64 per share, discussed below in Results of Operations. Included in Net Income is an after-tax gain of $228 million, or $0.90 per share, related to the sale of two generating stations in Poland, which is included in Income from Discontinued Operations and an after-tax loss of approximately $177 million, or $0.70 per share, related to the sale of Rio Grande Energia S.A. (RGE), an electric distribution company in Brazil. The loss at RGE primarily related to devaluation of the Brazilian Real subsequent to Global's acquisition of its interests in RGE in 1997. Also included in Net Income for the six months ended June 30, 2006 are Merger-related costs of approximately $8 million, after-tax, or $0.03 per share. In order to provide a more consistent and comparable measure of the performance of its businesses to help shareholders understand performance trends, earnings projections for PSEG and its subsidiaries consist of projected Income from Continuing Operations, excluding impacts from asset sales and Merger-related costs and do not contemplate any potential impacts from mark-to-market (MTM) accounting. Excluding such items, PSEG continues to project earnings for 2006 to range from $3.45 to $3.75 per share, although the range of expected earnings from each of PSE&G, Power and Energy Holdings has been revised from earlier announced projections. PSE&G's guidance has decreased due to the prolonged lack of rate relief; Power's guidance has increased due to improved operations and stronger energy markets and Energy Holdings' guidance has increased due to a strong Texas market. The projections for 2006 also include $60 million to $70 million of expenses at the PSEG parent level, primarily for financing costs. In addition, PSEG anticipates earnings per share growth to be in excess of 10% per year for 2007 and 2008.

      PSEG expects operating cash flows in 2006 and beyond to be sufficient to meet capital needs and dividend requirements and may employ any excess cash to reduce debt, invest in its businesses, increase dividends or, in the longer term, repurchase shares. On July 18, 2006, PSEG's Board of Directors approved a common stock dividend of $0.57 per share for the third quarter of 2006, reflecting an indicated annual dividend rate of $2.28 per share.

      Several key factors that will drive PSEG's future success are energy, capacity and fuel prices, performance of Power's generating facilities, PSE&G's ability to maintain a reasonable rate of return under its regulated rate structure and the stability of international economies for Energy Holdings.

PSE&G

      PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the BPU for its distribution operations and by the FERC for its electric transmission and wholesale sales operations. Consequently, PSE&G's earnings are largely determined by the regulation of its rates by those agencies.

      Commodity costs continue to put upward pressure on customer charges and have contributed to flat electric delivery sales and a decline in year-over-year gas delivery sales. On June 1, 2006, new electric Basic Generation Service (BGS)-Fixed Price (FP) rates went into effect and residential customers' bills are expected to increase by approximately 14%. While gas prices have stabilized, the current cost to a residential Basic Gas Supply Service (BGSS) customer is approximately 42% higher than a year ago. The 1% increase in the New Jersey sales tax on July 15, 2006 will also increase customer charges. Since sales tax and commodity price increases are passed through to customers, they do not increase PSE&G's earnings but they can have a negative impact on PSE&G's earnings if they result in reduced customer demand.

      On September 30, 2005, PSE&G filed a petition with the BPU seeking a $133 million increase in annual gas base rates, an overall 3.78% increase. PSE&G expects any rate relief from this filing to begin late in 2006 or early in 2007. The filing was based on a test year that ended nine months ago. Even if the increase were granted in full, PSE&G would not achieve the requested 11% return on equity due to sales declines and expense changes.

      PSE&G also has pending a request for a $64 million electric rate increase resulting from the expiration of a depreciation rate credit as of December 2005. PSE&G expects that final resolution of this case will likely be determined later in 2006.

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      Action on PSE&G's recent filings, including the excess depreciation rate credit and the gas base rate case, has been subject to ongoing delays. Until the Merger is resolved with the BPU, final resolution of PSE&G's rate requests is not expected.

      For the six months ended June 30, 2006, PSE&G had Net Income of $112 million. As a result of the substantial decline in earnings at PSE&G as compared to 2005 and the continued delay in decisions for the current gas base rate case and the elimination of the $64 million electric depreciation rate credit (approximately $68 million based on current sales volumes), PSE&G has lowered its earnings guidance from a range of $315 million to $335 million to a range of $250 million to $270 million in 2006. As disclosed previously, these amounts exclude any Merger-related costs.

      The risks to PSE&G's business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically the BPU and FERC. In 2006 and beyond, PSE&G's success will depend, in part, on its ability to maintain a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels and continued recovery, with an adequate return, of the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution system. Since PSE&G earns no margin on the commodity portion of its electric and gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G.

Power

      Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana. Power's principal operating subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Through its subsidiaries, Power seeks to balance its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear operations and pursue modest growth based on market conditions. Changes in the operation of Power's generating facilities, fuel and capacity prices, expected contract prices, capacity factors or other assumptions could materially affect its ability to meet earnings targets and/or liquidity requirements. In addition to the electric generation business described above, Power's revenues include gas supply sales under the BGSS contract with PSE&G.

      As a merchant generator, Power's profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, the prices of commodities, such as electricity, gas, coal and emissions, as well as the availability of Power's diverse fleet of generation units to produce these products, can have a material effect on Power's profitability.

      Power seeks to mitigate volatility in its results by contracting in advance for a significant portion of its anticipated electric output and fuel needs. Power believes this contracting strategy increases stability of earnings and cash flow. By keeping some portion of its output uncontracted, Power is able to retain some ability to take advantage of market changes as well as provide some protection in the event of unexpected generation outages.

      In a changing market environment, this hedging strategy may cause Power's realized prices to be materially different than current market prices. At the present time, a significant portion of Power's existing contractual obligations, entered into during lower-priced periods, resulted in lower margins than would have been the case if no or little hedging activity had been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins in excess of those implied by the then current market.

      For Power's BGSS contracts, commodity costs are passed on to residential customers. Any differences from the BGSS contract prices are deferred by PSE&G for future recovery. For commercial and industrial (C&I) customers, a tariff structure is applied that is adjusted monthly based on the current New York Mercantile Exchange (NYMEX) prices. During the first half of 2006, market prices for natural gas declined from the historically high price levels experienced in the second half of 2005

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while the cost of gas in inventory was relatively stable, which reduced Power's margins as compared to 2005.

      For the six months ended June 30, 2006, Power had Net Income of $189 million. Power has raised its earnings guidance from a range of $475 million to $525 million to a range of $500 million to $550 million for 2006, reflecting improved results and anticipated continued strong operating performance of its nuclear and fossil stations and attractive contracting opportunities in current energy markets. The guidance range does not include Merger-related costs.

      A key factor in Power's ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to satisfy its obligations. Power's ability to benefit from any future increases in market prices will depend, to a large extent, on efficient power plant operations, especially for its low-cost nuclear and coal-fired facilities. In addition, since forward prices are constantly changing, there is no assurance that Power will be able to contract its output at attractive prices. While these increases 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.

Energy Holdings

      Energy Holdings' operations are principally conducted through its subsidiaries: Global, which has invested in international, rate-regulated distribution companies and domestic and international merchant generation companies, and Resources, which primarily invests in energy-related leveraged leases.

      In the first half of 2006, Energy Holdings successfully closed on two major transactions as part of its strategy to opportunistically monetize assets that no longer have a strategic fit. In May 2006, Global completed the sale of its ownership interests in two generating facilities in Poland for $476 million, recording an after-tax gain of $228 million, which is included in Income from Discontinued Operations. In June 2006, Global completed the sale of its 32% interest in RGE for $185 million, resulting in an after-tax loss of $177 million. Together, Global received gross sales proceeds of $654 million, or approximately $612 million after taxes, and recorded a net after-tax gain of approximately $51 million. Energy Holdings is evaluating the use of the proceeds, including potential debt redemption and loans and/or dividends to PSEG. As part of this evaluation, Energy Holdings and PSEG will review the liquidity needs of their respective businesses in balance with maintaining Energy Holdings' credit metrics.

      In May 2006, Global also entered into an agreement to sell its 46% ownership interest in Dhofar Power Company S.A.O.C. (Dhofar Power), a generation facility and distribution system in Oman, for proceeds of approximately $33 million and an immaterial after-tax gain. The sale of Dhofar Power, which is contingent upon attaining consents from Dhofar Power's lenders and no objections from the government in Oman, is expected to be completed later in 2006. In May 2006, Global also converted its loans to Prisma 2000 S.p.A. (Prisma) to equity, thereby increasing its ownership interest from 50% to 85% and obtaining operating control of the project. Prisma is a joint venture that operates several biomass generation plants in Italy. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for further discussion.

      For the six months ended June 30, 2006, Energy Holdings had Net Income of $150 million, which includes the net gain of $51 million related to the asset sales, discussed above. Energy Holdings' earnings guidance for 2006, which excludes the $51 million net gain, has been increased from a range of $155 million to $175 million to a range of $185 million to $205 million. The increase was largely driven by the strong Texas market where Global operates two gas-fired, combined cycle plants totaling 2,000 MW through its investment in Texas Independent Energy (TIE). Spark margins, which increased substantially last year compared to previous years, have continued to remain strong and the plants' high availability factors have enabled TIE to benefit from these high margins. Stable earnings

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from Global's South American distribution companies also continue to be a sustainable platform for Energy Holdings' earnings.

      Global

      Although Global continues to produce significant earnings and operating cash flow, the returns on several of the investments in its international portfolio have not been commensurate with the level of risk associated with international investments in developing energy markets. As a result, since 2003, Energy Holdings has refocused its strategy from one of growth to one that places emphasis on increasing the efficiency and returns of its existing assets.

      Global's success will depend, in part, upon its ability to mitigate risks of its international strategy. The economic and political conditions in certain countries where Global has investments present risks that may be different or more significant than those found in the U.S., including: renegotiation or nullification of existing contracts, changes in law or tax policy, interruption of business, nationalization, expropriation, war and other factors. Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In some countries in which Global has interests, economic and monetary conditions and other factors could affect its ability to convert its cash distributions to U.S. Dollars or other freely-convertible currencies. Furthermore, the central bank of any such country may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to limit distributions to foreign investors.

      Resources

      Resources has primarily invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments. Resources' ability to realize tax benefits associated with its leveraged lease investments is dependent upon taxable income generated by its affiliates. Resources' earnings and cash flows are expected to decrease in the future as the investment portfolio matures. Resources faces risks related to potential changes in the current accounting and tax treatment of certain investments in leveraged leases. Resources also faces risks with regard to the creditworthiness of its counterparties, specifically certain lessees that collectively comprise a substantial portion of Resources' investment portfolio.

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RESULTS OF OPERATIONS

      The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and six months ended June 30, 2006 and 2005 are presented below:

	Earnings (Losses)
	Quarters Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(Millions)
PSE&G	$	34		$	49		$	112		$	167
Power		77			56			189			171
Energy Holdings:
Global		(122	)		15			(113	)		60
Resources		19			(1	)		38			22
Other (A)		(2	)		(2	)		(2	)		(3	)
Total Energy Holdings		(105	)		12			(77	)		79
Other (B)		(20	)		(26	)		(39	)		(46	)
PSEG (Loss) Income from Continuing Operations		(14	)		91			185			371
Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal (C)		223			(173	)		227			(168	)
PSEG Net Income (Loss)	$	209		$	(82	)	$	412		$	203

	Contribution to PSEG Earnings Per Share (Diluted) (D)
	Quarters Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
PSE&G	$	0.14		$	0.20		$	0.45		$	0.69
Power		0.31			0.23			0.75			0.70
Energy Holdings:
Global		(0.48	)		0.06			(0.44	)		0.25
Resources		0.07			—			0.15			0.09
Other (A)		(0.01	)		(0.01	)		(0.01	)		(0.01	)
Total Energy Holdings		(0.42	)		0.05			(0.30	)		0.33
Other (B)		(0.08	)		(0.10	)		(0.16	)		(0.19	)
PSEG (Loss) Income from Continuing Operations		(0.05	)		0.38			0.74			1.53
Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal (C)		0.88			(0.72	)		0.90			(0.69	)
PSEG Net Income (Loss)	$	0.83		$	(0.34	)	$	1.64		$	0.84

(A)	Other activities include non-segment amounts of Energy Holdings and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings.
(B)	Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include preferred securities dividends/preference unit distributions for PSE&G in 2006 and 2005 and Energy Holdings in 2005, interest on certain financing transactions, Merger expenses and certain other administrative and general expenses at PSEG (as parent company).
(C)	The Gain on Disposal of Skawina and Elcho is included in 2006 and their Discontinued Operations are included in 2005 and 2006. The Loss on Disposal and Discontinued Operations of Waterford, an electric generation facility in Waterford, Ohio that was sold in September 2005, are included in 2005. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes.

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(D) Earnings Per Share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct interest in PSEG's assets and liabilities as a whole.

      The $105 million or $0.43 per share decrease in Income from Continuing Operations for the quarter was due to decreases of $117 million and $15 million at Energy Holdings and PSE&G, respectively, partially offset by an increase of $21 million at Power and an improvement of $6 million at PSEG (as parent company), primarily due to decreased merger costs and lower Interest Expense. The decrease at Energy Holdings was primarily due to the $177 million after-tax loss on the sale of RGE in June 2006, which was partially offset by improved operations in Texas and the absence of a $15 million after-tax write-off of Resources' investment in an aircraft lease to United Airlines in June 2005. The decrease at PSE&G was mainly due to the full amortization of the excess depreciation reserve as of December 31, 2005. Also decreasing PSE&G's earnings were reduced demand due to higher pricing and weather. The increase at Power was due principally to higher realized prices from re-contracting its generation portfolio and spot market sales combined with improved nuclear performance. Power's increases were partially offset by increased costs due to the commencement of commercial operations at Linden and the Bethlehem Energy Center (BEC) in May 2006 and July 2005, respectively, and higher Operation and Maintenance costs.

      The $186 million or $0.79 per share decrease in Income from Continuing Operations for the six months was due to decreases of $156 million and $55 million at Energy Holdings and PSE&G, respectively, partially offset by an increase of $18 million at Power and an improvement of $7 million at PSEG (as parent company). These changes were primarily attributable to the same reasons discussed above for the quarter. Also contributing to the decrease at Energy Holdings for the six months ended June 30, 2006, as compared to the same period in 2005 was the absence of $37 million of income received in the first quarter of 2005 from withdrawal from the Eagle Point Cogeneration Partnership (EPCP). In addition to the increased costs related to Linden and BEC and higher Operations and Maintenance costs, discussed above, Power's increased earnings for the six months were partially offset by reduced margins on BGSS, primarily in the first quarter of 2006 as compared to 2005, as market prices for natural gas declined from the historically high price levels experienced in the second half of 2005 while the cost of gas in inventory was relatively stable.

PSEG

	For the Quarters Ended June 30,												For the Six Months Ended June 30,
	2006			2005			Increase (Decrease)			%			2006			2005			Increase (Decrease)			%
				(Millions)												(Millions)
Operating Revenues	$	2,606		$	2,377		$	229			10		$	6,124		$	5,616		$	508			9
Energy Costs	$	1,387		$	1,316		$	71			5		$	3,591		$	3,165		$	426			13
Operation and Maintenance	$	583		$	553		$	30			5		$	1,164		$	1,124		$	40			4
Write-down of Project Investment	$	263		$	—		$	263			N/A		$	263		$	—		$	263			N/A
Depreciation and Amortization	$	207		$	174		$	33			19		$	411		$	358		$	53			15
Income from Equity Method Investments	$	30		$	29		$	1			3		$	63		$	60		$	3			5
Other Income	$	52		$	34		$	18			53		$	106		$	77		$	29			38
Other Deductions	$	(20	)	$	(21	)	$	(1	)		(5	)	$	(51	)	$	(35	)	$	16			46
Interest Expense	$	(207	)	$	(198	)	$	9			5		$	(408	)	$	(398	)	$	10			3
Income Tax Expense	$	(7	)	$	(58	)	$	(51	)		(88	)	$	(150	)	$	(229	)	$	(79	)		(34	)
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax	$	223		$	(173	)	$	396			N/A		$	227		$	(168	)	$	395			N/A

      PSEG's results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power 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 13. Related-Party Transactions of the Notes. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for PSE&G, Power and Energy Holdings that follow.

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PSE&G

	For the Quarters Ended June 30,												For the Six Months Ended June 30,
	2006			2005			Increase (Decrease)			%			2006			2005			Increase (Decrease)			%
				(Millions)												(Millions)
Operating Revenues	$	1,534		$	1,441		$	93			6		$	3,884		$	3,625		$	259			7
Energy Costs	$	945		$	853		$	92			11		$	2,576		$	2,277		$	299			13
Operation and Maintenance	$	276		$	268		$	8			3		$	577		$	563		$	14			2
Depreciation and Amortization	$	150		$	128		$	22			17		$	302		$	263		$	39			15
Other Income	$	8		$	2		$	6			N/A		$	12		$	4		$	8			N/A
Other Deductions	$	(1	)	$	—		$	1			N/A		$	(2	)	$	(1	)	$	1			100
Interest Expense	$	(83	)	$	(86	)	$	(3	)		(3	)	$	(168	)	$	(170	)	$	(2	)		(1	)
Income Tax Expense	$	(26	)	$	(31	)	$	(5	)		(16	)	$	(91	)	$	(117	)	$	(26	)		(22	)

      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. The $93 million increase for the quarter ended June 30, 2006, as compared to the same period in 2005, was due to an increase of $90 million in commodity revenues, described below, and $3 million in delivery revenues. The $259 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was due to increases of $268 million in commodity revenues, described below, and $1 million in other operating revenues, primarily related to appliance service contracts, partially offset by a $10 million decrease in delivery revenues.

      Commodity

      PSE&G makes no margin on commodity sales as the costs are passed through to customers. The difference between gas costs and the amount provided by customers in revenues is deferred and collected from or returned to customers in future periods. Total commodity volumes and revenues are subject to market forces. Gas commodity prices fluctuate monthly for 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. Electric commodity prices are set at the annual BGS auctions.

      The $90 million increase in commodity revenues for the quarter ended June 30, 2006, as compared to the same period in 2005, was due to increases of $81 million in electric commodity revenues, primarily due to $67 million in higher BGS and Non-Utility Generation (NUG) prices and $14 million in higher BGS volumes due to sales growth and higher NUG volumes due to operations. Also contributing to the increase was $9 million in gas commodity revenues, primarily due to $55 million in higher BGSS prices offset by $34 million in lower volumes due to weather and a decrease of $12 million due to the expiration of the Third Party Shopping Incentive in July 2005. There was a corresponding $12 million increase in delivery revenues.

      The $268 million increase in commodity revenues for the six months ended June 30, 2006, as compared to the same period in 2005, was due to increases of $136 million in gas commodity revenues, primarily due to $343 million in higher BGSS prices offset by $149 million in lower volumes due to weather and a decrease of $58 million due to the expiration of the Third Party Shopping Incentive in July 2005. There was a corresponding $58 million increase in delivery revenues. Also contributing to the increase was $132 million in electric commodity revenues, primarily due to $111 million in higher BGS and NUG prices and $21 million in higher BGS volumes due to customer shopping and higher NUG volumes due to operations.

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      Delivery

      The $3 million increase in delivery revenues for the quarter ended June 30, 2006, as compared to the same period in 2005, was due to a $2 million increase in gas revenues and a $1 million increase in electric revenues. The $2 million increase in gas delivery revenues was due primarily to $13 million in increased prices, $12 million of which was due to the expiration of the Third Party Shopping Incentive in July 2005, described above in commodity revenues. This increase was offset by $9 million in lower volumes due to weather and $2 million due to impacts of price elasticity. The $1 million increase in electric revenues was due to $4 million in increased volumes due to weather offset by decreased prices of $2 million due to lower demand revenues and $1 million due to lower securitization tariff rates.

      The $10 million decrease in delivery revenues for the six months ended June 30, 2006, as compared to the same period in 2005, was due to a $9 million decrease in electric revenues and a $1 million decrease in gas revenues. The $9 million decrease in electric revenues was due to decreased prices of $4 million due to lower demand revenues and $2 million due to lower securitization tariff rates and $3 million in lower volumes due to weather. The $1 million decrease in gas delivery revenues was due primarily to $56 million in lower volumes due to weather and $8 million due to impacts of price elasticity. This was offset by $63 million in increased prices, primarily due to the expiration of the Third Party Shopping Incentive in July 2005, described above in commodity revenues.

      Operating Expenses

      Energy Costs

      The $92 million increase for the quarter ended June 30, 2006, as compared to the same period in 2005, was comprised of increases of $66 million in electric costs and $26 million in gas costs. The electric increase was due to $47 million in higher prices for BGS and NUG purchases and $19 million in higher BGS and NUG volumes. The increase in gas costs was caused by a $61 million or 10% increase in gas prices offset by a $35 million decrease in sales volumes due primarily to weather.

      The $299 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was comprised of increases of $194 million in gas costs and $105 million in electric costs. The increase in gas costs was caused by a $352 million or 28% increase in gas prices offset by an $8 million decrease due to the expiration of the Gas Cost Underrecovery Adjustment (GCUA) clause in January 2005, and a $150 million decrease in sales volumes due primarily to weather. The electric increase was due to $73 million in higher prices for BGS and NUG purchases and $32 million in higher NUG volumes.

      Operation and Maintenance

      The $8 million increase for the quarter ended June 30, 2006, as compared to the same period in 2005, was due primarily to $4 million in increased labor and fringe benefits due to increased wages and Other Postretirement Benefits (OPEB) costs and $2 million in increased bad debt expense.

      The $14 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was due primarily to $8 million in increased labor and fringe benefits due to increased wages and OPEB costs and $6 million in increased bad debt expense.

      Depreciation and Amortization

      The $22 million increase for the quarter ended June 30, 2006, as compared to the same period in 2005, was due primarily to a $23 million increase in the amortization of regulatory assets offset by a $1 million decrease in software amortization.

      The $39 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was due primarily to a $43 million increase in the amortization of regulatory assets. This was offset by a $3 million decrease in software amortization and a $1 million decrease in the amortization of the Remediation Adjustment Clause (RAC).

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      Other Income

      Other Income increased $6 million for the quarter ended June 30, 2006, as compared to the same period in 2005, primarily due to $5 million in an income tax gross-up on contributions in aid of construction (CIAC). CIAC is taxable and PSE&G recognizes the gross-up as income when collected. Also contributing to the increase was $1 million in increased income on investments.

      Other Income increased $8 million for the six months ended June 30, 2006, as compared to the same period in 2005, primarily due to $5 million in an income tax gross-up on CIAC. Also contributing to the increase was $2 million in increased income on investments.

      Income Taxes

      Income Taxes decreased $5 million for the quarter and $26 million for the six months ended June 30, 2006, as compared to the same periods in 2005, primarily due to lower pre-tax income.

Power

	For the Quarters Ended June 30,												For the Six Months Ended June 30,
	2006			2005			Increase (Decrease)			%			2006			2005			Increase (Decrease)		%
				(Millions)												(Millions)
Operating Revenues	$	1,135		$	1,060		$	75			7		$	3,102		$	2,790		$	312		11
Energy Costs	$	675		$	688		$	(13	)		(2	)	$	2,162		$	1,958		$	204		10
Operation and Maintenance	$	264		$	235		$	29			12		$	499		$	462		$	37		8
Depreciation and Amortization	$	40		$	32		$	8			25		$	75		$	62		$	13		21
Other Income	$	34		$	30		$	4			13		$	75		$	61		$	14		23
Other Deductions	$	(14	)	$	(12	)	$	2			17		$	(33	)	$	(20	)	$	13		65
Interest Expense	$	(44	)	$	(26	)	$	18			69		$	(84	)	$	(54	)	$	30		56
Income Tax Expense	$	(55	)	$	(41	)	$	14			34		$	(135	)	$	(124	)	$	11		9
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit	$	—		$	(183	)	$	183			100		$	—		$	(190	)	$	190		100

      Operating Revenues

      The $75 million increase for the quarter ended June 30, 2006, as compared to the same period in 2005, was due to increases of $71 million in generation revenues and $11 million in trading revenues, partially offset by a decrease of $7 million in gas supply revenues.

      The $312 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was due to increases of $222 million in generation revenues, $77 million in gas supply revenues and $13 million in trading revenues.

      Generation

      The increase of $71 million and $222 million in generation revenues for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to higher sales volumes in the various power pools, supported by improved nuclear operations and the commencement of the commercial operations of Linden in May 2006 and BEC in July 2005, and higher prices. The increases were partially offset by a reduction in load being served under the BGS contracts and lower fees for ancillary services.

      Gas Supply

      Gas supply revenues decreased $7 million for the quarter ended June 30, 2006, as compared to the same period in 2005, principally due to lower demand under the BGSS contract, largely resulting from customer conservation and milder weather in 2006, substantially offset by higher prices for gas sales.

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      The $77 million increase in gas supply revenues for the six months ended June 30, 2006, as compared to the same period in 2005, was primarily due to higher gas prices under the BGSS contract and from sales to nonaffiliated commercial end-users for gas and pipeline capacity. Increased prices were partially offset by lower demand in 2006, largely due to customer conservation and a milder winter heating season.

      Trading

      The $11 million and $13 million increase in trading revenues for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to higher realized gains related to emissions credits.

      Operating Expenses

      Energy Costs

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

      Energy Costs decreased approximately $13 million for the quarter ended June 30, 2006, as compared to the same period in 2005, primarily due to lower generation costs, reflecting decreases of $36 million resulting from a reduction in the volume of purchases from the various power pools due to higher generation and lower pool prices and $33 million due to favorable pricing of fuel-related asset-backed transactions in 2006. These decreases were substantially offset by higher fossil fuel expenses, largely due to a higher volume of gas purchased to operate Linden and BEC.

      The $204 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was primarily due to $130 million from higher prices on a reduced volume of gas purchased to satisfy Power's BGSS obligations and $74 million from a higher volume of fossil fuel purchases to support generation by Linden and BEC.

      Operation and Maintenance

      Operation and Maintenance expense increased $29 million and $37 million for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, due to higher maintenance costs at certain of the fossil plants, the addition of costs in 2006 related to BEC and Linden and the absence of a $6 million real estate tax refund recognized in 2005. These increases were partially offset by reductions in labor costs in 2006 due to a reduction in personnel at the nuclear generating facilities and other Power locations and the absence of a $10 million restructuring charge incurred in 2005 related to Nuclear's workforce realignment plan.

      Depreciation and Amortization

      The $8 million and $13 million increase for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to Linden and BEC being placed into service.

      Other Income

      Other Income increased $4 million and $14 million for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, primarily due to increased realized gains and income related to the NDT Funds and higher interest on margin call deposits.

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      Other Deductions

      Other Deductions increased $2 million and $13 million for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, primarily due to increased realized losses and miscellaneous expenses related to the NDT Funds.

      Interest Expense

      Interest Expense increased $18 million and $30 million for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, due primarily to lower capitalized interest costs in 2006 related to commencement of operations of the BEC facility in July 2005 and the Linden facility in May 2006.

      Income Taxes

      Income Taxes increased $14 million for the quarter and $11 million for the six months ended June 30, 2006, as compared to the same periods in 2005, primarily due to higher pre-tax income.

      Loss from Discontinued Operations, including Loss on Disposal, net of tax

      On May 27, 2005, Power reached an agreement to sell its Waterford generation facility for approximately $220 million and recognized a loss on disposal of approximately $177 million for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell. The loss from the discontinued operating results of Waterford was $6 million and $13 million for the quarter and six months ended June 30, 2005, respectively. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information.

Energy Holdings

	For the Quarters Ended June 30,												For the Six Months Ended June 30,
	2006			2005			Increase (Decrease)			%			2006			2005			Increase (Decrease)			%
				(Millions)												(Millions)
Operating Revenues	$	367		$	270		$	97			36		$	679		$	583		$	96			16
Energy Costs	$	194		$	162		$	32			20		$	388		$	300		$	88			29
Operation and Maintenance	$	52		$	53		$	(1	)		(2	)	$	101		$	110		$	(9	)		(8	)
Write-down of Project Investments	$	263		$	—		$	263			N/A		$	263		$	—		$	263			N/A
Depreciation and Amortization	$	12		$	11		$	1			9		$	24		$	25		$	(1	)		(4	)
Income from Equity Method Investments	$	30		$	29		$	1			3		$	63		$	60		$	3			5
Other Income	$	13		$	3		$	10			N/A		$	23		$	13		$	10			77
Other Deductions	$	(5	)	$	(8	)	$	(3	)		(38	)	$	(15	)	$	(14	)	$	1			7
Interest Expense	$	(51	)	$	(54	)	$	(3	)		(6	)	$	(101	)	$	(112	)	$	(11	)		(10	)
Income Tax Benefit (Expense)	$	63		$	(1	)	$	64			N/A		$	51		$	(15	)	$	66			N/A
Income from Discontinued Operations, including Gain on Disposal, net of tax	$	223		$	10		$	213			N/A		$	227		$	22		$	205			N/A

      The variances in Operating Revenues, Energy Costs, Operation and Maintenance, Depreciation and Amortization and Income from Equity Method Investments were partially attributed to Global's sale of a 35% interest in Dhofar Power Company S.A.O.C. (Dhofar Power) through a public offering on the Omani Stock Exchange in April 2005, reducing its ownership interest to 46% and thus accounting for the investment under the equity method of accounting following the sale. The variances are also related to Global's increased ownership interest in Prisma from 50% to 85%, thus consolidating the entity effective May 2006. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes.

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      Operating Revenues

      The $97 million increase for the quarter ended June 30, 2006, as compared to the same period in 2005, was due to higher revenues at Global of $80 million, which was the net result of a $57 million increase at TIE due to an increase in the average price per megawatt hour, a $25 million increase at Sociedad Austral de Electricidad S.A. (SAESA) in Chile due to increased tariff prices and volume, a $2 million increase at Electroandes S.A. (Electroandes) due to higher energy sales and a $7 million increase due to the consolidation of Prisma, partially offset by the absence of a $3 million pre-tax gain recognized in 2005 related to sale of Global's 35% interest in Dhofar Power and a $5 million decrease related to the deconsolidation of Dhofar Power. Also contributing to the increase were higher revenues at Resources of $17 million primarily due to the absence of a $22 million pre-tax write-off of its leveraged lease investment with United Airlines recorded in 2005.

      The $96 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was due to higher revenues at Global of $93 million, which was the net result of a $102 million increase at TIE due to an increase in the average price per megawatt hour, a $40 million increase at SAESA due to increased tariffs and volume, a $4 million increase at Electroandes due to higher energy sales and a $7 million increase due to the consolidation of Prisma, partially offset by decreased revenues due to the absence of $37 million of income received in 2005 from withdrawal from EPCP, the absence of a $3 million pre-tax gain recognized in 2005 related to sale of Global's 35% interest in Dhofar Power and a $20 million decrease related to the deconsolidation of Dhofar Power, respectively. Also contributing to the increase were higher revenues at Resources of $3 million primarily due to the absence of a $22 million pre-tax write-off of its leveraged lease investment with United Airlines recorded in 2005 partially offset by the reduction in leveraged lease income.

      Operating Expenses

      Energy Costs

      The $32 million increase for the quarter ended June 30, 2006, as compared to the same period in 2005, was primarily due to a $14 million increase at TIE resulting from an increase in gas prices, a $19 million increase related to SAESA due to increased volume and increases in energy costs due to higher spot prices and a $3 million increase due to the consolidation of Prisma, partially offset by a $2 million decrease related to the deconsolidation of Dhofar Power.

      The $88 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was primarily due to a $61 million increase at TIE resulting from an increase in gas prices, a $29 million increase related to SAESA due to increased volume and increases in energy costs due to higher spot prices and a $3 million increase due to the consolidation of Prisma, partially offset by a $5 million decrease related to the deconsolidation of Dhofar Power.

      Operation and Maintenance

      The $9 million decrease for the six months ended June 30, 2006, as compared to the same period in 2005, was primarily due to a $16 million decrease at TIE resulting from a scheduled hot gas path inspection outage that occurred in the first quarter of 2005 and a $3 million decrease related to the deconsolidation of Dhofar Power, offset by an $8 million increase related to SAESA due to repairs of a gas turbine and other costs and a $1 million increase due to the consolidation of Prisma.

      Write-down of Project Investments

      The $263 million write-down of project investments relates to Global's sale of its 32% indirect ownership interest in RGE to its partner. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes.

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      Income from Equity Method Investments

      The $3 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was primarily due to stronger results from Global's investments in Hawaii (Kalaeloa) and California (GWF).

      Other Income

      The $10 million increase for the quarter ended June 30, 2006, as compared to the same period in 2005, was primarily due to an increase in interest and dividend income primarily related to an intercompany loan to PSEG.

      The $10 million increase for the six months ended June 30, 2006, as compared to the same period in 2005, was primarily due to foreign exchange gains.

      Other Deductions

      The $3 million decrease for the quarter ended June 30, 2006, as compared to the same period in 2005, was primarily due to foreign currency losses.

      Interest Expense

      The $3 million and $11 million decrease for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to a decrease in Energy Holdings' debt outstanding.

      Income Taxes

      The $64 million and $66 million net increase in income tax benefits for the quarter and six months ended June 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to the tax benefit recognized in 2006 related to the write-down of project investments due to Global's sale of its 32% indirect ownership interest in RGE.

      Income from Discontinued Operations, including Gain on Disposal, net of tax

      In May 2006, Global completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale resulted in an after-tax gain of $228 million. (Loss) Income from Discontinued Operations related to Elcho and Skawina for the quarters ended June 30, 2006 and 2005 was $(5) million and $10 million, respectively. (Loss) Income from Discontinued Operations related to Elcho and Skawina for the six months ended June 30, 2006 and 2005 was $(1) million and $22 million, respectively. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes 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, PSE&G, Power and Energy Holdings.

Operating Cash Flows

      PSEG

      For the six months ended June 30, 2006, PSEG's operating cash flow increased approximately $242 million from $563 million to $805 million, as compared to the same period in 2005, primarily due to net increases from its subsidiaries as discussed below.

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      PSE&G

      PSE&G's operating cash flow increased approximately $73 million from $56 million to $129 million for the six months ended June 30, 2006, as compared to the same period in 2005, primarily due to less funding for employee benefit plans and higher over recovery of gas costs.

      Power

      Power's operating cash flow increased approximately $305 million from $416 million to $721 million for the six months ended June 30, 2006, as compared to the same period in 2005, due to decreased margin requirements and a decrease in fuel inventory due to decreased commodity prices and a reduction in natural gas inventory following the winter heating season.

      Energy Holdings

      Energy Holdings' operating cash flow decreased approximately $134 million from $152 million to $18 million for the six months ended June 30, 2006, as compared to the same period in 2005, due primarily to the timing of tax payments and benefits associated with the sales of Elcho, Skawina and RGE and other matters. The proceeds from these sales are included in Investing Activities on the Statements of Cash Flows.

Common Stock Dividends

      PSEG

      Dividend payments on common stock for the quarters ended June 30, 2006 and 2005 were $0.57 and $0.56 per share, respectively, and totaled approximately $143 million and $133 million, respectively. Dividend payments on common stock for the six months ended June 30, 2006 and 2005 were $1.14 and $1.12 per share, respectively, and totaled approximately $286 million and $267 million, respectively. Future dividends declared will be dependent upon PSEG's future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. On July 18, 2006, PSEG's Board of Directors approved a common stock dividend of $0.57 per share for the third quarter of 2006, reflecting an indicated annual dividend rate of $2.28 per share.

Short-Term Liquidity

      PSEG, PSE&G, Power and Energy Holdings

      As of June 30, 2006, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $2.9 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted to availability and use to the specific companies as listed below.

Company	Expiration Date	Total Facility		Primary Purpose	Usage as of June 30, 2006			Available Liquidity as of June 30, 2006
	(Millions)
PSEG:
4-year Credit Facility	April 2008	$	450	CP Support/ Funding/Letters of Credit	$	50		$	400
5-year Credit Facility	May 2010	$	650	CP Support/ Funding/Letters of Credit	$	6	(D)	$	644
Bilateral Term Loan (A)	May 2007	$	100	Funding	$	100		$	—
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	29			N/A

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Company	Expiration Date	Total Facility		Primary Purpose	Usage as of June 30, 2006			Available Liquidity as of June 30, 2006
	(Millions)
PSE&G:
5-year Credit Facility	June 2009	$	600	CP Support/ Funding/Letters of Credit	$	362		$	238
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	29			N/A
PSEG and Power: (B)
3-year Credit Facility	April 2007	$	600	CP Support/ Funding/Letters of Credit	$	29	(D)	$	571
Bilateral Credit Facility	Oct 2006	$	100	Funding/Letters of Credit	$	—		$	100
Bilateral Credit Facility	Dec 2006	$	100	Funding/Letters of Credit	$	—		$	100
Bilateral Credit Facility	Dec 2006	$	150	Funding/Letters of Credit	$	28	(D)	$	122
Bilateral Credit Facility	July 2006 (E)	$	150	Funding/Letters of Credit	$	—		$	150
Bilateral Credit Facility	July 2006 (F)	$	100	Funding/Letters of Credit	$	6	(D)	$	94
Bilateral Credit Facility	Sept 2006 (G)	$	100	Funding/Letters of Credit	$	39	(D)	$	61
Bilateral Credit Facility	Dec 2006	$	50	Funding/Letters of Credit	$	20	(D)	$	30
Bilateral Credit Facility	Dec 2006	$	275	Letters of Credit	$	75	(D)	$	200
Power:
Bilateral Credit Facility	March 2010	$	100	Funding/Letters of Credit	$	58	(D)	$	42
Energy Holdings:
5-year Credit Facility (C)	June 2010	$	150	Funding/Letters of Credit	$	9	(D)	$	141

(A)	Renewed in May 2006.
(B)	PSEG/Power joint and several co-borrower facility.
(C)	Energy Holdings/Global/Resources joint and several co-borrower facility.
(D)	These amounts relate to letters of credit outstanding.
(E)	Renewed in July 2006 with new expiration of December 2006.
(F)	Renewed in July 2006 with new expiration of June 2007.
(G)	Terminated in July 2006.

      PSEG and PSE&G

      PSEG and PSE&G believe sufficient liquidity exists to fund their short-term cash needs.

      Power

      As of June 30, 2006, Power had borrowed $145 million from PSEG in the form of an intercompany loan.

      During the second quarter of 2006, Power's required margin postings decreased for sales contracts entered into in the normal course of business as commodity prices declined. 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. Power believes that it has sufficient liquidity to fund its short-term cash needs.

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      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. Power believes it has sufficient liquidity to meet any required posting of collateral resulting from a credit rating downgrade. See Note 5. Commitments and Contingent Liabilities of the Notes for further information.

      Energy Holdings

      Energy Holdings and its subsidiaries had $101 million in cash, including $10 million invested offshore as of June 30, 2006. In addition, as of June 30, 2006, Energy Holdings had loaned $708 million of excess cash to PSEG, including a $450 million term loan expiring September 30, 2006. For further information see Note 13. Related-Party Transactions of the Notes. Energy Holdings is evaluating the use of the proceeds from these sales, including potential debt redemption and loans and/or dividends to PSEG. As part of this evaluation, Energy Holdings and PSEG will review the liquidity needs of their respective businesses in balance with maintaining Energy Holdings' credit metrics.

External Financings

      PSEG

      During the six months ended June 30, 2006, PSEG issued approximately 523,000 shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Program for approximately $34 million.

      In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity investment in the trust.

      PSE&G

      On June 23, 2006, PSE&G repaid at maturity $174 million of its Floating Rate Series A First and Refunding Mortgage Bonds.

      On March 1, 2006, PSE&G repaid at maturity $148 million of its 6.75% Series UU First and Refunding Mortgage Bonds.

      In June 2006 and March 2006, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $35 million and $36 million, respectively, of its transition bonds.

      In June 2006, PSE&G Transition Funding II LLC (Transition Funding II) repaid approximately $3 million of its transition bonds.

      Power

      In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes.

      Energy Holdings

      In January 2006, Energy Holdings redeemed all $309 million of its 7.75% Senior Notes due in 2007.

      On February 17, 2006, the maturity of the Odessa–Ector Power Partners, L.P. (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above LIBOR. On September 29, 2006, an interest rate swap will take effect which will convert the floating LIBOR interest rate on approximately 80% of Odessa's debt to a fixed rate of 5.4275% through December 31, 2009.

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Debt Covenants

      PSEG, PSE&G, Power and Energy Holdings

      PSEG's, PSE&G's, Power's and Energy Holdings' respective credit agreements generally contain customary provisions under which the lenders can refuse to advance loans in the event of a material adverse change in the borrower's business or financial condition.

      As explained in more detail below, these credit agreements may also contain maximum debt to equity ratios, minimum cash flow tests 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, PSE&G, Power and Energy Holdings, 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 a financial performance or liquidity measure.

      PSEG

      Financial covenants contained in PSEG's credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization (including preferred securities outstanding) covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 70.0%. As of June 30, 2006, PSEG's ratio of debt to capitalization (as defined above) was 55.0%.

      PSE&G

      Financial covenants contained in PSE&G's credit facilities 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 at the end of any quarterly financial period, such ratio will not be more than 65.0%. As of June 30, 2006, PSE&G's ratio of long-term debt to total capitalization (as defined above) was 46.0%.

      In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding 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 June 30, 2006, PSE&G's Mortgage coverage ratio was 4.8 to 1 and the Mortgage would permit up to approximately $1.9 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements.

      PSEG and Power

      Financial covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization for each specific borrower. This facility has a 70.0% debt to total capitalization covenant for PSEG (calculated as set forth above) and a 65.0% debt to total capitalization covenant for Power. 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 Condensed Consolidated Balance Sheets). This covenant requires that at the end of any quarterly financial period, such ratio will not exceed 65.0%. As of June 30, 2006, Power's ratio of debt to total capitalization (as defined above) was 43.8%.

      Energy Holdings

      Energy Holdings' revolving credit agreement has a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than or equal to 1.75. As of June 30, 2006, Energy Holdings' coverage of this covenant was 3.44. Additionally, Energy Holdings must maintain a ratio of net debt (recourse debt offset by funds loaned to PSEG) to EBITDA of less than 5.25. As of June 30, 2006, Energy Holdings' ratio under this covenant was 1.62. Energy Holdings is a co-borrower under this facility with Global and Resources, which are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings' membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfaction of

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certain financial covenants. Net cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts under the credit agreement. Net cash proceeds from asset sales during any 12-month period in excess of 10% of total assets must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources.

Credit Ratings

      PSEG, PSE&G, Power and Energy Holdings

      The current ratings of securities of PSEG and its subsidiaries are shown below and reflect the respective views of the rating agencies. Any downward revision or withdrawal may adversely affect the market price of PSEG's, PSE&G's, Power's and Energy Holdings' securities and serve to materially increase those companies' cost of capital and limit their access to capital. All ratings have a stable outlook unless otherwise noted. (N) denotes a negative outlook, (P) denotes a positive outlook and (WD) denotes a credit watch developing, indicating that ratings could be raised or lowered. 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 so 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.

	Moody's (A)	S&P (B)	Fitch (C)
PSEG:
Preferred Securities	Baa3	BB+(WD)	BBB–(P)
Commercial Paper	P2	A3(WD)	F2
Senior Unsecured Debt	Baa2	BBB–(WD)	BBB(P)
PSE&G:
Mortgage Bonds	A3	A–(WD)	A
Preferred Securities	Baa3	BB+(WD)	BBB+
Commercial Paper	P2	A3(WD)	F2
Power:
Senior Notes	Baa1	BBB(WD)	BBB(P)
Energy Holdings:
Senior Notes	Ba3(N)	BB–(N)	BB(N)

(A)	Moody's ratings range from Aaa (highest) to C (lowest) for long-term securities and P-1 (highest) to NP (lowest) for short-term securities.
(B)	S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A-1 (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 (OCI)

      PSEG, Power and Energy Holdings

      For the six months ended June 30, 2006, PSEG, Power and Energy Holdings had OCI of $370 million, $179 million and $191 million, respectively, due primarily to a reduction in the net unrealized losses on derivatives accounted for as hedges in accordance with SFAS 133 at Power and foreign currency translation adjustments at Energy Holdings.

      During the six months ended June 30, 2006, Power's Accumulated Other Comprehensive Loss (OCL) decreased from $487 million to $308 million. The primary cause was a decrease of approximately $179 million related to energy and related contracts that qualify for hedge accounting that were entered into by Power in the normal course of business. During the six months ended June 30, 2006, the decrease in gas and electric prices resulted in a reduction in unrealized losses on many of those contracts, which are recorded in OCL.

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      During the six months ended June 30, 2006, Energy Holdings' Accumulated Other Comprehensive (Loss) Income increased from $(110) million to $81 million. The primary cause was due to the realization of losses on Brazilian currency as a result of the sale of RGE.

CAPITAL REQUIREMENTS

      PSEG, PSE&G, Power and Energy Holdings

      It is expected that the majority of funding for capital requirements of PSE&G, Power and Energy Holdings will come from their respective internally generated funds. The balance will be provided by the issuance of debt at the respective subsidiary or project level and, for PSE&G and Power, equity contributions from PSEG. PSEG does not expect to contribute any additional equity to Energy Holdings. Projected construction and investment expenditures for PSEG, PSE&G, Power and Energy Holdings are consistent with amounts disclosed in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2005, with the exception of the indefinite postponement of the $30 million Electroandes hydro-expansion project at Energy Holdings which was planned for 2006 and 2007. For further information see Note 5. Commitments and Contingent Liabilities of the Notes.

      PSE&G

      During the six months ended June 30, 2006, PSE&G made approximately $259 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $259 million excludes approximately $17 million spent on cost of removal.

      Power

      During the six months ended June 30, 2006, Power made approximately $147 million of capital expenditures (excluding $46 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear.

      Energy Holdings

      During the six months ended June 30, 2006, Energy Holdings incurred approximately $20 million of capital expenditures, primarily related to SAESA.

ACCOUNTING MATTERS

      PSEG, PSE&G, Power and Energy Holdings

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

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES
ABOUT MARKET RISK

PSEG, PSE&G, Power and Energy Holdings

      The market risk inherent in PSEG's, PSE&G's, Power's and Energy Holdings' 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 Condensed 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, PSE&G, Power and Energy Holdings have a Risk Management Committee (RMC) comprised of executive officers who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.

      Additionally, PSEG, PSE&G, Power and Energy Holdings 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

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event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG and its subsidiaries' financial condition, results of operations or net cash flows.

      Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2005 or Quarterly Reports on Form 10-Q for the quarter ended March 31, 2006.

Commodity Contracts

      Power

      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 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 (OCL), 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 trading 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, which have significantly decreased over the past year. 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 mark-to-market (MTM)

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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.

      As of each of June 30, 2006 and December 31, 2005, trading VaR was less than $1 million.

	Trading VaR		Non-Trading MTM VaR
	(Millions)
For the Quarter Ended June 30, 2006
95% Confidence Level, One-Day Holding Period, One-Tailed:
Period End	$	—	$	44
Average for the Period	$	—	$	44
High	$	1	$	57
Low	$	—	$	33
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End	$	—	$	69
Average for the Period	$	—	$	69
High	$	2	$	90
Low	$	—	$	51

Other Supplemental Information Regarding Market Risk

      Power

      The following presentation of the activities of Power is included to address the recommended disclosures by the energy industry's Committee of Chief Risk Officers. For additional information, see Note 6. Risk Management of the Notes.

      The following table describes 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 six months ended June 30, 2006. 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 this table highlights, 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.

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Operating Revenues
For the Quarter Ended June 30, 2006

	Normal Operations and Hedging (A)			Trading			Total
	(Millions)
MTM Activities:
Unrealized MTM Gains (Losses)
Changes in Fair Value of Open Positions	$	8		$	11		$	19
Origination Unrealized Gain at Inception		—			—			—
Changes in Valuation Techniques and Assumptions		—			—			—
Realization at Settlement of Contracts		(13	)		(13	)		(26	)
Total Change in Unrealized Fair Value		(5	)		(2	)		(7	)
Realized Net Settlement of Transactions Subject to MTM		13			13			26
Broker Fees and Other Related Expenses		—			—			—
Net MTM Gains		8			11			19
Accrual Activities
Accrual Activities—Revenue, Including Hedge		1,116			—			1,116
Reclassifications		—			—			—
Total Operating Revenues	$	1,124		$	11		$	1,135

Operating Revenues
For the Six Months Ended June 30, 2006

	Normal Operations and Hedging (A)			Trading			Total
	(Millions)
MTM Activities:
Unrealized MTM Gains (Losses)
Changes in Fair Value of Open Positions	$	(3	)	$	23		$	20
Origination Unrealized Gain at Inception		—			—			—
Changes in Valuation Techniques and Assumptions		—			—			—
Realization at Settlement of Contracts		(22	)		(30	)		(52	)
Total Change in Unrealized Fair Value		(25	)		(7	)		(32	)
Realized Net Settlement of Transactions Subject to MTM		22			30			52
Broker Fees and Other Related Expenses		—			—			—
Net MTM (Losses) Gains		(3	)		23			20
Accrual Activities
Accrual Activities—Revenue, Including Hedge		3,082			—			3,082
Reclassifications		—			—			—
Total Operating Revenues	$	3,079		$	23		$	3,102

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

      The following table indicates Power's energy trading assets and liabilities, as well as Power's hedging activity related to asset-backed transactions and derivative instruments that qualify for hedge accounting under SFAS 133, its amendments and related guidance. This table presents amounts segregated by portfolio which 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 since balances with many counterparties are subject to offset and are shown net on the Condensed Consolidated Balance Sheets regardless of the portfolio in which they are included.

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Energy Contract Net Assets/Liabilities
As of June 30, 2006

	Normal Operations and Hedging			Trading			Total
	(Millions)
MTM Energy Assets
Current Assets	$	40		$	46		$	86
Noncurrent Assets		5			13			18
Total MTM Energy Assets	$	45		$	59		$	104
MTM Energy Liabilities
Current Liabilities	$	(419	)	$	(48	)	$	(467	)
Noncurrent Liabilities		(326	)		(15	)		(341	)
Total MTM Current Liabilities	$	(745	)	$	(63	)	$	(808	)
Total MTM Energy Contract Net Liabilities	$	(700	)	$	(4	)	$	(704	)

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

Maturity of Net Fair Value of MTM Energy Trading Contracts
As of June 30, 2006

	Maturities within
	2006			2007			2008-2009			Total
	(Millions)
Trading	$	(2	)	$	(4	)	$	2		$	(4	)
Normal Operations and Hedging		(214	)		(286	)		(200	)		(700	)
Total Net Unrealized Losses on MTM Contracts	$	(216	)	$	(290	)	$	(198	)	$	(704	)

      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.

      PSEG, Power and Energy Holdings

      The following table identifies losses on cash flow hedges that are currently in OCL, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights (FTRs) 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, Power and Energy Holdings 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 that are expected to be reclassified out of OCL and into earnings over the next 12 months.

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Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
As of June 30, 2006

	Accumulated Other Comprehensive Loss			Portion Expected to be Reclassified in next 12 months
	(Millions)
Commodities	$	(379	)	$	(189	)
Interest Rates		(4	)		(1	)
Foreign Currency		—			—
Net Cash Flow Hedge Loss	$	(383	)	$	(190	)

      Power

      Credit Risk

      The following table provides information on Power's credit exposure, net of collateral, as of June 30, 2006. 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 June 30, 2006

Rating	Current Exposure		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%			Net Exposure of Counterparties >10%
			(Millions)							(Millions)
Investment Grade—External Rating	$	144	$	55	$	143		1	(A)	$	60
Non-Investment Grade—External Rating		3		1		2		—			—
Investment Grade—No External Rating		1		—		1		—			—
Non-Investment Grade—No External Rating		25		—		25		1			21
Total	$	173	$	56	$	171		2		$	81

(A) Counterparty is PSE&G.

      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.

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ITEM 4. CONTROLS AND PROCEDURES

PSEG, PSE&G, Power and Energy Holdings

      Disclosure Controls and Procedures

      PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that information required to be disclosed is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and that material information relating to each company, including their respective consolidated subsidiaries, is accumulated and communicated to the respective company's management, including the Chief Executive Officer and Chief Financial Officer of each company by others within those entities to allow timely decisions regarding required disclosure. PSEG, PSE&G, Power and Energy Holdings have established a disclosure committee which is made up of 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 as of June 30, 2006 and, based on this evaluation, have concluded that the disclosure controls and procedures were effective in providing reasonable assurance during the period covered in these quarterly reports.

      Internal Controls

      During the second quarter of 2006, PSEG, PSE&G, Power and Energy Holdings each made significant enhancements to internal controls. These enhancements included improvements to internal controls, policies and procedures in the area of derivative accounting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

      Certain information reported under Item 3 of Part I of the 2005 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 is updated below.

PSEG, PSE&G, Power and Energy Holdings

      See information on the following proceedings at the pages indicated for PSEG and each of PSE&G, Power and Energy Holdings as noted:

(1)	Page 27. (PSE&G) Investigation Directive of NJDEP dated September 19, 2003 and additional investigation Notice dated September 15, 2003 by the EPA regarding the Passaic River site. Docket No. EX93060255.
(2)	Page 28. (Power) PSE&G's MGP Remediation Program instituted by NJDEP's Coal Gasification Facility Sites letter dated March 25, 1988.
(3)	Page 34. (Power) Filing of Complaint by Nuclear against the DOE on September 26, 2001 in the U.S. Court of Federal Claims, Docket No. 01-0551C seeking damages caused by DOE's failure to take possession of spent nuclear fuel. The complaint was amended to include PSE&G as a prior owner in interest.
(4)	Page 35. (PSE&G) Deferral Proceeding filed with the BPU on August 28, 2002, Docket No. EX02060363, and Deferral Audit beginning on October 2, 2002 at the BPU, Docket No. EA02060366.
(5)	Page 38. (Energy Holdings) Dhofar Power Company SAOC v. Ministry of Housing, Electricity and Water (Sultanate of Oman), ICC Reference EXP/233.
(6)	Page 85. (PSEG and PSE&G) BPU proceeding on August 1, 2005 relating to ratepayer protections due to repeal of PUHCA under the Energy Policy Act of 2005. Docket No. AX05070641.
(7)	Page 85. (PSEG, PSE&G and Power) PJM Interconnection, L.L.C., Schedule 12 (Cost Allocation) filing with FERC, Docket No. ER06-456-000.
(8)	Page 86. (PSEG, PSE&G and Power) FERC proceedings with MISO and PJM relating to RTOR and SECA methodology, Docket No. ER05-6-000 et al.
(9)	Page 86. (PSEG, PSE&G and Power) PJM Reliability Pricing Model filed with FERC on August 31, 2005, Docket Nos. ER05-1410-000 and EL05-148-000.
(10)	Page 86. (PSEG, PSE&G and Power) FERC proceeding relating to PJM Long-Term Transmission Rate Design, Docket No. EL05-121-000.
(11)	Page 87. (PSEG, PSE&G and Power) Notice of Inquiry issued by FERC on September 16, 2005 to prevent undue discrimination and preference in the provisions of transmission service. Docket No. RM05-25-000.
(12)	Page 87. (PSEG, PSE&G and Power) FERC proceeding relating to PJM's stated rate proposal, Docket No. ER05-1181-000.
(13)	Page 88. (Power) PJM Interconnection L.L.C. filing with FERC on November 2, 2004, Docket No. EL03-236-003 to amend Tariff and Operating Agreement to request Reliability Must-Run (RMR) compensation.
(14)	Page 88. (Power) PSEG Power Connecticut's filing with FERC on November 17, 2004, Docket No. ER05-231-000, to request RMR compensation.
(15)	Page 88. (PSE&G) Neptune Regional Transmission System, LLC v. PJM Interconnection, L.L.C. complaint filed with FERC on December 21, 2004, Docket No. EL05-48-00, alleging PJM impermissibly conducted an interconnection re-study triggered by generator retirements in PJM, which had the effect of increasing Neptune's cost exposure for network upgrades from approximately $4 million to $26 million.

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(16)	Page 89. (PSE&G) JCP&L v. ACE, et al. complaint filed with FERC on December 30, 2004, Docket No. EL05-50-000, seeking to terminate its construction obligations under the LDV Agreement.
(17)	Page 90. (PSE&G) BPU review of annual procurement process for BGS, Docket No. EO06020119.
(18)	Page 90. (PSE&G) BPU proceeding relating to Electric Base Rate Case financial review, Docket No. ER02050303.
(19)	Page 91. (PSE&G) PSE&G's BGSS Commodity filing with the BPU on May 28, 2004, Docket No. GR04050390.
(20)	Page 91. (PSE&G) PSE&G Petition for increase of gas base rates filed with BPU on September 30, 2005, Docket No. GR05100845.
(21)	Page 91. (PSE&G) Cost Recovery filing with the BPU on July 1, 2004, Docket No. EE04070718.

ITEM 5. OTHER INFORMATION

      Certain information reported under the 2005 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2006 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2005 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2006. References are to the related pages on the Form 10-K and Form 10-Q as printed and distributed.

Federal Regulation

      Public Utility Holding Company Act

      PSEG, PSE&G, Power and Energy Holdings

      2005 Form 10-K, Page 15. The Energy Policy Act, which became law on August 8, 2005, repealed the Public Utility Holding Company Act of 1935 (PUHCA) as of February 8, 2006 and established PUHCA 2005. FERC has promulgated rules that would waive the accounting and reporting obligations of PUHCA 2005 for PSEG and its subsidiaries. Thus, PSEG, PSE&G, and Power do not expect PUHCA 2005 to materially affect their respective businesses, prospects or properties. For additional information on the impact of PUHCA repeal, see State Regulation.

      FERC

      PSEG, PSE&G, Power and Energy Holdings

      Market Power

      2005 Form 10-K, Page 16 and March 31, 2006 Form 10-Q, Page 78. On February 28, 2006, PSEG Power Connecticut LLC (Power Connecticut) filed its triennial updated market power report with the FERC. The FERC has not yet acted on this filing. PSE&G and ER&T have received an extension from the FERC regarding the filing of their respective triennial updated market power reports, which were due to have been filed with FERC on June 19, 2006. FERC has granted the companies an extension for filing until the later of (i) 30 days after the close of the pending PSEG/Exelon Merger; or (ii) November 30, 2006. Further, when and if the Merger is consummated, all PSEG and Exelon subsidiaries holding market based rate authority will be required to provide appropriate updates of their market power analyses to the FERC.

      PSEG, PSE&G and Power

      PJM Schedule 12 Filing

      March 31, 2006 Form 10-Q, Page 78. On January 5, 2006, PJM for the first time proposed cost allocation recommendations for new transmission projects pursuant to Schedule 6 of its Operating Agreement and Schedule 12 of its Tariff. PJM identified the “Responsible Customers” that would be required to pay for certain transmission upgrades approved through PJM's Regional Transmission

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Expansion Planning (RTEP) process and the percentage of the project cost that would be allocated to such Responsible Customers. This was the first filing by PJM pursuant to these new cost allocation mechanisms and it included (i) large cost allocations to eastern load as a result of proposed construction in the western and southern portions of PJM and (ii) allocations to merchant transmission projects such as Neptune Regional Transmission System, LLC (Neptune) for the first time. On May 26, 2006, the FERC issued an order that accepted and suspended PJM's cost allocation filing, made the filing effective subject to refund as of May 30, 2006 and established a hearing and settlement judge procedure. The settlement proceeding is currently being conducted before a FERC Administrative Law Judge (ALJ). PSEG is actively participating in this proceeding, as the cost allocation methodology used by PJM may result in a disproportionate allocation of costs to load in the eastern portion of PJM. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding at this time.

      In addition, on May 4, 2006, PJM made a second RTEP cost allocation filing at FERC under Schedules 6 and 12, addressing cost allocations to Responsible Customers associated with additional RTEP projects. PSEG has protested the filing, objecting to, among other things, PJM's netting of zonal impacts to allocate RTEP costs and PJM's failure to consider the impact of certain adjustments in determining zonal cost allocation. FERC has not yet acted on this filing. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding.

      Regional through and out rates (RTOR)

      2005 Form 10-K, Page 17 and March 31, 2006 Form 10-Q, Page 78. A trial-type hearing, encompassing a review of the actual amount of lost revenues to be recovered via the Seams Elimination Charge/Cost Adjustment/Assignment (SECA) mechanism, was held in May 2006, with an initial decision expected by August 11, 2006. In addition, in March 2006, PSE&G and Power entered into a settlement with a limited group of parties in PJM, which settlement was certified to the FERC, under which the parties have agreed that, notwithstanding the resolution of the SECA hearing at the FERC, the parties will agree to pay and collect 80% of SECA revenues. PSE&G has deferred the collection of any SECA revenues on its books. At the present time, it is difficult to determine whether, and to what extent, the SECA hearing will have an impact on PSEG, PSE&G and Power.

      PJM Reliability Pricing Model (RPM)

      2005 Form 10-K, Page 17 and March 31, 2006 Form 10-Q, Page 79. On August 31, 2005, PJM filed its RPM with FERC. The RPM constitutes a locational installed capacity market design for the PJM region, including a forward auction for installed capacity priced according to a downward-sloping demand curve, recognition of locational value and a transitional implementation of the market design. PSEG generally supports the PJM approach. Following extensive comments and a technical conference, FERC issued an order on April 20, 2006 that accepted most of the core concepts of the RPM filing with an implementation date of June 1, 2007. The April 20, 2006 order set certain details of the filing for paper hearing and technical conference procedures including the slope of the demand curve and the mechanism for identification of the locational capacity zones. The paper hearing and technical conference procedures have now been completed. Also, commencing in June 2006, settlement discussions mediated by a FERC ALJ commenced at the request of certain intervenors. These discussions are currently ongoing and are being attended by representatives for PSE&G and Power. The April 20, 2006 order is subject to rehearing requests filed by several parties. Given the pending rehearing requests and likelihood of eventual judicial appeals, the paper hearing and technical conference procedures and the on-going settlement discussions, PSEG, PSE&G and Power are unable to predict the outcome of this proceeding.

      PJM Long-Term Transmission Rate Design

      2005 Form 10-K, Page 17. On May 31, 2005, FERC issued an order addressing the recovery of costs for transmission upgrades designated through PJM's RTEP process. Among other matters, FERC's order responded to a proposal to continue PJM's current zonal rate design. FERC concluded that the existing rate design may not be just and reasonable and it established a hearing to examine the justness and reasonableness of continuing PJM's modified zonal rate design. Several parties to the proceeding have proposed replacing zonal rate design with other rate design methodologies above certain voltage levels. A hearing in this proceeding was held in April 2006. An initial decision by the ALJ was issued on

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July 13, 2006, in which the ALJ concluded that the existing PJM modified zonal rate design for existing facilities has been shown to be unjust and unreasonable, and should be replaced with a postage stamp rate design for such facilities to be effective April 1, 2006. To mitigate rate impacts, the ALJ has determined that the rate design should be phased in, so that no customer receives greater than a 10% annual rate increase. Should the FERC ultimately approve this postage stamp rate design on review of the ALJ's initial decision, or adopt one or a combination of the alternative rate designs proposed, PSEG's, PSE&G's or Power's results of operations could be adversely impacted. It is not possible to predict the outcome of this proceeding at this time.

      FERC Order No. 888

      2005 Form 10-K, Page 18. On May 18, 2006, FERC issued a Notice of Proposed Rulemaking (NOPR) seeking comments on whether reforms are needed to the protections that FERC established in its Order No. 888 in order to prevent undue discrimination and preference in the provision of transmission service. FERC's NOPR solicits input from the industry as to whether it should revise the pro forma Open Access Transmission Tariff. Order No. 888 established this tariff to govern the terms and conditions under which transmission owners must provide transmission service to all eligible customers. If FERC ultimately adopts structural remedies, such as further separating the ownership of generation and transmission, or mandates joint ownership of backbone transmission facilities, PSEG, PSE&G and Power's results of operations could be negatively affected. Comments to the NOPR are due in August 2006 and the FERC is expected to issue a Final Rule thereafter.

      PJM Stated Rate Filing

      2005 Form 10-K, Page 18 and March 31, 2006 Form 10-Q, Page 79. On July 1, 2005, PJM filed with FERC a proposal to change the rate design for its administrative cost recovery from a formula rate, which allocates PJM's administrative costs to its members on a yearly basis, to a stated rate of 39 cents per MW-hour. On August 31, 2005, FERC accepted these changes subject to the provision of further cost-of-service data by PJM within 60 days to demonstrate that its stated rate is a just and reasonable prediction of its costs for future years. PJM provided this cost-of-service data on November 30, 2005. Several parties, including PSE&G, Power, the BPU and the New Jersey Ratepayer Advocate (RPA), submitted comments and protests regarding PJM's filing, which protested the filing and requested that FERC order an evidentiary hearing regarding the filing. Settlement discussions were conducted over the course of several months, and a settlement was reached establishing a base stated rate that is significantly lower than PJM's filed rate, establishing a rate for PJM's proposed second control center and establishing a revised protocol to govern future interaction among the PJM Finance Committee, PJM management, PJM's Board of Managers and the PJM membership, revisions which will result in the Finance Committee having greater access to PJM financial information and greater input into PJM's financial decision making processes. The uncontested settlement was filed with the FERC on April 18, 2006 and was approved by the FERC on May 26, 2006.

      Locational Installed Capacity (LICAP) Market Settlement in New England

      2005 Form 10-K, Page 18. On January 31, 2006, certain interested market participants in New England agreed to a settlement in principle of litigation regarding the design of the region's market for installed capacity, which would institute a transition period leading to the implementation of a new market design for capacity as early as 2010. Commencing in December 2006, all generators in New England would begin to receive fixed capacity payments that escalate gradually over the transition period. RMR contracts, such as Power's, would continue to be effective until the implementation of the new market design. The new market design would consist of a forward auction for installed capacity that is intended to recognize the locational value of generators on the system, and contains incentive mechanisms to encourage generator availability during generation shortages. The final version of the settlement was filed with the FERC on March 6, 2006 and was approved by order dated June 16, 2006 finding that, as a package, the settlement represents a just and reasonable outcome. The settlement was contested by certain parties and it is anticipated that rehearing of the June 16, 2006 order will be sought. PSEG and Power are unable to predict the outcome of this proceeding.

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      Power

      RMR Status

             PJM

      2005 Form 10-K, Page 18. Effective February 24, 2005, subject to refund and hearing, Power began to collect a monthly fixed payment of $3.3 million, net of operating margins for the Sewaren 1, 2, 3 and 4 and Hudson 1 units. A detailed settlement was filed with FERC on September 23, 2005 that permits Power to recover annual fixed costs of approximately $19 million and $14.5 million for the Sewaren and Hudson units, respectively, plus reimbursements of Power's expenditures in connection with certain construction at the units that are necessary to maintain reliability, offset by certain revenues earned in PJM's energy market. FERC accepted this settlement retroactive to February 24, 2005. On March 28, 2006, Power filed a refund report with FERC seeking to recover $11 million paid to PJM. FERC did not issue a public notice requesting comments on the report and no party has made any objections or other comments with respect to the report.

             New England

      2005 Form 10-K, Page 19 and March 31, 2006 Form 10-Q, Page 79. On November 17, 2004, Power Connecticut, a wholly owned indirect subsidiary of Power, filed a request for RMR treatment for the Unit 2 at the Bridgeport Harbor generation station and New Haven Harbor generation station. Beginning on January 14, 2005, when FERC issued an order accepting this filing, subject to refund and hearing, Power Connecticut began collecting monthly fixed payments of approximately $1.6 million and $3.9 million for reliability services provided by the Bridgeport Harbor Station, Unit 2 and the New Haven Harbor Station, respectively, net of operating margins at the units. On June 17, 2005, Power Connecticut filed revised studies supporting monthly recovery of $1.3 million and $3.3 million for the Bridgeport Harbor 2 and New Haven Harbor units, respectively.

      On June 20, 2005, FERC issued an order on rehearing of its January 14, 2005 order and reversed its prior conclusion that Power Connecticut's November 17, 2004 filing would become effective only after a 60-day notice period. Instead, the rehearing order allowed the filing to become effective as of November 18, 2004, which permits Power Connecticut two additional months of RMR compensation. On November 28, 2005, FERC denied rehearing of its June 20, 2005 order. Certain parties opposing the RMR filing, on January 27, 2006, sought judicial review of the FERC's orders in this proceeding.

      FERC assigned this matter to an ALJ for hearings that were scheduled to commence on April 19, 2006. Power Connecticut and the affected intervenors have, nonetheless, continued to engage in settlement discussions, and on April 21, 2006, Power Connecticut, the Connecticut Department of Public Utility Control, the Connecticut Office of Consumer Counsel and ISO New England Inc. filed with the FERC a Joint Stipulation and Settlement Agreement and Motion for Expedited Consideration. The Joint Stipulation and Settlement settled all matters associated with the RMR agreements filed by Power Connecticut for its Bridgeport Harbor 2 and New Haven Harbor stations. Among other things, the settlement provides for monthly fixed payments of approximately $1 million for Bridgeport Harbor and $3 million for New Haven Harbor. Trial Staff for the FERC also supports the settlement. The only disputed issues concern the standard of review applicable to certain types of potential tariff changes that could be filed in the future. No party challenges the settlement rates proposed to become effective at this time. The ALJ certified the settlement to FERC on June 21, 2006 as a contested offer of settlement. It is anticipated that the settlement, which resolves all issues set for hearing by FERC as well as issues raised in the appellate courts, will be approved as certified or, if modified, will not be modified in a manner that adversely affects the settlement rates. However, Power Connecticut cannot predict a final outcome at this time.

      Neptune Complaint Proceeding

      2005 Form 10-K, Page 19. On December 21, 2004, Neptune filed a complaint with FERC against PJM. Neptune is directly interconnected to the transmission system of FirstEnergy Corporation (FirstEnergy), but upgrades to the PSE&G transmission system will also be required to move power across the grid. In its complaint, Neptune alleges that PJM impermissibly conducted an interconnection re-study triggered by generator retirements in PJM, which had the effect of increasing Neptune's cost

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exposure for network upgrades. On February 10, 2005, FERC granted Neptune's complaint against PJM and then denied rehearing on June 24, 2005. As a result of these orders, Neptune's interconnection cost responsibility was capped at a level of approximately $6 million, and the remaining $20 million in interconnection costs may ultimately be allocated to the customers of PSE&G and FirstEnergy and flowed through to retail ratepayers should pass-through of these costs be permitted.

      On August 15, 2005, PSE&G sought judicial review of FERC's orders in the U.S. Circuit Court of Appeals. Two additional petitioners also sought judicial review of these orders, and the BPU and RPA have intervened in the case. Initial briefs in the case have been filed and reply briefs are due in August 2006. PSE&G cannot at this time predict the outcome of this appeal.

      PSE&G

      LDV Complaint Proceeding

      On December 30, 2004, Jersey Central Power & Light Company (JCP&L) filed a complaint at the FERC against the other four signatories to the Lower Delaware Valley (LDV) Transmission System Agreement, including PSE&G. The LDV Agreement, governing the construction of, and investment in, certain 500 kV transmission facilities in New Jersey, was entered into by the parties in 1977 and remains in effect until 2027. In the FERC complaint proceeding, JCP&L seeks to terminate its payment obligations to the other contract signatories. PSE&G receives from JCP&L approximately $2.7 million annually under the LDV Agreement and its related agreements. On May 6, 2005, the FERC issued an order dismissing JCP&L's complaint. Subsequently, in a rehearing order issued December 2, 2005, the FERC set certain issues raised by JCP&L for hearing. The parties engaged in settlement discussions from January 2006 through May 2006, and these efforts proved unsuccessful. The matter is now in litigation, with a hearing scheduled to take place in November 2006 and an initial decision to be rendered by the ALJ in March 2007. It is anticipated that JCP&L will seek not only to terminate its payment obligations but also to seek approximately $40 million in credits from PSE&G and the other LDV parties for transmission facilities previously constructed by JCP&L in New Jersey. PSE&G cannot predict the outcome of this proceeding.

      NRC

      Power

      Nuclear Safety Issues

      2005 Form 10-K, Page 20. In January 2004, the NRC issued a letter requesting Power to conduct a review of its Salem and Hope Creek nuclear generation facilities to assess the workplace environment for raising and addressing safety issues. Power responded to the letter in February 2004 and had independent assessments of the work environment at both facilities performed. The results of these assessments were provided to the NRC in May 2004. The assessments concluded that Salem and Hope Creek were safe for continued operations, but also identified issues that needed to be addressed.

      At an NRC public meeting on June 16, 2004, Power outlined its action plan to address these issues, which focused on a safety-conscious work environment, the corrective action program and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. On July 30, 2004, the NRC provided a letter to Power indicating that it had completed its review. The letter indicated that the NRC had not identified any safety violations and that it appeared that the PSEG action plan would address the key findings of both the NRC and Power assessments. On March 2, 2006, the NRC provided Power with its annual performance reviews of Salem and Hope Creek, which detailed the NRC's plan for enhanced oversight related to the work environment. The letter indicated the NRC plans to continue with this heightened oversight until Power has concluded that substantial, sustainable progress has been made, and the NRC has completed a review that confirms Power's conclusions. Under the NRC oversight program, Power provided the NRC with a report of its progress at a public meeting in May 2006.

      Recirculation Pump

      2005 Form 10-K, Page 21. In a letter to the NRC dated January 9, 2005, Power committed to install vibration-monitoring equipment on Hope Creek's “B” Reactor Recirculation Pump prior to the

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unit's return to service to address pump vibration concerns and replace the pump's shaft during the next refueling outage or any sooner outage of sufficient duration. This commitment was the subject of a January 11, 2005 Confirmatory Action Letter from the NRC. The shaft was replaced during the Hope Creek outage in April 2006. On April 20, 2006, the NRC issued a Closure of Confirmatory Action Letter indicating that all of the commitments were completed.

State Regulation

      PSEG, PSE&G, Power and Energy Holdings

      PUHCA Repeal

      2005 Form 10-K, Page 21 and March 31, 2006 Form 10-Q, Page 80. On March 31, 2006, the BPU issued draft proposed rules in this proceeding. Specifically, these proposed rules would preserve and further codify the BPU's access to both utility and utility holding company system books and records, establish ring-fencing measures around the utility, seek to separate the corporate boards of directors between the utility and its holding company system, and address issues regarding the extent of the BPU's oversight of service agreements between a utility and its holding company system. All of the New Jersey electric and gas utilities, including PSE&G, submitted a revised rulemaking proposal to the BPU on these issues, as well as on transitional and grandfathering issues that would allow the utilities sufficient time to comply with new rules and that would provide for the continuing validity of previously-issued BPU orders. Comments were filed by all parties to this proceeding on June 15, 2006. The BPU has not yet issued final rules in this proceeding. PSEG, PSE&G, Power and Energy Holdings are not able to predict the outcome of these proceedings at this time.

      PSE&G

      BGS Auction Review

      In 2006, the BPU initiated a proceeding to review the annual BGS procurement process as well as the policy issues thereto for all of the New Jersey EDCs. In June 2006, the BPU ruled on certain issues regarding the acquisition of BGS for the period beginning in June 2007. The BPU agreed that a descending clock auction format should be used for the procurement of BGS-FP supply for 2007. The BPU also agreed that BGS suppliers should not be required to disclose the sources of supply behind the BGS contracts.

      On July 10, 2006, PSE&G filed the Joint EDC proposal for the procurement of BGS for the period beginning June 1, 2007. This proposal includes a descending clock auction format to be held in February 2007 for the procurement of all BGS supply. A decision by the BPU on this proposal is expected in the third quarter of 2006. PSE&G cannot predict the outcome of this proceeding.

      Electric Distribution Financial Review

      2005 Form 10-K, Page 22 and March 31, 2006 Form 10-Q, Page 81. Based on the Electric Base Rate Case approved in July 2003, PSE&G recorded a regulatory liability in the second quarter of 2003 by reducing its depreciation reserve for its electric distribution assets by $155 million and amortized this liability from August 1, 2003 through December 31, 2005. The $64 million annual amortization of this liability resulted in a reduction of Depreciation and Amortization expense. PSE&G filed for the elimination of the $64 million (based on 2003 test year sales volumes) electric distribution rate credit effective January 1, 2006, subject to BPU approval, including a review of PSE&G's earnings and other relevant financial information. Based on current sales volumes, the amount approximates $68 million.

      The BPU issued an order on February 7, 2006 that found that insufficient information had been provided to support the elimination of the rate credit. The order permitted PSE&G to file actual data through March 31, 2006. The BPU will determine, based on the additional information, if the elimination of the rate credit is warranted. The impact of not eliminating the depreciation rate credit reduces PSE&G's earnings and cash flows by more than $5 million (pre-tax) per month. PSE&G filed an update of the original data containing first quarter 2006 actual financial information on June 14, 2006. Action on PSE&G's recent filings, including the excess depreciation rate credit, has been subject to

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ongoing delays. It appears that until the Merger is resolved with the BPU, decisions on PSE&G's revenue requests may be difficult to achieve.

      BGSS Filings

      2005 Form 10-K, Page 22 and March 31, 2006 Form 10-Q, Page 81. On March 8, 2006 a meeting of PSE&G, the BPU and the RPA was held regarding the BGSS rates for the 2005/2006 period. PSE&G addressed the RPA's discovery concerns, however the RPA requested that the BGSS not be finalized until the Merger case is resolved.

      The schedule at the Office of Administrative Law (OAL) called for the RPA's testimony to be filed on March 15, 2006. The RPA failed to file and subsequently argued that the 2005/2006 BGSS proceeding be held in abeyance until the Merger case is resolved. The ALJ directed the RPA to file a motion, which was subsequently filed. The motion requested that the BGSS proceeding be stayed, or that it be consolidated with the Gas Base Rate Case. PSE&G filed its reply on April 5, 2006 arguing that the issues of the two proceedings are unrelated and that the RPA's motion had no merit. The ALJ denied the RPA's motion to combine the BGSS proceeding with the Gas Base Rate Case. The RPA filed its testimony on May 26, 2006 on several gas contract related issues. PSE&G filed rebuttal testimony on June 22, 2006 on the gas contract issues. A hearing was held on June 29, 2006 after a settlement could not be reached. The parties agreed that the BGSS Commodity Charge increases of September 1, 2005 and December 15, 2005 that were previously approved by the BPU on a provisional basis should become final. The remaining gas contract issues are pending.

      PSE&G made its 2006/2007 BGSS filing on May 26, 2006. In this filing, PSE&G requested a reduction in annual BGSS gas revenues of approximately $19.7 million (excluding losses and New Jersey Sales and Use Tax) or approximately a 1.0% decrease to be implemented for service rendered on and after October 1, 2006 or earlier. Additionally, PSE&G requested an increase in its Balancing Charge. The combined impact of both changes for the class average residential heating customer is an increase in the winter monthly bills of approximately 0.1%; however, on an annual basis the impact is a decrease of approximately 0.2%.

      Gas Base Rate Case

      2005 Form 10-K, Page 23 and March 31, 2006 Form 10-Q, Page 81. On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78% increase in its gas base rates to cover the cost of gas delivery to be effective June 30, 2006. Approximately $55 million of the $133 million request is for an increase in book depreciation rates. The balance of the request will cover the return on increased plant investment, higher operating expenses and provide an 11% return on equity. PSE&G's current gas base rates have been in effect since January 2002.

      PSE&G presented a detailed overview of the filing to the BPU and the RPA in October 2005 and subsequent to the presentation signed an agreement with the BPU Staff providing for transfer of the matter to the OAL and agreeing to have the matter settled or ready for a BPU decision before September 28, 2006.

      On March 15, 2006, a pre-hearing conference was held for the parties and a schedule set for public hearings, direct and rebuttal testimony, evidentiary hearings and briefs, with an ALJ decision by late October and a BPU decision by early December 2006. Discovery commenced and will be conducted on a rolling basis.

      On June 15, 2006 and June 21, 2006, the RPA and Intervenors filed direct testimony and PSE&G filed rebuttal testimony on June 30, 2006 and July 14, 2006. The RPA recommended a $70 million rate decrease. Evidentiary hearings commenced on July 21, 2006 and will continue into mid August 2006.

      Action on PSE&G's recent filings, including the Gas Base Rate Case, has been subject to ongoing delays. It appears that until the Merger is resolved with the BPU, decisions on PSE&G's revenue requests may be difficult to achieve.

      CAS Cost Recovery Mechanism

      2005 Form 10-K, Page 23 and March 31, 2006 Form 10-Q, Page 82. The New Jersey Electric Discount and Energy Competition Act (EDECA) required that the BPU provide electric and natural

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gas customers with the opportunity to choose a supplier for some or all electric or natural gas customer account services (CAS). In July 2004, PSE&G filed a petition with the BPU to implement the CAS Cost Recovery Mechanism for both its electric and gas operations to recover $4 million of CAS costs and accumulated interest resulting from implementing PSE&G's dual billing for its delivery costs and for the third-party suppliers' commodity charges as a result of customer migration from PSE&G. In September 2004, the case was transferred to the OAL as a contested case. A pre-hearing conference was held on December 20, 2005 at which time a schedule was established. On April 7, 2006, a settlement agreement was reached and filed with the ALJ.

      On May 17, 2006, the BPU issued its Order approving the Initial Decision–Settlement that fully resolved this matter. The Settlement will allow PSE&G to recover a total of $3.3 million of costs over a one-year period. Recovery will begin as of the date of the next base rate change or January 1, 2007, whichever is earlier.

ENVIRONMENTAL MATTERS

      Power

      Carbon Dioxide (CO₂) Emissions

      2005 Form 10-K, Page 27 and March 31, 2006 Form 10-Q, Page 82. Several states, primarily in the Northeastern U.S., are developing state-specific or regional legislative initiatives to stimulate CO₂ emission reductions in the electric power industry. New York initiated the Regional Greenhouse Gas Initiative (RGGI) in April 2003. Currently, in the RGGI, seven Northeastern states have signed a memorandum of understanding (MOU) intended to cap and reduce CO₂ emissions from the electric power sector in the RGGI region. A draft model rule was issued on March 23, 2006 but stakeholder comments are being received and the model rule has not been finalized. States are expected to enact legislation and/or regulation representing, at least, the minimum requirements stipulated in the MOU. The NJDEP in 2005 finalized amendments to its regulations governing air pollution control that would designate CO₂ as an air contaminant subject to regulation. The RGGI program is scheduled to start in 2009. The outcome of this initiative cannot be determined at this time; however, adoption of stringent CO₂ emission reduction requirements in the Northeast could materially impact Power's operation of its fossil fuel-fired electric generating units.

      PSE&G and Power

      Remedial Investigation/Feasibility Study

      Form 10-Q, page 82. On March 9, 2006, the EPA sent PSE&G, Power and approximately 157 other entities a notice that the EPA considered each of the entities to be a potentially responsible party (PRP) with respect to contamination in Berry's Creek in Bergen County, New Jersey and requesting that the PRPs perform a Remedial Investigation/Feasibility Study (RI/FS) on Berry's Creek and the connected tributaries and wetlands. Berry's Creek flows through approximately 6.5 miles of areas that have been used for a variety of industrial purposes and landfills. The EPA estimates that the study could be completed in approximately five years at a total cost of approximately $18 million. PSE&G and Power are unable to predict the outcome of this matter; however, the related costs are not expected to be material.

      Energy Holdings

      GWF

      In April 2006, GWF Power Systems, L.P. and Hanford L.P., each a partnership 50% owned by Global, executed amendments to their respective power purchase agreements to establish fixed price energy sales terms for a five-year period. The California Public Utilities Commission approved the amendments on July 20, 2006, which started a 30-day period for parties in the proceeding to appeal or request rehearing. The amendments will be effective, and the five-year term will commence, at the end of the 30-day period if rehearing is not required.

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ITEM 6. EXHIBITS

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

      a. PSEG:

Exhibit 12: Computation of Ratios of Earnings to Fixed Charges

Exhibit 31: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

Exhibit 31.1: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

Exhibit 32: Certification by E. James Ferland 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. PSE&G:

Exhibit 12.1: Computation of Ratios of Earnings to Fixed Charges

Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements

Exhibit 31.2: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

Exhibit 31.3: Certification by Robert E. Busch Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

Exhibit 32.2: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Exhibit 32.3: Certification by Robert E. Busch Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

      c. Power:

Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges

Exhibit 31.4: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

Exhibit 31.5: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

Exhibit 32.4: Certification by E. James Ferland 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

      d. Energy Holdings:

Exhibit 12.4: Computation of Ratios of Earnings to Fixed Charges

Exhibit 31.6: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

Exhibit 31.7: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934

Exhibit 32.6: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

Exhibit 32.7: Certification by Thomas M. O'Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

93

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/ PATRICIA A. RADO       Patricia A. Rado       Vice President and Controller       (Principal Accounting Officer)

Date: August 1, 2006

94

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 ELECTRIC AND GAS COMPANY(Registrant)
	By:       /s/ PATRICIA A. RADO       Patricia A. Rado       Vice President and Controller       (Principal Accounting Officer)

Date: August 1, 2006

95

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.

PSEG POWER LLC(Registrant)
	By:       /s/ PATRICIA A. RADO       Patricia A. Rado       Vice President and Controller       (Principal Accounting Officer)

Date: August 1, 2006

96

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.

PSEG ENERGY HOLDINGS L.L.C.(Registrant)
	By:       /s/ PATRICIA A. RADO       Patricia A. Rado       Controller       (Principal Accounting Officer)

Date: August 1, 2006

97

EX-12

                                                                      EXHIBIT 12

                  PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
               COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES



                                                 For the Six
                                                 Months Ended                For the Years Ended
                                                   June 30,                     December 31,
                                                 ------------------------------------------------------------
                                                  2006   2005     2005      2004     2003     2002     2001
                                                 ------------------------------------------------------------
                                                                  (Millions, except ratios)
                                                                                 
Earnings as Defined in Regulation S-K (A):

Pre-tax Income from Continuing Operations        $ 335   $ 600   $ 1,399   $1,237   $1,324   $  659   $1,139

(Income) Loss from Equity Investees, net of
Distributions                                      (31)    (10)      (28)      78       60       (2)     (59)
Fixed Charges                                      446     459       931      928      963      946      876
Capitalized Interest (B)                           (28)    (52)      (92)    (109)    (116)    (104)     (74)
Preferred Securities Dividend Requirements
of Subsidiaries                                     (3)     (7)       (6)      (6)      (6)      (6)      (8)
                                                 ------------------------------------------------------------
Total Earnings                                   $ 722   $ 997   $ 2,204   $2,128   $2,225   $1,493   $1,874
                                                 ============================================================

Fixed Charges as Defined in Regulation S-K (C)

Interest Expense                                 $ 441   $ 454   $   915   $  913   $  949   $  926   $  852
Interest Factor in Rentals                           5       5        10        9        8       14       16
Preferred Securities Dividend Requirements
of Subsidiaries                                      3       7         6        6        6        6        8
                                                 ------------------------------------------------------------
Total Fixed Charges                              $ 449   $ 466   $   931   $  928   $  963   $  946   $  876
                                                 ============================================================

Ratio of Earnings to Fixed Charges                1.61    2.14      2.37     2.29     2.31     1.58     2.14
                                                 ============================================================


(A)   The term "earnings" shall be defined as pre-tax Income from Continuing
      Operations before income or loss from equity investees plus distributed
      income from equity investees. Add to pre-tax income the amount of fixed
      charges adjusted to exclude (a) the amount of any interest capitalized
      during the period and (b) the actual amount of any preferred securities
      dividend requirements of majority-owned subsidiaries stated on a pre-tax
      level.

(B)   Fixed Charges represent (a) interest, whether expensed or capitalized, (b)
      amortization of debt discount, premium and expense, (c) an estimate of
      interest implicit in rentals and (d) preferred securities dividend
      requirements of majority-owned subsidiaries stated on a pre-tax level.

(C)   Capitalized Interest excludes AFUDC for PSE&G.

EX-12

                                                                    Exhibit 12.1

                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
               COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES



                                                  For the Six Months            For the Years Ended
                                                    Ended June 30,                   December 31,
                                                -------------------------------------------------------------
                                                    2006      2005     2005     2004    2003     2002    2001
                                                -------------------------------------------------------------
                                                                            (Millions, except ratios)
                                                                                 
Earnings as Defined in Regulation S-K (A):

Pre-tax Income from Continuing Operations       $   203   $    284  $  583   $  592  $  376   $  320  $  324
Fixed Charges                                       168        170     342      362     390      408     461
                                                ------------------------------------------------------------
Earnings                                        $   371   $    454  $  925   $  954  $  766   $  728  $  785
                                                ============================================================

Fixed Charges as Defined in Regulation S-K (B)

Interest Expense                                $   168   $    170  $  342   $  362  $  390   $  406  $  458
Interest Factor in Rentals                           --         --      --       --      --        2       3
                                                ------------------------------------------------------------
Total Fixed Charges                             $   168   $    170  $  342   $  362  $  390   $  408  $  461
                                                ============================================================

Ratio of Earnings to Fixed Charges                 2.21       2.67    2.70     2.64    1.96     1.78    1.70
                                                ============================================================


(A)   The term "earnings" shall be defined as pretax income from continuing
      operations. Add to pretax income the amount of fixed charges adjusted to
      exclude the amount of any interest capitalized during the period.

(B)   Fixed Charges represent (a) interest, whether expensed or capitalized, (b)
      amortization of debt discount, premium and expense and (c) an estimate of
      interest implicit in rentals.

EX-12

                                                                    Exhibit 12.2

                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
               COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
                  Plus Preferred Security Dividend Requirements



                                                For the Six Months            For the Years Ended
                                                  Ended June 30,                   December 31,
                                                ------------------------------------------------------------
                                                  2006      2005     2005     2004    2003     2002    2001
                                                ------------------------------------------------------------
                                                                            (Millions, except ratios)
                                                                                 
Earnings as Defined in Regulation S-K (A):

Pre-tax Income from Continuing Operations       $   203   $    284  $  583   $  592  $  376   $  320  $  324
Fixed Charges                                       171        173     349      369     397      415     469
Preferred Securities Pre Tax                         (3)        (3)     (7)      (7)     (7)      (7)     (8)
                                                ------------------------------------------------------------
Earnings                                        $   371   $    454  $  925   $  954  $  766   $  728  $  785
                                                ============================================================

Fixed Charges as Defined in Regulation S-K (B)

Interest Expense                                $   168   $    170  $  342   $  362  $  390   $  406  $  458
Interest Factor in Rentals                           --         --      --       --      --        2       3
Preferred Securities Dividends                        2          2       4        4       4        4       5
Adjustment to state Preferred Securities
Dividends on a pre-income tax basis                   1          1       3        3       3        3       3
                                                ------------------------------------------------------------
Total Fixed Charges                             $   171   $    173  $  349   $  369  $  397   $  415  $  469
                                                ============================================================

Ratio of Earnings to Fixed Charges                 2.17       2.62    2.65     2.59    1.93     1.76    1.67
                                                ============================================================


(A)   The term "earnings" shall be defined as pretax income from continuing
      operations. Add to pretax income the amount of fixed charges adjusted to
      exclude (a) the amount of any interest capitalized during the period (b)
      the actual amount of any preferred securities dividend requirements of
      majority owned subsidiaries (c) preferred stock dividends which were
      included in such fixed charges amount but not deducted in the
      determination of pre-tax income.

(B)   Fixed Charges represent (a) interest, whether expensed or capitalized, (b)
      amortization of debt discount and premium expense (c) an estimate of
      interest implicit in rentals and (d) preferred securities dividend
      requirements of majority owned subsidiaries and preferred stock dividends,
      increased to reflect the pre-tax earnings requirement for PSE&G.

EX-12

                                                                    EXHIBIT 12.3

                                 PSEG POWER LLC
               COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES



                                                   For the Six
                                                   Months Ended            For the Years Ended
                                                  ------------------------------------------------------
                                                    June 30,                   December 31,
                                                  ------------------------------------------------------
                                                   2006    2005    2005    2004    2003    2002    2001
                                                  ------------------------------------------------------
                                                                  (Millions, except ratios)
                                                                             
Earnings as Defined in Regulation S-K (A):

Pre-tax Income from Continuing Operations         $ 324   $ 295   $ 705   $ 551   $ 815   $ 781   $ 644
Fixed Charges                                       115     109     228     225     219     219     213
Capitalized Interest                                (26)    (51)    (89)   (107)   (106)    (93)    (62)
Preferred Stock Dividend Requirements                --      --      --      --      --      --      --
                                                  ------------------------------------------------------

Total Earnings                                    $ 413   $ 353   $ 844   $ 669   $ 928   $ 907   $ 795
                                                  ======================================================

Fixed Charges as Defined in Regulation S-K (B)

Interest Expense                                  $ 115   $ 108   $ 226   $ 224   $ 217   $ 217   $ 206
Preferred Securities Dividend Requirements
of Subsidiaries                                      --      --      --      --      --      --      --
Interest Factor in Rentals                           --       1       2       1       2       2       7
                                                  ------------------------------------------------------

Total Fixed Charges                               $ 115   $ 109   $ 228   $ 225   $ 219   $ 219   $ 213
                                                  ======================================================

Ratio of Earnings to Fixed Charges                 3.59    3.24    3.70    2.97    4.24    4.14    3.73
                                                  ======================================================


(A)   The term "earnings" shall be defined as pre-tax Income from Continuing
      Operations. Add to pre-tax income the amount of fixed charges adjusted to
      exclude the amount of any interest capitalized during the period.

(B)   Fixed Charges represent (a) interest, whether expensed or capitalized, (b)
      amortization of debt discount, premium and expense and (c) an estimate of
      interest implicit in rentals.

EX-12

                                                                    EXHIBIT 12.4

                           PSEG ENERGY HOLDINGS L.L.C.
               COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES



                                                  For the Six
                                                  Months Ended                For the Years Ended
                                                    June 30,                      December 31,
                                                -------------------------------------------------------------
                                                 2006     2005     2005     2004     2003     2002     2001
                                                -------------------------------------------------------------
                                                                                 
Earnings as Defined in Regulation S-K (A):

Pre-tax (Loss) Income from Continuing
Operations                                      $ (127)  $   95   $  269   $  199   $  249   $ (369)  $  237
(Income)/Loss from Equity Investees, Net
of Distributions                                   (31)     (10)     (28)      78       60       (2)     (59)
Fixed Charges                                      102      113      214      224      215      219      186
Capitalized Interest                                --       (1)      (1)      (3)     (10)     (12)     (13)
                                                -------------------------------------------------------------
Total Earnings                                  $  (56)  $  197   $  454   $  498   $  514   $ (164)  $  351
                                                =============================================================

Fixed Charges as Defined in Regulation S-K
(B)

Interest Expense                                $  101   $  112   $  213   $  223   $  214   $  218   $  183
Interest Factor in Rentals                           1        1        1        1        1        1        3
                                                -------------------------------------------------------------
Total Fixed Charges                             $  102   $  113   $  214   $  224   $  215   $  219   $  186
                                                =============================================================

Ratio of Earnings to Fixed Charges (C)           (0.55)    1.74     2.12     2.22     2.39    (0.75)    1.88
                                                =============================================================


(A)   The term "earnings" is defined as pre-tax income from continuing
      operations before income or loss from equity investees plus distributed
      income from equity investees. Add to pre-tax income the amount of fixed
      charges adjusted to exclude the amount of any interest capitalized during
      the period.

(B)   Fixed Charges represent (a) interest, whether expensed or capitalized, (b)
      amortization of debt discount, premium and expense (c) an estimate of
      interest implicit in rentals.

(C)   The ratio of earnings to fixed charges for the six months ended June 30,
      2006 was (0.55), as noted above, which represents a deficiency of $158
      million. The ratio of earnings to fixed charges for the year ended
      December 31, 2002 was (0.75), as noted above, which represents a
      deficiency of $383 million.

EX-31

                                                                      EXHIBIT 31

                Certification Pursuant to Rules 13a-14 and 15d-14
                       of the 1934 Securities Exchange Act

I, E. James Ferland, certify that:

      1.    I have reviewed this Quarterly Report on Form 10-Q of Public Service
            Enterprise Group Incorporated;

      2.    Based on my knowledge, this report does not contain any untrue
            statement of a material fact or omit to state a material fact
            necessary to make the statements made, in light of the circumstances
            under which such statements were made, not misleading with respect
            to the period covered by this report;

      3.    Based on my knowledge, the financial statements, and other financial
            information included in this report, fairly present in all material
            respects the financial condition, results of operations and cash
            flows of the registrant as of, and for, the periods presented in
            this report;

      4.    The registrant's other certifying officer(s) and I are responsible
            for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
            internal control over financial reporting (as defined in Exchange
            Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

            (a)   Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;

            (b)   Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;

            (c)   Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and

            (d)   Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  second fiscal quarter in the case of this quarterly report)
                  that has materially affected, or is reasonably likely to
                  materially affect, the registrant's internal control over
                  financial reporting; and

      5.    The registrant's other certifying officer(s) and I have disclosed,
            based on our most recent evaluation of internal control over
            financial reporting, to the registrant's auditors and the audit
            committee of the registrant's board of directors (or persons
            performing the equivalent functions):

            (a)   All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and

            (b)   Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.

Date: August 1, 2006              /s/ E. James Ferland
                                 -----------------------------------------------
                                  E. James Ferland
                                  Public Service Enterprise Group Incorporated
                                  Chief Executive Officer

EX-31

                                                                    EXHIBIT 31.1

                Certification Pursuant to Rules 13a-14 and 15d-14
                       of the 1934 Securities Exchange Act

I, Thomas M. O'Flynn, certify that:

      1.    I have reviewed this Quarterly Report on Form 10-Q of Public Service
            Enterprise Group Incorporated;

      2.    Based on my knowledge, this report does not contain any untrue
            statement of a material fact or omit to state a material fact
            necessary to make the statements made, in light of the circumstances
            under which such statements were made, not misleading with respect
            to the period covered by this report;

      3.    Based on my knowledge, the financial statements, and other financial
            information included in this report, fairly present in all material
            respects the financial condition, results of operations and cash
            flows of the registrant as of, and for, the periods presented in
            this report;

      4.    The registrant's other certifying officer(s) and I are responsible
            for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
            internal control over financial reporting (as defined in Exchange
            Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

            (a)   Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;

            (b)   Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;

            (c)   Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and

            (d)   Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  second fiscal quarter in the case of this quarterly report)
                  that has materially affected, or is reasonably likely to
                  materially affect, the registrant's internal control over
                  financial reporting; and

      5.    The registrant's other certifying officer(s) and I have disclosed,
            based on our most recent evaluation of internal control over
            financial reporting, to the registrant's auditors and the audit
            committee of the registrant's board of directors (or persons
            performing the equivalent functions):

            (a)   All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and

            (b)   Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.

Date: August 1, 2006             /s/ Thomas M. O'Flynn
                                ------------------------------------------------
                                 Thomas M. O'Flynn
                                 Public Service Enterprise Group Incorporated
                                 Chief Financial Officer

EX-31

                                                                    EXHIBIT 31.2

                Certification Pursuant to Rules 13a-14 and 15d-14
                       of the 1934 Securities Exchange Act

I, E. James Ferland, certify that:

      1.    I have reviewed this Quarterly Report on Form 10-Q of Public Service
            Electric and Gas Company;

      2.    Based on my knowledge, this report does not contain any untrue
            statement of a material fact or omit to state a material fact
            necessary to make the statements made, in light of the circumstances
            under which such statements were made, not misleading with respect
            to the period covered by this report;

      3.    Based on my knowledge, the financial statements, and other financial
            information included in this report, fairly present in all material
            respects the financial condition, results of operations and cash
            flows of the registrant as of, and for, the periods presented in
            this report;

      4.    The registrant's other certifying officer(s) and I are responsible
            for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
            internal control over financial reporting (as defined in Exchange
            Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

            (a)   Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;

            (b)   Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;

            (c)   Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and

            (d)   Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  second fiscal quarter in the case of this quarterly report)
                  that has materially affected, or is reasonably likely to
                  materially affect, the registrant's internal control over
                  financial reporting; and

      5.    The registrant's other certifying officer(s) and I have disclosed,
            based on our most recent evaluation of internal control over
            financial reporting, to the registrant's auditors and the audit
            committee of the registrant's board of directors (or persons
            performing the equivalent functions):

            (a)   All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and

            (b)   Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.

Date: August 1, 2006                  /s/ E. James Ferland
                                     -------------------------------------------
                                      E. James Ferland
                                      Public Service Electric and Gas Company
                                      Chief Executive Officer

EX-31

                                                                    EXHIBIT 31.3

                Certification Pursuant to Rules 13a-14 and 15d-14
                       of the 1934 Securities Exchange Act

I, Robert E. Busch, certify that:

      1.    I have reviewed this Quarterly Report on Form 10-Q of Public Service
            Electric and Gas Company;

      2.    Based on my knowledge, this report does not contain any untrue
            statement of a material fact or omit to state a material fact
            necessary to make the statements made, in light of the circumstances
            under which such statements were made, not misleading with respect
            to the period covered by this report;

      3.    Based on my knowledge, the financial statements, and other financial
            information included in this report, fairly present in all material
            respects the financial condition, results of operations and cash
            flows of the registrant as of, and for, the periods presented in
            this report;

      4.    The registrant's other certifying officer(s) and I are responsible
            for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
            internal control over financial reporting (as defined in Exchange
            Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

            (a)   Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;

            (b)   Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;

            (c)   Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and

            (d)   Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  second fiscal quarter in the case of this quarterly report)
                  that has materially affected, or is reasonably likely to
                  materially affect, the registrant's internal control over
                  financial reporting; and

      5.    The registrant's other certifying officer(s) and I have disclosed,
            based on our most recent evaluation of internal control over
            financial reporting, to the registrant's auditors and the audit
            committee of the registrant's board of directors (or persons
            performing the equivalent functions):

            (a)   All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and

            (b)   Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.

Date: August 1, 2006                  /s/ Robert E. Busch
                                     -------------------------------------------
                                      Robert E. Busch
                                      Public Service Electric and Gas Company
                                      Chief Financial Officer

EX-31

                                                                    EXHIBIT 31.4

                Certification Pursuant to Rules 13a-14 and 15d-14
                       of the 1934 Securities Exchange Act

I, E. James Ferland, certify that:

      1.    I have reviewed this Quarterly Report on Form 10-Q of PSEG Power
            LLC;

      2.    Based on my knowledge, this report does not contain any untrue
            statement of a material fact or omit to state a material fact
            necessary to make the statements made, in light of the circumstances
            under which such statements were made, not misleading with respect
            to the period covered by this report;

      3.    Based on my knowledge, the financial statements, and other financial
            information included in this report, fairly present in all material
            respects the financial condition, results of operations and cash
            flows of the registrant as of, and for, the periods presented in
            this report;

      4.    The registrant's other certifying officer(s) and I are responsible
            for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
            internal control over financial reporting (as defined in Exchange
            Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

            (a)   Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;

            (b)   Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;

            (c)   Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and

            (d)   Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  second fiscal quarter in the case of this quarterly report)
                  that has materially affected, or is reasonably likely to
                  materially affect, the registrant's internal control over
                  financial reporting; and

      5.    The registrant's other certifying officer(s) and I have disclosed,
            based on our most recent evaluation of internal control over
            financial reporting, to the registrant's auditors and the audit
            committee of the registrant's board of directors (or persons
            performing the equivalent functions):

            (a)   All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and

            (b)   Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.

Date: August 1, 2006                         /s/ E. James Ferland
                                            ------------------------------------
                                             E. James Ferland
                                             PSEG Power LLC
                                             Chief Executive Officer

EX-31

                                                                    EXHIBIT 31.5

                Certification Pursuant to Rules 13a-14 and 15d-14
                       of the 1934 Securities Exchange Act

I, Thomas M. O'Flynn, certify that:

      1.    I have reviewed this Quarterly Report on Form 10-Q of PSEG Power
            LLC;

      2.    Based on my knowledge, this report does not contain any untrue
            statement of a material fact or omit to state a material fact
            necessary to make the statements made, in light of the circumstances
            under which such statements were made, not misleading with respect
            to the period covered by this report;

      3.    Based on my knowledge, the financial statements, and other financial
            information included in this report, fairly present in all material
            respects the financial condition, results of operations and cash
            flows of the registrant as of, and for, the periods presented in
            this report;

      4.    The registrant's other certifying officer(s) and I are responsible
            for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
            internal control over financial reporting (as defined in Exchange
            Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

            (a)   Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;

            (b)   Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;

            (c)   Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and

            (d)   Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  second fiscal quarter in the case of this quarterly report)
                  that has materially affected, or is reasonably likely to
                  materially affect, the registrant's internal control over
                  financial reporting; and

      5.    The registrant's other certifying officer(s) and I have disclosed,
            based on our most recent evaluation of internal control over
            financial reporting, to the registrant's auditors and the audit
            committee of the registrant's board of directors (or persons
            performing the equivalent functions):

            (a)   All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and

            (b)   Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.

Date: August 1, 2006                       /s/ Thomas M. O'Flynn
                                          --------------------------------------
                                           Thomas M. O'Flynn
                                           PSEG Power LLC
                                           Chief Financial Officer

EX-31

                                                                    EXHIBIT 31.6

                Certification Pursuant to Rules 13a-14 and 15d-14
                       of the 1934 Securities Exchange Act

I, E. James Ferland, certify that:

      1.    I have reviewed this Quarterly Report on Form 10-Q of PSEG Energy
            Holdings L.L.C.;

      2.    Based on my knowledge, this report does not contain any untrue
            statement of a material fact or omit to state a material fact
            necessary to make the statements made, in light of the circumstances
            under which such statements were made, not misleading with respect
            to the period covered by this report;

      3.    Based on my knowledge, the financial statements, and other financial
            information included in this report, fairly present in all material
            respects the financial condition, results of operations and cash
            flows of the registrant as of, and for, the periods presented in
            this report;

      4.    The registrant's other certifying officer(s) and I are responsible
            for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
            internal control over financial reporting (as defined in Exchange
            Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

            (a)   Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;

            (b)   Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;

            (c)   Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and

            (d)   Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  second fiscal quarter in the case of this quarterly report)
                  that has materially affected, or is reasonably likely to
                  materially affect, the registrant's internal control over
                  financial reporting; and

      5.    The registrant's other certifying officer(s) and I have disclosed,
            based on our most recent evaluation of internal control over
            financial reporting, to the registrant's auditors and the audit
            committee of the registrant's board of directors (or persons
            performing the equivalent functions):

            (a)   All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and

            (b)   Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.

Date: August 1, 2006                      /s/ E. James Ferland
                                         ---------------------------------------
                                          E. James Ferland
                                          PSEG Energy Holdings L.L.C.
                                          Chief Executive Officer

EX-31

                                                                    EXHIBIT 31.7

                Certification Pursuant to Rules 13a-14 and 15d-14
                       of the 1934 Securities Exchange Act

I, Thomas M. O'Flynn, certify that:

      1.    I have reviewed this Quarterly Report on Form 10-Q of PSEG Energy
            Holdings L.L.C.;

      2.    Based on my knowledge, this report does not contain any untrue
            statement of a material fact or omit to state a material fact
            necessary to make the statements made, in light of the circumstances
            under which such statements were made, not misleading with respect
            to the period covered by this report;

      3.    Based on my knowledge, the financial statements, and other financial
            information included in this report, fairly present in all material
            respects the financial condition, results of operations and cash
            flows of the registrant as of, and for, the periods presented in
            this report;

      4.    The registrant's other certifying officer(s) and I are responsible
            for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
            internal control over financial reporting (as defined in Exchange
            Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

            (a)   Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;

            (b)   Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;

            (c)   Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and

            (d)   Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  second fiscal quarter in the case of this quarterly report)
                  that has materially affected, or is reasonably likely to
                  materially affect, the registrant's internal control over
                  financial reporting; and

      5.    The registrant's other certifying officer(s) and I have disclosed,
            based on our most recent evaluation of internal control over
            financial reporting, to the registrant's auditors and the audit
            committee of the registrant's board of directors (or persons
            performing the equivalent functions):

            (a)   All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and

            (b)   Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.

Date: August 1, 2006                         /s/ Thomas M. O'Flynn
                                            ------------------------------------
                                             Thomas M. O'Flynn
                                             PSEG Energy Holdings L.L.C.
                                             Chief Financial Officer

EX-32

                                                                      EXHIBIT 32

        Certification Pursuant to Section 1350 of Chapter 63 of Title 18
                            of the United States Code

      I, E. James Ferland, Chief Executive Officer of Public Service Enterprise
Group Incorporated, to the best of my knowledge, certify that (i) the Quarterly
Report of Public Service Enterprise Group Incorporated on Form 10-Q for the
period ended June 30, 2006 (the "Report") fully complies with the requirements
of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of Public Service Enterprise
Group Incorporated.

                                 /s/ E. James Ferland
                                ------------------------------------------------
                                 E. James Ferland
                                 Public Service Enterprise Group Incorporated
                                 Chief Executive Officer
                                 August 1, 2006

EX-32

                                                                    EXHIBIT 32.1

        Certification Pursuant to Section 1350 of Chapter 63 of Title 18
                            of the United States Code

      I, Thomas M. O'Flynn, Chief Financial Officer of Public Service Enterprise
Group Incorporated, to the best of my knowledge, certify that (i) the Quarterly
Report of Public Service Enterprise Group Incorporated on Form 10-Q for the
period ended June 30, 2006 (the "Report") fully complies with the requirements
of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of Public Service Enterprise
Group Incorporated.

                                 /s/ Thomas M. O'Flynn
                                ------------------------------------------------
                                 Thomas M. O'Flynn
                                 Public Service Enterprise Group Incorporated
                                 Chief Financial Officer
                                 August 1, 2006

EX-32

                                                                    EXHIBIT 32.2

        Certification Pursuant to Section 1350 of Chapter 63 of Title 18
                            of the United States Code

      I, E. James Ferland, Chief Executive Officer of Public Service Electric
and Gas Company, to the best of my knowledge, certify that (i) the Quarterly
Report of Public Service Electric and Gas Company on Form 10-Q for the period
ended June 30, 2006 (the "Report") fully complies with the requirements of
Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the
information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of Public Service Electric and
Gas Company.

                                    /s/ E. James Ferland
                                   ---------------------------------------------
                                    E. James Ferland
                                    Public Service Electric and Gas Company
                                    Chief Executive Officer
                                    August 1, 2006

EX-32

                                                                    EXHIBIT 32.3

        Certification Pursuant to Section 1350 of Chapter 63 of Title 18
                            of the United States Code

      I, Robert E. Busch, Chief Financial Officer of Public Service Electric and
Gas Company, to the best of my knowledge, certify that (i) the Quarterly Report
of Public Service Electric and Gas Company on Form 10-Q for the period ended
June 30, 2006 (the "Report") fully complies with the requirements of Section
13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information
contained in the Report fairly presents, in all material respects, the financial
condition and results of operations of Public Service Electric and Gas Company.

                                      /s/ Robert E. Busch
                                     -------------------------------------------
                                      Robert E. Busch
                                      Public Service Electric and Gas Company
                                      Chief Financial Officer
                                      August 1, 2006

EX-32

                                                                    EXHIBIT 32.4

        Certification Pursuant to Section 1350 of Chapter 63 of Title 18
                            of the United States Code

      I, E. James Ferland, Chief Executive Officer of PSEG Power LLC, to the
best of my knowledge, certify that (i) the Quarterly Report of PSEG Power LLC on
Form 10-Q for the period ended June 30, 2006 (the "Report") fully complies with
the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934 and (ii) the information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations of PSEG
Power LLC.

                                             /s/ E. James Ferland
                                            ------------------------------------
                                             E. James Ferland
                                             PSEG Power LLC
                                             Chief Executive Officer
                                             August 1, 2006

EX-32

                                                                    EXHIBIT 32.5

        Certification Pursuant to Section 1350 of Chapter 63 of Title 18
                            of the United States Code

      I, Thomas M. O'Flynn, Chief Financial Officer of PSEG Power LLC, to the
best of my knowledge, certify that (i) the Quarterly Report of PSEG Power LLC on
Form 10-Q for the period ended June 30, 2006 (the "Report") fully complies with
the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934 and (ii) the information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations of PSEG
Power LLC.

                                            /s/ Thomas M. O'Flynn
                                           -------------------------------------
                                            Thomas M. O'Flynn
                                            PSEG Power LLC
                                            Chief Financial Officer
                                            August 1, 2006

EX-32

                                                                    EXHIBIT 32.6

        Certification Pursuant to Section 1350 of Chapter 63 of Title 18
                            of the United States Code

      I, E. James Ferland, Chief Executive Officer of PSEG Energy Holdings
L.L.C., to the best of my knowledge, certify that (i) the Quarterly Report of
PSEG Energy Holdings L.L.C. on Form 10-Q for the period ended June 30, 2006 (the
"Report") fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934 and (ii) the information contained in the Report
fairly presents, in all material respects, the financial condition and results
of operations of PSEG Energy Holdings L.L.C.

                                          /s/ E. James Ferland
                                         ---------------------------------------
                                          E. James Ferland
                                          PSEG Energy Holdings L.L.C.
                                          Chief Executive Officer
                                          August 1, 2006

EX-32

                                                                    EXHIBIT 32.7

        Certification Pursuant to Section 1350 of Chapter 63 of Title 18
                            of the United States Code

      I, Thomas M. O'Flynn, Chief Financial Officer of PSEG Energy Holdings
L.L.C., to the best of my knowledge, certify that (i) the Quarterly Report of
PSEG Energy Holdings L.L.C. on Form 10-Q for the period ended June 30, 2006 (the
"Report") fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934 and (ii) the information contained in the Report
fairly presents, in all material respects, the financial condition and results
of operations of PSEG Energy Holdings L.L.C.

                                             /s/ Thomas M. O'Flynn
                                            ------------------------------------
                                             Thomas M. O'Flynn
                                             PSEG Energy Holdings L.L.C.
                                             Chief Financial Officer
                                             August 1, 2006