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

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED MARCHJUNE 3130, 2003

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	~~Registrants,~~I.R.S. ~~State~~Employer ofIdentification ~~Incorporation, Address, and Telephone Number~~No.		~~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	~~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		~~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	~~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		~~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	~~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		~~22-3663480~~
	000-32503	PSEG ENERGY HOLDINGS LLC (A New Jersey Limited Liability Company) 80 Park Plaza—T22 Newark, New Jersey 07102-4194 973 456-3581 http://www.pseg.com	~~PSEG Energy Holdings LLC (A New Jersey Limited Liability Company) 80 Park Plaza—T22 Newark, New Jersey 07102-4194 (973) 456-3581 http://www.pseg.com~~	22-2983750		~~22-2983750~~

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

As of ~~April 30~~ July 25, 2003, Public Service Enterprise Group Incorporated had outstanding ~~225~~ 226,~~887~~367,~~080~~848 shares of its sole class of Common Stock, without par value.

As of ~~April 30~~July 25, 2003, 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 LLC 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.

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). ~~Yes [X] No [ ]~~

Public Service Enterprise Group Incorporated	Yes [X]	No [ ]
Public Service Electric and Gas Company	Yes [ ]	No [X]
PSEG Power LLC	Yes [ ]	No [X]
PSEG Energy Holdings LLC	Yes [ ]	No [X]

		Page
Part I. Financial Information
FORWARD-LOOKING STATEMENTS			ii
Item 1.	Consolidated Financial Statements
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 LLC		12
	Notes to Consolidated Financial Statements		16
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		42
	Note 1. Organization and Basis of Presentation		16
	Overview		42
	Note 2. New Accounting Standards		17
	Results of Operations		44
	Note 3. Adoption of SFAS 143		21
	Liquidity and Capital Resources		51
	Note 4. Earnings Per Share		22
	Capital Requirements		56
	Note 5. Discontinued Operations		23
	Accounting Issues		57
	Note 6. Regulatory Assets and Liabilities		25
	Forward-Looking Statements		58
	Note 7. Commitments and Contingent Liabilities		26
Item 3.	Qualitative and Quantitative Disclosures About Market Risk		60
	Note 8. Risk Management		32
Item 4.	Controls and Procedures		62
	Note 9. Comprehensive Income		35
Part II. Other Information
	Note 10. Other Income and Deductions		36
Item 1.	Legal Proceedings		63
	Note 11. Income Taxes		37
Item 4.	Submission of Matters to a Vote of Security Holders		63
	Note 12. Financial Information by Business Segment		38
Item 5.	Other Information		64
	Note 13. Stock-Based Compensation		39
Item 6.	Exhibits and Reports on Form 8-K		67
	Note 14. Related-Party Transactions		39
Signatures			69
	Note 15. Guarantees of Debt		42
	Note 16. Subsequent Events		43
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		45
	Overview		45
	Results of Operations		49
	Liquidity and Capital Resources		60
	Capital Requirements		67
	Accounting Issues		67
Item 3.	Qualitative and Quantitative Disclosures About Market Risk		69
Item 4.	Controls and Procedures		75
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		76
Item 5.	Other Information		76
Item 6.	Exhibits and Reports on Form 8-K		81
Signatures			83

PARTFORWARD-LOOKING I FINANCIAL INFORMATIONSTATEMENTS

~~Item~~ Except 1for the historical information contained herein, certain of the matters discussed in this report constitute ''forward-looking statements'' within the meaning of the Private Securities Litigation Reform Act of 1995. ~~Financial~~Such ~~Statements~~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 ''will'', ''anticipate'', ''intend'', ''estimate'', ''believe'', ''expect'', ''plan'', ''hypothetical'', ''potential'', ''forecast'', ''projections'', 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 LLC (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 of factors should not be construed as exhaustive.

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:

PSEG, PSE&G, Power and Energy Holdings

		•		credit, commodity, interest rate, counterparty and other financial market risks;
		•		liquidity and the ability to access capital and credit markets;
		•		acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG's, PSE&G's, Power's and Energy Holdings' structure;
		•		business combinations among competitors and major customers;
		•		general economic conditions including inflation;
		•		changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements;
		•		changes in tax laws and regulations;
		•		energy obligations, available supply and trading risks;
		•		changes in the electric industry including changes to power pools;
		•		regulation and availability of power transmission facilities that impact the ability to deliver output to customers;
		•		growth in costs and expenses;
		•		environmental regulation that significantly impact operations;
		•		changes in rates of return on overall debt and equity markets could have an adverse impact on the value of pension assets and the Nuclear Decommissioning Trust Fund;
		•		changes in political conditions, recession, acts of war or terrorism;
		•		insufficient insurance coverage;
		•		involvement in lawsuits including liability claims and commercial disputes could affect profits or the ability to sell and market products;
		•		inability to attract and retain management and other key employees;
		•		ability to service debt as a result of any of the aforementioned events;

PSE&G and Energy Holdings

		•		ability to obtain adequate and timely rate relief;
		•		regulatory issues that significantly impact operations;

Power and Energy Holdings

		•		adverse changes in the market place for energy prices;
		•		excess supply due to overbuild in the industry;
		•		generation operating performance may fall below projected levels;
		•		substantial competition from well capitalized participants in the worldwide energy markets;
		•		inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations;
		•		margin posting requirements;
		•		availability of fuel at reasonable prices;
		•		competitive position could be adversely affected by actions involving competitors or major customers;
		•		changes in product or sourcing mix;
		•		tardy or unsuccessful acquisition, construction and development;
		•		changes in technology that make power generation assets less competitive;

Power

•

changes in regulation and security measures at nuclear facilities;

Energy Holdings

		•		adverse international developments that negatively impact its business;
		•		changes in foreign currency exchange rates;
		•		substandard operating performance or cash flow from investments could fall below projected levels, adversely impacting the ability to service its debt; and
		•		credit of lessees to service the leases.

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 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 disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. In making any investment decision regarding PSEG, PSE&G, Power 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
CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Quarters Ended March 31,
	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
	(Millions, except share data) (Unaudited)
	(Millions, except for Share Data) (Unaudited)
Operating Revenues	$	3,364		$	1,883
OPERATING REVENUES	$	2,419		$	1,415		$	5,725		$	3,298
Operating Expenses
OPERATING EXPENSES
Energy Costs		21,~~022~~412			~~740~~449			3,376			1,189
Operation and Maintenance		~~520~~487			~~463~~457			1,007			920
Depreciation and Amortization		100			131
Write-down of Project Investments		—			506			—			506
Taxes Other Than Income Taxes		44			38
Depreciation and Amortization		103			135			203			266
Total Operating Expenses		2,686			1,372
Taxes Other Than Income Taxes		28			26			72			64
Income from Equity Method Investments		17			30
Total Operating Expenses		2,030			1,573			4,658			2,945
Operating Income		695			541
Income from Equity Method Investments		31			33			48			63
Other Income		60			11
OPERATING INCOME (LOSS)		420			(125	)		1,115			416
Other Deductions		(45	)		(52	)
Other Income		30			7			88			9
Interest Expense		(187	)		(191	)
Other Deductions		(21	)		(27	)		(64	)		(70	)
Preferred Securities Dividends		(18	)		(14	)
Interest Expense		(190	)		(188	)		(377	)		(379	)
Income from Continuing Operations Before Income Taxes		505			295
Preferred Securities Dividends		(18	)		(14	)		(36	)		(28	)
Income Taxes		(184	)		(114	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		221			(347	)		726			(52	)
Income from Continuing Operations		321			181
Income Taxes		(71	)		120			(255	)		6
Loss from Discontinued Operations, net of tax benefit (expense) of $3 and ($1) in 2003 and 2002, respectively, including $9 Loss on Disposal, net of tax benefit of $2 in 2003		(15	)		(1	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		150			(227	)		471			(46	)
Income Before Cumulative Effect of a Change in Accounting Principle		306			180
Loss from Discontinued Operations, including Loss on Disposal, net of tax		(2	)		(37	)		(17	)		(38	)
Cumulative Effect of a Change in Accounting Principle, net of tax (expense) benefit of ($255) and $66 in 2003 and 2002, respectively		370			(120	)
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		148			(264	)		454			(84	)
Net Income	$	676		$	60
Extraordinary Item, net of tax benefit of $12		(18	)		—			(18	)		—
Weighted Average Common Shares Outstanding (000s)		225,714			206,340
Cumulative Effect of a Change in Accounting Principle, net of tax (expense) benefit of ($255) and $66 in 2003 and 2002, respectively		—			—			370			(120	)
Earnings Per Share (Basic and Diluted):
NET INCOME (LOSS)	$	130		$	(264	)	$	806		$	(204	)
Income from Continuing Operations	$	1.42		$	0.88
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Loss from Discontinued Operations, net of tax		(0.06	)		(0.01	)
BASIC		225,910			206,246			225,627			206,049
Cumulative Effect of a Change in Accounting Principle, net of tax		1.64			(0.58	)
DILUTED		226,582			206,927			226,108			206,631
Net Income	$	3.00		$	0.29
EARNINGS PER SHARE:
Dividends Paid Per Share of Common Stock	$	0.54		$	0.54
BASIC
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	0.67		$	(1.10	)	$	2.09		$	(0.22	)
NET INCOME (LOSS)	$	0.58		$	(1.28	)	$	3.57		$	(0.99	)
DILUTED
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	0.66		$	(1.10	)	$	2.09		$	(0.22	)
NET INCOME (LOSS)	$	0.57		$	(1.28	)	$	3.57		$	(0.99	)
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.54		$	0.54		$	1.08		$	1.08

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS

	March 31, 2003			December 31, 2002
	June 30, 2003			December 31, 2002
	(Millions) (Unaudited)
ASSETS
Current Assets
CURRENT ASSETS
Cash and Cash Equivalents	$	~~218~~150		$	165
Accounts Receivable, Net of Allowances of $83 and $34 in 2003 and 2002, respectively		1,863			1,370
Accounts Receivable, net of allowances of $86 and $34 in 2003 and 2002, respectively		1,377			1,370
Unbilled Electric and Gas Revenues		~~210~~171			275
Fuel		~~209~~416			412
Materials and Supplies		~~221~~226			208
Energy Trading Contracts		~~180~~155			157
Restricted Cash		2637			32
Assets Held for Sale		8372			83
Current Assets of Discontinued Operations		44			107
Prepayments		297			60
Other		123			135
Current Assets of Discontinued Operations		31			107
Total Current Assets		3,177			2,944
Other		37			75
Property, Plant and Equipment		16,950			16,562
Total Current Assets		2,969			2,944
Less: Accumulated Depreciation and Amortization		(5,258	)		(5,113	)
PROPERTY, PLANT AND EQUIPMENT		17,329			16,571
Net Property, Plant and Equipment		11,692			11,449
Less: Accumulated Depreciation and Amortization		(5,193	)		(5,113	)
Noncurrent Assets
Net Property, Plant and Equipment		12,136			11,458
Regulatory Assets		4,955			5,002
NONCURRENT ASSETS
Long-Term Investments		4,613			4,581
Regulatory Assets		4,975			5,002
Nuclear Decommissioning Trust (NDT) Funds		772			766
Long-Term Investments		4,687			4,580
Other Special Funds		88			72
Nuclear Decommissioning Trust (NDT) Funds		869			766
Goodwill		433			452
Other Special Funds		91			72
Other Intangibles		207			206
Goodwill		442			452
Energy Trading Contracts		19			21
Other Intangibles		206			206
Other		207			226
Energy Trading Contracts		23			21
Total Noncurrent Assets		11,294			11,326
Other		172			201
Total Assets	$	26,163		$	25,719
Total Noncurrent Assets		11,465			11,300
TOTAL ASSETS	$	26,570		$	25,702

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS

	March 31, 2003			December 31, 2002
	June 30, 2003			December 31, 2002
	(Millions) (Unaudited)
LIABILITIES AND CAPITALIZATION
Current Liabilities
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	~~859~~733		$	749
Commercial Paper and Loans		~~640~~1,070			762
Accounts Payable		1,~~313~~117			1,115
Energy Trading Contracts		~~119~~85			101
Accrued Taxes		~~184~~72			229
Current Liabilities of Discontinued Operations		4431			83
Other		~~776~~762			755
Total Current Liabilities		3,~~935~~870			3,794
Noncurrent Liabilities
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		3,~~364~~526			2,~~924~~918
Regulatory Liabilities		~~198~~362			252
Nuclear Decommissioning Liabilities		~~267~~273			766
Other Postemployment Benefit (OPEB) Costs		~~512~~513			501
Accrued Pension Costs		~~373~~297			336
Cost of Removal		—			131
Other		~~655~~639			~~637~~634
Total Noncurrent Liabilities		5,~~369~~610			5,~~547~~538
Commitments and Contingent Liabilities (See Note 5)
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
Capitalization
CAPITALIZATION
Long-Term Debt
LONG-TERM DEBT
Long-Term Debt		67,~~989~~060			7,116
Securitization Debt		2,~~190~~160			2,222
Project Level, Non-Recourse Debt		1,~~695~~808			1,653
Total Long-Term Debt		1011,~~874~~028			10,991
Subsidiaries' Preferred Securities
SUBSIDIARIES' PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption		80			80
Preferred Stock With Mandatory Redemption		460			460
Guaranteed Preferred Beneficial Interest in Subordinated Debentures		860			860
Total Subsidiaries' Preferred Securities		1,400			1,400
Common Stockholders' Equity
COMMON STOCKHOLDERS' EQUITY
Common Stock, issued; 2003—251,956,396 shares 2002—251,385,937 shares		4,078			4,056
Common Stock, issued; 2003—252,460,006 shares 2002—251,385,937 shares		4,100			4,056
Treasury Stock, at cost; 2003 and 2002—26,118,590 shares		(981	)		(981	)
Retained Earnings		2,~~158~~160			1,601
Accumulated Other Comprehensive Loss		(~~670~~617	)		(~~689~~697	)
Total Common Stockholders' Equity		4,~~585~~662			3,~~987~~979
Total Capitalization		1617,~~859~~090			16,~~378~~370
Total Liabilities and Capitalization	$	26,163		$	25,719
TOTAL LIABILITIES AND CAPITALIZATION	$	26,570		$	25,702

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Quarters Ended March 31,
	For the Six Months Ended June 30,
	2003			2002
	(Millions) (Unaudited)
Cash Flows From Operating Activities
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	676		$	60
Net Income (Loss)	$	806		$	(204	)
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Extraordinary Item, net of tax		18			—
Write-Down of Project Investments		—			506
Loss on Disposal of Discontinued Operations, net of tax		9			34
Cumulative Effect of a Change in Accounting Principle, net of tax		(370	)		120
Depreciation and Amortization		~~100~~203			~~131~~266
Provision for Deferred Income Taxes (Other Than Leases) and ITC		10			16
Amortization of Nuclear Fuel		46			42
Non-Cash Employee Benefit Plan Costs		44			49
Provision for Deferred Income Taxes (Other than Leases) and ITC		59			(154	)
Income from NDT Funds		(14	)		—
Non-Cash Employee Benefit Plan Costs		126			97
Leveraged Lease Income, Adjusted for Rents Received		(235	)		1548
Foreign Currency Transaction (Gain) Loss		(3	)		52
Undistributed Earnings from Affiliates		(3	)		(17	)
Unrealized Losses (Gains) on Energy Contracts and Other Derivatives		2			(40	)
Foreign Currency Transaction Loss		—			69
Underrecovery of Electric Energy Costs (BGS and NTC) and Gas Costs		(16	)		(61	)
Unrealized Losses (Gains) on Energy Contracts and Other Derivatives		7			(37	)
Overrecovery of SBC		45			22
(Under) Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		(51	)		2
Other Non-Cash Charges		19			29
Over Recovery of SBC		91			34
Net Change in Certain Current Assets and Liabilities		116			41
Net Realized Gains and Income from NDT Fund		(28	)		—
Employee Benefit Plan Funding and Related Payments		(16	)		(86	)
Other Non-Cash Charges		5			31
Proceeds from the Withdrawal of Partnership Interests and Other Distributions		46			3
Net Change in Certain Current Assets and Liabilities		(176	)		(143	)
Other		34			(3	)
Employee Benefit Plan Funding and Related Payments		(153	)		(130	)
Net Cash Provided by Operating Activities		671			348
Proceeds from the Withdrawal of Partnership Interests and Other Distributions		47			4
Cash Flows from Investing Activities
Other		(43	)		(32	)
Additions to Property, Plant and Equipment		(341	)		(391	)
Net Cash Provided By Operating Activities		628			536
Investments in Joint Ventures, Partnerships and Capital Leases		(16	)		(95	)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Assets and Return of Capital from Partnerships		9			89
Additions to Property, Plant and Equipment		(715	)		(889	)
Other		(12	)		(64	)
Investments in Joint Ventures, Partnerships and Capital Leases		(17	)		(183	)
Net Cash Used In Investing Activities		(360	)		(461	)
Proceeds from the Sale of Investments and Return of Capital from Partnerships		2			90
Cash Flows From Financing Activities
Other		7			(96	)
Net Change in Short-Term Debt		(40	)		166
Net Cash Used In Investing Activities		(723	)		(1,078	)
Issuance of Long-Term Debt		392			73
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Common Stock		21			16
Net Change in Short-Term Debt		422			361
Redemptions of Long-Term Debt		(501	)		(25	)
Issuance of Long-Term Debt		476			733
Cash Dividends Paid on Common Stock		(122	)		(111	)
Issuance of Non-Recourse Debt		350			141
Other		(8	)		4
Issuance of Common Stock		42			36
Net Cash (Used In) Provided By Financing Activities		(258	)		123
Redemptions of Long-Term Debt		(933	)		(424	)
Effect of Exchange Rate Change		—			(4	)
Cash Dividends Paid on Common Stock		(244	)		(223	)
Net Change In Cash and Cash Equivalents		53			6
Other		(33	)		(1	)
Net Cash Provided By Financing Activities		80			623
Effect of Exhange Rate Change		—			(2	)
Net Change In Cash and Cash Equivalents		(15	)		79
Cash and Cash Equivalents at Beginning of Period		165			167
Cash and Cash Equivalents at End of Period	$	~~218~~150		$	~~173~~246
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	~~147~~150		$	~~119~~145
Interest Paid, Net of Amounts Capitalized	$	~~180~~383		$	~~188~~391

See Notes to Consolidated Financial Statements.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Quarters Ended March 31,
	For The Quarter Ended June 30,						For The Six Months Ended June 30,
	2003			2002			2003			2002
	(Millions) (Unaudited)
Operating Revenues	$	2,148		$	1,659
OPERATING REVENUES	$	1,342		$	1,230		$	3,490		$	2,889
Operating Expenses
OPERATING EXPENSES
Energy Costs		~~1,507~~919			~~1,059~~758			2,426			1,817
Operation and Maintenance		~~286~~224			~~254~~239			510			493
Depreciation and Amortization		6663			9597			129			192
Taxes Other Than Income Taxes		4428			3826			72			64
Total Operating Expenses		1,~~903~~234			1,~~446~~120			3,137			2,566
Operating Income		245			213
OPERATING INCOME		108			110			353			323
Other Income		103			—2			13			2
Other Deductions		(1—	)		—(1	)		(1	)		(1	)
Interest Expense		(94	)		(100	)		(188	)		(200	)
Preferred Securities Dividends		(3	)		(3	)		(6	)		(6	)
Income from Continuing Operations Before Income Taxes		157			110
INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM		14			8			171			118
Income Taxes		(56	)		(42	)
Income Benefit (Taxes)		8			—			(48	)		(42	)
Net Income		101			68
INCOME BEFORE EXTRAORDINARY ITEM		22			8			123			76
Preferred Stock Dividends		(1	)		(1	)
Extraordinary Item, net of tax benefit of $12		(18	)		—			(18	)		—
Earnings Available to Public Service Enterprise Group Incorporated	$	100		$	67
NET INCOME		4			8			105			76
Preferred Stock Dividends		(1	)		(1	)		(2	)		(2	)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	3		$	7		$	103		$	74

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS

	March 31, 2003			December 31, 2002
	June 30, 2003			December 31, 2002
	(Millions) (Unaudited)
ASSETS
Current Assets
CURRENT ASSETS
Cash and Cash Equivalents	$	~~117~~22		$	35
Accounts Receivable, Net of Allowances of $43 and $32 in 2003 and 2002, respectively		1,031			755
Accounts Receivable, net of allowances of $42 and $32 in 2003 and 2002, respectively		697			755
Unbilled Revenues		~~210~~171			275
Materials and Supplies		5157			45
Prepayments		11230			25
Restricted Cash		14			14
Other		2225			16
Total Current Assets		1,~~456~~216			1,165
Property, Plant and Equipment		9,663			9,581
PROPERTY, PLANT AND EQUIPMENT		9,785			9,581
Less: Accumulated Depreciation and Amortization		(3,~~675~~596	)		(3,604	)
Net Property, Plant and Equipment		56,~~988~~189			5,977
Noncurrent Assets
NONCURRENT ASSETS
Regulatory Assets		4,~~955~~975			5,002
Long-Term Investments		~~125~~127			123
Other Special Funds		4445			44
Intangibles		60			60
Other		5659			58
Total Noncurrent Assets		5,~~240~~266			5,287
Total Assets	$	12,684		$	12,429
TOTAL ASSETS	$	12,671		$	12,429

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS

	March 31, 2003			December 31, 2002
	June 30, 2003			December 31, 2002
	(Millions) (Unaudited)
LIABILITIES AND CAPITALIZATION
Current Liabilities
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	~~281~~419		$	429
Commercial Paper and Loans		~~166~~502			224
Accounts Payable		~~738~~513			724
Other		~~399~~336			315
Total Current Liabilities		1,~~584~~770			1,692
Noncurrent Liabilities
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credit (ITC)		2,441			2,436
Deferred Income Taxes and ITC		2,458			2,436
Regulatory Liabilities		~~198~~362			252
Other Postemployment Benefit (OPEB) Costs		494			486
OPEB Costs		495			486
Accrued Pension Costs		~~195~~151			175
Other		~~207~~181			209
Total Noncurrent Liabilities		3,~~535~~647			3,558
Commitments and Contingent Liabilities (See Note 5)
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
Capitalization Long-Term Debt
CAPITALIZATION
Long-Term Debt		2,777			2,627
LONG-TERM DEBT
Securitization Debt		2,190			2,222
Long-Term Debt		2,491			2,627
Total Long-Term Debt		4,967			4,849
Securitization Debt		2,160			2,222
Preferred Securities
Total Long-Term Debt		4,651			4,849
PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption		80			80
Subsidiaries' Preferred Securities with Mandatory Redemption		155			155
Subsidiaries' Preferred Securities With Mandatory Redemption		155			155
Total Preferred Securities		235			235
Common Stockholder's Equity
COMMON STOCKHOLDER'S EQUITY
Common Stock; 150,000,000 Shares Authorized, 132,450,344 Shares Issued and Outstanding		892			892
Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding		892			892
Contributed Capital		170			—
Basis Adjustment		986			986
Retained Earnings		~~488~~492			389
Accumulated Other Comprehensive Loss		(~~173~~172	)		(172	)
Total Common Stockholder's Equity		2,~~363~~368			2,095
Total Capitalization		7,~~565~~254			7,179
Total Liabilities and Capitalization	$	12,684		$	12,429
TOTAL LIABILITIES AND CAPITALIZATION	$	12,671		$	12,429

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Quarters Ended March 31,
	For the Six Months Ended June 30,
	2003			2002
	(Millions) (Unaudited)
Cash Flows from Operating Activities
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	~~101~~105		$	6876
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		66			95
Extraordinary Item, net of tax		18			—
Provision for Deferred Income Taxes and ITC		(17	)		(8	)
Depreciation and Amortization		129			192
Non-Cash Employee Benefit Plan Costs		25			37
Provision for Deferred Income Taxes and ITC		(11	)		(25	)
Non-Cash Interest Expense		5			4
Non-Cash Employee Benefit Plan Costs		88			72
Underrecovery of Electric Energy Costs (BGS and NTC)		(50	)		(11	)
Non-Cash Interest Expense		16			1
Over (Under) Recovery of Gas Costs		34			(50	)
(Under) Over Recovery of Electric Energy Costs (BGS and NTC)		(95	)		76
Overrecovery of SBC		45			22
Over (Under) Recovery of Gas Costs		44			(74	)
Gain on the Sale of Property, Plant and Equipment		(8	)		—
Over Recovery of SBC		91			34
Gain on the Sale of Property, Plant and Equipment		(8	)		(1	)
Other Non-Cash Regulatory Credits		(9	)		—
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		~~(211~~162	)		~~(70~~167	)
Natural Gas		—			~~248~~415
Prepayments		14			6
Fuel and Materials and Supplies		(12	)		(6	)
Accrued Taxes		46			29
Prepayments		(205	)		(235	)
Accounts Payable		14(211	)		(~~108~~138	)
Other Current Assets and Liabilities		385			494
Employee Benefit Plan Funding and Related Payments		(1295	)		(7589	)
Other		—(40	)		821
Net Cash Provided by Operating Activities		90			244
Net Cash (Used In) Provided By Operating Activities		(28	)		490
Cash Flows from Investing Activities
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(97229	)		(76196	)
Proceeds from the Sale of Property, Plant and Equipment		89			—1
Net Cash Used in Investing Activities		(89	)		(76	)
Net Cash Used In Investing Activities		(220	)		(195	)
Cash Flows From Financing Activities
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt		~~(58~~278	)		—
Issuance of Long-Term Debt		150			—
Redemption of Securitization Debt		(3058	)		(2551	)
Maturity of Long-Term Debt		(150	)		—
Redemption of Long-Term Debt		(300	)		—
Contributed Capital		170			—
Dividends on Common Stock		—			(150	)
Preferred Stock Dividends		(1	)		(1	)
Other		(5	)		(5	)
Net Cash Provided by (Used In) Financing Activities		81			(176	)
Net Cash Provided By (Used In) Financing Activities		235			(206	)
Net Change in Cash and Cash Equivalents		82			(8	)
Net Change In Cash and Cash Equivalents		(13	)		89
Cash and Cash Equivalents at Beginning of Period		35			102
Cash and Cash Equivalents at End of Period	$	~~117~~22		$	94191
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	5373		$	81117
Interest Paid, Net of Amounts Capitalized	$	~~102~~183		$	~~112~~202

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

PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Quarters Ended March 31,
	For the Quarter Ended June 30,						For the Six Months Ended June 30,
	2003			2002			2003			2002
	(Millions) (Unaudited)
Operating Revenues	$	1,887		$	576
OPERATING REVENUES	$	1,236		$	673		$	3,065		$	1,249
Operating Expenses
OPERATING EXPENSES
Energy Costs		~~1,348~~788			~~139~~284			2,078			423
Operation and Maintenance		~~202~~228			~~186~~189			430			375
Depreciation and Amortization		2324			2327			47			50
Total Operating Expenses		1,~~573~~040			~~348~~500			2,555			848
Operating Income		314			228
OPERATING INCOME		196			173			510			401
Other Income		4727			—			74			—
Other Deductions		(3312	)		—			(45	)		—
Interest Expense		(28	)		(28	)		(56	)		(56	)
Income from Continuing Operations Before Income Taxes		300			200
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		183			145			483			345
Income Taxes		(~~123~~74	)		(8062	)		(197	)		(142	)
Income from Continuing Operations		177			120
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		109			83			286			203
Cumulative Effect of a Change in Accounting Principle, net of tax of $255		~~370~~—			—			370			—
Earnings Available to Public Service Enterprise Group Incorporated	$	547		$	120
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	109		$	83		$	656		$	203

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

PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS

	March 31, 2003			December 31, 2002
	June 30, 2003			December 31, 2002
	(Millions) (Unaudited)
ASSETS
Current Assets
CURRENT ASSETS
Cash and Cash Equivalents	$	3725		$	26
Accounts Receivable, Net of Allowances of $31 in 2003		699			499
Accounts Receivable, net of allowances of $31 and $0 in 2003 and 2002, respectively		525			499
Short-Term Loan to Affiliate		204			—
Accounts Receivable—Affiliated Companies		80			238
Fuel		~~203~~409			406
Materials and Supplies		~~155~~158			148
Energy Trading Contracts		~~180~~155			157
Other		4313			44
Total Current Assets		1,~~521~~365			1,~~280~~518
Property, Plant and Equipment		5,570			5,347
PROPERTY, PLANT AND EQUIPMENT		5,686			5,342
Less: Accumulated Depreciation and Amortization		(1,~~368~~365	)		(1,302	)
Net Property, Plant and Equipment		4,~~202~~321			4,~~045~~040
Noncurrent Assets
NONCURRENT ASSETS
Deferred Income Taxes and Investment Tax Credits (ITC)		~~234~~176			~~545~~547
Nuclear Decommissioning Trust Funds		~~772~~869			766
Intangibles		~~142~~141			141
Other		124			164
Energy Trading Contracts		23			21
Total Noncurrent Assets		1,272			1,616
Other		104			143
Total Assets	$	6,995		$	6,941
Total Noncurrent Assets		1,313			1,618
TOTAL ASSETS	$	6,999		$	7,176
LIABILITIES AND MEMBER'S EQUITY
Current Liabilities
CURRENT LIABILITIES
Accounts Payable	$	~~746~~678		$	~~432~~670
Short-Term Loan from Affiliate		—4			239
Energy Trading Contracts		~~119~~85			101
Other		~~262~~272			283
Total Current Liabilities		1,~~127~~039			1,~~055~~293
Noncurrent Liabilities
NONCURRENT LIABILITIES
Nuclear Decommissioning		267			766
Nuclear Decommissioning Liabilities		273			766
Cost of Removal		—			131
Accrued Pension Costs		~~112~~88			101
Other		~~148~~128			130
Total Noncurrent Liabilities		~~527~~489			1,128
Commitments and Contingent Liabilities (See Note 5)
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
Long-Term Debt
LONG-TERM DEBT
Project Level, Non-Recourse Debt		800			800
Long-Term Debt		2,516			2,516
Total Long-Term Debt		3,316			3,316
Member's Equity
MEMBER'S EQUITY
Contributed Capital		1,550			1,550
Basis Adjustment		(986	)		(986	)
Retained Earnings		1,~~513~~622			966
Accumulated Other Comprehensive Loss		(5231	)		(8891	)
Total Member's Equity		2,~~025~~155			1,~~442~~439
Total Liabilities and Member's Equity	$	6,995		$	6,941
TOTAL LIABILITIES AND MEMBER'S EQUITY	$	6,999		$	7,176

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

PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Quarters Ended March 31,
	For the Six Months Ended June 30,
	2003			2002
	(Millions) (Unaudited)
Cash Flows from Operating Activities
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	~~547~~656		$	~~120~~203
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Cumulative Effect Adjustment, net of tax		(370	)		—
Cumulative Effect of a Change in Accounting Principle, net of tax		(370	)		—
Depreciation and Amortization		2347			2350
Amortization of Nuclear Fuel		2346			2142
Interest Accretion on NDT Liability		612			—
Provision for Deferred Income Taxes		3078			1223
Unrealized Gains on Energy Trading Contracts		(45	)		(3035	)
Income from NDT Funds		(14	)		—
Non-Cash Employee Benefit Plan Costs		26			16
Non-Cash Employee Benefit Plan Costs		13			8
Net Realized Gains and Income on NDT Fund		(28	)		—
Net Changes in Certain Current Assets and Liabilities:
Inventory, Materials and Supplies		196			4
Fuel, Materials and Supplies		(13	)		(287	)
Accounts Receivable		~~(200~~132	)		~~148~~(116	)
Accounts Payable		~~314~~8			~~(163~~207	)
Other Current Assets and Liabilities		911			2846
Other		42			(11	)
Benefit Plan Funding Payments		(37	)		(29	)
Net Cash Provided by Operating Activities		615			160
Other		17			(45	)
Cash Flows from Investing Activities
Net Cash Provided By Operating Activities		580			75
Additions to Property, Plant and Equipment		(153	)		(278	)
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(330	)		(545	)
Proceeds from the Sale of Property, Plant and Equipment		—			47
Short Term Loan—Affiliate		(204	)		—
Short-Term Loan—Affiliate		—			(22	)
Other		(816	)		(816	)
Net Cash Used in Investing Activities		(365	)		(239	)
Net Cash Used In Investing Activities		(346	)		(536	)
Cash Flows from Financing Activities
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt		—			30629
(Repayment) Issuance of Note Payable—Affiliated Company		(239	)		51
Short-Term Loan—Affiliate		(235	)		(164	)
Net Cash Provided by (Used In) Financing Activities		(239	)		81
Net Cash (Used In) Provided By Financing Activities		(235	)		465
Net Change in Cash and Cash Equivalents		11			2
Net Change In Cash and Cash Equivalents		(1	)		4
Cash and Cash Equivalents at Beginning of Period		26			9
Cash and Cash Equivalents at End of Period	$	3725		$	1113
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	394		$	(565	)
Interest Paid, Net of Amounts Capitalized	$	39108		$	3987

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

PSEG ENERGY HOLDINGS LLC
CONSOLIDATED STATEMENTS OF OPERATIONS

	For The Quarters Ended March 31,
	For The Quarter Ended June 30,						For The Six Months Ended June 30,
	2003			2002			2003			2002
	(Millions) (Unaudited)
Operating Revenues
OPERATING REVENUES
Electric Generation and Distribution Revenues	$	~~113~~122		$	7160		$	235		$	131
Income From Capital and Operating Leases		56			57
Income from Capital and Operating Leases		54			59			110			116
Gain On Withdrawal From/Sale of Partnerships		45			7
Gain on Withdrawal from/Sale of Partnerships		—			40			45			47
Net Investment Losses		(11	)		(5	)
Net Investment Gains (Losses)		6			(33	)		(5	)		(38	)
Other		6			67			12			13
Total Operating Revenues		~~209~~188			~~136~~133			397			269
Operating Expenses
OPERATING EXPENSES
Energy Costs		4752			3028			99			58
Operation and Maintenance		3541			2737			76			64
Depreciation and Amortization		10			8
Write-down of Project Investments		—			506			—			506
Total Operating Expenses		92			65
Depreciation and Amortization		14			6			24			14
Income From Equity Method Investments		17			30
Total Operating Expenses		107			577			199			642
Operating Income		134			101
Income from Equity Method Investments		31			33			48			63
Other Income		3			10
OPERATING INCOME (LOSS)		112			(411	)		246			(310	)
Other Deductions		(6	)		(52	)
Other Income		—			—			1			1
Interest Expense		(50	)		(54	)
Other Deductions		(8	)		(26	)		(12	)		(69	)
Income From Continuing Operations Before Income Taxes		81			5
Interest Expense		(54	)		(54	)		(104	)		(108	)
Income Taxes		(17	)		—
INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST, DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		50			(491	)		131			(486	)
Minority Interests in (Earnings) Losses of Subsidiaries		(5	)		1
Income Taxes		(16	)		177			(33	)		177
Income From Continuing Operations		59			6
Minority Interests in (Earnings) Losses of Subsidiaries		(1	)		4			(6	)		5
Loss From Discontinued Operations, net of tax benefit (expense) of $3 and ($1)		(6	)		(1	)
INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		33			(310	)		92			(304	)
Loss on Disposal of Discontinued Operations, net of tax benefit of $2		(9	)		—
DISCONTINUED OPERATIONS
Income Before Cumulative Effect of a Change in Accounting Principle		44			5
Loss From Discontinued Operations, net of tax		(2	)		(3	)		(8	)		(4	)
Cumulative Effect of a Change in Accounting Principle, net of tax of $66		—			(120	)
Loss on Disposal of Discontinued Operations, net of tax		—			(34	)		(9	)		(34	)
Net Income (Loss)		44			(115	)
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		31			(347	)		75			(342	)
Preference Units Distributions/Preferred Stock Dividends		(6	)		(6	)
Cumulative Effect of a Change in Accounting Principle, net of tax benefit of $66		—			—			—			(120	)
Earnings (Loss) Available to Public Service Enterprise Group Incorporated	$	38		$	(121	)
NET INCOME (LOSS)		31			(347	)		75			(462	)
Preference Units Distributions/Preferred Stock Dividends		(5	)		(5	)		(11	)		(11	)
EARNINGS (LOSS) AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	26		$	(352	)	$	64		$	(473	)

See disclosures regarding PSEG Energy Holdings LLC
included in the Notes to Consolidated Financial Statements.

PSEG ENERGY HOLDINGS LLC
CONSOLIDATED BALANCE SHEETS

	March 31, 2003			December 31, 2002
	June 30, 2003			December 31, 2002
	(Millions) (Unaudited)
ASSETS
Current Assets
CURRENT ASSETS
Cash and Cash Equivalents	$	63102		$	104
Accounts Receivable:
Trade—Net of Allowances of $9 and $0 in 2003 and 2002, respectively		99			91
Trade—net of allowances of $13 and $0 in 2003 and 2002, respectively		121			91
Other Accounts Receivable		~~155~~118			24
Assets Held for Sale		8372			83
Notes Receivable		10			73
Notes Receivable:
Inventory		21			22
Affiliated Companies		131			62
Prepayments		3			4
Other		7			11
Restricted Cash		12			18
Inventory		18			22
Current Assets of Discontinued Operations		44			107
Prepayments		4			4
Total Current Assets		490			526
Restricted Cash		23			18
Property, Plant and Equipment		1,620			1,534
Current Assets of Discontinued Operations		31			107
Less: Accumulated Depreciation and Amortization		(146	)		(139	)
Total Current Assets		627			526
Net Property, Plant and Equipment		1,474			1,395
PROPERTY, PLANT AND EQUIPMENT		1,758			1,548
Investments
Less: Accumulated Depreciation and Amortization		(162	)		(139	)
Capital Leases—net		2,886			2,844
Net Property, Plant and Equipment		1,596			1,409
Corporate Joint Ventures		1,017			1,004
INVESTMENTS
Partnership Interests		486			484
Capital Leases—net		2,929			2,844
Other Investments		35			38
Corporate Joint Ventures		1,061			1,003
Total Investments		4,424			4,370
Partnership Interests		471			484
Goodwill		417			436
Other Investments		33			38
Other Assets		116			111
Total Investments		4,494			4,369
Total Assets	$	6,921		$	6,838
OTHER ASSETS
Goodwill		426			436
Other		80			86
Total Other Assets		506			522
TOTAL ASSETS	$	7,223		$	6,826

See disclosures regarding PSEG Energy Holdings LLC
included in the Notes to Consolidated Financial Statements.

PSEG ENERGY HOLDINGS LLC
CONSOLIDATED BALANCE SHEETS

	March 31, 2003			December 31, 2002
	June 30, 2003			December 31, 2002
	(Millions) (Unaudited)
LIABILITIES AND MEMBER'S EQUITY
Current Liabilities
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	~~579~~314		$	320
Accounts Payable		~~213~~224			257
Notes Payable		9667			137
Borrowings Under Lines of Credit		47			—
Current Liabilities of Discontinued Operations		31			95
Current Liabilities of Discontinued Operations		44			95
Total Current Liabilities		636			809
Total Current Liabilities		979			809
NONCURRENT LIABILITIES
Noncurrent Liabilities
Deferred Income Taxes and Investment and Energy Tax Credits		1,252			1,038
Deferred Income Taxes and Investment and Energy Tax Credits		1,164			1,042
Other Noncurrent Liabilities		216			179
Other Noncurrent Liabilities		196			179
Total Noncurrent Liabilities		1,468			1,217
Total Noncurrent Liabilities		1,360			1,221
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
Commitments and Contingent Liabilities (See Note 5)
MINORITY INTERESTS		113			103
Minority Interests		98			106
LONG-TERM DEBT
Long-Term Debt
Project Level, Non-Recourse Debt		1,008			853
Project Level, Non-Recourse Debt		895			853
Senior Notes		1,800			1,725
Senior Notes		1,446			1,725
Total Long-Term Debt		2,808			2,578
Total Long-Term Debt		2,341			2,578
MEMBER'S EQUITY
Member's Equity
Ordinary Unit		1,888			1,888
Preference Units		509			509
Retained Earnings		~~145~~171			107
Accumulated Other Comprehensive Loss		(~~399~~370	)		(~~380~~385	)
Total Member's Equity		2,~~143~~198			2,~~124~~119
Total Liabilities and Member's Equity	$	6,921		$	6,838
TOTAL LIABILITIES AND MEMBER'S EQUITY	$	7,223		$	6,826

See disclosures regarding PSEG Energy Holdings LLC
included in the Notes to Consolidated Financial Statements.

PSEG ENERGY HOLDINGS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For The Quarters Ended March 31,
	For The Six Months Ended June 30,
	2003			2002
	(Millions) (Unaudited)
Cash Flows From Operating Activities
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	4475		$	(~~115~~462	)
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation and Amortization		13			14
Write-down of Project Investment		—			506
Deferred Income Taxes (Other Than Leases)		(5	)		13
Leveraged Lease Income, Adjusted for Rents Received		(2	)		15
Investment Distributions		1			3
Change in Fair Value of Derivative Financial Instruments		6			(10	)
Undistributed Earnings from Affiliates		(5	)		(14	)
Net Gains on Sale of Investments		(33	)		(2	)
Loss on Disposal of Discontinued Operations, net of tax		9			—
Foreign Currency Transaction (Gain) Loss		(3	)		52
Proceeds on Withdrawal from Partnership		45			7
Cumulative Effect of a Change in Accounting Principle, net of tax		—			120
Loss on Disposal of Discontinued Operations, net of tax		9			34
Depreciation and Amortization		29			20
Deferred Income Taxes (Other than Leases)		(8	)		(177	)
Leveraged Lease Income, Adjusted for Rents Received		35			48
Investment Distributions		2			4
Change in Fair Value of Derivative Financial Instruments		12			(2	)
Undistributed Earnings from Affiliates		(3	)		(17	)
Net Gain on Investments		(40	)		(9	)
Foreign Currency Transaction (Gain) Loss		(1	)		69
Proceeds on Withdrawal from Partnership		45			47
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable		~~(16~~11	)		(76105	)
Accounts Payable		(5497	)		(6338	)
Other Current Assets and Liabilities		(123	)		31(25	)
Other		111			711
Net Cash Used in Operating Activities		—			(18	)
Net Cash Provided By Operating Activities		103			24
Cash Flows from Investing Activities
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(90152	)		(77183	)
Investments in Joint Ventures and Partnerships		(1617	)		(95152	)
Return of Capital from Partnerships		—			89
Investment in Capital Leases		—			(31	)
Collection of Note Receivable—Affiliated Company		62			—
Return of Capital from Partnerships		2			90
Other		1			(60	)
Change in Note Receivable—Affiliated Company		(69	)		—
Net Cash Used in Investing Activities		(43	)		(143	)
Other		15			(83	)
Cash Flows from Financing Activities
Net Cash Used In Investing Activities		(221	)		(359	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Capital Contributions		—			200
Net Increase (Decrease) in Short-Term Debt		90			(28	)
Net Change in Short-Term Debt		45			21
Cash Dividends Paid		(611	)		(611	)
Restricted Cash Decrease		7			—
Net Decrease in Short-Term Affiliate Borrowings		—			(38	)
Net Decrease in Short-Term Affiliate Borrowings		—			(35	)
Proceeds from Project-Level Non-Recourse Long-Term Debt		322			111
Proceeds from Project-Level Non-Recourse Debt		242			43
Proceeds from Sale of Senior Notes		343			134
Repayment of Medium-Term and Project-Level Non-Recourse Debt		(~~321~~575	)		—(98	)
Other		(108	)		32
Net Cash Provided by Financing Activities		2			177
Net Cash Provided By Financing Activities		116			321
Effect of Exchange Rate Changes		—			(42	)
Net Change in Cash and Cash Equivalents		(41	)		12
Net Change In Cash and Cash Equivalents		(2	)		(16	)
Cash and Cash Equivalents at Beginning of Period		104			54
Cash and Cash Equivalents at End of Period	$	63102		$	6638
Supplemental Disclosure of Cash Flow Information
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid	$	74		$	48
Income Tax Receipts	$	(42	)	$	(14	)
Interest Paid, Net of Amount Capitalized	$	31		$	33
Interest Paid, Net of Amounts Capitalized	$	57		$	87

See disclosures regarding PSEG Energy Holdings LLC
included in the Notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UnauditedUNAUDITED)

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 LLC (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 makes no ~~other~~ 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).

PSE&G

PSE&G is an operating public utility providing electric and gas transmission and distribution service in certain areas within the State of New Jersey. PSE&G's ~~gas supply business was transferred to Power in May 2002. PSE&G~~ owns PSE&G Transition Funding LLC, a bankruptcy remote entity established for the purpose of purchasing intangible transition property and issuing transition bonds.

Power

Power is a multi-regional wholesale energy supply business that ~~utilizes~~optimizes ~~energy trading to optimize~~ the value of its portfolio of electric ~~generating~~generation ~~and~~assets, gas ~~capacity~~supply contracts and ~~its~~electric and gas supply obligations by integrating the management of this portfolio with its energy trading and risk management functions. Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Power also has a finance company subsidiary, PSEG Power Capital Investment Co., which provides certain financing for Power's and its subsidiaries.

Energy Holdings

Energy Holdings is the parent of PSEG Global LLC (Global), which invests and participates in the development and operation of international and domestic projects in the generation and distribution of energy, which include cogeneration and independent power production facilities and electric distribution companies; PSEG Resources LLC (Resources), which makes investments primarily in energy-related leveraged leases; PSEG Energy Technologies Inc. (Energy Technologies), presented as discontinued operations, which ~~provides~~provided energy-related services and construction to industrial and commercial customers; Enterprise Group Development Corporation (EGDC), a commercial real estate property management business which has been conducting a controlled exit from this business since 1993; PSEG Capital Corporation (PSEG Capital), which served ~~serves~~ as a financing vehicle for Energy Holdings' subsidiaries and is in the process of dissolution; and Enterprise Capital Funding Corporation, which is currently inactive. ~~EGDC~~and ~~has~~is ~~been~~also ~~conducting~~in ~~a controlled exit from~~ the ~~real~~process ~~estate business since 1993. The businesses~~ of ~~Energy Technologies are presented as discontinued operations~~dissolution.

Global, a New Jersey limited liability company, is the successor to PSEG Global Inc. pursuant to a merger which was consummated in March 2003. The merger was consummated to change the form of the business from a corporation to a limited liability company in accordance with the New Jersey Limited Liability Company Act.

Basis of Presentation

ThePSEG, financialPSE&G, statementsPower included herein have been prepared pursuant to the rules and regulationsEnergy of the Securities and Exchange Commission (SEC) for Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted Holdings

16 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 generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, in the opinion of management, the disclosures herein are adequate to make the information presented not misleading. These consolidated financial statements and Notes

accounting principles have been condensed or omitted pursuant to such rules and regulations. However, in the opinion of management, the disclosures herein are adequate to make the information presented not misleading. These consolidated financial statements and Notes to Consolidated Financial Statements (Notes) should be read in conjunction with and update and supplement matters discussed in the 2002 Annual Report on Form 10-K.16

TheNOTES unauditedTO financialCONSOLIDATED informationFINANCIAL furnishedSTATEMENTS 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 consolidated balance sheets were derived from the audited consolidated financial statements included in the 2002 Annual Report on Form 10-K. Certain reclassifications of prior period data have been made to conform with the current presentation.(UNAUDITED)

to Consolidated Financial Statements (Notes) should be read in conjunction with and update and supplement matters discussed in the respective 2002 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2003.

The unaudited 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 consolidated balance sheets were derived from the audited consolidated financial statements included in the 2002 Annual Report on Form 10-K. Certain reclassifications of prior period data have been made to conform with the current presentation.

Note 2. New Accounting Standards

Statement of Financial Accounting Standards (SFAS) No. 142, ''Goodwill and Other Intangible Assets'' (SFAS 142)

PSEG, PSE&G, Power and Energy Holdings

On January 1, 2002, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 142. Under this standard, PSEG, PSE&G, Power and Energy Holdings were required to complete an impairment analysis of goodwill before June 30, 2002 and record any required impairment retroactive to January 1, 2002. Under SFAS 142, goodwill is considered a nonamortizable asset and is subject to an annual review for impairment and an interim review when certain events or changes in circumstances occur. At the time of adoption, PSE&G had no goodwill. The effect of no longer amortizing goodwill on an annual basis was not material to PSEG's or Power's financial position and results of operations upon adoption.

Power and Energy Holdings evaluated the recoverability of the recorded amount of goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests, which require broad assumptions and significant judgment to be exercised by management.

In addition to goodwill, PSEG's total intangible assets as of June 30, 2003 and December 31, 2002 were $206 million, all of which are not subject to amortization, ~~were $207 million,~~ including $~~113~~114 million, $5452 million and $40 million related to defined benefit pension plans, emissions allowances, ~~and~~which ~~various~~are ~~access~~expensed ~~rights,~~as ~~respectively~~used, asand ofvarious ~~March~~access 31rights, ~~2003~~respectively.

PSE&G

As of ~~March~~June 3130, 2003 and December 31, 2002, PSE&G ~~has~~had intangible assets relating to its defined benefit pension plans totaling $60 million. These intangible assets are not subject to amortization.

Power

In addition to goodwill, as of ~~March~~June 3130, 2003 and December 31, 2002, Power's intangible assets were $~~142~~125 million, of which $3233 million, $5452 million, ~~$40 million~~ and $1640 million, ~~relate~~related to its defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights at its Albany Station, ~~and goodwill,~~ respectively.

Energy Holdings

On January 1, 2002, Energy Holdings recorded the results of its evaluation of the effect of SFAS 142. The total amount of goodwill impairments was $120 million, net of tax of $66 million ~~and was comprised of $36 million (after-tax) at Empresa Distribuidora de Electricidad de Entre Rios S~~.A. (EDEERSA), an Argentine distribution company, $34 million (after-tax) at Rio Grande Energia (RGE), a Brazilian distribution company of which Global owns 32%, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi, a generating facility in India, which was 74%

17 As of June 30, 2003 and December 31, 2002, the remaining carrying value of Energy Holdings' goodwill was $426 million and $436 million, respectively, as displayed in the table below.

~~owned~~ As byof June ~~Global~~30, ~~until~~2003 ~~sold~~and inDecember ~~the~~31, ~~fourth~~2002, ~~quarter~~Energy ofHoldings' ~~2002.~~pro-rata ~~All~~share of the remaining goodwill ~~related~~included toon ~~these~~the ~~companies~~balance sheets of its equity method investees totaled $300 million and $287 million, ~~other~~respectively. ~~than~~In ~~RGE~~accordance with generally accepted accounting principles, ~~was~~such ~~fully~~goodwill ~~impaired~~is not consolidated on the Energy Holdings' Consolidated Balance Sheets.

~~As of March 31, 2003, the remaining carrying value of Energy Holdings' goodwill was $417 million, as displayed in the table below.~~17

AsNOTES ofTO MarchCONSOLIDATED 31,FINANCIAL 2003,STATEMENTS Energy Holdings' pro-rata share of the remaining goodwill included on the balance sheets of its equity method investees totaled $283 million. In accordance with generally accepted accounting principles, such goodwill is not consolidated on the balance sheet.(UNAUDITED)

In addition to goodwill, Energy Holdings has an intangible asset related to its defined benefit pension plans, which is not subject to amortization. This intangible asset totaled $45 million as of ~~March 31~~June 30, 2003 and December 31, 2002.

Power and Energy Holdings

As of ~~March~~June 3130, 2003 and December 31, 2002, Power and Energy Holdings' goodwill and pro-rata share of goodwill in ~~consolidated~~ equity method ~~projects~~investments was as follows:

	As of
	March 31, 2003		December 31, 2002
	June 30, 2003		December 31, 2002
	(Millions)
Consolidated Investments
Energy Holdings—Global
Sociedad Austral de Electricidad S.A. (SAESA) (A)	$	~~278~~287	$	290
Empresa de Electricidad de los Andes S.A. (Electroandes)(B)		133		140
Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO)		6		6
Total Energy Holdings—Global		~~417~~426		436
Power—Albany Steam Station		16		16
Total PSEG Consolidated Goodwill		~~433~~442		452
Pro-Rata Share of Equity Method Investments
Energy Holdings—Global
RGE (A)		61		60
Rio Grande Energia (RGE) (A)		72		60
Chilquinta Energia S.A. (Chilquinta)		~~163~~164		163
Luz del Sur S.A.A		3439		3439
Kalaeloa		25		25
Pro-Rata Share of Equity Investment Goodwill		~~283~~300		~~282~~287
Total PSEG Goodwill	$	~~716~~742	$	~~734~~739

(A) Changes in goodwill relate to changes in foreign exchange rates. (B) Changes in goodwill at Electroandes relate to purchase price allocation adjustments.

SFAS No. 143, ''Accounting for Asset Retirement Obligations'' (SFAS 143)

PSEG, PSE&G, Power and Energy Holdings

Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 143. SFAS 143 addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract.

18 Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company is required to subsequently accrete that asset retirement cost to expense over its useful life. In periods subsequent to initial measurement, an entity is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion will be charged to Operation and Maintenance expense on the Consolidated Statements of Operations, whereas

Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company shall subsequently allocate that asset retirement cost to expense over its useful life. In periods subsequent to initial measurement, an entity shall recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion will be charged to the Consolidated Statements of Operations, whereas changes due to the timing or amount of cash flows shall be an adjustment to the carrying amount of the related asset. See Note 3. Adoption of SFAS 143 for additional information.18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

changes due to the timing or amount of cash flows will be an adjustment to the carrying amount of the related asset. See Note 3. Adoption of SFAS 143 for additional information.

Emerging Issues Task Force (EITF) Issue No. 02-3, ''Accounting for Contracts Involved in Energy Trading and Risk Management Activities'' (EITF 02-3)

PSEG and Power

EITF 02-3 requires all gains and losses on energy trading derivatives to be reported on a net basis. Also, energy trading contracts that are not derivatives will no longer be marked to market. Instead, settlement accounting will be used. EITF 02-3 was effective for new contracts entered into on or after October 25, 2002. For contracts entered into prior to October 25, 2002, EITF 02-3 was effective January 1, 2003. Substantially all of Power's energy contracts qualify as derivatives under SFAS No. 133, ''Accounting for Derivative Instruments and Hedging Activities'' (SFAS 133) and will therefore continue to be marked to market. The impact of implementing these rules ~~was~~had ~~not~~no ~~material~~effect toon PSEG's or Power's ~~results of operations~~earnings.

Financial Interpretation (FIN) No. 46, ''Consolidation of Variable Interest Entities (VIE)'' (FIN 46)

PSEG, PSE&G, Power and Energy Holdings

FIN 46 ~~clarified~~clarifies the application of Accounting Research Bulletin No. 51, ''Consolidated Financial Statements'', to certain entities in which equity investors do not have the characteristics of a controlling financial interest. Because a controlling financial interest in an entity may be achieved through arrangements that do not involve voting interests, FIN 46 sets forth specific requirements with respect to consolidation, measurement and disclosure of such relationships. Disclosure requirements for existing qualifying entities are effective for financial statements issued after January 31, 2003. All enterprises with VIEs created after February 1, 2003, ~~shall~~are required to apply the provisions of FIN 46 no later than the beginning of the first interim period beginning after June 15, 2003. ~~The adoption of this standard is not expected to have a material impact on~~ PSEG, PSE&G, Power and Energy Holdings' ~~respective~~are ~~financial~~still ~~statements~~evaluating this guidance.

SFAS No. 149, ''Amendment of Statement 133 on Derivative Instruments and Hedging Activities'' (SFAS 149)

PSEG, PSE&G, Power and Energy Holdings

SFAS 149 amends and clarifies the accounting guidance for derivative instruments (including certain derivative instruments embedded in other contracts) and hedging activities that fall within the scope of SFAS 133.

In particular, SFAS 149 clarifies circumstances under which a contract with an initial net investment meets the characteristic of a derivative discussed in SFAS 133, clarifies when a derivative contains a financing component and amends the definition of an underlying to conform it to language used in FIN No. 45, ''Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others''.

Additionally, SFAS 149 amends SFAS 133's criteria for electing the normal purchase and sale exception, which exempts certain derivatives that meet the normal purchase and sales criteria, from fair value reporting. The new guidance allows ''normal'' treatment for a power purchase or sale agreement (whether a forward, an option or combination of both) that is a capacity contract, as defined, even if the contract is closed out before maturity. However, any non-power commodity contract (e.g. gas contracts) and non-capacity power contract closed out before maturity will be ineligible for ''normal'' treatment and could result in those contracts being marked to market.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. Although PSEG, PSE&G, Power and Energy Holdings do not expect a material impact on their respective financial statements due to the adoption of these rules, no assurances can be given.

SFAS No. 150, ''Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity'' (SFAS 150)

PSEG and PSE&G

SFAS 150, which is effective July 1, 2003, establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Many of these instruments that were previously presented as equity or as mezzanine instruments (between the liabilities and the equity section) will now be recorded as liabilities. SFAS 150 requires an issuer to classify qualifying instruments issued in the form of shares that are mandatorily redeemable as liabilities. Those items will no longer be presented as mezzanine instruments on the Consolidated Balance Sheets.

As of June 30, 2003, the following instruments are included in Preferred Securities on PSEG's and PSE&G's respective Consolidated Balance Sheets between Long-Term Debt and Common Equity.

	Shares Outstanding		As of June 30, 2003
			(Millions)
PSEG (Parent)
PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures
7.44%		9,000,000	$	225
Floating Rate		150,000		150
7.25%		6,000,000		150
8.75%		7,200,000		180
PSEG Participating Units
10.25%		9,200,000		460

Total PSEG (Parent)				1,165

PSE&G
PSE&G 8.00% Monthly Guaranteed Preferred Beneficial Interest in Subordinated Debentures		2,400,000		60
PSE&G Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's 8.125% Subordinated Debentures		3,800,000		95

Total PSE&G				155

Total PSEG Consolidated			$	1,320

Effective July 1, 2003, these instruments will be presented separately in Noncurrent Liabilities on the Consolidated Balance Sheets and dividend payments on these instruments will be recorded as Interest Expense on the Consolidated Statements of Operations and be included in the Interest Paid supplemental disclosure on the Consolidated Statements of Cash Flows.

Other

PSEG, PSE&G, Power and Energy Holdings

AtIn ~~the~~ January ~~2003 EITF meeting~~2001, ~~the Financial Accounting Standards Board (FASB) was requested to reconsider an interpretation of SFAS 133. The interpretation~~PSEG, which is contained in the Derivatives Implementation Group's C-11 guidance, relates to contracts that include broad market indices (e.g., CPI). That interpretation sets forth the guidelines under which the contract could qualify as a normal purchase or sale under SFAS 133. PSE&G, Power and Energy Holdings ~~reevaluated~~each ~~their~~adopted ~~respective~~SFAS ~~contracts~~133. ~~and~~In ~~determined~~accordance ~~that~~with ~~there~~SFAS ~~were~~133, noall ~~contracts~~derivative ~~impacted~~instruments byare ~~this~~recognized ~~interpretation and accordingly there was no effect~~ on the ~~Consolidated~~balance ~~Financial~~sheet ~~Statements.~~at ~~The~~their ~~FASB~~fair ~~has agreed to reconsider the guidance under C-11~~values. ~~Although~~In ~~the~~relation ~~ultimate~~to ~~outcome~~this ~~is uncertain~~standard, ~~this~~the ~~potential~~Financial ~~change~~Accounting inStandards ~~guidance~~Board is(FASB) ~~not~~Derivative ~~expected~~Implementation toGroup ~~have~~(DIG) ~~a material~~issued ~~impact~~certain oninterpretive ~~PSEG~~guidance, ~~PSE&G,~~including ~~Power~~DIG ~~and~~Issue ~~Energy~~C-11 ~~Holdings'~~that ~~respective financial statements.~~

1920

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

relates to contracts which include broad market indices (e.g., Consumer Price Index). That interpretation sets forth the guidelines under which a contract could qualify as a normal purchase or sale under SFAS 133. In 2003, the FASB issued DIG Issue C-20 to amend the previous interpretation stating that the phrase ''not clearly and closely related to the asset being sold or purchased'' should involve an analysis of both qualitative and quantitative considerations. PSE&G, Power and Energy Holdings have reviewed their respective contracts and each have determined that there will be no impact resulting from the adoption of this interpretation.

Note 3. Adoption of SFAS 143

PSEG, PSE&G and Power

~~PSEG,~~In ~~PSE&G~~the ~~and~~first ~~Power~~quarter ~~have~~of ~~performed~~2003, aPower completed its review of ~~their~~ potential obligations under SFAS 143 and ~~believe~~determined that these obligations are primarily related to the decommissioning of ~~Power's~~its nuclear power plants. Power's liability atas of December 31, 2002 was approximately $766 million, which equaled the balance of its Nuclear Decommissioning Trust (NDT) Fund, as discussed below. As of January 1, 2003, ~~the liability~~ as calculated under SFAS 143, isthe liability was approximately $261 million and the asset was approximately $50 million. This asset and liability ~~was~~were calculated using a probability-weighted average of multiple scenarios. The scenarios were each based on estimated cash flows, which were discounted using Power's risk-adjusted interest rate at the required effective date of the standard and considering the expected time period of the cash outflows. The scenarios included estimates for inflation, contingencies, and assumptions related to the timing of decommissioning costs, using the current license lives for each unit as well as early shutdown and license extensions scenarios. Management believes that these assumptions, which had a material impact on the calculation of the liability, and therefore the cumulative effect adjustment resulting from the adoption of this new accounting standard, were reasonable and appropriate.

In addition to the $261 million nuclear decommissioning liability, Power identified certain other legal obligations that meet certain of the criteria of SFAS 143, which at this time are not quantifiable but could be material in the future. These obligations relate to certain industrial establishments subject to the New Jersey Industrial Site Recovery Act (ISRA), underground storage tanks subject to closure requirements, permits and authorizations, the restoration of an area to be occupied by a reservoir at the end of its useful life, an obligation to retire certain plants prior to the start up of a new plant and the demolition and restoration of certain other ~~plants~~plant sites once they are no longer in service.

Power also had $131 million of cost of removal liabilities ~~related to its fossil units~~, as of December 31, 2002, which did not meet the requirements of an asset retirement obligation (ARO) and were therefore reversed and included in the Cumulative Effect of a Change in Accounting Principle recorded in the first quarter of 2003.

InAs ~~addition,~~a result of reducing the existing nuclear decommissioning and cost of removal liabilities to their fair value and recording an ARO asset, PSEG and Power recorded a Cumulative Effect of a Change in Accounting Principle of $50370 million ~~was~~after-tax ~~created~~ in ~~accordance~~the ~~with~~first ~~SFAS~~quarter ~~143~~of 2003. Of this amount, $292 million (after-tax) relates to Nuclear and $78 million (after-tax) relates to the cost of removal liabilities for the fossil units being reversed.

AsIn aJuly ~~result~~2003, ofthe ~~reducing~~New ~~the~~Jersey ~~existing~~Board ~~nuclear~~of ~~decommissioning~~Public ~~and~~Utilities ~~cost~~(BPU) ofissued ~~removal~~an ~~liabilities~~oral todecision ~~their~~determining ~~fair~~that ~~value~~PSE&G's ~~and~~customers ~~creating~~will anno ~~ARO~~longer ~~asset~~pay, ~~PSEG~~ and ~~Power~~do ~~recorded~~not ahave ~~Cumulative~~responsibility ~~Effect~~for ofnuclear adecommissioning ~~Change~~costs inafter ~~Accounting~~July ~~Principle~~31, ~~of $370 million after-tax~~2003. OfBeginning ~~this~~August ~~amount~~1, ~~$292~~2003, ~~million~~the ~~(after-tax)~~responsibility ~~relates~~rests towith ~~Nuclear,~~the owners of ~~which~~the ~~approximately~~nuclear ~~$244~~power ~~million~~plants. ~~(after-tax)~~The ~~relates~~BPU toalso ~~interests~~indicated in ~~certain~~the ~~nuclear~~oral ~~units~~decision ~~Power~~that ~~acquired from~~ PSE&G ~~which~~is ~~are~~required ~~subject~~ to ~~the~~refund ~~New Jersey Board of Public Utilities (BPU) issue discussed below, approximately~~ $4830 million, ~~(after~~pre-tax), ~~relates~~related to ~~interests~~revenues inpreviously ~~certain~~collected ~~nuclear~~through ~~units~~the ~~Power~~SBC ~~purchased~~for ~~from~~nuclear ~~Atlantic~~decommissioning, ~~City~~however, ~~Electric~~the ~~Company~~refund ~~(ACE)~~will ~~and~~not ~~Delmarva~~affect ~~Power~~any ~~and~~previously ~~Light~~collected ~~Company~~funds ~~(DP&L)~~deposited ~~which~~into ~~are~~external ~~not~~trusts. ~~subject~~For toadditional ~~BPU~~information ~~approval.~~relating ~~Also~~to ~~included in~~ the ~~$370~~oral ~~million~~decision ~~was~~issued ~~$78~~in ~~million~~connection ~~(after-tax)~~with ~~that~~PSE&G's ~~relates to~~Electric ~~the~~Base ~~cost~~Rate ofCase, ~~removal~~see ~~liabilities~~Note ~~for~~16. ~~the~~Subsequent ~~fossil units being reversed~~Events.

In August 2002, PSE&G filed a petition requesting clarification from the BPU regarding the future cost responsibility for nuclear decommissioning and whether: (a) PSE&G's customers will continue to pay for such costs; or (b) such customer responsibility will terminate at the end of the four-year transition period on July 31, 2003 and become the sole responsibility of Power. The outcome of this petition could affect the treatment of a material portion of the liability recorded for Power's nuclear decommissioning obligation. If the BPU determines that PSE&G's customers will continue to pay and have responsibility for these costs, $244 million will be reversed and deferred on PSEG's and Power's Consolidated Balance Sheet as a liability. Also, the Ratepayer Advocate has filed testimony in this petition recommending a return of funds to ratepayers due to the fact that they believe the NDT Fund is overfunded. An adverse resolution to this matter could have a material adverse effect on PSEG's and Power's results of operations, financial position and cash flows. A decision is expected prior to August 2003 and the outcome of this petition cannot be predicted. The $48 million related to the nuclear units purchased from ACE and DP&L and the $78 million related to the cost of removal liabilities for the fossil units would be unaffected by such a ruling.21

20NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The following table reflects pro forma results which include accretion and depreciation expense as if SFAS 143 had always been in effect.

	Quarters Ended March 31,				Years Ended December 31,
	2003		2002		2002		2001		2000
	(Millions, except share data)
PSEG
Net Income—as reported	$	676	$	60	$	245	$	770	$	764
Pro Forma Net Income Assuming Accounting Change Applied Retroactively:	$	306	$	57	$	231	$	758	$	755
Earnings per share:
Basic and Diluted—as reported	$	3.00	$	0.29	$	1.17	$	3.70	$	3.55
Basic and Diluted—pro forma	$	1.36	$	0.27	$	1.10	$	3.64	$	3.51
Power
Net Income—as reported	$	547	$	120	$	468	$	394	$	313
Pro Forma Net Income Assuming Accounting Change Applied Retroactively:	$	177	$	117	$	454	$	382	$	304

The pro forma amount of the liability for Power's asset retirement obligations for the periods ended December 31, 2002, and 2001, as well as the actual amount of the liability recorded on Power's Consolidated Balance Sheets as of March 31, 2003 are highlighted in the following table. These amounts were calculated using current information, current assumptions and current interest rates.

			As of December 31,
	As of March 31, 2003		2002		2001
	(Millions)
PSEG and Power
Beginning of Period ARO Liability	$	261	$	239	$	220
Accretion Expense		6		22		19
End of Period ARO Liability	$	267	$	261	$	239

PSE&G

PSE&G has identified certain other legal obligations that meet the criteria of SFAS 143, which at this time are not quantifiable and therefore are unable to be recorded. These obligations relate to certain industrial establishments subject to the ~~Industrial Site Recovery Act~~ISRA, underground storage tanks subject to closure requirements, leases and licenses, and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service.

As of January 1, 2003, PSE&G had no ~~quantifiable~~ legal liabilities, as contemplated under SFAS 143, recorded on its Consolidated Balance Sheets and, therefore, the effect of adoption did not result in an adjustment to the Consolidated ~~Statements~~Financial ~~of Operations~~Statements. PSE&G does, however, have cost of removal liabilities embedded within Accumulated Depreciation and Amortization pursuant to SFAS No. 71, ''Accounting for the Effects of Certain Types of Regulation'' (SFAS 71). Since PSE&G is a regulated enterprise, these amounts, which total approximately $~~372~~358 million as of June 30, 2003, continue to be recorded and presented in Accumulated Depreciation and Amortization on the Consolidated Balance Sheets.

Energy Holdings

Energy Holdings has identified certain legal obligations that meet the criteria of SFAS 143. However, ~~which~~it has determined that they are not material to its financial position, results of operations or net cash flows.

Effect on the NDT Fund

Power

Prior to the adoption of SFAS 143, amounts collected from PSE&G customers that have been deposited into the NDT Fund and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Fund with an offsetting charge to the nuclear decommissioning liability. ~~Because~~Due ~~management~~to ~~believes~~the ~~that~~oral itdecision isissued noby ~~longer~~the ~~probable~~BPU that PSE&G's customers will ~~continue~~no tolonger fund the NDT Fund, ~~beginning in the first quarter of 2003,~~ deferral accounting is no longer appropriate. ~~Therefore~~In anticipation of this decision, beginning January 1, 2003, realized gains and losses were recorded in earnings and unrealized gains and losses were recorded as a component of Other Comprehensive Income (OCI), as appropriate under SFAS No. 115, ''Accounting for Certain Investments in Debt and Equity Securities'' (SFAS 115). Additionally, because deferral accounting iswas no longer appropriate, as of January 1, 2003, Power had ~~determined~~expensed ~~that~~ approximately $40 million, of the $68 million of pre-tax unrealized losses on securities in the NDT Fund which were ~~Other~~other than ~~Temporarily~~temporarily impaired, ~~discussed below,~~ and recorded this amount against earnings in the Cumulative Effect of a Change in an Accounting Principle.

Note 4. Discontinued OperationsPSEG

Diluted earnings per share are calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under PSEG's stock option plans. The following table shows the effect of these stock

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

options on the weighted average number of shares outstanding used in calculating diluted earnings per share:

	Quarter Ended June 30,												Six Months Ended June 30,
	2003			2003			2002			2002			2003			2003			2002			2002
	Basic			Diluted			Basic			Diluted			Basic			Diluted			Basic			Diluted
EPS Numerator:
Earnings (Loss) (Millions)
Continuing Operations	$	150		$	150		$	(227	)	$	(227	)	$	471		$	471		$	(46	)	$	(46	)
Discontinued Operations		(2	)		(2	)		(37	)		(37	)		(17	)		(17	)		(38	)		(38	)
Extraordinary Item		(18	)		(18	)		—			—			(18	)		(18	)		—			—
Cumulative Effect of a Change in Accounting Principle		—			—			—			—			370			370			(120	)		(120	)

Net Income (Loss)	$	130		$	130		$	(264	)	$	(264	)	$	806		$	806		$	(204	)	$	(204	)

EPS Denominator (Thousands):
Weighted Average Common Shares Outstanding		225,910			225,910			206,246			206,246			225,627			225,627			206,049			206,049
Effect of Stock Options		—			672			—			681			—			481			—			582

Total Shares		225,910			226,582			206,246			206,927			225,627			226,108			206,049			206,631

Earnings (Loss) per share:
Continuing Operations	$	0.67		$	0.66		$	(1.10	)	$	(1.10	)	$	2.09		$	2.09		$	(0.22	)	$	(0.22	)
Discontinued Operations		(0.01	)		(0.01	)		(0.18	)		(0.18	)		(0.08	)		(0.08	)		(0.19	)		(0.19	)
Extraordinary Item		(0.08	)		(0.08	)		—			—			(0.08	)		(0.08	)		—			—
Cumulative Effect of a Change in Accounting Principle		—			—			—			—			1.64			1.64			(0.58	)		(0.58	)

Net Income (Loss)	$	0.58		$	0.57		$	(1.28	)	$	(1.28	)	$	3.57		$	3.57		$	(0.99	)	$	(0.99	)

There were approximately 5.4 million stock options and 9.2 million participating units not included in the weighted average common shares calculation used for diluted earnings per share due to their antidilutive effect for the quarter ended June 30, 2003.

Note 5. Discontinued Operations

Energy Holdings

Energy Technologies' Investments

Energy Technologies is comprised primarily of its remaining heating, ventilating and air conditioning (HVAC) and mechanical operating companies. In June 2002, Energy Holdings adopted a plan to sell its ~~interests in the~~ HVAC/mechanical operating companies. The ~~sale of these companies is expected to be completed by June 30, 2003. Energy Holdings has retained the services of an investment-banking firm to market these companies to interested parties. The~~ HVAC/mechanical operating companies meet the criteria for classification as components of discontinued operations and all prior periods have been reclassified to conform to the current year's presentation.

~~Due to current market conditions,~~ Energy Holdings continues to re-~~evaluated~~evaluate the carrying value of Energy Technologies' assets and ~~has~~liabilities ~~determined~~to ~~that~~determine anif current market conditions require additional write-~~down~~downs to fair value less cost to sell ~~was required~~. InFor the ~~first~~six ~~quarter~~months ofended June 30, 2003, Energy Holdings recorded an additional loss on disposal of Energy Technologies of $9 million, net of a $2 million tax benefit. ~~Energy~~Of ~~Holdings'~~the ~~remaining~~11 ~~investment~~HVAC ~~position~~companies held for sale in ~~Energy~~2002, ~~Technologies~~eight iswere ~~approximately~~sold ~~$40~~by ~~million~~June 30, of2003. ~~which~~In ~~approximately~~July ~~$35~~2003 ~~million~~two ~~relates~~additional tocompanies ~~tax~~were ~~assets,~~sold ~~associated~~at ~~with~~book ~~losses~~value ~~from~~and ~~the~~a ~~sale~~letter of ~~HVAC~~intent ~~companies,~~has ~~with~~been ~~the~~entered ~~remaining~~into ~~balance relating~~ to ~~other~~sell ~~net~~the ~~assets~~final company. OfThe sale of the 11remaining ~~HVAC~~company ~~companies~~has ~~owned~~been atdelayed ~~year~~due ~~end~~to market conditions, ~~four~~however, ~~were~~Energy ~~sold~~Holdings asexpects ofthe ~~March 31,~~sale ~~2003.~~to Inbe ~~April~~completed ~~2003,~~by anthe ~~additional~~end ~~four~~of ~~companies~~the ~~were~~third ~~sold~~quarter of 2003.

22 Energy Holdings' remaining investment position in Energy Technologies as of June 30, 2003 consists of $86 million in assets and $49 million in liabilities. Of the $86 million in assets approximately $31 million relates to tax assets associated with tax benefits from the sale of the HVAC companies, with the remaining balance relating primarily to its investment in the remaining three HVAC companies.

~~The revenues and results of operations are displayed below:~~23

	Quarters Ended March 31,
	2003			2002
	(Millions)
Operating Revenues	$	49		$	95
Pre-Tax Operating Loss	$	(9	)	$	(6	)
Net Loss	$	(6	)	$	(4	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The ~~carrying~~revenues ~~amounts~~and results of ~~the~~operations ~~assets~~of ~~and~~Energy ~~liabilities~~Technologies offor the ~~HVAC/mechanical~~quarter ~~operating~~and ~~companies,~~six asmonths ofended ~~March~~June 3130, 2003 and ~~December 31,~~ 2002 are ~~summarized~~displayed ~~in the following table~~below:

	As of
	Quarter Ended June 30,						Six Months Ended June 30,
	March 31, 2003			December 31, 2002
	2003			2002			2003			2002
	(Millions)
Current Assets	$	21		$	82
Operating Revenues	$	12		$	91		$	61		$	186
Noncurrent Assets		23			25
Pre-Tax Operating Loss	$	(4	)	$	(9	)	$	(13	)	$	(15	)
Total Assets	$	44		$	107
Net Loss	$	(2	)	$	(5	)	$	(8	)	$	(9	)
Current Liabilities	$	27		$	85
Noncurrent Liabilities		5			5
Long-Term Debt		12			5
Total Liabilities	$	44		$	95

~~Tanir~~ The ~~Bavi~~carrying amounts of the assets and liabilities of the HVAC/mechanical operating companies, as of June 30, 2003 and December 31, 2002 are summarized in the following table:

In 2002, the Tanir Bavi generating facility in India, met the criteria for classification as a component of discontinued operations and all prior periods were reclassified to conform to the current year's presentation. The operating results of Tanir Bavi are summarized below. In the fourth quarter of 2002, Global sold its 74% interest in Tanir Bavi for approximately $45 million.

	As of
	June 30, 2003		December 31, 2002
	(Millions)
Current Assets	$	10	$	82
Noncurrent Assets		21		25

Total Assets	$	31	$	107

Current Liabilities	$	15	$	85
Noncurrent Liabilities		5		5
Long-Term Debt		11		5

Total Liabilities	$	31	$	95

	Quarter Ended March 31, 2002
	(Millions)
Operating Revenues		$29
Pre-Tax Operating Income		$ 6
Net Income		$ 3

Tanir Bavi Power Company Ltd. (Tanir Bavi)

~~Note~~ In 5the fourth quarter of 2002, Global sold its 74% interest in the Tanir Bavi generating facility in India for approximately $45 million. ~~Commitments~~The facility met the criteria for classification as a component of discontinued operations and ~~Contingent~~all ~~Liabilities~~prior periods were reclassified to conform to that presentation. The operating results of Tanir Bavi for the quarter and six months ended June 30, 2002 are summarized below.

Old Dominion Electric Cooperative (ODEC)

	Quarter Ended June 30, 2002		Six Months Ended June 30, 2002
	(Millions)
Operating Revenues	$	32	$	61
Pre-Tax Operating Income	$	3	$	9
Net Income	$	2	$	5

~~PSE&G and Power~~ 24

InNOTES 1995,TO PSE&GCONSOLIDATED enteredFINANCIAL intoSTATEMENTS a ten-year wholesale power contract with ODEC. The contract was transferred to Power in conjunction with the generation asset transfer in 2000. The contract provides for Power to supply ODEC with capacity and energy for a bundled rate that includes a component to recover multiple transmission charges (referred to as ''pancaked transmission rates''UNAUDITED).

InNote November 1997, Federal Energy Regulatory Commission (FERC) issued the Pennsylvania-New Jersey-Maryland Power Pool (PJM) Restructuring Order, which required PSE&G to modify its contract with ODEC to remove pancaked transmission rates. While PSE&G sought rehearing of this order, it was nonetheless required to reduce its rate to ODEC by approximately $6 million per year, effective April 1, 1998. OnRegulatory DecemberAssets 19,and 2002, based on a court ruling, FERC reversed its November 1997 order Liabilities

23PSEG and PSE&G

~~thereby~~ As ~~reinstating~~of ~~the~~June original contract terms. This allows Power to collect amounts for April 1998 through December 2002 pursuant to the original contract. The difference in revenues between the contracted rate and the FERC-ordered reduced rate is approximately $30 ~~million~~, ~~inclusive of back interest. Power billed ODEC for this amount in January~~ 2003 and ~~will~~December ~~record~~31, ~~this~~2002, ~~gain when realized. Power has been billing~~respectively, ~~recording~~PSEG and ~~receiving~~PSE&G ~~payment~~had ondeferred the ~~higher~~following ~~rate~~regulatory ~~beginning~~assets ~~in January 2003. ODEC is paying these amounts but has protested both the past due~~ and ~~current~~liabilities ~~amounts~~on at the ~~higher~~Consolidated ~~rates~~Balance ~~in a complaint at FERC. This matter is currently pending.~~Sheets:

	As of
	June 30, 2003		December 31, 2002		Recovery/Refund Period
	(Millions)
Regulatory Assets
Securitized Stranded Costs	$	3,782	$	3,885		Through December 2015(1)(2)
Deferred Income Taxes		371		326		Various
OPEB-Related Costs		183		193		Through December 2012(2)
Manufactured Gas Plant Remediation Costs		115		115		Various(2)
Unamortized Loss on Reacquired Debt and Debt Expense		84		86		Over remaining debt life(1)
Underrecovered Gas Costs		110		154		Through September 2004(1)
Non-Utility Generation Transition Charge (NTC)		68		—		Through December 31, 2005(1)
Unrealized Losses on Interest Rate Swap		73		66		Through December 2015(2)
Repair Allowance Taxes		97		93		Through August 2013(1)(2)
Decontamination and Decommissioning Costs		21		21		Through December 2007(2)
Plant and Regulatory Study Costs		24		25		Through December 2021(2)
Regulatory Restructuring Costs		42		33		Through August 2013(1)(2)
Other		5		5

Total Regulatory Assets	$	4,975	$	5,002

Regulatory Liabilities
Excess Depreciation Reserve	$	179	$	171		Through December 31, 2005(2)
NTC		—		27		Through December 31, 2005(1)
Societal Benefits Charges (SBC)		177		50		Through December 31, 2005(1)(2)
Other		6		4		Various(1)

Total Regulatory Liabilities	$	362	$	252


(1)		Recovered/Refunded with interest
(2)		Recoverable/Refundable per specific rate order

In July 2003, the BPU issued an oral decision in PSE&G's Electric Base Rate Case. The descriptions below supplement the information contained in Note 7. Regulatory Assets and Liabilities in the 2002 Annual Report on Form 10-K to reflect the effects of changes resulting from the oral decision. For additional information relating to the oral decision, see Note 16. Subsequent Events.

SBC: The SBC, as authorized by the BPU and the Energy Competition Act, includes costs related to PSE&G's electric and gas business as follows: 1) the universal service fund; 2) nuclear plant decommissioning; 3) demand side management (DSM) programs; 4) social programs which include bad debt expense; 5) consumer education; and 6) Market Transition Charge (MTC) over recovery. All components except for MTC accrue interest. Effective August 1, 2003, nuclear plant decommissioning will no longer be included in the electric SBC.

NTC: This clause was established by the Energy Competition Act to account for above market costs related to non-utility generation (NUG) contracts, as approved by the BPU. Costs or benefits associated with the restructuring of these contracts are deferred. This clause also includes Basic Generation Service (BGS) costs in excess of current rates, as approved by the BPU.

Repair Allowance Taxes: This represents tax, interest and carrying charges relating to disallowed tax deductions for repair allowance as authorized by the BPU with recovery over 10 years effective August 1, 2003.

Regulatory Restructuring Costs: These are costs related to the restructuring of the energy industry in New Jersey through the Energy Competition Act and include such items as the system design work

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

necessary to transition PSE&G to a transmission and distribution only company, as well as costs incurred to transfer and establish the generation function as a separate corporate entity with recovery over 10 years beginning August 1, 2003.

Excess Depreciation Reserve: As required by the BPU in 1999, PSE&G reduced its depreciation reserve for its electric distribution assets and recorded such amount as a regulatory liability. The remaining amount of the original liability as of June 30, 2003 is $24 million, which will be amortized in July 2003. In June 2003, PSE&G recorded an additional $155 million liability as a result of the oral decision issued by the BPU in PSE&G's Electric Base Rate Case. This $155 million will be amortized from August 1, 2003 through December 31, 2005.

Note 7. Commitments and Contingent Liabilities

Guaranteed Obligations

Power

Power has guaranteed certain commodity related transactions for its subsidiary, ER&T, which is involved in energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial agreements in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power guarantees support the current exposure, interest and other costs on sums due and payable by ER&T under these agreements. Guarantees offered for trading and marketing cover the granting of lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can go either direction. The face value of the guarantees outstanding on ~~March~~June 30, 2003 and December 31, ~~2003~~2002 was $1.25 billion and $1.1 billion, respectively. In order for Power to experience a liability of $1.25 billion, ER&T 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 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 being simultaneously ''out-of-the-money'' ~~given the nature of ER&T's asset backed transactions~~ is highly unlikely. 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 ~~from such liabilities was $506 million as of March 31, 2003. The current exposure~~ consists of the net of accounts receivable and accounts payable (AR/AP), ~~where netting is permitted,~~ and the forward value on open positions., ~~The~~less ~~net~~any ~~AR/AP~~margins ~~for~~posted. ~~these~~The ~~transactions~~current isexposure ~~included in~~from ~~the~~such ~~Consolidated~~liabilities ~~Balance~~was ~~Sheets~~$313 million and ~~for~~$268 ~~the~~million ~~transactions~~as ~~that~~of ~~receive~~June 30, ~~mark-to-market or~~2003 ~~cash~~and ~~flow~~December 31, ~~hedge accounting treatment~~2002, ~~that~~respectively. ~~portion~~Of ofthe ~~current~~$313 million, ~~exposure~~$240 million is ~~also~~ ~~included~~recorded inon ~~the~~Power's Consolidated Balance Sheets as of June 30, 2003. ~~The~~A ~~majority~~significant portion of the current exposure under such guarantees is attributable to the ~~BGS~~load contracts that ~~will~~ expire on July 31, ~~2002~~2003 and the overlap of the mark-to-market exposure of ~~these~~ those contracts and the contracts recently signed through the auction for the period beginning August 1, 2003. The ~~BGS~~load contracts are accounted for on a settlement basis. As energy is delivered under all of these contracts, the portion of Power's exposure under such guarantees will decrease. Also, beginning August 1, 2003 the realized portion of the exposure on the new BGS contracts will offset the forward value exposure on the open positions for the contracts that are included in the $506 million current exposure.

In addition, all Master Agreements and other supply contracts, including Power's BGS-related load contracts, contain margin and/or other collateral requirements that, as of ~~March 31~~June 30, 2003, could require Power to post additional collateral of approximately $~~652~~353 million if a) Power were to lose its investment grade credit rating, and b) all counterparties, ~~where~~with whom Power is ''out-of-the money'' under such contracts, were entitled to and called for collateral.

In addition, Power has issued an approximate $40 million guarantee on behalf of a third party's performance under a ~~Basic Generation Service (~~BGS) contract expiring in July 2003. Because Power supplies the third party with the energy needed for performance under the guarantee, it is highly unlikely Power would incur any liabilities in connection with the guarantee. As of ~~March 31~~June 30, 2003, there were no ~~claims against~~amounts recorded in connection with the guarantee.

~~As of March 31~~Also, ~~2003,~~Power ~~letters~~has ~~of credit~~ issued bya ~~Power~~guarantee ~~were~~relating ~~outstanding~~to inpotential ~~the~~future ~~amount~~environmental ofliabilities ~~approximately~~at ~~$74~~its ~~million~~Connecticut infacilities ~~support of various contractual obligations, environmental liabilities, and~~ to ~~satisfy~~the ~~trading~~State ~~collateral~~regulatory ~~obligations~~bodies.

Power has also provided credit support for equity contributions relating to its subsidiaries relating to the construction of its Lawrenceburg and Waterford facilities. Should Power lose its investment grade credit rating, it would be required to post $151 million in letters of credit for those projects. The amount of credit support is expected to decrease as Power completes the projects.26

EnergyNOTES HoldingsTO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

~~Energy~~As ~~Holdings~~of ~~and/or~~June ~~Global~~30, ~~have~~2003, ~~guaranteed~~letters ~~certain~~of ~~obligations~~credit ofissued ~~their~~by ~~subsidiaries~~Power orwere ~~affiliates,~~outstanding ~~including~~in the ~~successful~~amount ~~completion,~~of ~~performance~~approximately or$86 ~~other~~million in support of various contractual obligations, ~~related~~environmental liabilities and to ~~certain~~satisfy trading collateral obligations.

24 Power has also guaranteed equity contributions by its subsidiaries relating to the construction of its Lawrenceburg, Indiana and Waterford, Ohio facilities. Should Power lose its investment grade credit rating, it would be required to post $128 million in letters of credit for those projects. Such guarantees will be cancelled upon satisfaction of Power's equity commitments, which are included in its anticipated capital expenditures for the remainder of 2003.

projects in an aggregate amount of approximately $306 million as of March 31, 2003. The guarantees include a $61 million equity commitment for Elektrocieplownia Chorzow Sp. z.o.o. (ELCHO) in Poland, a $49 million standby equity commitment for Skawina in Poland, $41 million of various guarantees for Dhofar Power Company in Oman, $31 million in guarantees related to financing at Electroandes in Peru and a $25 million contingent guarantee related to debt service obligations of Chilquinta Energia Finance LLC in connection with electric distribution companies in Chile and Peru. Additional guarantees consist of a $36 million leasing agreement guarantee for Prisma in Italy and various other guarantees comprising the remaining $63 million. Approximately $85 million of such guarantees will be cancelled upon satisfaction of Global's equity commitments, which are included in Energy Holdings' anticipated capital expenditures for the remainder of 2003.

InEnergy ~~the~~Holdings ~~normal~~and/or ~~course~~Global have guaranteed certain obligations of ~~business~~their subsidiaries or affiliates, ~~Energy~~including ~~Technologies~~the ~~secures~~successful ~~construction~~completion, performance or other obligations ~~with~~related ~~performance~~to ~~bonds~~certain ~~issued~~projects byin ~~insurance~~an ~~companies.~~aggregate Asamount of ~~March~~approximately 31$261 million as of June 30, 2003,. ~~Energy~~The ~~Technologies~~guarantees ~~had~~include a $~~234~~61 million ofequity ~~such~~commitment ~~bonds~~for ~~outstanding,~~ELCHO ofin ~~which~~Poland, a $4149 million ~~was~~standby atequity ~~risk~~commitment for Skawina CHP Plant in ~~ongoing~~Poland ~~construction~~(Skawina), ~~projects.~~$17 ~~The~~million ~~performance~~of ~~bonds~~various ~~are~~guarantees ~~not~~for ~~included~~Dhofar Power Company in ~~the~~Oman, and a $~~306~~25 million ofcontingent ~~guaranteed~~guarantee related to debt service obligations ~~discussed~~of ~~above.~~Chilquinta InEnergia ~~January~~Finance ~~2003,~~LLC ~~Energy~~in ~~Holdings~~connection ~~provided~~with anelectric ~~indemnification~~distribution ~~agreement~~companies in Chile and Peru. Additional guarantees consist of a $3138 million ofleasing ~~letters~~agreement ofguarantee ~~credit~~for Prisma in ~~support~~Italy ofand ~~Energy~~various ~~Technologies'~~other ~~obligations~~guarantees comprising the remaining $71 million. ~~These~~Approximately ~~amounts~~$61 ~~are~~million ~~expected~~of tosuch ~~decrease~~guarantees ~~over~~will ~~time~~be ascancelled ~~Energy~~upon ~~Technologies~~satisfaction ~~completes~~of ~~the~~Global's ~~work~~equity commitments, which are included in ~~process~~Energy orHoldings' ~~transfers~~anticipated ~~ownership~~capital toexpenditures ~~other~~for ~~companies~~the remainder of 2003.

In the normal course of business, Energy Technologies secures construction obligations with performance bonds issued by insurance companies. As of June 30, 2003, Energy Technologies had $209 million of such bonds outstanding, of which $34 million related to ongoing construction projects. The performance bonds are not included in the $261 million of guaranteed obligations discussed above. In January 2003, Energy Holdings provided an indemnification agreement and $31 million of letters of credit in support of Energy Technologies' obligations. As of June 30, 2003, $25 million in letters of credit remain, including obligations relating to certain of the HVAC companies that have been previously sold. These amounts are expected to decrease over time as each of the HVAC companies completes the work in process or transfers ownership to other companies.

Environmental Matters

PSE&G and Power

Hazardous Waste

The New Jersey Department of Environmental Protection (NJDEP) regulations concerning site investigation and remediation require an ecological evaluation of potential injuries to natural resources in connection with a remedial investigation of contaminated sites. The NJDEP is presently working with the energy industry to develop procedures for implementing these regulations. These regulations may substantially increase the costs of remedial investigations and remediations, where necessary, particularly at sites situated on surface water bodies. PSE&G, Power and 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 on these projects is not currently estimable. PSE&G and Power do not anticipate that the compliance with these regulations will have a material adverse effect on their respective financial positions, results of operations or net cash flows.

~~PSE&G~~ 27

PSE&GNOTES ManufacturedTO GasCONSOLIDATED PlantFINANCIAL STATEMENTS (MGPUNAUDITED) Remediation Program

PSE&G is currently working with the NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at PSE&G's former MGP sites. To date, 38 sites have been identified. The Remediation Program is periodically reviewed and revised by PSE&G based on regulatory requirements, experience with the Remediation Program and available remediation technologies. The long-term costs of the Remediation Program cannot be reasonably estimated, but experience to date indicates that at least $20 million per year could be incurred over a period of about 30 years since inception of the program in 1988 and that the overall cost could be material. The costs for this remediation effort are recovered through charges to utility customers.

As of March 31, 2003, PSE&G's estimatedManufactured netGas liabilityPlant for(MGP) remediationRemediation costs through 2005 aggregated $115 million. Expenditures beyond 2005 cannot be reasonably estimated and are therefore not accrued.Program

25 PSE&G is currently working with the NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at PSE&G's former MGP sites. To date, 38 sites have been identified. The Remediation Program is periodically reviewed and revised by PSE&G based on regulatory requirements, experience with the Remediation Program and available remediation technologies. The long-term costs of the Remediation Program cannot be reasonably estimated, but experience to date indicates that at least $20 million per year could be incurred over a period of about 30 years since inception of the program in 1988 and that the overall cost could be material. The costs for this remediation effort are recovered through SBC charges to utility customers.

~~Passaic~~ As ~~River~~of ~~Site~~June 30, 2003, PSE&G's estimated net liability for remediation costs through 2005 aggregated $115 million. Expenditures beyond 2005 cannot be reasonably estimated and are therefore not accrued.

The United States Environmental Protection Agency (EPA) has determined that a nine 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 and that, to date, at least thirteen corporations, including PSE&G, may be potentially liable for performing required remedial actions to address potential environmental pollution in the Passaic River ''facility.''Site

~~PSE&G~~The ~~and~~United ~~certain~~States ofEnvironmental ~~its~~Protection ~~predecessors~~Agency ~~conducted~~(EPA) ~~industrial~~has ~~operations~~determined atthat ~~properties~~a ~~within~~nine mile stretch of the Passaic River ~~facility.~~in ~~The~~the ~~operations~~area ~~included~~of ~~one operating electric generating station~~Newark, ~~one~~New ~~former~~Jersey ~~generating~~is ~~station~~a ~~and four former MGPs. PSE&G~~'s'facility'' ~~costs~~within ~~to clean up former MGPs are recoverable from utility customers through~~ the ~~SBC.~~meaning ~~PSE&G~~of ~~has~~that ~~sold~~term ~~the~~under ~~site of~~ the ~~former~~Federal ~~generating~~Comprehensive ~~station~~Environmental ~~and~~Response, ~~obtained~~Compensation ~~releases~~ and ~~indemnities~~Liability ~~for~~Act ~~liabilities arising out~~ of ~~the~~1980 ~~site~~and inthat, ~~connection with the sale. The operating generating station was transferred~~ to ~~Power~~date, ~~pursuant~~at toleast ~~the~~thirteen ~~Final~~corporations, ~~Order.~~including PSE&G ~~cannot predict what action~~, ~~if any, the EPA or any third party~~ may ~~take~~be ~~against~~potentially ~~PSE&G~~liable ~~with~~for ~~respect~~performing torequired ~~this~~remedial ~~matter,~~actions ~~or in such an event, what costs may be incurred~~ to address ~~any~~potential ~~such~~environmental ~~claims.~~pollution ~~However,~~in ~~such~~the ~~costs~~Passaic ~~may~~River ~~be material~~''facility.''

PSE&G and certain of its predecessors conducted industrial operations at properties within the Passaic River facility. The operations included one operating electric generating station, one former generating station and four former MGPs. PSE&G's costs to clean up former MGPs are recoverable from utility customers through the 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 operating generating station was transferred to Power in August 2000. PSE&G cannot predict what action, if any, the EPA or any third party may take against PSE&G with respect to this matter, or in such an event, what costs may be incurred to address any such claims. However, such costs may be material.

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

ThePrevention EPAof andSignificant theDeterioration NJDEP issued a demand in March 2000 under the Federal Clean Air Act (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 the information request in November 2000. In January 2002, Power reached an agreement with New JerseySource andReview the federal governments to resolve allegations of noncompliance with federal and State of New Jersey PSD/NSR regulations. Under that agreement, over the course of 10 years, Power must install advanced air pollution controls that are designed to reduce emissions of Nitrogen Oxide (NOx), Sulfur Dioxide (SO2), particulate matter and mercury. The estimated cost of the program at the time of the settlement was $337 million to be incurred through 2011. 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 the dispute over Bergen 2 regarding the applicability of PSD requirements, and allowed construction of the unit to be completed and operation to commence.)

~~Power has~~The ~~recently notified the~~ EPA and the NJDEP ~~that~~issued ita isdemand ~~evaluating~~in March 2000 under the ~~continued operation~~Federal ofClean Air Act (CAA) requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal ~~unit~~burning ~~beyond~~units ~~2006,~~were implemented in ~~light~~accordance ofwith ~~changes~~applicable inPSD/NSR regulations. Power completed its response to the ~~energy~~ information request in November 2000. In January 2002, Power reached an agreement with New Jersey and ~~capacity~~the ~~markets~~federal government to resolve allegations of noncompliance with federal and ~~increases~~New inJersey PSD/NSR regulations. Under that agreement, over the ~~cost~~course of 10 years, Power must install advanced air pollution ~~control~~controls ~~equipment and~~that ~~other~~are ~~necessary~~designed ~~modifications~~to reduce emissions of Nitrogen Oxide (NOx), Sulfur Dioxide (SO2), particulate matter and mercury. The Aestimated ~~decision~~cost isof ~~expected~~the program at the time of the settlement was $337 million to be ~~made~~incurred inthrough ~~2003 as~~2011. Power also paid a $1.4 million civil penalty and has agreed to ~~the~~spend ~~Hudson~~up ~~unit's~~to ~~continued~~$6 ~~operation~~million on supplemental environmental projects. The ~~related~~agreement ~~costs~~resolving ~~associated~~the ~~with these~~NSR ~~modifications~~allegations ~~have~~concerning ~~not~~the ~~been~~Hudson ~~included~~and inMercer ~~Power's~~coal-fired ~~capital~~units ~~expenditure~~also ~~projections~~resolved the dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operation to commence.

Power has notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit beyond 2006, in light of changes in the energy and capacity markets and increases in the cost of pollution control equipment and other necessary modifications. Power is also exploring the

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

feasibility of installing less costly pollution control equipment at the Hudson coal unit to satisfy the requirements of its agreement with the EPA and the NJDEP. A decision is expected to be made in 2003 as to the Hudson unit's continued operation. The related costs associated with these modifications have not been included in Power's capital expenditure projections.

New Generation and Development

Power and Energy Holdings

~~Through~~Completion anof ~~indirect,~~the ~~wholly-owned subsidiary~~projects, ~~Power~~discussed ~~is developing the Bethlehem Energy Center~~below, awithin ~~763 MW combined-cycle power plant that will replace~~ the ~~376~~estimated MWtime ~~Albany,~~frames NYand ~~Steam~~cost ~~Station.~~estimates ~~Total~~cannot ~~costs for this project are expected to~~ be ~~approximately~~assured. ~~$483~~Construction ~~million~~delays, ~~with~~cost ~~expenditures~~increases toand ~~date~~various ofother ~~approximately~~factors ~~$212~~could ~~million.~~result ~~Construction~~in ~~began~~changes in ~~2002~~the ~~with~~operational ~~the~~dates ~~expected~~or ~~completion~~ultimate ~~date~~costs into ~~2005~~complete.

Power is constructing a 1,218 MW combined-cycle generation plant at Linden, New Jersey. Total costs are estimated at approximately $711 million with expenditures to date of approximately $575 million. Completion is expected in 2005.

26 Through an indirect, wholly-owned subsidiary, Power is developing the Bethlehem Energy Center, a 763 MW combined-cycle power plant that will replace the 376 MW Albany, NY Steam Station. Total costs for this project are expected to be approximately $500 million with expenditures to date of approximately $248 million. Construction began in 2002 with the expected completion date in 2005.

Power is constructing, ~~through~~a ~~indirect~~1,220 ~~wholly-owned~~MW ~~subsidiaries, two natural gas-fired~~ combined-cycle ~~electric~~ generation ~~plants~~plant inat ~~Waterford~~Linden, ~~Ohio~~New ~~(821 MW) and Lawrenceburg, Indiana (1,096 MW) at an estimated aggregate total cost of $1~~Jersey.2 ~~billion.~~ Total ~~expenditures~~ tocosts ~~date~~are ~~on these projects have been approximately $1 billion. The required~~ estimated ~~equity~~at ~~investment in these projects is~~ approximately $~~400~~ 750 million, with ~~the~~expenditures ~~remainder~~to ~~being~~date ~~financed with non-recourse bank financing. As~~ of ~~March 31, 2003,~~ approximately $~~294~~587 million ~~of equity has been invested in these projects~~. InCompletion ~~connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to which it~~ is ~~obligated~~expected toin purchase the output of these facilities. Based on current prices, the purchase price under this contract is currently above market. ER&T may terminate the agreement upon repayment of the current financing scheduled for August 2005. Additional equity investments may be required if the proceeds received from ER&T under this tolling agreement are not sufficient to cover the required payments under the bank financing. The Waterford facility is currently scheduled to achieve commercial operation in June 2003. The Lawrenceburg facility is currently scheduled to achieve commercial operation in the fourth quarter of 2003.

Power ~~also~~is ~~has~~constructing, ~~contracts~~through ~~with~~indirect, ~~outside~~wholly-owned ~~parties~~subsidiaries, totwo ~~purchase~~natural ~~upgraded~~gas-fired ~~turbines~~combined-cycle ~~for~~electric ~~the~~generation ~~Salem~~plants ~~Nuclear~~in ~~Generating~~Waterford, ~~Station~~Ohio ~~Units~~(821 MW) and Lawrenceburg, Indiana (1,096 MW) ~~and~~at an estimated aggregate total cost of $1.2 ~~and~~billion. Total expenditures to ~~purchase~~date ~~upgraded~~on ~~turbines~~these ~~and~~projects ~~complete~~have abeen ~~power~~approximately ~~uprate~~$1.0 ~~for~~billion. ~~Hope~~The ~~Creek~~required ~~Generating~~estimated ~~Station~~equity toinvestment ~~increase~~in ~~its~~these ~~generating~~projects ~~capacity~~is approximately $400 million, with the remainder being financed with non-recourse bank financing. ~~The~~As ~~contracts~~of ~~for~~June 30, ~~Hope~~2003, ~~Creek~~approximately ~~are~~$337 ~~subject~~million of equity has been invested in these projects. In connection with these projects, ER&T has entered into a five-year tolling agreement pursuant to ~~Nuclear~~which ~~Regulatory~~it ~~Commission~~is ~~(NRC)~~obligated ~~approval~~to ~~and~~purchase the ~~projects~~output ~~are~~of these facilities. Based on current prices, the purchase price under this contract is currently above market. ER&T may terminate the agreement upon repayment of the current financing scheduled tofor August 2005. Additional equity investments may be ~~completed~~required byif ~~2004~~the ~~for~~proceeds ~~Salem~~received ~~Unit~~from 1ER&T ~~and~~under ~~Hope~~this ~~Creek~~tolling ~~and~~agreement ~~2006~~are ~~for~~not ~~Salem~~sufficient ~~Unit~~to 2cover the required payments under the bank financing. ~~Power's~~The ~~aggregate~~Waterford ~~estimated~~facility ~~costs~~is ~~for~~currently ~~these~~scheduled ~~projects~~to ~~are~~achieve ~~$210~~commercial ~~million,~~operation ~~with~~in ~~expenditures~~August 2003. The Lawrenceburg facility is currently scheduled to ~~date~~achieve ofcommercial ~~approximately~~operation ~~$47~~in ~~million~~the fourth quarter of 2003.

~~Completion~~Power ofalso ~~the~~has ~~above~~contracts ~~projects~~with ~~within~~outside parties to purchase upgraded turbines for the ~~estimated~~Salem ~~time~~Nuclear ~~frames~~Generating Station (Salem) Units 1 and ~~cost~~2 ~~estimates~~and ~~cannot~~to bepurchase ~~assured~~upgraded turbines and complete a power uprate for Hope Creek Generating Station (Hope Creek) to increase its generating capacity. ~~Construction~~The ~~delays,~~power ~~cost~~uprate ~~increases~~for ~~and~~Hope ~~various~~Creek ~~other~~is ~~factors~~currently ~~could~~scheduled ~~result~~to inbe ~~changes~~completed inby 2005, assuming timely approval from the ~~operational~~Nuclear ~~dates~~Regulatory orCommission ~~ultimate~~(NRC). The turbine replacements are currently scheduled to be completed by 2004 for Salem Unit 1 and Hope Creek and 2006 for Salem Unit 2. Power's aggregate estimated costs for these projects are $210 million, with expenditures to ~~complete~~date of approximately $61 million.

Power has commitments to purchase gas turbines and/or other services to meet its current plans to develop additional generating capacity. The aggregate amount due under these commitments is approximately $480 million, approximately $370 million of which is included in estimated costs for the projects discussed above. The approximate $110 million remaining relates to obligations to purchase hardware and services that have not been designated to any specific projects. If Power ~~does~~is ~~not~~currently ~~contract~~discussing tothe ~~satisfy~~restructuring ~~its~~of ~~commitment~~these ~~relating~~obligations. toThe ~~the~~negotiation ~~$110~~period ~~million~~for inrestructuring ~~obligations~~these bycontracts ~~July~~has been extended from July 2003 to September 30, it2003 ~~may~~and bePower ~~subject~~has toprovided ~~penalties~~a letter of upcredit to ~~$24~~the ~~million~~supplier for the potential penalty amount, which will expire on that date. Power believes that this

~~Energy Holdings~~ 29

CaliforniaNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

~~GWF~~matter ~~Energy~~will ~~LLC~~be ~~(GWF~~satisfactorily ~~Energy)~~resolved, ~~a joint venture between Global and Harbinger GWF LLC (Harbinger)~~however, ~~owns~~no ~~and~~assurances ~~operates~~can ~~two~~be ~~peaker plants in California and is currently constructing the Tracy Peaker Plant, a 167 MW facility which is scheduled for completion in the second quarter of 2003~~given. AsIf ~~of March 31, 2003, Global's investment in GWF Energy was $204 million and its ownership interest in GWF Energy was 76%. The commercial operations date deadline of~~ the ~~Tracy~~negotiations ~~Peaker~~are ~~Plant is July 1~~unsuccessful, ~~2003~~Power ~~under~~may ~~GWF Energy's power purchase agreement with the California Department of Water Resources. Global's permanent equity investment in GWF Energy, including contingencies, is expected to~~ be ~~reduced~~subject to apenalties ~~maximum~~ of ~~$100~~up million upon successful completion of permanent project financing, which has been delayed as a result of the litigation between Global and Harbinger discussed below. The duration of the delay in permanent project financing that may result from the litigation cannot be determined at this time. In the event permanent project financing does not occur and Harbinger does not buy back any of its ownership interest in GWF Energy from Global or make any additional investment in GWF Energy, Global's permanent investment in GWF Energy could increase to ~~approximately~~ $~~280~~24 million. ~~For a description of working capital loans from Global to GWF Energy pending completion of project financing, see Note 12. Related-Party Transactions.~~

27Energy Holdings

On February 19, 2003, Harbinger filed an action with the Circuit Court of Shelby Co., Alabama alleging that Global wrongfully diluted Harbinger's membership interest percentage in GWF Energy. Harbinger is seeking an injunction preventing Global from converting or maintaining the conversion of optional loans made to GWF Energy by Global into capital contributions and thus diluting Harbinger's membership interest percentage, along with other injunctive or equitable relief, including a reallocation of equity in GWF Energy for appropriate funding from Harbinger. On March 26, 2003, Global filed with the American Arbitration Association (AAA) requesting a determination and declaration in accordance with GWF Energy's Operating Agreement. On March 27, 2003, Global filed a ''Motion to Dismiss the Complaint or Stay Litigation and to Compel Arbitration'' (Motion) with the Circuit Court. A Circuit Court hearing is scheduled for May 7, 2003 relative to Global's Motion.California

~~Peru~~ GWF Energy LLC (GWF Energy), which is jointly owned by Global and Harbinger GWF LLC (Harbinger), owns and operates three peaker plants in California, including the Tracy Peaker Plant, a 170 MW facility that completed construction and achieved commercial operation under GWF Energy's power purchase agreement with the California Department of Water Resources in the second quarter of 2003.

In December 2001, Global acquired an interest in Electroandes, a 183 MW hydroelectric generation company in Peru that sells its output to non-regulated purchasers (primarily mining companies) under power purchase agreements. Part of the purchase price was financed with a $100 million one-year bridge loan with an original maturity date in December 2002 that was subsequently extended to June 2003. On March 26, 2003, Electroandes refinanced the $100 million bridge loan with a $70 million seven-year amortizing facility and two $15 million one-year facilities (each guaranteed by Energy Holdings). Additionally, on March 25, 2003, Electroandes filed a request for approval of a $100 million bond program. Bonds issued under this program following the expected approval will be used for general corporate purposes, including servicing the seven-year and one-year loan facilities.Poland

In 2002, Global acquired a 50% interest in the 590 MW (electric) and 618 MW (thermal) coal-fired Skawina plant, located in Poland. The transaction includes Global's obligation to increase its equity interest in Skawina to approximately 65% and the obligation to offer to purchase an additional 10% from Skawina's employees, increasing Global's potential ownership interest to 75%. Global's total equity investment is expected to be approximately $105 million, including contingencies and equity commitment guarantees. Through June 30, 2003, Global's equity exposure was approximately $37 million at Skawina.

In 2002, Global acquired a 50% interest in the 590 MW (electric) and 618 MW (thermal) coal-fired Skawina CHP Plant (Skawina), located in Poland. The transaction includes Global's obligation to increase its equity interest in Skawina to approximately 65% and the obligation to offer to purchase an additional 10% from Skawina's employees, increasing Global's potential ownership interest to 75%. Global's total equity investment is expected to be approximately $105 million, including contingencies and equity commitment guarantees. Through March 31, 2003, Global had invested approximately $36 million at Skawina.

Minimum Fuel Purchase Requirements

Power

Power uses coal for certain of its fossil electric generation stations. Power purchases coal through various contracts and in the spot market for its generation plants. The total minimum purchase requirements included in these contracts amount to approximately $~~137~~229 million through ~~2006~~2008.

Power has several long-term purchase contracts with uranium suppliers, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek nuclear power plants. On average, Power has various multi-year requirements-based purchase commitments that total approximately $88 million per year to meet Salem's and Hope Creek's fuel needs. Power has been advised by Exelon Generation LLC (Exelon), the co-owner and operator of Peach Bottom Atomic Power Station (Peach Bottom), that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom.

In addition to its fuel requirement, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas. As of June 30, 2003, the total minimum purchase requirements under these contracts was approximately $1.1 billion through 2016.

Nuclear Fuel Disposal

Power

Under the Nuclear Waste Policy Act of 1982 ~~(NWPA)~~, 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 Kilowatt-hour (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 US 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 to be available earlier than 2010.

2830

disposalNOTES ofTO spentCONSOLIDATED nuclearFINANCIAL fuel.STATEMENTS To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001UNAUDITED) per Kilowatt-hour (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 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 to be available earlier than 2010.

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). The availability of adequate spent fuel storage capacity is estimated through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power presently expects to construct an on-site storage facility that would satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of their respective license lives. This construction will require certain regulatory approvals, the timely receipt of which cannot be assured. Exelon has advised Power that it has ~~constructed~~ constructed an on-site storage facility at Peach Bottom that is now licensed and operational. ~~and~~This ~~can~~on-site ~~provide~~ storage ~~capacity~~facility atwill ~~least~~satisfy ~~through~~Peach ~~the~~Bottom's ~~end~~fuel ofstorage ~~the~~until ~~current~~at ~~licenses~~least ~~for the two Peach Bottom units~~2014.

Exelon has advised Power that it had signed an agreement with the DOE applicable to Peach Bottom under which Exelon would be reimbursed for costs incurred resulting from the DOE's delay in accepting spent nuclear fuel. Under this agreement, Power's portion of Peach Bottom's Nuclear Waste Fund fees have been reduced by approximately $18 million through August 31, 2002, at which point the credits were fully utilized and covered the cost of Exelon's storage facility. In 2000, a petition was filed against the DOE in the US Court of Appeals for the Eleventh Circuit, seeking to set aside the receipt of credits by Exelon. In September 2002, the Court issued an opinion upholding the challenge by the petitioners. Under the terms of the agreement, the DOE and Exelon are required to meet and discuss alternative funding sources for the settlement credits. The Eleventh Circuit's opinion suggests that the federal judgment fund should be available as an alternate source. If such negotiations are unsuccessful, any payments required by Power resulting from a disallowance of the previously reduced fees would be included in Energy Costs on the Consolidated Statements of Operations.

In ~~2000~~September 2001, aNuclear ~~petition was~~ filed ~~against~~a ~~the~~complaint ~~DOE~~ in the US Court of ~~Appeal~~Federal ~~for~~Claims ~~the Eleventh Circuit,~~ seeking todamages ~~set~~caused ~~aside the receipt of credits~~ by ~~Exelon. On September 24, 2002,~~ the ~~Court~~DOE ~~issued~~not antaking ~~opinion~~possession ~~upholding the challenge by the petitioners. Under the terms~~ of ~~the~~spent ~~agreement,~~nuclear ~~DOE~~fuel ~~and~~in ~~Exelon are required to meet and discuss alternative funding sources for the settlement credits~~1998. ~~The~~No ~~Eleventh~~assurances ~~Circuit's~~can ~~opinion suggests that the federal judgment fund should~~ be ~~available~~given as anto ~~alternate source. If such negotiations are unsuccessful,~~ any ~~payments~~damage ~~required~~recovery byor ~~Power~~the ~~resulting~~ultimate ~~from~~availability ~~a disallowance~~ of ~~the~~a ~~previously~~disposal ~~reduced fees would be included in Energy Costs in the Consolidated Statements of Operations~~facility.

In ~~September~~October 2001, ~~Nuclear~~Power filed a complaint in the US Court of Federal Claims, ~~seeking~~along ~~damages~~with ~~caused~~a bynumber ~~the~~of ~~DOE~~other ~~not~~plaintiffs, ~~taking~~seeking ~~possession~~$28 ofmillion ~~spent~~in ~~nuclear~~relief ~~fuel~~from inpast ~~1998~~overcharges by the DOE for enrichment services. No assurances can be given as to any damage recovery ~~or the ultimate availability of a disposal facility~~.

In October 2001, Power filed a complaint in the US Court of Federal Claims, along with a number of other plaintiffs, seeking $28 million in relief from past overcharges by the DOE for enrichment services. No assurances can be given as to any damage recovery.

Other

Energy Holdings

Argentina

~~Under~~The ~~certain~~shares ~~circumstances,~~formerly ~~Global~~held ~~could~~by beGlobal ~~obligated~~in ~~to settle its share (approximately $26 million) of a project loan for~~ Empresa Distribuidora La Plata S.A. (EDELAP), ahave ~~distribution~~been ~~company~~transferred into ~~Argentina, should it or the majority owner of the project (~~The AES Corporation ~~(AES)), take certain actions including forcing or permitting certain loan parties to declare bankruptcy~~. In ~~addition,~~connection ~~the~~with ~~guarantee~~that ~~can~~transfer, ~~be triggered by transferring the shares of~~ certain ~~loan~~contingent ~~parties~~obligations ~~without~~Global ~~lender~~had ~~consent.~~with ~~Breach~~respect ~~of this transfer covenant can be cured by delivering certain pledge agreements relating~~ to the ~~ownership~~project ofloans ~~loan~~relating ~~parties~~ to ~~the~~EDELAP ~~lenders.~~have ~~Global~~been ~~could~~terminated ~~also~~by beagreement ~~liable~~with ~~for any incremental direct damages arising from~~ the ~~breach of these covenants~~lenders. ~~Given the likely cure of any breach by the project sponsors, such a contingent obligation is remote and, therefore, no provision has been made in Energy Holdings'~~

29India

~~Consolidated~~ Global ~~Financial~~has ~~Statements.~~a ~~Under~~20% interest in a 330 MW plant, PPN Power Generating Station (PPN) in the ~~terms~~Indian State of Tamil Nadu. Output from the ~~settlement~~facility is sold under a long-term Power Purchase Agreement (PPA) with the Tamil Nadu Electricity Board (TNEB) which sells the power to retail end-user customers. TNEB has not made full payment to PPN for the purchase of energy under contract. The past due receivable at PPN as of June 30, 2003 was approximately $85 million, Global's ~~litigation~~share ~~with~~of ~~AES~~which is approximately $8 million, ~~AES~~net isof ~~required~~a to$9 ~~deliver~~million ~~pledge~~reserve. ~~agreements~~Global's ~~that~~exposure ~~are~~to ~~required~~the ~~under~~open receivables is included in the ~~loan~~$40 ~~documents~~million investment exposure discussed below.

~~India~~ On April 1, 2003, PPN did not receive two expected partial payments from TNEB, which resulted in PPN defaulting on a debt payment of $10 million to its project lenders. Consequently, PPN advised lenders of its inability to make the scheduled debt payment. Also, PPN has not paid working capital

Global has a 20% interest in a 330 MW plant, PPN Power Generating Company Limited (PPN) in the Indian State of Tamil Nadu. Energy Holdings' investment exposure (investment less non-recourse debt) in this facility is approximately $40 million. Power from the facility is sold under a long-term Power Purchase Agreement (PPA) with the Tamil Nadu Electricity Board (TNEB) which sells the power to retail end-user customers. TNEB has not been able to make full payment to PPN for the purchase of energy under contract due to its overall poor liquidity situation. The past due receivable at PPN as of March 31, 2003 is approximately $84 million, Energy Holdings' share of which is approximately $17 million, net of a $7 million reserve. Energy Holdings' exposure to the open receivables is included in the $40 million investment exposure discussed above.

OnNOTES AprilTO 1,CONSOLIDATED 2003,FINANCIAL PPNSTATEMENTS did not receive an expected partial payment from TNEB, which resulted in PPN defaulting on a debt payment to its project lenders of $10 million. Consequently, PPN advised lenders of its inability to make the scheduled debt payment. Also, PPN has not paid working capital interest, amounts due under letters of credit covering fuel supplies, gas supply invoices and fuel supply letters of credit due in April 2003.(UNAUDITED)

~~PPN is~~interest, ~~developing~~amounts adue ~~contingency~~under ~~plan~~letters of credit covering fuel supplies, gas supply invoices and ~~has~~fuel supply letters of credit due in April 2003. As a result, PPN closed the plant as of April 10, 2003. ~~The~~ TNEB ~~has~~was ~~been~~ notified of the plant closing resulting from PPN's inability to procure fuel and fund operating expenses due to non-payment by TNEB. InSubsequently ~~late April~~TNEB made adequate payments in May 2003 to enable PPN to pay its lenders and fuel suppliers. The plant restarted on May 30, a2003 ~~partial~~and has been in operation since then. Adequate payments were also made by TNEB in June 2003 to enable PPN to meet its debt payment obligations on June 30, 2003. As a result of $8these ~~million~~issues, ~~was~~Energy ~~received~~Holdings has performed an impairment test on this investment and ~~negotiations~~determined ~~are continuing~~that ~~toward~~no ~~full~~impairment ~~resolution~~is necessary as of ~~this~~June 30, ~~matter~~2003. NoIf ~~changes~~TNEB fails to make required payments under the ~~long-term forecasts~~PPA, PPN may have further liquidity problems. Negotiations with TNEB are continuing and Energy Holdings cannot predict the outcome of ~~cash~~this ~~flows~~matter. ~~were~~Energy ~~deemed~~Holdings' ~~appropriate~~investment ~~for~~exposure ~~PPN~~is approximately $40 million. ~~Global~~An ~~will~~adverse ~~continue~~ outcome to ~~monitor~~such ~~the~~negotiations ~~situation~~could potentially result in ~~India~~an ~~closely~~impairment of this investment, which could be material to PSEG's and Energy Holdings' respective results of operations.

Tunisia

~~Global~~On ~~owns~~April a24, ~~60%~~2003, ~~interest in~~ Carthage Power Company (CPC), aand ~~471~~Alstom MWCentrales ~~gas-fired~~Energetiques ~~combined-cycle electric generation facility located in Rades, Tunisia~~S.A. ~~CPC has entered into a 20-year power purchase contract for the sale of 100% of the output to Societe Tunisienne de l' Electricite et du Gaz~~ (~~STEG~~Alstom). ~~The~~entered ~~contract~~in ~~called~~an ~~for~~agreement ~~the~~settling ~~plant~~all toliquidated bedamages ~~operational~~caused by ~~November~~the ~~24,~~delay ~~2001, however, due to delays~~ in construction~~, this deadline was not met~~. ~~STEG~~As ~~has~~per ~~declared~~this ~~that~~agreement, itAlstom ispaid ~~entitled~~ to ~~liquidated~~CPC ~~damages~~an ataggregate ~~the~~amount ~~rate~~ of approximately $6717 ~~thousand~~million acomposed ~~day~~of ~~since~~approximately ~~November~~$9 ~~24,~~million ~~2001~~ in ~~accordance~~cash, ~~with~~$3 ~~the~~million ~~terms~~in ofspare ~~the~~parts ~~power purchase contract. CPC is contesting STEG's claim~~ and ~~the~~Alstom ~~two~~waived ~~parties~~payments ~~are~~from ~~currently~~Societe inTunisienne ~~negotiations~~de tol' ~~settle~~Electricite ~~this~~et ~~dispute.~~du ~~The~~Gaz ~~facility was built by Alstom Centrales Energetiques S.A.,~~ (~~Alstom~~STEG) anfor ~~independent~~contracts ~~contractor,~~for ~~who~~equipment ~~was obligated~~totaling toapproximately ~~complete~~$5 ~~construction~~million. byOn ~~September 3~~June 5, ~~2001. The facility commenced operation on May 14~~2003, ~~2002.~~STEG ~~CPC~~confirmed ~~believes it is entitled~~ to ~~liquidated~~CPC ~~damages~~its ~~from~~acceptance ~~Alstom~~of inthe ~~amounts~~services ~~greater~~to ~~than~~be ~~the~~provided ~~claims~~ by ~~STEG. CPC and~~ Alstom ~~are~~as insettlement ~~negotiations~~of toits ~~settle the liquidated damages~~ claims. ~~Such~~of liquidated damages ~~are~~for ~~secured~~the bydelay ~~letters of credit totaling $30 million. In April an agreement~~ in ~~principle was reached between CPC, Alstom and STEG. If~~ the ~~agreement~~start ~~becomes~~of ~~final, all related matters will be settled without an adverse material effect on CPC~~operations.

Note 68. 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 ~~the~~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 losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings use derivative instruments as risk management tools consistent with their respective business plans and prudent business practices.

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 losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings use derivative instruments as risk management tools consistent with their respective business plans and prudent business practices.

Derivative Instruments and Hedging Activities

Energy Trading Contracts

Power

Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, fixed transmission rights (FTR), coal and emission allowances, in the spot, forward and futures markets, primarily in the Pennsylvania-New Jersey-Maryland Power Pool (PJM), and also in the ~~Super~~surrounding ~~Region~~region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana and natural gas in the producing region~~, the Henry Hub Basin, as well as the Super Region~~.

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 does not engage in the practice of simultaneous trading for the purpose of increasing trading volume or revenue. 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. These contracts also involve financial transactions including swaps, options and futures.

Power marks to market its energy trading contracts in accordance with SFAS 133. As of March 31, 2003 and December 31, 2002, substantially all of these contracts had terms of two years or less. 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 or price options. The effect of using such modeling techniques is not material to Power's financial results.32

ForNOTES theTO quartersCONSOLIDATED endedFINANCIAL MarchSTATEMENTS 31, 2003 and 2002, Power recorded net margins as shown below:(UNAUDITED)

	Quarters Ended March 31,
	2003		2002
	(Millions)
Realized Gains (Losses)	$	22	$	(2	)
Unrealized Gains		4		30
Gross Margin		26		28
Broker Fees and Other Trading-Related Expenses		2		2
Net Margin	$	24	$	26

engage in the practice of simultaneous trading for the purpose of increasing trading volume or revenue. 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. These contracts also involve financial transactions including swaps, options and futures.

Power marks to market its energy trading contracts in accordance with SFAS 133. As of ~~March 31~~June 30, 2003 and December 31, 2002, ~~the~~substantially ~~cumulative~~all ~~unrealized~~of ~~gains~~these ~~for~~contracts ~~all~~had ~~periods~~terms ~~related~~of totwo years or less. Wherever possible, fair values for these ~~energy~~contracts ~~trading~~were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were ~~approximately~~employed ~~$28~~using ~~million~~assumptions ~~and~~reflective ~~$24~~of ~~million~~current market rates, ~~respectively~~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, exchange-traded futures contracts require a deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. The amount of Power's margin deposits as of ~~March 31~~June 30, 2003 was approximately $1218 million.

31Commodity Contracts

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 and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase contracts, swaps, options and futures.

TheCash availabilityFlow 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 and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase contracts, swaps, options, futures, etc.Hedges

~~Cash~~ In ~~Flow~~order ~~Hedges~~to hedge a portion of its forecasted energy purchases to meet its electric supply requirements, Power enters into forward purchase contracts, futures, options, swaps and FTR contracts. These contracts, in conjunction with owned electric generation capacity, are designed to cover estimated wholesale electric customer commitments. Power also forecasts the energy delivery from its generating stations based on the forward price curve movement of energy and, as a result, it enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of June 30, 2003, the fair value of these hedges was $(12) million. During the next 12 months, $7 million of unrealized losses (net of gains) on these commodity derivatives accumulated in OCI is expected to be reclassified as earnings. As defined in SFAS 133, there was no ineffectiveness associated with these hedges since the terms of the instruments perfectly match the transaction or risk the instruments are hedging. These hedges will mature through 2004.

InEffective ~~order~~with tothe ~~hedge~~transfer ~~a portion~~ of ~~Power~~PSE&G's ~~forecasted~~gas ~~energy~~contracts ~~purchases~~ to ~~meet its electric supply requirements,~~ Power ~~enters~~on ~~into forward purchase contracts~~May 1, ~~futures~~2002, ~~options~~Power ~~and~~acquired ~~swaps.~~all ~~These~~of ~~contracts,~~the ingas-related ~~conjunction~~derivatives ~~with~~entered ~~owned~~into ~~electric~~by ~~generation~~PSE&G. ~~capacity,~~The ~~are~~derivatives ~~designed~~used to ~~cover~~hedge ~~estimated wholesale electric customer commitments. Power also forecasts~~ the ~~energy~~forecasted ~~delivery~~purchase ~~from~~and ~~its~~sale ~~generating~~of ~~stations~~natural ~~based~~gas onare ~~the~~designated ~~forward price curve movement of energy~~ and, effective as acash ~~result,~~flow ~~Power~~hedges. ~~enters~~Gains ~~into~~or ~~swaps,~~losses ~~options~~from ~~and futures transactions to hedge~~ the ~~price~~derivatives ofentered ~~fuel~~into to ~~meet~~hedge ~~its~~residential ~~fuel~~customer ~~purchase~~ requirements ~~for generation. These derivative transactions~~ are ~~designated~~deferred and ~~effective~~recovered asfrom ~~cash~~PSE&G's ~~flow~~customers ~~hedges~~as ~~under~~part ~~SFAS 133. As~~ of ~~March 31, 2003,~~ the ~~fair~~monthly ~~value~~billing ofto ~~these hedges was $20 million~~PSE&G. Unrealized gains ~~and~~or losses ~~associated~~on ~~with~~the ~~these hedges~~derivatives ofentered ~~$(12)~~to ~~million,~~hedge ~~net~~commercial ofand ~~tax,~~industrial ~~was~~customer requirements are recorded to OCI ~~for the quarter ended March 31, 2003~~. AsThere ~~defined in SFAS 133, there~~ was no ineffectiveness ~~associated~~realized ~~with~~on these hedges. ~~Under~~As ~~SFAS~~of ~~133~~June 30, ~~ineffectiveness~~2003, ~~can occur when~~ the ~~terms~~fair value of anhedge ~~instrument~~instruments doassociated ~~not~~with ~~perfectly~~hedging ~~match~~residential ~~the~~customer ~~transaction~~requirements orwas ~~risk~~$38 ~~the instrument is hedging~~million. These hedges will mature through ~~2004~~2005.

Effective with the transfer of PSE&G's gas contracts to Power on May 1, 2002, Power acquired all of the derivatives entered into by PSE&G. The derivatives used to hedge the forecasted purchase of natural gas are designated and effective as cash flow hedges. Gains or losses from the derivatives entered to hedge residential customer requirements are deferred and recovered from PSE&G's customers as part of the monthly billing to PSE&G. Gains or losses on the derivatives entered to hedge commercial and industrial customer requirements are recorded to OCI. There was no ineffectiveness realized on these hedges. As of March 31, 2003, the fair value of hedge instruments associated with hedging residential customer requirements was $33 ~~million. The maximum term of these contracts is approximately two years.~~

OtherNOTES DerivativesTO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

PowerOther also enters into certain other contracts which are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are option contracts for fuel purchases for generation requirements. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs on the Consolidated Statement of Operations at the end of each reporting period. For the quarters ended March 31, 2003 and 2002, Power recorded gross margins as shown below:Derivatives

	Quarters Ended March 31,
	2003			2002
	(Millions)
Realized Losses	$	(14	)	$	(12	)
Unrealized (Losses) Gains		(7	)		20
Gross Margin	$	(21	)	$	8

Power also enters into certain other contracts which are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are for fuel purchases for generation requirements. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs on the Consolidated Statements of Operations at the end of each reporting period.

As of March 31, 2003 and December 31, 2002, the cumulative unrealized gains and losses for all periods related to these contracts were approximately $13 million and $20 million, respectively. The contracts related to the majority of these gains and losses had terms of less than two years and were valued through market exchanges and, where necessary, broker quotes.

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 rate debt, floating rate debt and interest rate derivatives.

FairCash ValueFlow Hedges

PSEG, PSE&G, Power and Energy Holdings

PSEG, ~~uses~~PSE&G, Power and Energy Holdings use interest rate swaps and other interest rate derivatives to ~~convert~~manage atheir ~~portion~~exposures to the variability of ~~fixed-rate~~cash ~~debt~~flows, ~~into~~primarily related to variable-rate debt instruments. The interest ~~swaps~~rate derivatives are designated and effective as ~~fair~~cash ~~value~~flow hedges. The fair value changes of these ~~interest~~derivatives ~~rate~~are ~~swaps~~initially ~~are~~recorded ~~fully~~in ~~offset~~OCI. byAs of June 30, 2003, the fair value ~~changes~~of inthese ~~the~~cash ~~underlying~~flow ~~debt.~~hedges ~~For~~was ~~the~~$(268) ~~quarter~~million, ~~ended~~including ~~March 31~~$(24) million, ~~2003~~$(73) million, $(10) million and $(161) million at PSEG, PSE&G, Power and Energy Holdings, respectively. The $(73) million at PSE&G is deferred and will be recovered from PSE&G's customers. During the ~~fair~~next ~~value~~12 months, $25 million of ~~these~~unrealized ~~hedges~~losses ~~was~~(net of gains) on interest rate derivatives accumulated in OCI is expected to be reclassified as earnings, including $(4) million., ~~There~~$(3) million ~~was~~and no$(18) million ~~ineffectiveness~~at ~~related~~PSEG, toPower ~~these~~and ~~hedges~~Energy Holdings, respectively.

Energy Holdings

In April 2003, Energy Holdings, in a private placement, issued $350 million of 7.75% Senior Notes due in 2007. Energy Holdings is using an interest rate swap to convert a portion of this fixed-rate debt into variable-rate debt. The interest swaps are designated and effective as fair value hedges. The fair value changes of these interest rate swaps are fully offset by the fair value changes in the underlying debt.

Cash Flow Hedges

PSEG, PSE&G, Power and Energy Holdings

PSEG, PSE&G, Power 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 the variable rate debt instruments. The interest rate derivatives are designated and effective as cash flow hedges. The fair value changes of these derivatives are initially recorded in OCI. Reclassification of unrealized gains or losses on these cash flow hedges from OCI into earnings occurs as interest payments are accrued on the debt instrument and generally offsets the change in the interest accrued on the underlying variable rate debt. As of March 31, 2003, the fair value of these cash flow hedges was $(236) million, including $(65) million of loss that is deferred and recovered from PSE&G's customers. $(19) million of unrealized losses (net of gains) on interest rate derivatives accumulated in OCI is expected to be reclassified as earnings during the next 12 months.

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 this risk is that some of its foreign subsidiaries and affiliates ~~utilize~~have functional currencies other than the consolidated reporting currency, the US Dollar. Additionally, certain of Global's foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in US Dollars or currencies other than their own functional currencies. Global, a US Dollar functional currency entity, is primarily exposed to changes in the US Dollar against the Brazilian Real, the Euro, the Polish Zloty, the Peruvian Nuevo Sol and the Chilean Peso. With respect to the foreign currency risk associated with the Brazilian Real and the Chilean Peso, there has already been significant devaluation since the initial acquisition of these investments, which has resulted in reduced US Dollar earnings and cash flows relative to initial projections. Whenever possible, these subsidiaries and affiliates have 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, wherever possible, to manage risk related to certain foreign currency fluctuations.

33 As of June 30, 2003, net foreign currency devaluations have reduced the total amount of Energy Holdings' Member's Equity by $284 million, of which $181 million and $110 million were caused by the devaluation of the Brazilian Real and the Chilean Peso, respectively.

subsidiaries and affiliates have 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, wherever possible, to manage risk related to certain foreign currency fluctuations.34

AsNOTES ofTO MarchCONSOLIDATED 31,FINANCIAL 2003,STATEMENTS net foreign currency devaluations have reduced the total amount of Energy Holdings' total Member's Equity by $333 million, of which $192 million and $138 million were caused by the devaluation of the Brazilian Real and the Chilean Peso, respectively.(UNAUDITED)

Cash Flow Hedges

Affiliates of Energy Holdings purchase forward-exchange contracts as hedges of anticipated payments to contractors for projects under construction. These contracts are designed to hedge against the risk that the future cash payments will be adversely affected by changes in foreign currency rates. As of ~~March~~June 3130, 2003, Energy Holdings recorded its pro-rata share of the fair value on the forward -exchange contracts as an increase of $2 million in OCI. There was no ineffectiveness associated with these hedges.

Additionally, an affiliate of Energy Holdings entered into a PPA that contains an embedded derivative. This embedded derivative is designated as a cash flow hedge of foreign currency debt exposure. To the extent that the derivative is effective in offsetting foreign currency exposure, the amount is recorded in OCI. Amounts will be reclassified from OCI to earnings over the life of the debt. To the extent that the derivative is provided to hedge ana ~~equity~~ return in US Dollars, the offsetting amount is recorded in earnings, which amounted to approximately $3 million for the six months ended June 30, 2003. As of ~~March 31~~June 30, 2003, the fair value of the derivative was $1913 million. The ineffectiveness associated with this hedge was immaterial to earnings. The maximum term of these cash flow hedges is related to the embedded derivative, which will expire in 2022.

For the quarter March 31, 2003, the maximum term of these cash flow hedges is related to the embedded derivative, which will expire in 2022.

Hedges of Net Investments in Foreign Operations

Energy Holdings has numerous investments in foreign subsidiaries. The net assets of these subsidiaries are exposed to volatility in currency exchange rates and Energy Holdings uses both derivative and nonderivative financial instruments to hedge a part of this exposure.

An affiliate of Energy Holdings entered into a foreign currency option contract to hedge its exposure to changes in the US Dollar to the Korean Won exchange rate. As of March 31, 2003, Energy Holdings pro-rata share of the fair value of the foreign currency option was immaterial.

Equity Securities

Energy Holdings

During the first quarter of 2003, Resources recognized a $10 million of other than temporary impairments of non-publicly traded equity securities, which are held within its investment in certain leveraged buyout funds. ~~and~~In ~~other~~the ~~investments~~second quarter of 2003, ~~which~~Resources isrecognized a $6 million gain on the publicly traded equity securities within those funds. These gains and losses are included in Operating Revenues in the Consolidated Statements of Operations. As of ~~March 31~~June 30, 2003, Resources had investments in leveraged buyout funds of approximately $8287 million, of which $2429 million was comprised of public securities with available market prices and $58 million was comprised of non-publicly traded securities. As of December 31, 2002, Resources had investments in leveraged buyout funds of approximately $93 million, of which $24 million was comprised of public securities with available market prices and $69 million was comprised of non-publicly traded securities.

34Note 9. Comprehensive Income

Note 7. Comprehensive Income

	PSE&G			Power (A)			Energy Holdings (B)			Other (C)			Consolidated Total
	(Millions)
For the Quarter Ended June 30, 2003:
Net Income (Loss)	$	4		$	109		$	31		$	(14	)	$	130
Other Comprehensive Income		1			24			34			3			62

Comprehensive Income (Loss)	$	5		$	133		$	65		$	(11	)	$	192

For the Quarter Ended June 30, 2002:
Net Income (Loss)	$	8		$	83		$	(347	)	$	(8	)	$	(264	)
Other Comprehensive Income (Loss)		—			(14	)		34			(5	)		15

Comprehensive Income (Loss)	$	8		$	69		$	(313	)	$	(13	)	$	(249	)

For the Six Months Ended June 30, 2003:
Net Income (Loss)	$	105		$	656		$	75		$	(30	)	$	806
Other Comprehensive Income		—			60			14			6			80

Comprehensive Income (Loss)	$	105		$	716		$	89		$	(24	)	$	886

For the Six Months Ended June 30, 2002:
Net Income (Loss)	$	76		$	203		$	(462	)	$	(21	)	$	(204	)
Other Comprehensive Income (Loss)		(1	)		(7	)		(38	)		(4	)		(50	)

Comprehensive Income (Loss)	$	75		$	196		$	(500	)	$	(25	)	$	(254	)

~~Comprehensive~~(A) ~~Income,~~Changes ~~Net~~at Power primarily relate to unrealized gains and losses in the NDT Fund in 2003. (B) Changes at Energy Holdings primarily relate to foreign currency translation adjustments. (C) Other primarily consists of ~~Tax:~~activity at PSEG (parent company), Services and intercompany eliminations.

	PSE&G			Power		Energy Holdings			Other (A)			Consolidated Total
	(Millions)
For the Quarter Ended March 31, 2003:
Net Income	$	101		$	547	$	44		$	(16	)	$	676
Other Comprehensive Income		(1	)		36		(19	)		3			19
Comprehensive Income (Loss)	$	100		$	583	$	25		$	(13	)	$	695
For the Quarter Ended March 31, 2002:
Net Income	$	68		$	120	$	(115	)	$	(13	)	$	60
Other Comprehensive Income		(1	)		7		(72	)		1			(65	)
Comprehensive Income (Loss)	$	67		$	127		(187	)	$	(12	)	$	(5	)

(A)NOTES OtherTO primarilyCONSOLIDATED consistsFINANCIAL ofSTATEMENTS activity at PSEG (parent companyUNAUDITED), Services and intercompany eliminations.

Note 810. Other Income and Deductions

Other Income:

	PSE&G		Power		Energy Holdings		Other (A)		Consolidated Total
	(Millions)
Other Income:
For the Quarter Ended June 30, 2003:
Interest Income	$	2	$	4	$	—	$	—	$	6
NDT Fund Realized Gains		—		21		—		—		21
NDT Dividend Income		—		2		—		—		2
Other		1		—		—		—		1

Total Other Income	$	3	$	27	$	—	$	—	$	30

For the Quarter Ended June 30, 2002:
Interest Income	$	1	$	—	$	—	$	—	$	1
Gain on Disposition of Property		1		—		—		—		1
Minority Interest		—		—		—		4		4
Other		—		—		—		1		1

Total Other Income	$	2	$	—	$	—	$	5	$	7

For the Six Months Ended June 30, 2003:
Interest Income	$	4	$	9	$	—	$	—	$	13
Gain on Disposition of Property		8		—		—		—		8
NDT Fund Realized Gains		—		60		—		—		60
NDT Dividend Income		—		5		—		—		5
Other		1		—		1		—		2

Total Other Income	$	13	$	74	$	1	$	—	$	88

For the Six Months Ended June 30, 2002:
Interest Income	$	1	$	—	$	—	$	—	$	1
Gain on Disposition of Property		1		—		—		—		1
Change in Derivative Fair Value		—		—		1		—		1
Minority Interest		—		—		—		5		5
Other		—		—		—		1		1

Total Other Income	$	2	$	—	$	1	$	6	$	9

	PSE&G		Power		Energy Holdings		Other (A)		Consolidated Total
	(Millions)
For the Quarter Ended March 31, 2003:
Other Deductions:
Interest Income	$	2	$	4	$	—	$	—	$	6
For the Quarter Ended June 30, 2003:
Gain on Disposition of Property		8		—		—		—		8
NDT Fund Realized Losses and Expenses	$	—	$	12	$	—	$	—	$	12
Foreign Currency Transaction Gain		—		—		3		—		3
NDT Fund Realized Gains		—		41		—		—		41
Other		—		2		—		—		2
Total Other Income	$	10	$	47	$	3	$	—	$	60
For the Quarter Ended March 31, 2002:
Change in Derivative Fair Value	$	—	$	—	$	10	$	—	$	10
Minority Interest		—		—		—		1		1
Total Other Income	$	—	$	—	$	10	$	1	$	11
Change in Derivative Fair Value		—		—		6		—		6
Foreign Currency Losses		—		—		2		—		2
Total Other Deductions	$	—	$	12	$	8	$	1	$	21
For the Quarter Ended June 30, 2002:
Donations	$	1	$	—	$	—	$	—	$	1
Change in Derivative Fair Value		—		—		9		—		9
Foreign Currency Losses		—		—		17		—		17
Total Other Deductions	$	1	$	—	$	26	$	—	$	27
For the Six Months Ended June 30, 2003:
Donations	$	1	$	—	$	—	$	—	$	1
NDT Fund Realized Losses and Expenses		—		45		—		—		45
Minority Interest		—		—		—		6		6
Change in Derivative Fair Value		—		—		12		—		12
Total Other Deductions	$	1	$	45	$	12	$	6	$	64
For the Six Months Ended June 30, 2002:
Donations	$	1	$	—	$	—	$	—	$	1
Foreign Currency Losses		—		—		69		—		69
Total Other Deductions	$	1	$	—	$	69	$	—	$	70

35(A) Other consists of reclassifications for minority interests in PSEG's consolidated results of operations.

~~Other Deductions:~~36

	PSE&G		Power		Energy Holdings		Other (A)		Consolidated Total
	(Millions)
For the Quarter Ended March 31, 2003:
Donations	$	1	$	—	$	—	$	—	$	1
NDT Fund Realized Losses		—		33		—		—		33
Minority Interest		—		—		—		5		5
Change in Derivative Fair Value		—		—		6		—		6
Total Other Deductions	$	1	$	33	$	6	$	5	$	45
For the Quarter Ended March 31, 2002:
Foreign Currency Losses	$	—	$	—	$	52	$	—	$	52
Total Other Deductions	$	—	$	—	$	52	$	—	$	52

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(A)Note Other11. consistsIncome of reclassifications for minority interests in PSEG's consolidated results of operations.Taxes

~~Note~~ An 9.analysis ~~Income~~of ~~Taxes~~the tax provision expense is as follows:

An analysis of the tax provision expense is as follows:

	PSE&G (A)			Power			Energy Holdings			Other (B)			Consolidated Total
	(Millions)
For the Quarter Ended June 30, 2003:
Income (Loss) before Income Taxes	$	14		$	183		$	50		$	(26	)	$	221
Tax computed at the statutory rate		5			64			18			(9	)		78
Increase (decrease) attributable to flow through of certain tax adjustments:
State Income Taxes after Federal Benefit		3			10			—			(1	)		12
Rate Differential of Foreign Operations		—			—			(1	)		—			(1	)
Plant Related Items		(14	)		—			—			—			(14	)
Other		(2	)		—			(1	)		(1	)		(4	)

Total Income Tax Expense	$	(8	)	$	74		$	16		$	(11	)	$	71

Effective income tax rate		(57.1	)%		40.4	%		32.0	%		42.3	%		32.1	%

For the Quarter Ended June 30, 2002:
Income (Loss) before Income Taxes	$	8		$	145		$	(491	)	$	(9	)	$	(347	)
Tax computed at the statutory rate		2			51			(172	)		(3	)		(122	)
Increase (decrease) attributable to flow through of certain tax adjustments:
State Income Taxes after Federal Benefit		1			10			—			(1	)		10
Rate Differential of Foreign Operations		—			—			(6	)		—			(6	)
Plant Related Items		(5	)		—			—			—			(5	)
Other		2			1			1			(1	)		3

Total Income Tax Expense	$	—		$	62		$	(177	)	$	(5	)	$	(120	)

Effective income tax rate		0.0	%		42.8	%		36.0	%		55.6	%		34.6	%

For the Six Months Ended June 30, 2003:
Income (Loss) before Income Taxes	$	171		$	483		$	131		$	(59	)	$	726
Tax computed at the statutory rate		60			169			46			(21	)		254
Increase (decrease) attributable to flow through of certain tax adjustments:
State Income Taxes after Federal Benefit		14			28			—			(3	)		39
Rate Differential of Foreign Operations		—			—			(13	)		—			(13	)
Plant Related Items		(26	)		—			—			—			(26	)
Other		—			—			—			1			1

Total Income Tax Expense	$	48		$	197		$	33		$	(23	)	$	255

Effective income tax rate		28.1	%		40.8	%		25.2	%		39.0	%		35.1	%

For the Six Months Ended June 30, 2002:
Income (Loss) before Income Taxes	$	118		$	345		$	(486	)	$	(29	)	$	(52	)
Tax computed at the statutory rate		41			121			(170	)		(10	)		(18	)
Increase (decrease) attributable to flow through of certain tax adjustments:
State Income Taxes after Federal Benefit		10			20			1			(2	)		29
Rate Differential of Foreign Operations		—			—			(9	)		—			(9	)
Plant Related Items		(7	)		—			—			—			(7	)
Other		(2	)		1			1			(1	)		(1	)

Total Income Tax Expense	$	42		$	142		$	(177	)	$	(13	)	$	(6	)

Effective income tax rate		35.6	%		41.2	%		36.4	%		44.8	%		11.5	%

	PSE&G			Power			Energy Holdings			Other(A)			Consolidated Total
(A)	For the quarters ended June 30, 2003 and 2002, regulatory accounting differences, primarily plant-related items, are proportionally higher relative to pre-tax income resulting in relatively low or negative effective tax rates.
	(Millions)
(B)	PSEG's other activities include amounts applicable to PSEG (parent corporation) that primarily relate to financing and certain administrative and general costs.
For the Quarter Ended March 31, 2003:
Income from Continuing Operations before Cumulative Effect of a Change in Accounting Principle	$	157		$	300		$	81		$	(33	)	$	505
Tax computed at the statutory rate		55			105			28			(12	)		176
Increase (decrease) attributable to flow through of certain tax adjustments:
State Income Taxes after Federal Benefit		11			18			—			(2	)		27
Rate Differential of Foreign Operations		—			—			(12	)		—			(12	)
Plant Related Items		(12	)		—			—			—			(12	)
Other		2			—			1			2			5
Total Income Tax Expense	$	56		$	123		$	17		$	(12	)	$	184
Effective income tax rate		35.7	%		41.0	%		21.0	%		36.4	%		36.4	%
For the Quarter Ended March 31, 2002:
Income from Continuing Operations before Cumulative Effect of a Change in Accounting Principle	$	110		$	200		$	5		$	(20	)	$	295
Tax computed at the statutory rate		39			70			2			(7	)		104
Increase (decrease) attributable to flow through of certain tax adjustments:
State Income Taxes after Federal Benefit		9			10			1			(1	)		19
Rate Differential of Foreign Operations		—			—			(3	)		—			(3	)
Plant Related Items		(2	)		—			—			—			(2	)
Other		(4	)		—			—			—			(4	)
Total Income Tax Expense	$	42		$	80		$	—		$	(8	)	$	114
Effective income tax rate		38.2	%		40.0	%		(10.2	)%		40.0	%		38.6	%

~~(A) PSEG's other activities include amounts applicable to PSEG (parent corporation) that primarily relate to financing and certain administrative and general costs.~~37

36NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1012. Financial Information by Business Segments

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

						Energy Holdings
	PSE&G			Power		Resources			Global			Other (A)			Other (B)			Consolidated Total
	(Millions)
For the Quarter Ended March 31, 2003:
For the Quarter Ended June 30, 2003:
Total Operating Revenues	$	21,~~148~~342		$	1,~~887~~236	$	5167		$	~~157~~122		$	(1	)	$	(~~880~~347	)	$	32,~~364~~419
Income from Continuing Operations		100			177		12			42			(1	)		(9	)		321
Income (Loss) from Continuing Operations		22			109		23			11			(1	)		(14	)		150
Segment Earnings (Loss)		100			547		12			42			(16	)		(9	)		676
Loss from Discontinued Operations, net of tax		—			—		—			—			(2	)		—			(2	)
Gross Additions to Long-Lived Assets		97			153		—			105			1			6			362
Extraordinary Item, net of tax		(18	)		—		—			—			—			—			(18	)
As of March 31, 2003:
Net Income (Loss)		4			109		23			11			(3	)		(14	)		130
Total Assets	$	12,684		$	6,995	$	3,143		$	3,850		$	(72	)	$	(437	)	$	26,163
Segment Earnings (Loss)		3			109		22			7			(3	)		(8	)		130
Investments in Equity Method Subsidiaries	$	—		$	—	$	105		$	1,327		$	20		$	—		$	1,452
Gross Additions to Long-Lived Assets		132			177		—			62			1			(2	)		370
For the Quarter Ended March 31, 2002:
For the Six Months Ended June 30, 2003:
Total Operating Revenues	$	13,~~659~~490		$	~~576~~3,065	$	58118		$	78279		$	—		$	(~~488~~1,227	)	$	15,~~883~~725
Income from Continuing Operations		67			120		15			(13	)		(2	)		(6	)		181
Income (Loss) from Continuing Operations		123			286		37			57			(2	)		(30	)		471
Segment Earnings (Loss)		67			120		15			(98	)		(38	)		(6	)		60
Loss from Discontinued Operations, net of tax		—			—		—			—			(17	)		—			(17	)
Gross Additions to Long-Lived Assets		76			278		5			229			(2	)		(39	)		547
Extraordinary Item, net of tax		(18	)		—		—			—			—			—			(18	)
Cumulative Effect of a Change In Accounting Principle, net of tax		—			370		—			—			—			—			370
Net Income (Loss)		105			656		37			57			(19	)		(30	)		806
Segment Earnings (Loss)		103			656		34			49			(19	)		(17	)		806
Gross Additions to Long-Lived Assets		229			330		—			167			2			4			732
As of June 30, 2003:
Total Assets	$	12,671		$	6,999	$	3,177		$	3,967		$	79		$	(323	)	$	26,570
Investments in Equity Method Subsidiaries	$	—		$	—	$	111		$	1,344		$	20		$	—		$	1,475
For the Quarter Ended June 30, 2002:
Total Operating Revenues	$	1,230		$	673	$	32		$	101		$	—		$	(621	)	$	1,415
Income (Loss) from Continuing Operations		8			83		(3	)		(305	)		(2	)		(8	)		(227	)
Loss from Discontinued Operations, net of tax		—			—		—			(11	)		(26	)		—			(37	)
Net Income (Loss)		8			83		(3	)		(316	)		(28	)		(8	)		(264	)
Segment Earnings (Loss)		7			83		(4	)		(320	)		(28	)		(2	)		(264	)
Gross Additions to Long-Lived Assets		120			267		1			177			8			32			605
For the Six Months Ended June 30, 2002:
Total Operating Revenues	$	2,889		$	1,249	$	90		$	179		$	—		$	(1,109	)	$	3,298
Income (Loss) from Continuing Operations		76			203		14			(314	)		(4	)		(21	)		(46	)
Loss from Discontinued Operations, net of tax		—			—		—			(9	)		(29	)		—			(38	)
Cumulative Effect of a Change In Accounting Principle, net of tax		—			—		—			(89	)		(31	)		—			(120	)
Net Income (Loss)		76			203		14			(412	)		(64	)		(21	)		(204	)
Segment Earnings (Loss)		74			203		11			(420	)		(64	)		(8	)		(204	)
Gross Additions to Long-Lived Assets		196			545		6			406			6			(7	)		1,152
As of December 31, 2002:
Total Assets	$	12,429		$	67,~~941~~176	$	3,086		$	3,~~802~~790		$	(50	)	$	(~~489~~729	)	$	25,~~719~~702
Investments in Equity Method Subsidiaries	$	—		$	—	$	118		$	1,~~306~~305		$	20		$	—		$	1,~~444~~443

(A)		Energy Holdings' other activities include amounts applicable to Energy Holdings (parent company), the HVAC/operating companies of Energy Technologies, which were reclassified into discontinued operations in 2002, and EGDC. The net losses primarily relate to financing and certain administrative and general costs at the Energy Holdings parent corporation. For a discussion of the charges relating to Discontinued Operations at Energy Technologies, see Note 4. Discontinued Operations.
(B)		PSEG's other activities include amounts applicable to PSEG (parent corporation), 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 Basic Gas Supply Service (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 12. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at the PSEG parent corporation.

(A)

Energy Holdings' other activities include amounts applicable to Energy Holdings (parent company), the HVAC/operating companies of Energy Technologies, which were reclassified into discontinued operations in 2002, and EGDC. The net losses primarily relate to financing and certain administrative and general costs at the Energy Holdings parent corporation. For a

~~Note 11. Stock-Based Compensation~~38

PSEGNOTES appliesTO AccountingCONSOLIDATED PrinciplesFINANCIAL BoardSTATEMENTS (APBUNAUDITED) Opinion No. 25, ''Accounting for Stock Issued to Employees,'' and related interpretations in accounting for stock-based compensation plans. Accordingly, no compensation cost has been recognized for fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant. Had compensation costs for stock option grants been determined based on the fair value at the grant dates for awards under these plans in accordance with SFAS No. 123 ''Accounting for Stock-Based Compensation,'' there would have been a charge to net income of approximately $2 million and $3 million for the quarters ended March 31, 2003 and 2002, respectively, with a $(0.01) and $(0.01) impact on earnings per share for the quarters ended March 31, 2003 and 2002, respectively.

37discussion of the charges relating to Discontinued Operations at Energy Technologies, see Note 5. Discontinued Operations.

~~The~~(B) ~~following~~PSEG's ~~table~~other ~~illustrates~~activities ~~the~~include ~~effect~~amounts applicable to PSEG (parent corporation), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on ~~net~~any ~~income~~intercompany transactions, rather, all intercompany transactions are at cost or, in the case of the BGS and ~~earnings~~Basic ~~per~~Gas ~~share~~Supply ifService ~~PSEG~~(BGSS) ~~had~~contracts ~~applied~~between Power and PSE&G, at rates prescribed by the ~~fair~~BPU. ~~value~~For ~~recognition~~a ~~provisions~~further discussion of ~~SFAS~~the Nointercompany transactions between Power and PSE&G, see Note 14. ~~123~~Related-Party Transactions. The net losses primarily relate to ~~stock-based~~financing ~~employee~~and ~~compensation:~~certain administrative and general costs at the PSEG parent corporation.

	Quarters Ended March 31,
	2003			2002
	(Millions)
Net Income, as reported	$	676		$	60
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 Income	$	674		$	57
Earnings per share:
Basic and Diluted—as reported	$	3.00		$	0.29
Basic and Diluted—pro forma	$	2.99		$	0.28

Note 13. Stock-Based Compensation

~~Note~~ PSEG 12applies Accounting Principles Board (APB) Opinion No. ~~Related~~25, ''Accounting for Stock Issued to Employees,'' and related interpretations in accounting for stock-~~Party~~based ~~Transactions~~compensation plans. Accordingly, no compensation cost has been recognized for fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant.

The following table illustrates the effect on net income and earnings per share if PSEG had applied the fair value recognition provisions of SFAS No. 123, ''Accounting for Stock-Based Compensation,'' to stock-based employee compensation:

	Quarter Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
	(Millions, except Share Data)
Net Income (Loss), as reported	$	130		$	(264	)	$	806		$	(204	)
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2	)		(3	)		(4	)		(5	)

Pro forma Net Income (Loss)	$	128		$	(267	)	$	802		$	(209	)

Earnings per share:
Basic—as reported	$	0.58		$	(1.28	)	$	3.57		$	(0.99	)
Basic—pro forma	$	0.57		$	(1.29	)	$	3.55		$	(1.01	)
Diluted—as reported	$	0.57		$	(1.28	)	$	3.57		$	(0.99	)
Diluted—pro forma	$	0.56		$	(1.29	)	$	3.55		$	(1.01	)

BGSS and BGS Contracts

PSE&G and Power

Effective May 1, 2002, PSE&G transferred its gas supply contracts and gas inventory requirements to Power. On the same date, PSE&G entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G's BGSS requirements.

~~From~~For ~~January~~the 1quarter ended June 30, 2003 ~~through~~and ~~March~~2002, 31Power billed PSE&G approximately $293 and $97 million, respectively, for BGSS. For the six months ended June 30, 2003 and 2002, Power billed PSE&G approximately $~~832~~1.1 billion and $97 million, respectively, for BGSS. As of ~~March 31~~June 30, 2003 and December 31, 2002, PSE&G's payable to Power related to the BGSS contract was approximately $~~256~~67 million and $241 million, respectively.

Power charged PSE&G for the energy and capacity provided to meet its BGS requirements through July 31, 2002. Power also charges PSE&G for the ~~Market Transition Charge (~~MTC) ~~though~~through July 31, 2003. For the quarters ended ~~March 31~~June 30, 2003 and 2002, Power charged PSE&G approximately $4853 million and $~~460~~488 million, ~~respectively, for the MTC and BGS. As of March 31, 2003 and December 31, 2002, PSE&G's payable to Power relating to these costs was approximately $19 million and $2 million, respectively.~~

For the quarter ended March 31, 2002, PSE&G sold energy and capacity to Power at the market price of approximately $28 million, which PSE&G purchased under various Non-Utility Generation (NUG) contracts at costs above market prices.39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

respectively, for the MTC and BGS. For the six months ended June 30, 2003 and 2002, Power charged PSE&G approximately $101 million and $948 million, respectively, for the MTC and BGS. As of June 30, 2003 and December 31, 2002, PSE&G's payable to Power relating to these costs was approximately $14 million and $2 million, respectively.

For the quarter and six months ended June 30, 2002, PSE&G sold energy and capacity to Power at the market price of approximately $35 million and $63 million, respectively, which PSE&G purchased under various NUG contracts at costs above market prices.

Affiliate Loans

ThesePSEG transactions were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's consolidated financial statements.Power

~~PSEG~~ As of June 30, 2003 and December 31, 2002, Power had a payable to PSEG of approximately $4 million and $239 million, respectively, for short-term funding needs. There was no interest expense related to these borrowings for the quarter ended June 30, 2003, as compared to $2.9 million for the quarter ended June 30, 2002.

As of March 31, 2003, Power had a receivable from PSEG ofand approximatelyEnergy $204 million for short-term funding needs. As of December 31, 2002, Power had a payable to PSEG of approximately $239 million for short-term funding needs. There was no interest expense related to these borrowings for the quarter ended March 31, 2003, as compared to $1 million for the quarter ended March 31, 2002.Holdings

~~PSEG~~ As of June 30, 2003 and December 31, 2002, Energy Holdings had a receivable due from PSEG of $131 million and $62 million, respectively, for short-term funding needs. Interest Income related to this intercompany transaction was immaterial.

As of March 31, 2003, Energy Holdings had no outstanding affiliate loan balances with PSEG. As of December 31, 2002, Energy Holdings had a receivable due from PSEG of $62 million for short-term funding needs. Interest Income related to this borrowing was immaterial.

38Loans to Texas Independent Energy, L.P. (TIE)

Global and its partner, Panda Energy ~~Holdings~~International, Inc. (Panda), own and operate two electric generation facilities in Texas through TIE, a 50/50 joint venture. In January 2003, Panda indirectly transferred 50% of its interest in TIE to Teco Power Services (Teco). As of June 30, 2003, Global's investment in TIE was approximately $238 million including $72 million of loans that earn interest at an annual rate of 12% and that are scheduled to be repaid in quarterly installments through 2012. The quarterly loan installments due to Global are expected to be repaid out of the project cash flows or additional contributions from project partners in the event of insufficient project cash flows. For the quarter and six months ended June 30, 2003, Global recorded approximately $3 million and $5 million, respectively, of interest income related to this loan.

~~Affiliate~~ In ~~Payables~~March ~~due~~2003, Global funded $14 million of convertible preferred equity to ~~PSEG~~the ~~from~~two ~~Energy~~TIE ~~Technologies~~projects as part of its negotiations with project lenders to amend the projects' credit agreements. The convertible preferred equity has a 15% coupon and is convertible at Global's option into an approximate 13% equity interest in TIE if not repaid in full by June 2004.

AsLoans of December 31, 2002, Energy Technologies had recorded an affiliate payable due to PSEGGWF of $12 million. The amount was recorded as a component of Current Liabilities of Discontinued Operations on the Consolidated Balanced Sheets. Energy Technologies repaid this balance during the first quarter of 2003.

~~Loans~~ As of June 30, 2003, Global has provided GWF Energy $4 million of working capital loans to ~~TIE~~fund construction costs pending completion of permanent project financing. The loan earns interest at 20% per annum and is not convertible into equity. Global's ownership interest in GWF Energy was approximately 76% as of June 30, 2003. Harbinger has the right to buy back from Global up to one-half of the reduction of its equity ownership in GWF Energy from the 50% ownership level.

Global and its partner, Panda Energy International, Inc. (Panda), own and operate two electric generation facilities in Texas through Texas Independent Energy, L.P. (TIE), a 50/50 joint venture. In January 2003, Panda indirectly transferred 50% of its interest in TIE to Teco Power Services (Teco). As of June ~~March 31~~30, 2003, Global's equity investment in ~~TIE~~GWF Energy was ~~approximately~~ $~~246~~212 million, ~~including~~and its ~~$73~~ownership ~~million of loans that earn~~ interest atin anGWF ~~annual~~Energy ~~rate~~was ofapproximately 1276%. Global and ~~that~~ Harbinger are ~~scheduled~~currently ~~to be repaid~~ in ~~quarterly~~arbitration ~~installments~~ over ~~the~~allegations ~~next~~that 10Global ~~years.~~wrongfully ~~The~~diluted Harbinger's ~~quarterly~~ownership ~~loan~~percentage ~~installments~~interest ~~due~~in toGWF Energy. Global ~~are~~and ~~expected~~Harbinger agreed toon beJune ~~repaid~~4, ~~out~~2003 ofthat the ~~project~~issues ~~cash~~and ~~flows~~claims orraised ~~additional~~by ~~contributions~~Harbinger ~~from~~will ~~project~~be determined ~~partners~~ in ~~the~~arbitration ~~event~~and ofthat ~~insufficient project cash flows. For~~ the ~~quarter~~deadline ~~ended~~for ~~March 31,~~Harbinger ~~2003,~~to ~~Global~~buy ~~recorded~~back ~~approximately $2 million~~from of Global ~~interest~~up ~~income related~~ to ~~this loan.~~

In March 2003, Global funded $14 million of convertible preferred equity to the two TIE projects as part of its negotiations with project lenders to amend the projects' credit agreements. The convertible preferred equity has a 15% coupon and is convertible at Global's option into an approximate 13% equity interest in TIE if not repaid in full by June 2004.40

LoansNOTES toTO GWFCONSOLIDATED EnergyFINANCIAL STATEMENTS (UNAUDITED)

As50% of ~~March~~the ~~31,~~dilution ~~2003,~~of ~~Global~~its ~~has~~ownership ~~provided~~interest in GWF Energy $4would ~~million~~be ofextended ~~loans~~ to ~~fund~~30 ~~construction~~days ~~costs~~after ~~pending~~the ~~completion~~issuance of ~~project~~the ~~financing.~~decision ~~The~~in ~~loan~~the ~~earns interest at 20% per annum and is not convertible into equity~~arbitration. ~~Global's~~In ~~ownership interest in GWF Energy was 76% as of March 31~~addition, ~~2003.~~ Harbinger ~~GWF~~agreed ~~LLC has the right~~ to ~~buy~~dismiss ~~back~~such ~~from~~action ~~Global~~with upprejudice toupon ~~one-half~~completion of the ~~reduction~~arbitration. ofThe ~~its~~parties ~~equity~~are ~~ownership~~targeting into ~~GWF~~complete ~~Energy from~~ the ~~50%~~arbitration ~~ownership~~by ~~level.~~November ~~Such right terminates at the earlier of project financing or September~~ 30, 2003. ~~For~~though ano ~~discussion~~assurances ofcan ~~the~~be ~~dispute with Harbinger, see Note 5~~given. ~~Commitments and Contingent Liabilities.~~

Changes in Capitalization

PSE&G

On January 21, 2003, PSEG contributed $170 million of equity to PSE&G.

PSEG, PSE&G, Power and Energy Holdings

Services provides and bills administrative services to ~~PSEG,~~ PSE&G, Power and Energy Holdings as follows:

	Services Billings for the Quarters Ended March 31,				Payable to Services as of
	Services Billings for the Quarter Ended June 30,				Services Billings for the Six Months Ended June 30,				Payable to Services as of
	2003		2002		~~March 31,~~ 2003		~~December 31,~~ 2002		June 30, 2003		December 31, 2002
	(Millions)
PSEG	$	—	$	4	$	—	$	1
PSE&G	$	54	$	51	$	100	$	103	$	17	$	16
PSE&G		46		52		16		16
Power		27		31		54		66		6		2
Power		27		35		9		2
Energy Holdings		4		5		8		10		2		3
Energy Holdings		4		5		1		3

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

~~Note 13. Guarantees of Debt~~41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 15. Guarantees of Debt

Power

In April 2001, Power issued $500 million of 6.875% Senior Notes due 2006, $800 million of 7.75% Senior Notes due 2011 and $500 million of 8.625% Senior Notes due 2031. Additionally, in June 2002, Power issued $600 million of 6.95% Senior Notes due 2012. Each series of the Senior 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, for the quarters and six months then ended.

		Power			Guarantor ~~Subsidiaries~~Subsidaries			Other ~~Subsidiaries~~Subsidaries			Consolidating Adjustments			Total
								(millions)
								(Millions)
For the Quarter Ended March 31, 2003:
For the Quarter Ended June 30, 2003:
Revenues	$	—		$	2,058		$	127		$	(298	)	$	1,887
Operating Revenues	$	—		$	1,488		$	74		$	(326	)	$	1,236
Operating Expenses		—			1,~~744~~314			~~126~~52			(~~297~~326	)		1,~~573~~040
Operating Income (Loss)		—			314			1			(1	)		314
Operating Income		—			174			22			—			196
Other Income and Deductions		571			14			—			(571	)		14
Other Income		106			65			—			(144	)		27
Interest Expense		(41	)		(18	)		31			—			(28	)
Other Deductions		—			(45	)		—			33			(12	)
Income Taxes		17			(129	)		(12	)		1			(123	)
Interest Expense		(50	)		(21	)		32			11			(28	)
Cumulative Change in Accounting Principle		—			370			—			—			370
Income Taxes		54			(108	)		(19	)		(1	)		(74	)
Net Income (Loss)	$	~~547~~110		$	~~551~~65		$	2035		$	(~~571~~101	)	$	~~547~~109
For the Quarter Ended March 31, 2003:
For the Six Months Ended June 30, 2003:
Net Cash Provided By (Used In) Operating Activities	$	386		$	657		$	(262	)	$	(166	)	$	615
Operating Revenues	$	—		$	3,546		$	144		$	(625	)	$	3,065
Net Cash Provided By (Used In) Investing Activities	$	(205	)	$	(586	)	$	291		$	135		$	(365	)
Operating Expenses		—			3,070			110			(625	)		2,555
Net Cash Provided By (Used In) Financing Activities	$	(181	)	$	(50	)	$	(27	)	$	19		$	(239	)
Operating Income (Loss)		—			476			34			—			510
For the Quarter Ended March 31, 2002:
Other Income		677			80			—			(683	)		74
Revenues	$	—		$	574		$	2		$	—		$	576
Other Deductions		—			(45	)		—			—			(45	)
Operating Expenses		20			324			4			—			348
Interest Expense		(91	)		(39	)		63			11			(56	)
Operating Income (Loss)		(20	)		250			(2	)		—			228
Income Taxes		71			(232	)		(36	)		—			(197	)
Other Income and Deductions		156			(1	)		—			(155	)		—
Cumulative Effect of a Change in Accounting Principle		—			366			4			—			370
Interest Expense		(41	)		(16	)		29			—			(28	)
Net Income (Loss)	$	657		$	606		$	65		$	(672	)	$	656
Income Taxes		25			(96	)		(9	)		—			(80	)
For the Six Months Ended June 30, 2003:
Net Income (Loss)	$	120		$	137		$	18		$	(155	)	$	120
Net Cash Provided By (Used In) Operating Activities	$	261		$	736		$	8		$	(425	)	$	580
Net Cash (Used In) Provided By Investing Activities	$	(403	)	$	(478	)	$	(11	)	$	546		$	(346	)
Net Cash Provided By (Used In) Financing Activities	$	142		$	(270	)	$	12		$	(119	)	$	(235	)
For the Quarter Ended June 30, 2002:
Operating Revenues	$	1		$	668		$	4		$	—		$	673
Operating Expenses		16			478			6			—			500
Operating (Loss) Income		(15	)		190			(2	)		—			173
Other Income		117			9			—			(126	)		—
Interest Expense		(41	)		(14	)		27			—			(28	)
Income Taxes		22			(74	)		(10	)		—			(62	)
Net Income (Loss)	$	83		$	111		$	15		$	(126	)	$	83
For the Six Months Ended June 30, 2002:
Operating Revenues	$	1		$	1,242		$	6		$	—		$	1,249
Operating Expenses		36			802			10			—			848
Operating (Loss) Income		(35	)		440			(4	)		—			401
Other Income		273			13			—			(286	)		—
Interest Expense		(82	)		(30	)		56			—			(56	)
Income Taxes		47			(170	)		(19	)		—			(142	)
Net Income (Loss)	$	203		$	253		$	33		$	(286	)	$	203

~~(table continued on next page)~~ 42

40NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

		Power			Guarantor ~~Subsidiaries~~Subsidaries			Other ~~Subsidiaries~~Subsidaries			Consolidating Adjustments			Total
								(Millions)
For the Quarter Ended March 31, 2002:
For the Six Months Ended June 30, 2002:
Net Cash Provided By (Used In) Operating Activities	$	148		$	90		$	81		$	(159	)	$	160
Net Cash (Used In) Provided By Operating Activities	$	(413	)	$	714		$	(23	)	$	(203	)	$	75
Net Cash Provided By (Used In) Investing Activities	$	(205	)	$	(140	)	$	(138	)	$	244		$	(239	)
Net Cash (Used In) Provided By Investing Activities	$	(224	)	$	(466	)	$	(157	)	$	311		$	(536	)
Net Cash Provided By (Used In) Financing Activities	$	58637		$	51(244	)	$	57180		$	(85108	)	$	81465
As of March 31, 2003:
As of June 30, 2003:
Current Assets	$	1,~~250~~255		$	21,~~033~~498		$	~~101~~154		$	(1,~~863~~542	)	$	1,~~521~~365
Property, Plant and Equipment, Net		41			2,516			1,645			—			4,202
Property, Plant and Equipment, net		37			2,567			1,717			—			4,321
Noncurrent Assets		43,~~056~~675			1,~~436~~616			1,~~410~~342			(5,~~630~~320	)		1,~~272~~313
Total Assets	$	54,~~347~~967		$	5,~~985~~681		$	3,~~156~~213		$	(76,~~493~~862	)	$	6,~~995~~999
Current Liabilities	$	~~141~~116		$	21,~~363~~954		$	~~603~~636		$	(1,~~980~~667	)	$	1,~~127~~039
Noncurrent Liabilities		~~128~~97			~~375~~433			24			—(65	)		~~527~~489
Note Payable—Affiliated Company		~~155~~79			1,150			—			(1,~~305~~229	)		—
Long-Term Debt		2,516			—			800			—			3,316
Member's Equity		2,~~407~~159			2,~~097~~144			1,~~729~~753			(43,~~208~~901	)		2,~~025~~155
Total Liabilities and Member's Equity	$	54,~~347~~967		$	5,~~985~~681		$	3,~~156~~213		$	(76,~~493~~862	)	$	6,~~995~~999
As of December 31, 2002:
Current Assets	$	1,~~307~~329		$	1,~~609~~566		$	89102		$	(1,~~725~~479	)	$	1,~~280~~518
Property, Plant and Equipment, Net		42			2,430			1,573			—			4,045
Property, Plant and Equipment, net		42			2,430			1,568			—			4,040
Noncurrent Assets		3,~~196~~258			1,~~783~~786			1,~~355~~360			(4,~~718~~786	)		1,~~616~~618
Total Assets	$	4,~~545~~629		$	5,~~822~~782		$	3,~~017~~030		$	(6,~~443~~265	)	$	67,~~941~~176
Current Liabilities	$	367		$	1,~~897~~907		$	~~504~~522		$	(1,~~713~~503	)	$	1,~~055~~293
Noncurrent Liabilities		~~125~~209			~~990~~991			2829			(15101	)		1,128
Note Payable—Affiliated Company		97			1,150			—			(1,247	)		—
Long-Term Debt		2,516			—			800			—			3,316
Member's Equity		1,440			1,~~785~~734			1,~~685~~679			(3,~~468~~414	)		1,~~442~~439
Total Liabilities and Member's Equity	$	4,~~545~~629		$	5,~~822~~782		$	3,~~017~~030		$	(6,~~443~~265	)	$	67,~~941~~176

There are no restrictions on the ability of Power's subsidiaries to transfer funds in the form of dividends, loans or advances to Power for the periods noted above.

41Note 16. Subsequent Events

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 2002 Annual Report on Form 10-K affecting the consolidated financial condition and the results of operations. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to 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 LLC (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 other representations as to any other company.

Overview

PSEG

PSEG's business consists of four reportable segments, which are Power, PSE&G, PSEG Global LLC (Global) and PSEG Resources LLC (Resources). The following is a discussion of the major quarter-to-quarter financial statement variances and follows the financial statement presentation as it relates to each of its segments.

PSEG's results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings. For a more detailed discussion of the changes referenced for PSEG, see the applicable results of operations discussion for each respective subsidiary registrant.

Income from Continuing Operations for the quarters ended March 31, 2003 and 2002 was $321 million and $181 million or $1.42 and $0.88 per share, respectively. For the full year of 2003, PSEG expects Income from Continuing Operations to range from $3.70 to $3.90 per share. Net Income for the quarters ended March 31, 2003 and 2002 was $676 million and $60 million or $3.00 and $0.29 per share of common stock, respectively.

The significant quarter-to-quarter increase in Income from Continuing Operations for the quarter ended March 31, 2003 is due primarily to higher margins at Power resulting from the effective management of its electric and natural gas portfolio, improved earnings at PSE&G due to favorable weather effects, and improvements at Energy Holdings largely due to the timing of an annual payment under Global's Eagle Point cogeneration contract and due to the absence of the currency-related charges in Argentina recorded in 2002.

Additionally, during the first quarter ended 2003, PSEG recorded an after-tax benefit in the amount of $370 million related to the adoption of Statement of Financial Accounting Standard (SFAS) No. 143, ''Accounting for Asset Retirement Obligations'' (SFAS 143). This benefit was due mainly to the required remeasurement of Power's nuclear decommissioning obligations. Similarly for the quarter ended March 31, 2002, PSEG adopted SFAS No. 142, ''Goodwill and Other Intangible Assets'' (SFAS 142) and incurred an after-tax charge of $120 million related to goodwill impairments at Energy Holdings.

	Earnings (Losses)						Contribution to Earnings Per Share (Basic and Diluted)
	Quarters Ended March 31,						Quarters Ended March 31,
	2003			2002			2003			2002
	(Millions)
Power	$	177		$	120		$	0.78		$	0.58
PSE&G		100			67			0.44			0.32
Energy Holdings:
Resources		12			15			0.05			0.07
Global		42			(13	)		0.19			(0.06	)
Other (A)		(1	)		(2	)		—			(0.01	)
Other (B)		(9	)		(6	)		(0.04	)		(0.02	)
Income from Continuing Operations	$	321		$	181		$	1.42		$	0.88
Loss from Discontinued Operations, including Loss on Disposal		(15	)		(1	)		(0.06	)		(0.01	)
Cumulative Effect of a Change in Accounting Principle (C)		370			(120	)		1.64			(0.58	)
PSEG Net Income	$	676		$	60		$	3.00		$	0.29

(A) Other activities include non-segment amounts of Energy Holdings, PSEG Energy Technologies Inc. (Energy Technologies), Enterprise Group Development Corporation (EGDC) 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 (parent company) and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at PSEG (parent company). (C) Relates to the adoption of SFAS 143 in 2003 and the adoption of SFAS 142 in 2002. See Note 2. New Accounting Standards and Note 3. Adoption of SFAS 143 of the Notes.

PSE&G

EarningsElectric AvailableBase toRate PSEG from PSE&G increased $33 million to $100 million during the first quarter ended March 31, 2003 as compared to the same period in 2002. Colder weather, causing greater demand for heating was the key driver for improved margins at PSE&G during the first quarter of 2003. This improved PSE&G's earnings significantly when compared to the results produced during the mild winter last year and helped to offset higher operation and maintenance expenses, pension and other costs. PSE&G is projecting earnings of $210 million to $230 million for the full year of 2003.Case

~~Power~~ In May 2002, PSE&G filed an Electric Base Rate Case with the BPU requesting an annual $250 million increase for its electric distribution business. In June 2003, a proposed settlement was filed with the Administrative Law Judge (ALJ) who recommended approval of the settlement to the BPU. In July 2003, PSE&G received an oral decision from the BPU approving the proposed settlement with certain modifications. As a result of the oral decision, in the second quarter of 2003, PSE&G has:

Power's Income from Continuing Operations increased $57 million to $177 million during the quarter ended March 31, 2003 as compared to the same period in 2002. The principal driver of these results was the effective management of its electric and natural gas portfolio during the period. The Basic Gas Supply Service (BGSS) and the Basic Generation Service (BGS) related contracts became effective on May 1 and August 1, 2002, respectively. The impact of these contracts helped provide Power with ongoing results that were more than 35% higher than achieved in the first quarter of last year. In addition, Power benefited in the first quarter from its operation of two generating facilities in Connecticut that were acquired in December 2002. Power is projecting Income from Continuing Operations at $475 million to $520 million for the full year of 2003.

		•		recorded a regulatory liability by reducing its depreciation reserve for its electric distribution assets by $155 million, which will be amortized from August 1, 2003 through December 31, 2005; and
		•		recorded certain adjustments in connection with the resolution of various issues relating to the Final Order PSE&G received from the BPU in 1999 relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings. These amounts include a $30 million pre-tax refund related to revenues previously collected through the SBC for nuclear decommissioning. Because this amount reflects the final accounting for PSEG's generation-related business pursuant to the

Also impacting the quarter was the adoption of SFAS 143 resulting in an after-tax benefit of $370 million. The benefit is related to the required remeasurement of Power's asset retirement obligations, mainly nuclear decommissioning, within its businesses. Earnings Available to PSEG from Power increased $427 million to $547 million during the first quarter ended March 31, 2003 versus 2002.43

43NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

four year transition plan mandated by PSE&G's Final Order received from the BPU in 1999 relating to the New Jersey Electric Discount and Energy ~~Holdings~~Competition Act, the adjustment has been recorded as an $18 million, after-tax, Extraordinary Item as required under APB No. 30, ''Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions'' (APB 30). Also included is an $18 million, pre-tax, increase in MTC overcollections which was recorded as a reduction to Operating Revenues and a $4 million, pre-tax, reduction in interest capitalized on various deferred balances during the transition period which was recorded as a charge to Interest Expense. On July 31, 2003, PSE&G received a summary written order which was substantially consistent with the oral decision.

Energy Holdings' Income from Continuing Operations increased $53 million during the quarter ended March 31, 2003 as compared to the same period in 2002 due primarily to the timing of a contractual payment from Eagle Point Cogeneration Partnership (EPCP), which was recorded in the first quarter of 2003 as compared to the second quarter of 2002 and due to the absence of the currency-related charges in Argentina recorded in 2002. Energy Holdings expects Income from Continuing Operations of $145 million to $155 million for the full year of 2003.44

EarningsITEM Available to PSEG increased $159 million to $38 million during the first quarter ended March 31, 2003 as compared to the same period in 20022. ForMANAGEMENT'S theDISCUSSION sameAND periodANALYSIS inOF 2002,FINANCIAL EnergyCONDITION HoldingsAND generatedRESULTS aOF lossOPERATIONS of $121 million. The quarter-to-quarter change is largely attributable to the adoption of SFAS 142 in the first quarter of 2002, which resulted in an after-tax charge of $120 million. Also contributing was the timing of a contractual payment from EPCP, discussed above, which was partially offset by higher Losses from Discontinued Operations.(MD&A)

~~Results~~ Following are the significant changes in or additions to information reported in the 2002 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, affecting the consolidated financial condition and the results of ~~Operations~~operations of the registrants. This discussion refers to the registrants' Consolidated Financial Statements (Statements) and the related Notes to Consolidated Financial Statements (Notes) and should be read in conjunction with such Statements and Notes.

OVERVIEW

PSEG

~~Operating~~ PSEG's ~~Revenues~~business consists of four reportable segments, which are Power, PSE&G, PSEG Global LLC (Global) and PSEG Resources LLC (Resources). The following is a discussion of the major financial statement variances and follows the financial statement presentation as it relates to each of the segments. PSEG's results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings. For a more detailed discussion of the changes referenced for PSEG, see the applicable results of operations discussion for each respective subsidiary registrant.

~~For~~Income from Continuing Operations for the quarter ended ~~March~~June 3130, 2003, ~~Operating~~was ~~Revenues~~$150 ~~increased~~million byor $10.566 ~~billion~~per ~~or 79%~~share. ~~This~~Losses ~~was~~from ~~due~~Continuing ~~primarily~~Operations tofor anthe ~~increase~~quarter atended ~~PSEG's~~June ~~operating~~30, ~~companies~~2002 ~~including~~were a $~~479~~227 million ~~increase~~or ~~from~~$1.10 ~~Power~~per ~~related~~share, towhich ~~the~~included ~~new BGS~~after-~~related~~tax ~~revenues~~losses ~~from~~of ~~third-party~~$343 ~~wholesale~~million ~~electric~~or ~~suppliers which went into effect August~~ $1,.66 ~~2002~~per ~~and~~share ~~increased~~related ~~energy~~to ~~sales~~Energy ~~into~~Holdings' ~~the~~abandoned ~~New~~investments ~~England~~in ~~Power~~Argentina. ~~Pool~~Net ~~resulting~~Income ~~from~~(Loss) ~~Power's~~for ~~operation~~the ofquarters ~~two~~ended ~~generation~~June ~~facilities~~30, in2003 ~~Connecticut~~and ~~that were acquired in December~~ 2002, awas $~~489~~130 million ~~increase in PSE&G's operating revenues due primarily to increased weather-related demand as explained below under PSE&G,~~ and a $73(264) million ~~increase~~or in$0.57 ~~Energy~~and ~~Holdings'~~$(1.28) ~~operating~~per ~~revenues~~share ~~relating to the withdrawal~~ of ~~EPCP~~common ~~and generation projects going into operation during 2002~~stock, ~~partially offset by lower investment earnings at Resources, as detailed below under Energy Holdings~~respectively.

InIncome ~~addition,~~from aContinuing ~~portion~~Operations offor the ~~increase~~six ~~was~~month ~~due~~period toended ~~the~~June ~~fact~~30, ~~that~~2003 ~~Power's~~was ~~BGS~~$471 ~~revenues~~million ~~are~~or ~~not~~$2.09 ~~being~~per ~~eliminated~~share. inLosses ~~consolidation~~from ~~subsequent~~Continuing toOperations ~~July~~for ~~2002 by PSEG. Under~~ the ~~prior~~six ~~BGS~~month ~~contract,~~period ~~which~~ended ~~terminated~~June ~~on July 31~~30, 2002, ~~Power~~were ~~sold~~$46 ~~energy~~million ~~directly~~or to$0.22 ~~PSE&G,~~per share which inincluded ~~turn~~after-tax ~~sold~~losses ~~this~~of ~~energy~~$374 tomillion ~~its~~or ~~customers~~$1.81 ~~These~~per ~~revenues~~share ~~were~~related ~~properly~~to ~~recognized~~Energy ~~on each company~~Holdings's ~~stand-alone~~abandoned ~~financial~~investments ~~statements~~in ~~and were eliminated when preparing PSEG's Consolidated Financial Statements~~Argentina. ~~For~~Net ~~the~~Income ~~BGS contract period beginning August 1, 2002, Power entered into contracts with third parties who are direct suppliers of New Jersey's Electric Distribution Companies~~ (~~EDCs~~Loss) ~~and PSE&G purchases the energy~~ for ~~its customers' needs from such direct suppliers. Due to this change in~~ the ~~BGS~~six ~~model,~~month ~~these~~periods ~~revenues are no longer intercompany revenues and therefore are not eliminated in consolidation. For the quarter~~ ended ~~March~~June 3130, 2003, ~~PSEG's~~and ~~elimination~~2002 ~~related~~was to$806 ~~intercompany~~million ~~BGS~~ and ~~Market Transition Charge~~ $(~~MTC~~204) ~~revenues decreased by approximately $412~~ million asor ~~compared to the quarter ended March 31, 2002 due primarily to this change~~$3.57 ~~Also~~and ~~related to this change in the BGS model, PSE&G, in 2002, began selling energy purchased under non-utility generation~~ $(~~NUG~~0.99) ~~contracts,~~per ~~which~~share itof ~~had~~common ~~previously sold to Power~~stock, ~~to third parties~~respectively. ~~As a result, for the quarter ended March 31, 2003, PSEG's revenues related to NUG contracts increased by approximately $28 million.~~

~~Operating~~ Based ~~Expenses~~on these results, PSEG continues to project 2003 Income from Continuing Operations to be within its original range of $3.70 to $3.90 per share. In addition, PSEG has established initial 2004 guidance for Income from Continuing Operations in the range of $3.75 to $3.95 per share. These projected results will depend on several factors, including, but not limited to, the expected benefits from the conclusion of PSE&G's Electric Base Rate Case, Power's ability to continue to effectively manage its portfolio of electric generation assets, gas supply contracts and electric and gas supply obligations, and Power's ability to mitigate against the effects of volatility in energy prices on the outcome of the next Basic Generation Service (BGS) auction and the loss of the market transition charge (MTC) revenues effective August 1, 2003, and the continued contributions from investments at Resources and Global. PSEG is reviewing its dividend policy and is considering the viability of an increase to its current dividend level as earnings continue to grow, however, a decision is not expected until approximately the end of 2003. This decision will be based on several factors, including a review of PSEG's expected earnings and long-term growth rate, credit quality, dividend payout ratio, anticipated future cash flows and financial requirements and ability to maintain the dividend at a consistent level.

~~Energy~~ The ~~Costs~~significant period-to-period increase in Income from Continuing Operations for the quarter and six months ended June 30, 2003, as compared to the same periods in the prior year is due primarily

For the quarter ended March 31, 2003 as compared to the quarter ended March 31, 2002, Energy Costs increased approximately $1.3 billion or 173% due primarily to a $401 million net increase in gas costs at PSE&G and Power, a $362 million increase at Power primarily related to increased energy purchases and third-party wholesale electric supplier contracts, discussed further below under Power, a $62 million increase in electric energy costs at PSE&G discussed further below under PSE&G and a $17

million increase at Energy Holdings, relating to projects going into operation at Global, discussed further below under Energy Holdings.

In addition, a portion of the increase was due to the fact that PSE&G no longer purchases electric energy directly from Power, as discussed above in Operating Revenues. Amounts attributable to this change totaled $440 million between the quarters ended March 31, 2003 and 2002.

Operations and Maintenance

For the quarter ended March 31, 2003, Operations and Maintenance expense increased $57 million or 12% as compared to the quarter ended March 31, 2002 due to a $16 million increase at Power primarily caused by scheduled outages at certain electric generating stations, an increase at Energy Holdings of $8 million, due mainly to costs associated with projects going into operation and a $32 million increase at PSE&G due primarily to higher Demand Side Management (DSM) amortization, discussed further below under PSE&G.

Depreciation and Amortization

For the quarter ended March 31, 2003, Depreciation and Amortization decreased by $31 million or 24% as compared to the quarter ended March 31, 2002, due primarily to a decrease of $29 million at PSE&G, mainly due to an increase in the amortization of the excess depreciation reserve.

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes is comprised of the Transitional Energy Facility Assessment (TEFA) tax at PSE&G. Taxes Other Than Income Taxes increased $6 million or 16% for the quarter ended March 31, 2003 as compared to the quarter ended March 31, 2002. This increase was due primarily to an increase of $6 million in the TEFA due to increased sales. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.

Income from Equity Method Subsidiaries

Income from Equity Method Investments decreased $13 million or 43% to $17 million for the quarter ended March 31, 2003 from $30 million for the quarter ended March 31, 2002. This decrease was due primarily to lower earnings in 2002 of $8 million at Rio Grande Energia (RGE), an electric distribution company in Brazil mainly driven by regulatory changes that allowed RGE to recover from customers prior tariff charges previously expensed, as well as higher energy purchases, higher inflation rates and higher effective tax rates in the current year. Also contributing to the decrease was $3 million in interest income related to a note receivable from The AES Corporation (AES) in 2002.

Other Income

For the quarter ended March 31, 2003, Other Income increased by $49 million as compared to the quarter ended March 31, 2002, due primarily to a $47 million increase at Power, a $10 million increase at PSE&G, partially offset by a $7 million decrease at Energy Holdings. Power's increase is due primarily to realized gains and the recognition of interest and dividend income in its Nuclear Decommissioning Trust (NDT) Fund. The increase at PSE&G primarily relates to $8 million of gains recorded on the disposition of property in the current year. The decrease at Energy Holdings primarily relates to a decrease in net derivative gains.

Other Deductions

For the quarter ended March 31, 2003, Other Deductions decreased by $7 million as compared to the quarter ended March 31, 2002, due primarily to $52 million less in foreign currency transaction losses related to US Dollar debt in Argentina recorded in 2002. This was partially offset by the recognition of $33 million of realized losses in Power's NDT Fund.

~~Interest~~to ~~Expense~~the absence of losses from Energy Holdings' Argentine investments recorded in 2002. Also contributing to the increase were higher margins at Power from the electric and natural gas portfolio, improved earnings at PSE&G due to favorable weather effects and improvements at Energy Holdings, largely due to the absence of write-downs of securities at Resources held within certain leveraged buyout funds recorded in the second quarter of 2002 combined with improvements in the performance of Resources' lease portfolio. For the quarter ended June 30, 2003, as compared to the same period in 2002, these favorable amounts were partially offset due to the timing of an annual partnership withdrawal installment payment for the Eagle Point Cogeneration Partnership (EPCP) which was received in the first quarter of 2003 compared to the second quarter of 2002.

~~For~~Additionally, during the first quarter ~~ended~~of ~~March 31,~~ 2003, ~~Interest~~PSEG ~~Expense~~recorded ~~decreased~~an $4after-tax ~~million~~benefit orto 2%Net asIncome ~~compared~~in the amount of $370 million related to the ~~quarter~~adoption ~~ended~~of ~~March~~Statement 31of Financial Accounting Standard (SFAS) No. 143, ~~2002~~''Accounting for Asset Retirement Obligations'' (SFAS 143). This benefit was due ~~primarily~~mainly to athe $6required ~~million~~remeasurement ~~decrease~~of atPower's ~~PSE&G~~nuclear ~~and~~decommissioning aobligations. $4Similarly, ~~million~~for ~~decrease~~the atfirst ~~Energy~~quarter ~~Holdings~~of 2002, ~~partially~~PSEG ~~offset~~adopted bySFAS aNo. 142, ''Goodwill and Other Intangible Assets'' (SFAS 142) and incurred an after-tax charge of $6120 million ~~increase~~related to goodwill impairments at ~~PSEG~~Energy Holdings.

~~Preferred~~ Also ~~Securities~~contributing ~~Dividends~~to the changes in Net Income was a decrease in Energy Holdings' Loss from Discontinued Operations of $35 million and $21 million for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002, and an $18 million, after-tax, extraordinary charge recorded at PSE&G in the second quarter of 2003 related to the oral decision received from the New Jersey Board of Public Utilities (BPU) in July 2003, discussed below in PSE&G's Overview.

~~For~~The ~~the~~results ~~quarter~~for ~~ended March 31~~PSEG, ~~2003~~PSE&G, ~~Preferred~~Power ~~Securities~~and ~~Dividends~~Energy ~~increased~~Holdings ~~approximately~~for $4the ~~million~~quarter ~~due~~and ~~primarily~~six tomonths ~~higher~~ended ~~preferred~~June ~~dividend~~30, ~~requirements~~2003 atand ~~PSEG.~~2002 are presented below:

Income Taxes

	Earnings (Losses)						Earnings (Losses)
	Quarter Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
	(Millions)						(Millions)
PSE&G	$	22		$	8		$	123		$	76
Power		109			83			286			203
Energy Holdings:
Global (A)		11			(305	)		57			(314	)
Resources		23			(3	)		37			14
Other (B)		(1	)		(2	)		(2	)		(4	)

Total Energy Holdings (A)		33			(310	)		92			(304	)
Other (C)		(14	)		(8	)		(30	)		(21	)

Income from Continuing Operations (A)	$	150		$	(227	)	$	471		$	(46	)
Loss from Discontinued Operations, including Loss on Disposal (D)		(2	)		(37	)		(17	)		(38	)
Extraordinary Item (E)		(18	)		—			(18	)		—
Cumulative Effect of a Change in Accounting Principle (F)		—			—			370			(120	)

PSEG Net Income (A)	$	130		$	(264	)	$	806		$	(204	)

For the quarter ended March 31, 2003, Income Taxes increased $70 million or 61% as compared to the quarter ended March 31, 2002 including a $43 million increase at Power, a $14 million increase at PSE&G and a $17 million increase at Energy Holdings which were primarily attributable to higher pre-tax income. These increases were partially offset by a $4 million decrease at PSEG, which was attributable to lower pre-tax income.46

Losses From Discontinued Operations

	Contribution to Earnings Per Share (Diluted)						Contribution to Earnings Per Share (Diluted)
	Quarter Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
PSE&G	$	0.10		$	0.04		$	0.54		$	0.37
Power		0.48			0.40			1.27			0.98
Energy Holdings:
Global (A)		0.05			(1.47	)		0.25			(1.52	)
Resources		0.10			(0.02	)		0.16			0.06
Other (B)		(0.01	)		(0.01	)		(0.01	)		(0.02	)

Total Energy Holdings (A)		0.14			(1.50	)		0.40			(1.48	)
Other (C)		(0.06	)		(0.04	)		(0.12	)		(0.09	)

Income from Continuing Operations (A)	$	0.66		$	(1.10	)	$	2.09		$	(0.22	)
Loss from Discontinued Operations, including Loss on Disposal (D)		(0.01	)		(0.18	)		(0.08	)		(0.19	)
Extraordinary Item (E)		(0.08	)		—			(0.08	)		—
Cumulative Effect of a Change in Accounting Principle (F)		—			—			1.64			(0.58	)

PSEG Net Income (A)	$	0.57		$	(1.28	)	$	3.57		$	(0.99	)

~~Operating~~(A) ~~results~~Includes write-down and losses related to Argentine investments of ~~Energy~~$343 ~~Technologies'~~million ~~HVAC/mechanical~~and ~~operating~~$374 ~~companies~~million for the quarter and six months ended June 30, ~~less~~2002, ~~certain~~respectively. ~~allocated~~(B) ~~costs~~Other ~~from~~activities include non-segment amounts of Energy Holdings, ~~have~~PSEG ~~been~~Energy ~~reclassified~~Technologies ~~into~~Inc. ~~Discontinued~~(Energy ~~Operations~~Technologies), inEnterprise ~~the~~Group ~~Consolidated~~Development ~~Statements~~Corporation of(EGDC) ~~Operations~~and intercompany eliminations. ~~The~~Specific ~~results~~amounts ofinclude ~~operations~~interest ofon ~~these~~certain ~~discontinued~~financing ~~operations~~transactions ~~for~~and ~~the~~certain ~~quarters~~other ~~ended~~administrative ~~March~~and ~~31,~~general ~~2003~~expenses ~~and~~at ~~2002~~Energy ~~yielded~~Holdings. ~~additional~~(C) ~~after~~Other activities include non-~~tax~~segment ~~losses~~amounts of $6PSEG ~~million~~(parent company) and $4intercompany ~~million, respectively~~eliminations. ~~For~~Specific ~~additional~~amounts ~~information~~include preferred securities dividends requirements for PSE&G and Energy Holdings, ~~see~~interest ~~Note~~on 4certain financing transactions and certain other administrative and general expenses at PSEG (parent company). (D) Includes Discontinued Operations of ~~the~~Energy ~~Notes.~~Technologies ~~Due~~in to2003 ~~current~~and ~~market~~2002 ~~conditions,~~and ~~Energy~~Global's ~~Holdings~~Tanir ~~re-evaluated~~Bavi facility in 2002. (E) Relates to charge recorded in the ~~carrying~~second ~~value~~quarter of ~~Energy~~2003 ~~Technologies~~at ~~and~~PSE&G ~~has~~resulting ~~determined~~from ~~that~~the anoral ~~additional~~decision ~~write-down~~issued toby ~~fair~~the ~~value~~BPU ~~less~~in ~~cost~~PSE&G's toElectric ~~sell~~Base ~~was~~Rate ~~required~~Case in July 2003. In(F) ~~the~~Relates ~~first~~to ~~quarter~~the adoption of SFAS 143 in 2003, ~~Energy~~and ~~Holdings~~the ~~recorded~~adoption anof ~~additional~~SFAS ~~after-tax~~142 ~~loss~~in on2002. ~~disposal~~See Note 2. New Accounting Standards and Note 3. Adoption of ~~Energy~~SFAS ~~Technologies~~143 of $9the ~~million~~Notes.

In addition, Tanir Bavi, a 220 MW barge mounted, combined-cycle generating facility in India which was sold in the fourth quarter of 2002, met the criteria for classification as a component of discontinued operations. The operating results of Tanir Bavi for the quarter ended March 31, 2002 yielded after-tax income of $3 million.

Cumulative Effect of a Change in Accounting Principle

For the quarter ended March 31, 2003, Power recorded a $370 million after-tax benefit to Net Income relating to the adoption of SFAS 143 as detailed further below under Power. In the first quarter of 2002, Energy Holdings recorded a $120 million after-tax charge to Net Income due to goodwill impairments relating to the adoption of SFAS 142 as detailed further below under Energy Holdings.

PSE&G

Income from Continuing Operations increased $14 million and $47 million for the quarter and six month periods ended June 30, 2003, respectively, as compared to the same periods in 2002. PSE&G's Earnings Available to PSEG decreased $4 million or 57% and increased $29 million or 39% for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002. The increases were primarily due to favorable winter weather and lower Operation and Maintenance expenses, as discussed in Results of Operations. Partially offsetting these amounts were certain charges recognized in accordance with the Electric Base Rate Case as discussed further below. These included a pre-tax charge to Operating Revenues of $18 million relating to the MTC and a $30 million pre-tax, $18 million after-tax, extraordinary charge, discussed below.

In May 2002, PSE&G's ~~operating~~filed ~~revenues~~an ~~increased~~Electric byBase Rate Case with the BPU requesting an annual $~~489~~250 million orincrease ~~29%~~ for ~~the~~its ~~first~~electric ~~quarter~~distribution ofbusiness. In June 2003, asa ~~compared~~proposed tosettlement was filed with the ~~first~~Administrative ~~quarter~~Law Judge (ALJ) who subsequently recommended approval of ~~2002~~the settlement to the BPU. ~~The~~In ~~primary~~July 2003, ~~reason~~PSE&G ~~for~~received an oral decision from the ~~increase~~BPU ~~was~~approving athe ~~$459~~proposed settlement ~~million~~with orcertain ~~56%~~modifications ~~increase~~and insubsequently ~~gas~~received ~~revenues.~~a ~~Electric~~summary ~~revenues~~written order ~~also~~which ~~increased~~was bysubstantially ~~$30~~consistent ~~million~~with orthe 4%oral decision.

Total gas sales volumes increased by 25% in 2003 due primarily to favorable weather conditions this past winter resulting in added revenues of $222 million comprised of commodity sales of $117 million and delivery sales of $105 million. Increase in prices added $245 million to 2003 revenues. Gas commodity charges vary monthly with the price of gas for commercial and industrial customers and those revenues increased $188 million for the quarter ended March 2003. Commodity charges to residential customers are levelized through the BGSS-RSG tariff with the difference between commodity revenue and cost deferred. Two BGSS-Residential Service Gas (RSG) rate increases were implemented during the first quarter of 2003 totaling 12%, which contributed $57 million to 2003

revenues. Other gas operating revenues declined by $7 million in 2003 as a result of no longer having off-system sales following the sale of the gas contract business to Power in May of 2002, a reduction of $13 million which was offset partially by a $4 million improvement in gas appliance repair sales.

Electric sales volumes increased by 7% due primarily to favorable weather conditions this past winter which resulted in approximately $60 million in added revenue. Offsetting this increase was the effect of a 4.9% rate decrease effective in August 2002, which reduced revenues by approximately $45 million. This is offset by lower Energy Costs, discussed below. Sales of NUG power added $20 million to 2003 revenues as compared to 2002 due primarily to an increase in the Pennsylvania-New Jersey-Maryland Power Pool (PJM) locational marginal pricing.

Operating Expenses

Energy Costs

Gas costs increased by $386 million or 73% for the first quarter of 2003 as compared to the first quarter of 2002. The cost of gas purchased increased $173 million due to a 25% increase in the price of gas, and $130 million due to an increase in commodity sales volume due primarily to favorable weather conditions this past winter. Additionally, gas cost increased by $75 million for the current deferral of BGSS-RSG costs to match current commodity revenues.

Electric costs increased $62 million or 12% for the first quarter of 2003 as compared to the first quarter of 2002. BGS purchases increased $67 million due to a 15% increase in prices effective August 1, 2002 and $30 million due to an increase in sales volumes due primarily to favorable weather conditions this past winter. Net MTC payments to Power increased $6 million due to a $52 million increase in the amortization of the excess depreciation reserve partially offset by the impact of the rate reduction of $45 million. NUG energy cost decreased $4 million as the result of a $15 million decrease in volumes purchased offset by a higher average price of $11 million. In addition, electric costs decreased by $37 million due to the deferral of energy costs in excess of the amount included in revenues.

Operations and Maintenance

Operations and Maintenance expense increased $32 million or 13% for the first quarter of 2003 as compared to the first quarter of 2002. The primary reason for the change was an $18 million increase in DSM program amortization driven by higher sales and a rate increase for gas DSM recovery in November 2002. The gas increase is included in the delivery volume revenue increase discussed above. DSM costs are deferred when incurred and amortized to Operations and Maintenance expense when recovered in revenues. Other contributors to the Operations and Maintenance expense increase were higher labor costs of $12 million, almost half of which was attributable to higher pension costs.

Depreciation and Amortization

Depreciation and Amortization decreased $29 million or 31% for the first quarter of 2003 as compared to the first quarter of 2002. The primary reason for the decrease is a reduction of $37 million for an increase in the amortization of an excess electric distribution depreciation reserve. This amortization will conclude on July 31, 2003, the end of the transition period. Offsetting this decrease was a $2 million increase in depreciation expense due to increased plants in service and a $6 million increase in the amortization of the regulatory asset related to securitization which was caused primarily by an increase in Securitization Transition Charge (STC) revenues.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $6 million or 16% for the first quarter of 2003 as compared to the first quarter of 2002. The increase is the result of higher TEFA due to higher taxable sales in 2003. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.

~~Other~~ The following ~~Income~~is a summary of the significant issues provided for in the oral decision and summary written order.

Other Income increased $10 million or 175% for the quarter ended March 31, 2003 as compared to the quarter ended March 31, 2002, due primarily to gains on the disposal of various electric transmission properties.

		•		PSE&G will receive a $159.5 million annual increase in its electric distribution rates commencing August 1, 2003.
		•		PSE&G will decrease its electric distribution depreciation rates from 3.52% to 2.49%, effective August 1, 2003. This change will reduce depreciation expense by approximately $40 million per year.
		•		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 will amortize the liability from August 1, 2003 through December 31, 2005. The annual amortization of this liability is $64 million and will result in a reduction of Depreciation and Amortization expense. Subsequent to the amortization of this reserve, the BPU's oral decision allows PSE&G to petition for an additional $64 million annual increase in electric distribution rates effective January 1, 2006, subject to BPU approval, including a review of PSE&G's return on equity and other relevant financial information.
		•		PSE&G will refund approximately $238 million to ratepayers through the Non-Utility Generation Transition Charge (NTC) and Societal Benefits Charge (SBC), which include amounts related to the resolution of various issues relating to the Final Order PSE&G received from the BPU in 1999 relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings. These amounts include a $30 million pre-tax refund related to revenues previously collected through the SBC for nuclear decommissioning. Because this amount reflects the final accounting for PSEG's generation-related business pursuant to the four year transition plan mandated by PSE&G's Final Order received from the BPU in 1999 relating to the New Jersey Electric Discount and Energy Competition Act (EDECA), the adjustment has been recorded as an $18 million, Extraordinary Item in the second quarter of 2003, as required under Accounting Principles Board (APB) No. 30, ''Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions'' (APB 30). Also included in the refund amount is an $18 million, pre-tax, increase in the refund for MTC overcollections which was recorded in the second quarter of 2003 as a reduction to Operating Revenues and a $4 million, pre-tax, reduction in interest capitalized on various deferred balances during the transition period which was recorded as a charge to Interest Expense.
		•		PSE&G will be allowed to recover deferred Repair Allowances and deferred Restructuring Costs over a ten-year period commencing August 1, 2003.
		•		PSE&G will transfer approximately $80 million of assets, at book value, to PSEG Services Corporation (Services) in the third quarter of 2003.

~~Interest~~ The ~~Expense~~combined effects of the expiration of the electric rate discounts on July 31, 2003, which had been phased in beginning in August 1999, the refunds through certain reductions and the approved increase in base rates, combined with the effects of the recent BGS auction, will result in rates slightly lower than those in effect prior to the initial electric rate discount on August 1, 1999.

Interest expense decreased by $6 million or 6% for the first quarter of 2003 as compared to the first quarter of 2002. Interest on long-term debt decreased $11 million due to the maturity of Medium-Term Notes in August and September 2002 and January 2003. These were offset by increased interest of $6 million due to Medium-Term Notes issued in September 2002 and January 2003.

Income Taxes

Income taxes increased $14 million or 33% for the quarter ended March 31, 2003 as compared to the quarter ended March 31, 2002 due primarily to an increase in pre-tax income offset by increased benefits attributable to the excess depreciation reserve adjustment in 2003.

Power

~~Operating~~ Power's ~~Revenues~~Income from Continuing Operations increased $26 million to $109 million and $83 million to $286 million for the quarter and six months ended June 30, 2003, respectively as compared to the same periods in 2002. The increases were primarily due to higher margins from Power's electric load contracts, which became effective August 1, 2002, and increases in MTC revenues. Power benefited during 2003 from its operation of two generating facilities in Connecticut that were acquired in December 2002. In addition, net gains realized in Power's Nuclear Decommissioning Trust (NDT) Fund were favorable for the periods.

~~For~~Earnings ~~the~~Available ~~quarter~~to ~~ended~~PSEG ~~March~~were ~~31,~~$109 ~~2003,~~million ~~Power's~~and ~~Operating Revenues increased~~ $~~1.3~~656 ~~billion~~million orfor ~~228%~~the asquarter ~~compared~~and tosix ~~the~~months ~~quarter~~ ended ~~March~~June 3130, ~~2002~~2003, ~~due~~respectively, ~~primarily~~as compared to ~~the inclusion of approximately~~ $~~900~~83 million ~~of gas revenues relating to its BGSS contract~~ and ~~off-system~~$203 ~~gas~~million ~~sales~~for ~~resulting from~~ the ~~gas~~same ~~contracts~~periods ~~transferred from PSE&G~~ in ~~May~~ 2002. ~~Also~~Included ~~contributing to the increase was an approximate $300 million increase~~ in ~~electric revenues, due primarily to~~ the ~~BGS~~six ~~related~~months ~~contracts~~ended ~~with~~June ~~third party wholesale electric suppliers which went into effect August 1~~30, ~~2002.~~2003 ~~Also contributing to the increase in revenues~~ was ~~an approximate $125 million increase in electric energy sales in~~ the ~~New~~adoption ~~England Power Pool from Power's operation~~ of ~~two~~SFAS ~~Connecticut~~143 ~~generating~~resulting ~~facilities that were acquired~~ in ~~December~~an ~~2002.~~

Operating Expenses

Energy Costs

For the quarter ended March 31, 2003, Power's energy costs increased $1.2 billion or 870% compared to the quarter ended March 31, 2002, due primarily to increased gas purchases of $847 million to satisfy Power's BGSS contract with PSE&G and increased electric energy purchases and third party wholesale electric supplier contracts of approximately $266 million. Also contributing to the increase were higher network transmission expenses of $72 million. These higher expenses were partially offset by a $28 million decrease in NUG purchases.

Operations and Maintenance

For the quarter ended March 31, 2003, Operations and Maintenance expense increased $16 million or 9% as compared to the same period in 2002, due primarily to increases caused by higher accretion relating to the adoption of SFAS 143, higher pension related expenses, scheduled outage work at electric generating stations and the acquisition of the two Connecticut generating facilities in December 2002.

Depreciation and Amortization

For the quarter ended March 31, 2003, Depreciation and Amortization expense remained flat as compared to the same period in 2002. Power did have higher depreciation expense of approximately $7 million for the period ended March 31, 2003 due primarily to a higher asset base. Depreciation expense was offset by the absence of decommissioning charges which are no longer recorded as a result of the

~~implementation~~after-tax benefit of ~~SFAS~~$370 ~~143~~million. ~~For~~The ~~additional~~benefit ~~information,~~is ~~see~~related ~~Note~~to 3.the ~~Adoption~~required remeasurement of ~~SFAS~~Power's ~~143~~asset ofretirement ~~the~~obligations, ~~Notes~~mainly nuclear decommissioning, within its businesses.

Other Income

For the quarter ended March 31, 2003, Other Income increased by $47 million as compared to the quarter ended March 31, 2002, due to realized gains and the recognition of interest and dividend income in the NDT Fund.

Other Deductions

For the quarter ended March 31, 2003, Other Deductions increased by $33 million as compared to the quarter ended March 31, 2002, due to the recognition of $33 million of realized losses in Power's NDT Fund.

Interest Expense

Interest Expense remained flat for the quarter ended March 31, 2003 from the comparable period in 2002. Although Power incurred additional interest charges of $10 million for the period ended March 31, 2003 due primarily to the new financing of $600 million in June 2002, this increase was offset by capitalized interest relating to various construction projects of $8 million and $2 million of reductions associated with interest rate swap agreements.

Income Taxes

Income Taxes increased $43 million or 54% for the quarter ended March 31, 2003 as compared to the quarter ended March 31, 2002, due primarily to increases in pre-tax income.

Cumulative Effect of Change in Accounting Principle

Power has performed a review of its potential obligations under SFAS 143 and believes that its quantifiable obligations are primarily related to the decommissioning of its nuclear power plants. Upon adoption of this standard on January 1, 2003, Power recorded a Cumulative Effect of a Change in Accounting Principle in the amount of $370 million. See Note 2. New Accounting Standards and Note 3. Adoption of SFAS 143 of the Notes for additional information.

Energy Holdings

~~Operating~~ Energy ~~Revenues~~Holdings' Income from Continuing Operations was $33 million and $92 million for the quarter and six months ended June 30, 2003, respectively. Losses from Continuing Operations for the quarter and six months ended June 30, 2002 were $310 million and $304 million, respectively, which included losses of $343 million and $374 million for the quarter and six months ended June 30, 2002, respectively, related to Global's abandoned investments in Argentina. In addition, contributing to the increase for the quarter and six months ended June 30, 2003 was a decrease in other than temporary impairments of non-publicly traded equity securities held within Resources' KKR leveraged buyout funds. Partially offsetting the increase for the quarter ended June 30, 2003 was lower gains recorded due to the timing of a partnership installment payment from EPCP, which was recorded in the first quarter of 2003 as compared to the second quarter of 2002.

~~Energy~~Earnings ~~Holdings'~~Available ~~revenues~~to ~~increased~~PSEG was $7326 million, orand ~~54%, to~~ $~~209~~64 million for the quarter and six months ended ~~March~~June 3130, 2003, ~~from~~respectively, as compared to Losses Available to PSEG of $~~136~~352 million ~~for~~and ~~the~~$473 ~~quarter~~million ~~ended~~in ~~March~~the ~~31,~~same periods in 2002. ~~This~~The ~~increase~~change ~~was~~is ~~driven~~largely byattributable ~~higher~~to ~~electric~~losses ~~generation~~related ~~revenues~~to at Global's ~~and~~investments ~~the~~in ~~timing~~Argentina ofdiscussed anabove, ~~increased~~and ~~annual~~higher ~~withdrawal~~losses ~~payment~~in 2002 from ~~EPCP~~Discontinued Operations. InThe ~~2001,~~adoption ~~Global~~of ~~withdrew~~SFAS ~~from~~142 ~~its~~in ~~interest~~the infirst ~~EPCP~~quarter inof ~~exchange~~2002, ~~for~~which aresulted ~~series~~in ofan ~~payments~~after-tax ~~through~~charge ~~2005~~of $120 million, ~~provided~~also ~~certain~~contributed ~~operating~~to ~~contingencies~~the ~~are~~increase ~~met~~for the six months ended June 30, 2003.

GlobalRESULTS OF OPERATIONS

For the quarter ended March 31, 2003, the operating revenues increased by $79 million or 101% to $157 million for the quarter ended March 31, 2003 from $78 million for the quarter ended March 31, 2002. This increase at Global was partly due to an increase of $37 million of realized revenue from the withdrawal from EPCP which was recorded in the first quarter of 2003 as compared to the second quarter of 2002. The increase in revenue was also due to a $26 million increase from Skawina, a generation facility in Poland, in which Global purchased a majority ownership in the second quarter of 2002 and a $22 million increase from Rades, a generation facility in Tunisia which commenced operations in the second quarter of 2002. Also contributing is a $9 million increase at GWF Energy. In the second half of 2002, Global's ownership of GWF Energy increased to 76%. Accordingly, Global PSEG

49Operating Revenues

~~consolidates~~ For ~~GWF~~the ~~Energy~~quarter ended June 30, 2003, Operating Revenues increased by $1.0 billion or 71% as compared to the ~~first~~same ~~quarter~~period in 2002. ~~when~~This it was ~~recorded~~primarily ~~under~~due to a change in the ~~equity~~BGS ~~method~~contracing process, discussed below. ~~These~~Also ~~increases~~contributing ~~were~~to ~~partially~~the ~~offset~~increase bywere aPSEG's ~~decrease~~operating ofcompanies including a $15270 million increase from ~~Empresa~~Power ~~Distribuidora~~related deto ~~Electricidad~~the derevenues ~~Entre~~from ~~Rios~~new ~~S.A.~~load ~~(EDEERSA),~~contracts inwith ~~Argentina,~~third-party wholesale electric suppliers which ~~was~~went ~~fully~~into ~~written~~effect ~~off~~August 1, 2002 and increased energy sales into the New England Power Pool resulting from Power's operation of two generation facilities in Connecticut that were acquired in December 2002, a $112 million increase in PSE&G's operating revenues due primarily to increased sales volumes due to weather and ~~was~~price ~~abandoned~~increases mostly due to the rising cost of natural gas as explained below under PSE&G and a $55 million increase in Energy Holdings' operating revenues relating to Global's generation projects going into operation during the ~~first~~fourth quarter of ~~2003~~2002 and higher investment earnings at Resources, as detailed below under Energy Holdings.

~~Resources~~ For the six months ended June 30, 2003, Operating Revenues increased by $2.4 billion or 74%. This was due primarily to a change in the BGS contracting process, discussed below. Also contributing to the increase were PSEG's operating companies including a $690 million increase from Power related to the new load contracts mentioned above and increased revenues from the two generation facilities in Connecticut, a $601 million increase in PSE&G's operating revenues due primarily to increased weather-related demand in the first quarter of 2003 as explained below under PSE&G and a $128 million increase in Energy Holdings' operating revenues relating to Global's generation projects going into operation as discussed above and increased revenues at Resources.

~~Resources'~~In ~~operating~~addition, ~~revenues~~a ~~decreased~~portion $7of ~~million~~the orincrease ~~12%~~was due to ~~$51~~the ~~million~~fact ~~for~~that ~~the~~Power's ~~quarter~~electric ~~ended~~revenues ~~March~~are ~~31,~~not ~~2003,~~being ~~from~~eliminated ~~$58~~in ~~million~~consolidation ~~for~~subsequent to July 2002 by PSEG. Under the ~~quarter~~prior ~~ended~~BGS ~~March~~contract, which terminated on July 31, 2002, ~~due~~Power ~~primarily~~sold toenergy andirectly ~~increase~~to ofPSE&G, $5which ~~million~~in ~~from~~turn ~~net~~sold ~~investment~~this ~~losses,~~energy ofto ~~which~~its ~~$10~~customers. ~~million~~These ~~resulted~~revenues ~~from~~were ~~other~~properly ~~than~~recognized ~~temporary~~on ~~impairments~~each ofcompany's ~~non~~stand-~~publicly~~alone ~~traded~~financial ~~equity~~statements ~~securities~~and ~~within~~were ~~certain~~eliminated ~~leveraged~~when ~~buyout~~preparing ~~funds~~PSEG's ~~and~~Consolidated ~~other~~Financial ~~investments~~Statements. ~~Also~~For ~~contributing~~the ~~was~~BGS acontract $2period ~~million~~beginning ~~decrease~~August in1, ~~income~~2002, Power entered into contracts with third parties who are direct suppliers of New Jersey's Electric Distribution Companies (EDCs) and PSE&G purchases the energy for its customers' needs from ~~capital~~direct ~~leases~~third ~~due~~party suppliers. Due to ~~terminated~~this ~~leases.~~change in the BGS model,

~~Operating Expenses~~ 49

~~Operating~~these ~~Expenses~~revenues ~~increased~~are ~~$27~~no ~~million~~longer orintercompany ~~42%~~revenues toand ~~$92~~therefore ~~million~~are ~~for~~not eliminated in consolidation. For the quarter and six months ended ~~March~~June 3130, 2003, ~~from~~PSEG's ~~$65~~elimination ~~million~~related ~~for~~to ~~the~~intercompany ~~quarter~~BGS ~~ended~~and ~~March~~MTC 31revenues decreased by approximately $435 million and $847 million, ~~2002~~respectively, as compared to the comparable prior year due primarily to athis ~~$16~~change. ~~million~~Also ~~increase~~ related to this change in the ~~acquisition~~BGS ofmodel, ~~Skawina~~PSE&G, ~~Poland~~in August 2002, began selling energy purchased under non-utility generation (NUG) contracts, which ~~became~~it ~~majority~~had ~~owned~~previously insold to Power, to PJM, with the ~~second~~capacity ~~quarter~~purchased ~~2002~~under ~~and~~these contracts being provided to the BGS suppliers on a ~~$15~~pro-rata ~~million~~basis. ~~increase~~As a result, for the quarter and six months ended June 30, 2003, PSEG's revenues related to ~~Rades,~~NUG ~~Tunisia~~contracts ~~which~~increased ~~commenced~~by ~~operation~~approximately in$35 ~~the~~million ~~second~~and ~~quarter~~$63 ~~2002~~million, respectively.

IncomeOperating from Equity Method Investments Expenses

IncomeEnergy from Equity Method Investments decreased $13 million or 43% to $17 million for the quarter ended March 31, 2003 from $30 million for the quarter ended March 31, 2002. This decrease was due primarily to lower earnings in 2002 of $8 million at RGE mainly driven by regulatory changes that allowed RGE to recover from customers prior tariff charges previously expensed, as well as higher energy purchases, higher inflation rates and higher effective tax rates in the current year. Also contributing to the decrease was $3 million in interest income related to a note receivable from AES in 2002.Costs

~~Other~~ For ~~Income~~the quarter ended June 30, 2003 as compared to the quarter ended June 30, 2002, Energy Costs increased approximately $963 million or 214% due primarily to the fact that PSE&G no longer purchases electric energy directly from Power, as discussed above in Operating Revenues. Amounts attributable to this change totaled $470 million between the quarters ended June 30, 2003 and 2002. Also contributing to the increase were a $101 million net increase in natural gas costs, a $250 million increase at Power primarily related to increased energy purchases and third-party wholesale electric supply contracts, discussed further below under Power, a $21 million increase in electric energy costs at PSE&G discussed further below under PSE&G and a $24 million increase at Energy Holdings, relating to projects going into operation at Global, discussed further below under Energy Holdings.

~~Other~~For ~~Income~~the ~~decreased~~six $7months ~~million~~ended ~~for~~June 30, 2003 as compared to the ~~quarter~~six months ended ~~March~~June 3130, ~~2003~~2002, asEnergy ~~compared~~Costs increased approximately $2.2 billion or 184% due primarily to the ~~same~~fact ~~period~~that PSE&G no longer purchases electric energy directly from Power, as discussed above in Operating Revenues. Amounts attributable to this change totaled $910 million between the six months ended June 30, 2003 and 2002. ~~due~~Also contributing to the increase were a ~~decrease~~$501 ofmillion net increase in natural gas costs, a $10554 million ofincrease ~~net~~at ~~derivative~~Power ~~gains~~primarily ~~partially~~related ~~offset~~to byincreased anpower purchases and third-party wholesale electric supply contracts, discussed further below under Power, a $83 million increase ofin electric energy costs at PSE&G discussed further below under PSE&G and a $341 million ofincrease ~~foreign~~at ~~currency~~Energy ~~transaction~~Holdings, ~~gains~~relating to projects going into operation at Global, discussed further below under Energy Holdings.

OtherOperation Deductionsand Maintenance

~~Other~~For ~~Deductions decreased $46 million for~~ the quarter ended ~~March~~June 3130, 2003, Operation and Maintenance expense increased $30 million or 7% as compared to the quarter ended ~~March~~June 3130, 2002 due ~~primarily~~ to a ~~decrease of~~ $5239 million inincrease ~~foreign~~at ~~currency~~Power ~~transaction~~primarily ~~losses,~~due ~~primarily~~to the acquisition of the generating facilities in ~~Argentina~~Connecticut in December 2002, ~~partially~~and ~~offset~~higher bynuclear refueling outage costs at Power and an increase at Energy Holdings of $64 million, indue ~~net~~mainly ~~derivative~~to ~~losses~~costs ~~primarily~~associated ~~related~~with projects going into operation, offset by a $15 million decrease at PSE&G due primarily to a reduction in real estate tax expense and the ~~Rades~~reversal ~~Power~~of ~~Purchase~~a ~~Agreement~~reserve ~~(PPA)~~associated ~~indexation~~with a regulatory asset, discussed further below under PSE&G.

~~Interest~~ For ~~Expense~~the six months ended June 30, 2003, Operation and Maintenance expense increased $87 million or 9% as compared to the six months ended June 30, 2002 due to a $55 million increase at Power primarily due to the acquisition of the generating facilities in Connecticut in December 2002 and a planned refueling outages at Power, an increase at Energy Holdings of $12 million, due mainly to costs associated with projects going into operation and a $17 million increase at PSE&G due primarily to higher Demand Side Management (DSM) amortization and higher pension costs offset by a reduction in real estate tax expense, discussed further below under PSE&G.

InterestDepreciation Expense decreased $4 million or 7% to $50 million for the quarter ended March 31, 2003 from $54 million for the quarter ended March 31, 2002 due primarily to the retirement of $228 million of Medium-Term Notes at PSEG Capital Corporation (PSEG Capital) in 2002, which resulted in a decrease of $2 million in interest expense. Also contributing to the decrease was the repurchase of Senior Notes in 2002 and reductions in borrowings under the revolving credit facilities.Amortization

~~Income~~ For ~~Taxes~~the quarter and six months ended June 30, 2003, Depreciation and Amortization decreased by $32 million and $63 million, respectively, as compared to the quarter and six months ended June 30,

~~Income Taxes expense increased $17 million for the quarter ended March 31, 2003 compared to the quarter ended March 31, 2002 due primarily to higher pre-tax income.~~50

502002. The decrease was primarily due to an increase in the amortization of the excess depreciation reserve, discussed further below under PSE&G.

LossesTaxes FromOther DiscontinuedThan OperationsIncome Taxes

~~Operating~~Taxes ~~results~~Other ofThan ~~Energy~~Income ~~Technologies'~~Taxes ~~HVAC/mechanical~~is ~~operating~~comprised ~~companies,~~of ~~less~~the ~~certain~~Transitional ~~allocated costs from~~ Energy ~~Holdings,~~Facility ~~have~~Assessment ~~been~~(TEFA) ~~reclassified~~tax ~~into~~at ~~Discontinued~~PSE&G. ~~Operations~~Taxes inOther ~~the~~Than ~~Consolidated~~Income ~~Statements~~Taxes ofincreased ~~Operations.~~$2 ~~The~~million ~~results~~and of$8 ~~operations~~million offor ~~these~~the ~~discontinued~~quarter ~~operations~~and ~~for~~six ~~the~~months ~~quarters~~ ended ~~March~~June 3130, 2003, ~~and~~respectively, ~~2002~~as ~~yielded~~compared ~~additional~~to ~~after-tax~~the ~~losses~~quarter ofand $6six ~~million~~months ~~and~~ended $4June ~~million~~30, ~~respectively~~2002. ~~For~~The ~~additional~~increase ~~information,~~was ~~see~~the ~~Note~~result ~~4. Discontinued Operations~~ of ~~the~~higher ~~Notes.~~TEFA ~~Due~~due to ~~current~~higher ~~market~~taxable ~~conditions,~~sales ~~Energy~~in ~~Holdings~~2003. ~~re-evaluated~~Legislation ~~the~~enacted ~~carrying~~in ~~value~~January of2002 ~~Energy~~freezes ~~Technologies~~the ~~and~~TEFA ~~has~~unit ~~determined~~rate ~~that~~surcharges anat ~~additional~~the ~~write-down~~2001 tolevels ~~fair~~through ~~value~~2004 ~~less~~and ~~cost~~then toreduces ~~sell~~the ~~was~~rates ~~required.~~over In the ~~first~~next ~~quarter~~three ~~of 2003~~years, ~~Energy~~phasing ~~Holdings~~out ~~recorded~~the anTEFA ~~additional~~by ~~after-tax loss on disposal of Energy Technologies of $9 million~~2007.

InIncome addition,from TanirEquity Bavi,Method a 220 MW barge mounted, combined-cycle generating facility in India which was sold in the fourth quarter of 2002, met the criteria for classification as a component of discontinued operations. The operating results of Tanir Bavi for the quarter ended March 31, 2002 yielded after-tax income of $3 million.Investments

~~Cumulative~~ For ~~Effect~~the ofquarter ~~Change~~ended June 30, 2003, Income from Equity Method Investments decreased by $2 million or 6% to $31 million from $33 million for the quarter ended June 30, 2002. For the six months ended June 30, 2003 Income from Equity Method Investments decreased $15 million or 24% to $48 million from $63 million for the six months ended June 30, 2002. These decreases were primarily due to lower earnings in ~~Accounting~~2003 ~~Principle~~from Rio Grande Energia (RGE), an electric distribution company in Brazil, offset by a change in accounting for GWF Energy which had a loss in 2002 when it was accounted for under the equity method and is now recorded as a consolidated entity due to Energy Holdings' increased ownership percentage.

InOther 2002, Energy Holding finalized the evaluation of the effect of adopting SFAS 142 on the recorded amount of goodwill. The total amount of goodwill impairments was $120 million, net of tax of $66 million and was comprised of write downs of $36 million (after-tax) at EDEERSA, $34 million (after-tax) at RGE, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill related to these companies, other than RGE, was fully impaired.Income

~~Liquidity~~ For the quarter ended June 30, 2003, Other Income increased by $23 million, as compared to the quarter ended June 30, 2002, due primarily to a $27 million increase at Power. Power's increase was due primarily to realized gains and ~~Capital~~the ~~Resources~~recognition of interest and dividend income in its NDT Fund.

~~The~~For ~~following~~the ~~discussion~~six ofmonths ~~liquidity~~ended ~~and~~June ~~capital~~30, ~~resources~~2003, isOther onIncome aincreased ~~consolidated~~by ~~basis~~$79 ~~for PSEG~~million, ~~noting~~as compared to the ~~uses~~six months ended June 30, 2002, due primarily to a $74 million increase at Power and ~~contributions~~an of$11 ~~PSEG~~million increase at PSE&G. Power's ~~three~~increase ~~direct~~was ~~operating~~due ~~subsidiaries,~~to realized gains and the recognition of interest and dividend income in its NDT Fund. The increase at PSE&G, ~~Power~~was primarily due to gains on the disposal of various electric transmission properties and ~~Energy~~gains ~~Holdings~~from short-term investments.

Other Deductions

For the quarter ended June 30, 2003, Other Deductions decreased by $6 million, as compared to the quarter ended June 30, 2002, due primarily to $15 million less in foreign currency transaction losses and $3 million less in net derivative losses primarily related to the embedded derivative in the Rades Power Purchase Agreement (PPA). This was partially offset by the recognition of $12 million of realized losses in Power's NDT Fund.

For the six months ended June 30, 2003, Other Deductions decreased by $6 million as compared to the six months ended June 30, 2002, due primarily to $69 million less in foreign currency transaction losses, primarily related to US Dollar debt in Argentina recorded in 2002. This was partially offset by the recognition of $45 million of realized losses in Power's NDT Fund and $12 million in net derivative losses of which $8 million is related to the embedded derivative in the Rades PPA.

Interest Expense

For the quarter ended June 30, 2003, Interest Expense increased by $2 million or 1% as compared to the quarter ended June 30, 2002, primarily due to an $8 million increase at PSEG related to higher levels of debt outstanding, partially offset by a $6 million decrease at PSE&G discussed below.

For the six months ended June 30, 2003, Interest Expense decreased $2 million as compared to the six months ended June 30, 2002, primarily due to a $12 million decrease at PSE&G and a $4 million

decrease at Energy Holdings, partially offset by a $14 million increase at PSEG, related to higher levels of debt outstanding.

Preferred Securities Dividends

For the quarter and six months ended June 30, 2003, Preferred Securities Dividends increased approximately $4 million and $8 million, respectively, as compared to the same periods in 2002, primarily due to the issuance of preferred securities in September 2002 and December 2002.

Income Taxes

For the quarter and six months ended June 30, 2003, Income Taxes increased $191 million and $261 million, respectively, as compared to the same periods in 2002, primarily due to higher pre-tax income.

Losses From Discontinued Operations

Operating results of Energy Technologies' heating, ventilating and air conditioning (HVAC)/mechanical operating companies, less certain allocated costs from Energy Holdings, have been reclassified into Discontinued Operations in the Consolidated Statements of Operations. The results of operations of these discontinued operations for the quarter ended June 30, 2003 and 2002 yielded after-tax losses of $2 million and $5 million, respectively. The results of operations of these discontinued operations for the six months ended June 30, 2003 and 2002 yielded after-tax losses of $8 million and $9 million, respectively. Due to market conditions, Energy Holdings re-evaluated the carrying value of Energy Technologies and has determined that additional adjustments to fair value less cost to sell were required in the first quarter of 2003 and, for the six months ended June 30, 2003, Energy Technologies recorded an after-tax loss of $9 million.

In addition, Tanir Bavi, a 220 MW barge mounted, combined-cycle generating facility in India which was sold in the fourth quarter of 2002, met the criteria for classification as a component of discontinued operations. The operating results of Tanir Bavi for the quarter and six months ended June 30, 2002 yielded after-tax income of $2 million and $5 million, respectively. For additional information, see Note 5. Discontinued Operations of the Notes.

Extraordinary Item

As discussed above, the oral decision issued by the BPU in connection with the Electric Base Rate Case included a $30 million refund related to revenues collected through the SBC for nuclear decommissioning. Because this amount reflects the final accounting for PSEG's generation-related business pursuant to the four-year transition plan mandated by PSE&G's Final Order received from the BPU in 1999 relating to EDECA, it has been recorded as an $18 million, after-tax, Extraordinary Item as required under APB 30. For additional information, see Note 16. Subsequent Events of the Notes.

Cumulative Effect of a Change in Accounting Principle

For the six months ended June 30, 2003, Power recorded a $370 million after-tax benefit to Net Income relating to the adoption of SFAS 143 as detailed further below under Power. For the six months ended June 30, 2002, Energy Holdings recorded a $120 million after-tax charge to Net Income due to goodwill impairments relating to the adoption of SFAS 142 as detailed further below under Energy Holdings.

PSE&G

Operating Revenues

PSE&G's Operating Revenues increased by $112 million or 9% for the quarter ended June 30, 2003 as compared to the quarter ended June 30, 2002. The primary reason for the increase was a $172 million or 56% increase in gas revenues, which was offset by a decrease of $60 million in electric revenues.

Total gas sales volumes increased by 17% for the quarter ended June 30, 2003 due primarily to favorable weather conditions resulting in added revenues of $68 million. Higher commodity prices added $99 million to revenues for the quarter. The price of gas for commercial and industrial customers, which varies monthly with market changes, increased $54 million. Gas price changes for residential customers, which must be approved by the BPU, increased by $39 million. In addition, revenues increased $5 million due to an SBC clause increase in November 2002 to recover additional DSM program charges which are offset in Operation and Maintenance expense.

Electric revenues decreased primarily due to the impact of the final rate decrease, effective August 2002, which reduced revenues by $44 million, and is offset by lower Energy Costs, discussed below. Also contributing to the decrease was the MTC overcollection adjustment of $18 million resulting from the Electric Base Rate Case settlement and decreases in sales volumes which resulted in a $15 million decrease in revenues. Offsetting the decreases were increased revenues from sales of NUG power of $15 million, primarily due to higher locational marginal pricing in PJM.

PSE&G's Operating Revenues increased by $601 million or 21% for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002. The increase was driven by a $631 million increase in gas revenues offset by lower electric revenues of $30 million.

Total gas sales volumes increased by 23% for the six months ended June 30, 2003 due primarily to favorable weather conditions resulting in added revenues of $278 million. Increases in commodity prices added $356 million to revenues for the six months ended June 30, 2003. The price of gas for commercial and industrial customers, which varies monthly with market changes, increased $243 million. Gas price changes for residential customers, which must be approved by the BPU, increased by $95 million. In addition, revenues increased $18 million due to an SBC clause increase in November 2002 to recover additional DSM program charges which are offset in Operation and Maintenance expense.

Electric revenues decreased by $30 million for the six months ended, June 30, 2003. The impact of the 4.9% rate decrease, effective August 2002, which reduced revenues by $88 million, was the primary driver of the decrease, offset by lower Energy Costs, discussed below. The Electric Base Rate Case settlement MTC over-collection adjustment of $18 million also contributed to the decrease. Offsetting the decreases were higher electric sales volumes of 2.6%, primarily due to favorable weather conditions, which resulted in an increase of approximately $43 million and an increase of $34 million for revenues from sales of NUG power, primarily due to increased market prices.

Operating Expenses

Energy Costs

Energy Costs increased by $161 million, or 21% for the quarter ended June 30, 2003 as compared to the same period in 2002. This was primarily due to an increase in gas costs of $140 million for the second quarter of 2003 as compared to the second quarter of 2002. The cost of gas purchased increased $51 million due to a 19% increase in the price of gas and $52 million due to an increase in commodity sales volume due primarily to favorable weather conditions. Additionally, gas costs increased by $35 million for the current deferral of BGSS-RSG costs to match current commodity revenues. In addition, electric costs increased $21 million. BGS purchases increased $55 million due to a 13% increase in prices effective August 1, 2002 and decreased by $12 million due to lower sales volumes. Net MTC payments to Power increased by $14 million. The MTC payment to Power includes an increase of $52 million due to higher amortization of the excess depreciation reserve offset by the impact of the rate reduction. The impact of the amortization of the excess depreciation reserve was offset in amortization and tax expenses on the Consolidated Statements of Operations. In addition, electric costs decreased by $37 million due to the deferral of energy costs in excess of the amount included in revenues.

Energy Costs increased $609 million, or 34% for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002. This was primarily due to an increase in gas costs of $526 million. The cost of gas purchased increased $223 million due to a 23% increase in the price of gas and $182 million due to an increase in commodity sales volume due primarily to favorable weather conditions this year. Additionally, gas costs increased by $110 million for the current deferral of BGSS-RSG costs to match current commodity revenues and $10 million for amortization of previous deferrals.

Also, electric costs increased $83 million. BGS purchases increased $122 million due to a 14% increase in prices effective August 1, 2002 and increased by $19 million due to higher sales volumes. Net MTC payments to Power increased by $20 million. The MTC payment to Power includes an increase of $103 million due to higher amortization of the excess depreciation reserve offset by the impact of the rate reduction. The impact of the amortization of the excess depreciation reserve was offset in amortization and tax expenses on the Consolidated Statements of Operations. NUG energy purchases decreased by $3 million as a result of a $21 million decrease in volumes purchased offset by a higher average price of $18 million. In addition, electric costs decreased by $74 million due to the deferral of energy costs in excess of the amount included in revenues.

Operation and Maintenance

Operation and Maintenance expense decreased $15 million or 6% for the second quarter of 2003 as compared to the second quarter of 2002. The primary reason for the decrease was a reduction in real estate tax expense of $18 million and the reversal of a $10 million reserve against a regulatory asset that is now being recovered. Partially offsetting the decrease was a $7 million increase in DSM program amortization driven by higher sales and a rate increase for gas DSM recovery in November 2002. The gas increase is included in the delivery volume revenue increase discussed above. DSM costs are deferred when incurred and amortized to Operations and Maintenance expense when recovered in revenues. Also offsetting the decreases were higher labor related costs of $6 million, almost half of which was attributable to higher pension costs.

Operation and Maintenance expense increased $17 million or 3% for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002. The primary reason for the change was a $25 million increase in DSM program amortization, as discussed above. Other contributors to the Operation and Maintenance expense increase were higher labor related costs of $22 million, almost half of which was attributable to higher pension costs. Offsetting these increases was $28 million relating to a reduction in real estate tax expense and the reversal of a reserve, discussed above.

Depreciation and Amortization

Depreciation and Amortization decreased $34 million or 35% for the second quarter of 2003 as compared to the second quarter of 2002. The primary reason for the decrease is a reduction of $37 million, which relates to increased amortization of an excess electric distribution depreciation reserve. Based on the Final Order, approximately $148 million was amortized on a straight-line basis during 2002 and approximately $171 million is being amortized on a straight-line basis from January 1, 2003 to July 31, 2003, the end of the transition period under EDECA. Offsetting this decrease was a $3 million increase in depreciation expense due to increased plant in service.

Depreciation and Amortization decreased $63 million or 33% for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002. The primary reason for the decrease is a reduction of $73 million relating to the amortization of an excess electric distribution depreciation reserve. Offsetting this decrease was a $6 million increase in depreciation expense due to increased plant in service and a $6 million increase in the amortization of the regulatory asset related to securitization, which was caused primarily by an increase in Securitization Transition Charge (STC) revenues.

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes increased $2 million or 8% and $8 million or 13% for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002. The increases were the result of higher TEFA due to higher taxable sales in 2003. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.

Other Income

Other Income increased $1 million or 50% for the second quarter of 2003 as compared to the second quarter of 2002, due primarily to gains from short-term investments.

Other Income increased $11 million for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002, due primarily to gains on the disposal of various electric transmission properties and gains from short-term investments.

Interest Expense

Interest Expense decreased by $6 million or 6% for the quarter ended June 30, 2003 as compared to the same period in 2002. Interest on long-term debt decreased $7 million, due to various maturities and issuances of Medium-Term Notes subsequent to the second quarter of 2002, and $2 million due to the payment of Securitization Bonds subsequent to the second quarter of 2002. The decreases were partially offset by $4 million of increased interest on restructuring costs as a result of the settlement of the Electric Base Rate Case.

Interest Expense decreased by $12 million or 6% for the six months ended June 30, 2003 as compared to the same period in 2002. Interest on long-term debt decreased $13 million, due to various maturities and issuances of Medium-Term Notes subsequent to the second quarter of 2002, and $4 million due to the payment of Securitization Bonds subsequent to the second quarter of 2002. The decreases were partially offset by $4 million of increased interest on restructuring costs as a result of the settlement of the Electric Base Rate Case.

Income Taxes

Income Taxes decreased by $8 million for the quarter ended June 30, 2003, as compared to the same period in 2002, due primarily to increased amortization of the excess depreciation reserve for financial statement purposes on which full deferred taxes are not provided, offset by an increase in pre-tax income.

Income Taxes increased by $6 million for the six months ended June 30, 2003, as compared to the same period in 2002, due primarily to an increase in pre-tax income offset by increased amortization of the excess depreciation reserve for financial statement purposes on which full deferred taxes are not provided.

Extraordinary Item

Power

Operating Revenues

For the quarter and six months ended June 30, 2003, Operating Revenues increased $563 million and $1.8 billion, respectively, as compared to the quarter and six months ended June 30, 2002.

For the quarter and six months ended June 30, 2003, generation revenues increased $305 million and $653 million, respectively, compared to the same periods in 2002. The primary drivers contributing to the increase in generation revenues were the increased supply of generation under the load contracts with third party suppliers of BGS, which went into effect on August 1, 2002 and the participation in the New England Power Market mainly as the result of the acquisition of two Connecticut facilities in December 2002. As a result, Power experienced an increase in generation revenues of $289 million and $668 million for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002. Also contributing to the increase in generation revenues were additional MTC revenues of $14 million and $18 million for the quarter and six months ended June 30, 2003, respectively, as

compared to the same periods in 2002. Offsetting these increases for the six months ended June 30, 2003, were unrealized losses on financial instruments of $33 million primarily related to asset-backed financial transactions.

For the quarter and six months ended June 30, 2003, gas revenues increased $251 million and $1.2 billion, respectively, as compared to the same periods in 2002. The increases primarily relate to the fact that the BGSS contract with PSE&G did not commence until May 2002, therefore, Power did not have an operational gas business for the first four months of 2002. Gas revenues for April 2003, and for the first four months of 2003, totaled $167 million, and $1.1 billion, respectively. Gas revenues for the months of May and June of 2003 increased by approximately $84 million, compared to the prior months in 2002 due primarily to cooler temperatures resulting in higher sales volumes and higher gas prices.

Power seeks to trade around its owned assets and supply obligations using various financial instruments in order to maximize its generation and gas businesses. For the quarter and six months ended June 30, 2003, revenues from trading activities increased $7 million and $5 million, respectively, compared to same periods in 2002. Favorable market conditions led to higher trading volumes.

Operating Expenses

Energy Costs

For the quarter and six months ended June 30, 2003, Energy Costs increased $504 million and $1.7 billion, respectively, as compared to the same periods in 2002. Energy costs represent the cost of generation, which includes fuel purchases for generation, as well as purchased energy in the spot market and gas purchases to meet Power's obligation under its BGSS contract with PSE&G.

The increased Energy Costs were primarily due to higher gas costs relating to Power's BGSS contract with PSE&G combined with higher fuel expenses for generation which contributed approximately $273 million and $1.2 billion to the increase for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002. This increase was due primarily to the fact that Power did not have an operational gas business for the first four months of 2002 prior to the transfer of the gas contracts from PSE&G combined with higher gas sales volumes and prices and higher gas, oil and coal costs for generation. Additionally, the increase in Energy Costs was due to increased purchases on the spot market in order to meet the increased obligations under the new load contracts, which went into effect on August 1, 2002 which amounted to approximately $155 million and $335 million for the quarter and six months ended June 30, 2003, respectively. Also, beginning August 1, 2002, Power began paying network transmission charges, which amounted to approximately $64 million and $135 million for the quarter and six months ended June 30, 2003, respectively.

Operation and Maintenance

Operation and Maintenance expense increased $39 million or 21% and $55 million or 15% for the quarter and six months ended June 30, 2003, respectively, from the comparable periods in 2002. This was primarily due to the acquisition of the generating facilities in Connecticut in December 2002, which increased Operation and Maintenance expenses by $13 million and $24 million for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002 combined with non-cash accretion expense of $6 million and $12 million for the quarter and six months ended June 30, 2003, respectively, associated with the implementation of SFAS 143. Also contributing to the increases were higher pension expenses, higher nuclear refueling outage costs and higher real estate tax expenses for the quarter and six months ended June 30, 2003, as compared to the same periods in 2002.

Depreciation and Amortization

Depreciation and Amortization expense decreased $3 million for the quarter and six months ended June 30, 2003 from the comparable periods in 2002. Power had higher depreciation expense of approximately $12 million for the six month period ended June 30, 2003 due primarily to the acquisition of the generating facilities in Connecticut in December 2002 and a higher asset base, however this was

more than offset by the absence of decommissioning charges, which are no longer recorded as a result of the implementation of SFAS 143.

Other Income

Other Income increased $27 million and $74 million for the quarter and six months ended June 30, 2003, respectively, from the comparable periods in 2002, due primarily to the recording of realized gains and income on the NDT Fund.

Other Deductions

Other Deductions increased $12 million and $45 million for the quarter and six months ended June 30, 2003, respectively, from the comparable periods in 2002, due primarily to the recording of realized losses on the NDT Fund.

Interest Expense

Interest Expense remained flat for the quarter and six months ended June 30, 2003 from the comparable periods in 2002. Although Power incurred additional interest charges of $16 million for the six months ended June 30, 2003 due primarily to the new financing of $600 million in June 2002, this increase was offset by capitalized interest relating to various construction projects.

Income Taxes

Income Taxes increased $12 million or 19% and $55 million or 39% for the quarter and six months ended June 30, 2003, respectively, as compared to the same periods in 2002, due primarily to increases in pre-tax income.

Cumulative Effect of Change in Accounting Principle

Power has performed a review of its potential obligations under SFAS 143 and believes that its quantifiable obligations are primarily related to the decommissioning of its nuclear power plants. Upon adoption of this standard on January 1, 2003, Power recorded a Cumulative Effect of a Change in Accounting Principle in the amount of $370 million, after-tax. For additional information, see Note 3. Adoption of SFAS 143 of the Notes.

Energy Holdings

Operating Revenues

For the quarter ended June 30, 2003, Energy Holdings' Operating Revenues increased $55 million, or 41%, to $188 million from the comparable period in 2002. This increase was driven by higher electric generation revenues at Global of $62 million, discussed below, and an increase in revenues at Resources of $35 million. This increase was due to lower revenue in 2002 primarily related to the net change in the carrying value of publicly traded and private securities held within Resources' KKR leveraged buyout funds. Partially offsetting the increase was the timing of a partnership withdrawal payment from EPCP received in the first quarter 2003 compared to the second quarter 2002. In 2001, Global withdrew from its interest in EPCP in exchange for a series of payments through 2005, provided certain operating contingencies are met.

For the six months ended June 30, 2003, Energy Holdings' Operating Revenues increased $128 million, or 48%, to $397 million from the comparable period in 2002. This increase was driven by higher electric generation revenues at Global of $126 million and an increase in revenues at Resources of $28 million. This increase was due to lower revenue in 2002 primarily related to the net change in the carrying value of publicly traded and private securities held within the KKR leveraged buyout funds. This increase was partially offset by lower electric distribution and other electric revenue at Global in 2003 of $23 million, discussed below.

Global

For the quarter ended June 30, 2003, Operating Revenues increased by $21 million or 21% to $122 million from $101 million for the quarter ended June 30, 2002. The increase in revenue was due to a $24 million increase from Skawina, a generation facility in Poland, in which Global purchased a majority ownership in June 2002, a $20 million increase from Rades, a generation facility in Tunisia which commenced operations in May 2002, and a $10 million increase from Salalah, a generation facility in Oman which began commercial operation in May 2003. Also contributing was a $13 million increase at GWF Energy. In the second half of 2002, Global's ownership of GWF Energy exceeded 75% and under the operating agreement Global gained a controlling interest. Accordingly, Global consolidates GWF Energy as compared to the second quarter 2002 when it was recorded under the equity method. These increases were partially offset by a decrease of $39 million of realized revenue from the partnership withdrawal from EPCP, which was recorded in the first quarter of 2003 as compared to the second quarter of 2002. Also offsetting the increase was a decrease of $6 million from Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), in Argentina, which was fully written off in 2002 and was abandoned in the first quarter of 2003.

For the six months ended June 30, 2003, Operating Revenues increased $100 million or 56% to $279 million from $179 million for the six months ended June 30, 2002. The increase in revenue was due to a $50 million increase from Skawina, a $42 million increase from Rades and a $10 million increase from Salalah. Also contributing was a $22 million increase at GWF Energy. These increases were partially offset by a decrease of $20 million from EDEERSA.

Resources

For the quarter ended June 30, 2003, Operating Revenues increased $35 million or 109% to $67 million from $32 million for the quarter ended June 30, 2002. The increase was primarily related to $38 million of other than temporary impairments of non-publicly traded equity securities held within the KKR leveraged buyout funds recorded in the second quarter of 2002 compared to $6 million in gains in the second quarter of 2003. This increase was partially offset by a decrease of $4 million in income from capital leases due to terminated leases.

For the six months ended June 30, 2003, Operating Revenues increased $28 million or 31% to $118 million from $90 million for the six months ended June 30, 2002. This increase was primarily related to a $33 million net decrease of other than temporary impairments of non-publicly traded equity securities held within the KKR leveraged buyout funds recorded in the first quarter 2003 and second quarter of 2002. Also contributing was a $6 million decrease in income from capital leases due to terminated leases.

Operating Expenses

For the quarter ended June 30, 2003, Operating Expenses decreased $470 million or 81% to $107 million from $577 million for the quarter ended June 30, 2002. This decrease was primarily due to the write-down of project investments in Argentina at Global of $506 million in the second quarter of 2002. Partially offsetting this decrease was an increase in operating expenses of $17 million from Skawina, a $14 million increase from Rades and a $6 million increase from Salalah.

For the six months ended June 30, 2003, Operating Expenses decreased $443 million or 69% to $199 million from $642 million for the six months ended June 30, 2002. This decrease was primarily due to the write-down of project investments in Argentina at Global of $506 million in the second quarter of 2002. Partially offsetting this decrease was an increase in operating expenses of $33 million from Skawina and a $29 million increase from Rades.

Income from Equity Method Investments

For the quarter ended June 30, 2003, Income from Equity Method Investments decreased by $2 million or 6% to $31 million from $33 million for the quarter ended June 30, 2002. These decreases are primarily due to lower earnings in 2003 of $4 million at RGE and lower interest income of $12 million

from GWF Energy and EPCP. This decrease was partially offset by increased revenue of $7 million from TIE. Also offsetting the decrease was a change in accounting for GWF Energy, which was accounted for under the equity method and reported a loss of $6 million in 2002 and is now recorded as a consolidated entity due to Energy Holdings' increased ownership percentage.

For the six months ended June 30, 2003, Income from Equity Method Investments decreased $15 million or 24% to $48 million from $63 million for the six months ended June 30, 2002. These decreases are primarily due to lower earnings in 2003 of $13 million at RGE and lower interest income of $9 million from GWF Energy and EPCP. This decrease was partially offset by increased revenue of $8 million at TIE. Also offsetting the decrease was changes in accounting for GWF expansion, which was accounted for under the equity method and reported a loss of $5 million in 2002 and is now recorded as a consolidated entity due to Energy Holdings' increased ownership percentage.

Other Deductions

For the quarter ended June 30, 2003, Other Deductions decreased $18 million due primarily to a decrease of $15 million in foreign currency transaction losses, primarily related to losses of $17 million in Argentina in 2002, and a decrease of $3 million in net derivative losses primarily related to the embedded derivative in the Rades PPA.

For the six months ended June 30, 2003, Other Deductions decreased by $57 million to $12 million. The decrease was largely due to $1 million in foreign currency transactions gains for the six months ended June 30, 2003 compared to a $69 million foreign currency transaction loss for the same period in 2002. This decrease was partially offset by an increase of $12 million in net derivative losses of which $8 million is related to the embedded derivative in the Rades PPA.

Interest Expense

For the six months ended June 30, 2003, Interest Expense decreased $4 million or 4% to $104 million from $108 million for the six months ended June 30, 2002. The decrease is primarily due to the maturity of Medium-Term Notes at PSEG Capital Corporation (PSEG Capital) in the second half of 2002 of $130 million and in May 2003 of $252 million, which resulted in a decrease of $9 million in interest expense. Partially offsetting this decrease is interest expense related to Energy Holdings' $350 million of Senior Notes issued in April 2003.

Income Taxes

Income Taxes increased $193 million and $210 million for the quarter and six months ended June 30, 2003, respectively, from a benefit of $177 million from the comparable periods in 2002. This increase is attributed to taxable income for the quarter and six months ended June 30, 2003 compared to tax benefits in the same period in 2002 related to pre-tax losses.

Losses From Discontinued Operations

Operating results of Energy Technologies' HVAC/mechanical operating companies, less certain allocated costs from Energy Holdings, have been reclassified into Discontinued Operations in the Consolidated Statements of Operations. The results of operations of these discontinued operations for the quarter ended June 30, 2003 and 2002 yielded after-tax losses of $2 million and $5 million, respectively. The results of operations of these discontinued operations for the six months ended June 30, 2003 and 2002 yielded after-tax losses of $8 million and $9 million, respectively. Due to market conditions, Energy Holdings re-evaluated the carrying value of Energy Technologies and has determined that an additional adjustments to fair value less cost to sell were required in the first quarter of 2003 and, for the six months ended June 30, 2003, Energy Technologies recorded an after-tax loss of $9 million.

In addition, Tanir Bavi, which was sold in the fourth quarter of 2002, met the criteria for classification as a component of discontinued operations. The operating results of Tanir Bavi for the

quarter and six months ended June 30, 2002 yielded after-tax income of $2 million and $5 million, respectively. For additional information, see Note 5. Discontinued Operations of the Notes.

Cumulative Effect of Change in Accounting Principle

In 2002, Energy Holding finalized the evaluation of the effect of adopting SFAS 142 on the recorded amount of goodwill. The total amount of goodwill impairments was $120 million, net of tax of $66 million and was comprised of write-downs of $36 million (after-tax) at EDEERSA, $34 million (after-tax) at RGE, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill related to these companies, other than RGE, was fully impaired.

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

PSEG's operating cash flow increased approximately $~~323~~92 million from $536 million to $628 million for the ~~quarter~~six months ended ~~March~~ June 3130, 2003, as compared to the ~~quarter~~six months ended ~~March~~June 3130, 2002, due primarily to increases of $~~455~~505 million at Power and $1879 million at Energy Holdings, ~~partially~~ largely offset by a $~~154~~518 million decrease at PSE&G. PSEG expects operating cash flows to be sufficient to fund the majority of capital requirements and future dividend payments.

~~PSE&G~~ Dividend payments on common stock for the quarter ended June 30, 2003 were $0.54 per share and totaled approximately $122 million. Dividend payments on common stock for the six months ended June 30, 2003 were $1.08 per share and totaled approximately $244 million. Future dividends declared will be dependent upon PSEG's future earnings, cash flows, financial requirements, alternate investment opportunities and other factors. For additional information on PSEG's dividends, see Overview.

PSE&G's operating cash flow decreased approximately $154 million for the quarter ended March 31, 2003 as compared to the quarter ended March 31, 2002, due primarily to increased working capital needs, mostly due to seasonally higher accounts receivable balances as a result of increased billings in the colder than normal first quarter. This was partially offset by increased income from continuing operations, lower payments to benefit plans and increased recoveries of deferred commodity and other costs.

PSE&G's operating cash flow decreased approximately $518 million from $490 million to $(28) million for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002, due primarily to the sale of its entire gas inventory for approximately $415 million in the first half of 2002, including approximately $183 million received from Power for the gas contract transfer in May 2002, combined with the timing of collections from customers as compared to payments under energy contracts. This was partially offset by increased Income from Continuing Operations and increased recoveries of deferred commodity and other costs.

Power's operating cash flow increased approximately $455 million for the quarter ended March 31, 2003 as compared to the quarter ended March 31, 2002, due primarily to decreased working capital needs, as Power's gas inventory was drawn down to supply its requirements under the BGSS contract with PSE&G, and increased income from continuing operations.

51 Power's operating cash flow increased approximately $505 million from $75 million to $580 million for the six months ended June 30, 2003, as compared to the six months ended June 30, 2002, due to several factors, including approximately $282 million of lower working capital requirements for the six months ended June 30, 2003, as compared to the same period in 2002, primarily due to the Gas Contract Transfer from PSE&G which occurred in the second quarter of 2002 and positive cash inflow in 2003 mainly from sales under the BGSS contract. Also contributing to the increase was increased Income from Continuing Operations of approximately $83 million.

Energy Holdings

Energy Holdings' operating cash flow increased approximately $1879 million ~~for~~from ~~the~~$24 ~~quarter~~million ~~ended~~to ~~March 31,~~$103 ~~2003~~million asfor ~~compared to~~ the ~~quarter~~six months ended ~~March 31~~June 30, ~~2002~~2003, ~~due~~as ~~primarily~~compared to ~~higher~~the ~~income~~six ~~from~~months ~~continuing~~ended ~~operations~~June 30, ~~partially offset by lower rents received on leverage leases and lower foreign currency transaction losses~~2002.

This increase is primarily related to the absence in 2003 of loans made to TIE and GWF Energy in 2002 that were used to provide funding for project level construction prior to permanent project financing.

Debt Covenants

PSEG, PSE&G, Power and Energy Holdings

~~The~~PSEG's, PSE&G's, Power's and Energy Holdings' respective credit agreements generally contain customary provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's business or financial condition. ~~In that event, loan funds may not be advanced.~~

As explained in detail below, some of these credit agreements 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 ~~PSEG's~~the future financial position, ~~and the~~ level of earnings and cash ~~flow,~~flows asof ~~to which no assurances can be given. Management believes that~~ PSEG, PSE&G, Power and Energy Holdings, ~~are~~as into ~~compliance~~which ~~with~~no ~~all~~assurances ~~covenants~~can asbe ~~of March 31, 2003~~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. The preferred securities of PSEG and PSE&G, which will be presented as Noncurrent Liabilities, effective July 1, 2003 in accordance with SFAS 150, will not be included as debt when calculating these ratios, as provided in the various credit agreements.

PSEG

Financial covenants contained in PSEG's credit facilities include a ratio of debt (excluding non-recourse project financings and securitization debt and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 0.70 to 1. As of ~~March~~June 3130, 2003, PSEG's ratio of debt to capitalization (as defined above) was 0.59 to 1.

PSE&G

Financial covenants contained in PSE&G's credit facilities include a ratio of ~~Long~~long-~~Term~~term ~~Debt~~debt (excluding ~~Long~~securitization debt and long-~~Term~~term ~~Debt~~debt ~~Maturing~~maturing within 1one ~~Year~~year) to ~~Total~~total ~~Capitalization~~capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 0.65 to 1. As of ~~March~~June 3130, 2003, PSE&G's ratio of ~~Long~~long-~~Term~~term ~~Debt~~debt to ~~Total~~total ~~Capitalization~~capitalization was 0.5249 to 1.

~~PSEG~~ In addition, under its 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 2:1, and/~~Power~~or against retired Mortgage Bonds. At June 30, 2003, PSE&G's Mortgage coverage ratio was 3:1 and the Mortgage would permit up to approximately $1.5 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements.

Financial covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization covenant for each specific borrower. When PSEG is the borrower, the covenant described above in PSEG is applicable. When Power is the borrower a debt (excluding non-recourse project financings and including loans, certain letters of credit and similar instruments) to total capitalization, adjusted for the $986 million Basis Adjustment (see Power's Consolidated Balance Sheets), covenant applies. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 0.65 to 1. As of March 31, 2003, Power's ratio of debt to capitalization (as defined above) was 0.46 to 1.

~~Energy~~ Financial ~~Holdings~~covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization covenant for each specific borrower. Where PSEG is the borrower, the covenant described above in PSEG is applicable. Where Power is the borrower, a debt (excluding non-recourse project financings and including loans, certain letters of credit and similar instruments) to total capitalization, adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets), covenant applies. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 0.65 to 1. As of June 30, 2003, Power's ratio of debt to capitalization (as defined above) was 0.45 to 1.

Financial covenants contained in Energy Holdings' credit facilities include the ratio of cash flow available for debt service (CFADS) to fixed charges. CFADS includes, but is not limited to, operating cash flows before interest and taxes, pre-tax cash distributions from all asset liquidations and equity capital contributions from PSEG to the extent not used to fund investing activity. At the end of any quarterly financial period such ratio shall not be less than 1.50x for the 12-month period then ending. As a condition of borrowing, the pro-forma CFADS to fixed charges ratio shall not be less than 1.75x as of the quarterly financial period ending immediately following the first anniversary of each borrowing or 61

52Energy Holdings

Financial covenants contained in Energy Holdings' credit facility includes the ratio of cash flow available for debt service (CFADS) to fixed charges. CFADS includes, but is not limited to, operating cash flows before interest and taxes, pre-tax cash distributions from all asset liquidations and equity capital contributions from PSEG to the extent not used to fund investing activity. At the end of any quarterly financial period such ratio is required to be not less than 1.50x for the 12-month period then ending. As a condition of borrowing, the pro forma CFADS to fixed charges ratio is required to be not less than 1.75x as of the quarterly financial period ending immediately following the first anniversary of each borrowing or letter of credit issuance. As of ~~March~~June 3130, 2003, Energy Holdings ratio of CFADS to fixed charges was 5.4x6x. In addition, the ratio of consolidated recourse indebtedness to recourse capitalization, as atof the end of any quarterly financial period, shall not be greater than 0.60 to 1. This ratio is calculated by dividing the total recourse indebtedness of Energy Holdings by the total recourse capitalization. ~~This ratio excludes the debt of PSEG Capital, which is supported by PSEG.~~ As of ~~March~~June 3130, 2003, Energy Holdings' ratio of consolidated recourse indebtedness to recourse capitalization was 0.4347 to 1.00.

On April 16, 2003, Energy Holdings issued $350 million ofin Senior Notes which contain financial covenants that include debt incurrence tests consisting of a debt service coverage test and a ratio of consolidated recourse indebtedness to recourse capitalization test. ~~These~~which ~~tests~~ require that Energy Holdings will not incur additional consolidated recourse indebtedness, ~~other than certain permitted indebtedness, such as permitted refinancings,~~ unless, on a pro forma basis giving effect to the incurrence of the additional consolidated recourse indebtedness, (i) the debt service coverage ratio would be at least 2 to 1 and (ii) the ratio of consolidated recourse indebtedness to recourse capitalization would not exceed 0.60 to 1. ~~These~~Certain ~~covenants~~permitted indebtedness, such as permitted refinancings and borrowings under its 5-year credit facility are excluded from this test. The provisions of the Senior Notes also restrict Energy Holdings from selling greater than 10% of its assets in any four consecutive quarters, unless the proceeds are used to reduce debt of Energy Holdings or its subsidiaries or are ~~reinvested or~~ retained by Energy Holdings.

Cross Default Provisions

Certain information reported in the ~~December~~2002 ~~31,~~Annual ~~2002~~Report ~~Form~~on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 is updated below.

PSEG and Energy Holdings

~~The~~ PSEG's bank credit agreements and ~~certain~~note ofpurchase agreements (Credit Agreements) relating to its ~~financing~~private ~~agreements~~placement of institutional debt contain ~~several~~cross default provisions under ~~one~~which ofcertain ~~which~~payment isdefaults aby ~~payment~~PSE&G, ~~cross~~Power ~~default~~or ~~whereby~~Energy aHoldings, certain ~~default~~bankruptcy byevents itrelating to PSE&G, Power or Energy Holdings, the failure by PSE&G, Power or Energy Holdings into ansatisfy ~~aggregate~~certain ~~amount~~final ofjudgments or ~~$50~~the ~~million~~occurrence ~~would~~of ~~result~~certain inevents aof default ~~and~~under the ~~potential~~financing ~~acceleration~~ agreements of ~~payment~~PSE&G, ~~under~~Power ~~those~~or ~~credit~~Energy ~~and~~Holdings, ~~financing~~would ~~agreements.~~each ~~All~~constitute an event of default under the PSEG ~~credit~~Credit ~~agreements~~Agreements. ~~contain~~It ~~provisions~~is ~~that~~also ~~will~~an ~~eliminate~~event ~~this~~of ~~cross-~~default tounder the PSEG Credit Agreements, if PSE&G, Power or Energy Holdings, ~~once~~ceases to be wholly-owned by PSEG. Energy Holdings' ~~$495~~current ~~million~~credit ~~Credit~~agreement, ~~Agreement~~which expires in May 2004, provides orthat iscertain ~~renewed~~payment ~~prior~~or toother ~~that~~events ~~time.~~of default by PSEG ~~expects~~or a failure by PSEG to ~~negotiate~~satisfy ~~similar~~certain ~~provisions~~final injudgments, ~~PSEG's~~maintain ~~financing~~ownership ~~agreements~~of at least 80% of the capital stock of Energy Holdings or maintain a specified level of consolidated net worth, aswould ~~applicable~~each constitute an event of default under Energy Holdings' credit agreement.

PSEG's bank credit agreements have been amended to eliminate the payment cross-default relating to Energy Holdings as a PSEG-level event of default, effective with the termination of the current Energy Holdings' credit agreement. PSEG has recently amended its note purchase agreements and is in the process of seeking consents from the lenders under its bank credit agreements to exclude Energy Holdings from all cross-default provisions effective with the termination of the current Energy Holdings' credit agreement. PSEG is also in the process of replacing Energy Holdings' credit agreement with a new bank credit agreement seeking to eliminate PSEG-level covenants other than the maintenance of ownership of at least 80% of the capital stock of Energy Holdings.

Ratings Triggers

PSEG, PSE&G, Power and Energy Holdings

The debt indentures and credit agreements of PSEG, PSE&G, Power and Energy Holdings do not contain any material ''ratings triggers'' that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and collateral requirements.

Power

In connection with its energy marketing and trading activities, Power must meet certain credit quality standards required by counterparties. If Power loses its investment grade credit rating, PSEG Energy Resources & Trade LLC (ER&T) would have to provide credit support (letters of credit or cash), which would significantly impact the cost of the energy trading activities. Power's Master Agreements and other supply contracts contain margin and/or other collateral requirements that, as of March 31, 2003, could require Power to post additional collateral of approximately $652 million if Power were to lose its investment grade credit rating and all counterparties were entitled to and called for collateral. These same contracts provide reciprocal benefits to Power. Providing this credit support would increase Power's costs of doing business and could limit Power's ability to successfully conduct its energy trading operations.

5362

~~Energy~~cash), ~~Holdings~~which would significantly impact the cost of its energy trading activities. In addition, all Master Agreements and other supply contracts, including Power's BGS-related load contracts, contain margin and/or other collateral requirements that, as of June 30, 2003, could require Power to post additional collateral of approximately $353 million if Power were to lose its investment grade credit rating and all counterparties, where Power is ''out-of-the money'' under such contracts, were entitled to and called for collateral. Providing this credit support would increase Power's costs of doing business and could limit Power's ability to successfully conduct its energy trading operations.

Energy Holdings and Global may have to provide collateral of approximately $85 million for certain of their equity commitments if Energy Holdings' ratings should fall below investment grade.

Energy Holdings and Global may have to post letters of credit of approximately $70 million for certain of their equity commitments if one of Energy Holdings' ratings should fall below investment grade. Approximately $61 million of these equity commitments are included in Energy Holdings' anticipated capital expenditures for the remainder of 2003. These letters of credit, if required, would be readily available under Energy Holdings' credit facility.

Credit Ratings

The current ratings of securities of PSEG and its subsidiaries are shown below and reflect the respective views of the rating agencies, from whom an explanation of the significance of their ratings may be obtained. In the ordinary course of business, PSEG has regular discussions with each of the rating agencies. There is no assurance that these 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. Any downward revision or withdrawal may adversely effect the market price of PSEG's, Energy Holdings', Power's and PSE&G's securities and serve to increase those companies' cost of capital and limit their access to capital.

	Moody's	Standard & Poor's	Fitch
PSEG:
Preferred Securities	Baa3	BB+	BBB
Commercial Paper	P2	A2	Not Rated
PSE&G:
Mortgage Bonds	A3	A-	A
Preferred Securities	Baa2	BB+	BBB+
Commercial Paper	P2	A2	F1
Power:
Senior Notes	Baa1	BBB	BBB+
Energy Holdings:
Senior Notes	Baa3	BBB-	BBB-

On June 16, 2003, Moody's announced that it had placed the ratings of PSEG's Preferred Securities, and Power's and Energy Holdings' Senior Notes under review for possible downgrade and reaffirmed PSE&G's ratings. Moody's stated that it does not expect that the review would result in the ratings of PSEG or Power falling by more than one notch. PSEG, Power and Energy Holdings are continuing their discussions with Moody's to facilitate this process. No assurances can be given as to the final outcome of this matter.

Short-Term Liquidity

PSEG, PSE&G, Power and Energy Holdings

As of June ~~March 31~~30, 2003, PSEG had a total of approximately $2.42 billion of committed credit facilities, with approximately $~~544~~842 million ~~drawn~~reserved ~~against~~for ~~such~~commercial ~~facilities,~~paper ~~including~~program liquidity support and an additional $719 million and $75 42 million indrawn for letters of credit at Power and Energy Holdings, respectively,. ~~resulting~~This resulted in approximately $1.83 billion inof available liquidity. In addition to this amount, PSEG, PSE&G and Energy Holdings had access to certain uncommitted credit facilities under which PSE&G had $82161 million ~~was~~ outstanding as of ~~March~~June 3130, 2003. The following table summarizes the various revolving credit facilities of PSEG and its subsidiaries and the liquidity available as of ~~March~~June 3130, 2003.

Company	Expiration Date	Total Facility		Primary Purpose	Usage at 0306/3130/2003		Available Liquidity at 0306/3130/2003
	(millions)
	(Millions)
PSEG:
364-day Credit Facility	March 2004	$	350	CP Support	$	~~306~~350	$	44—
5-year Credit Facility	March 2005	$	280	CP Support	$	—151	$	~~280~~129
3-year Credit Facility	December 2005	$	350	CP Support/ Funding	$	—	$	350
Uncommitted Bilateral Agreement	N/A		*N/A	Funding	$	25—		N/A
PSE&G:
364-day Credit Facility	June ~~2003~~2004	$	200	CP Support	$	~~156~~200	$	44—
3-year Credit Facility	June 2005	$	200	CP Support	$	—141	$	~~200~~59
Uncommitted Bilateral Agreement	N/A		*N/A	Funding	$	10161		N/A
Power:
PSEG and Power:
364-day Credit Facility(A)	March 2004	$	250	CP Support/ Funding	$	—	$	250
(PSEG/Power)
Power:
3-year Credit Facility	August 2005	$	25	Funding	$	719	$	186
Energy Holdings:
364-day Credit Facility	May 2003	$	200	Funding	$	—	$	200
5-year Credit Facility	May 2004	$	495	Funding	$	42	$	453
5-year Credit Facility	May 2004	$	495	Funding	$	75	$	420
Uncommitted Bilateral Agreement	N/A		N/A	Funding	$	—		N/A
Uncommitted Bilateral Agreement	N/A		*	Funding	$	47		N/A

~~In addition,~~ (A) PSEG/Power ~~had~~co-borrower ~~approximately $76 million of cash available as of March 31, 2003 to retire commercial paper.~~facility

In order to support its short-term financing requirements, as well as those of Power, PSEG has revolving credit facilities that are used both as a source of short-term funding and to provide backup liquidity for its $1 billion commercial paper program.

~~On March 19, 2003,~~ PSEG ~~closed~~has ~~on two 364-day credit facilities;~~ a $350 million facility ~~for~~expiring ~~PSEG~~in ~~and~~December a2005 ~~joint~~that ~~and several PSEG/Power $250 million facility. These facilities replace two existing 364-day facilities at PSEG. The new PSEG facility~~ provides liquidity support for ~~the~~its ~~PSEG~~ commercial paper program. ~~The joint~~ and ~~several~~can ~~PSEG/Power facility~~ also ~~provides liquidity support for the PSEG commercial paper program and can~~ be used ~~by either PSEG or Power~~ as a source of short-term funding and to issue letters of credit. ~~Under~~PSEG ~~this~~also ~~facility,~~has ~~either~~a ~~PSEG~~$350 ormillion ~~Power~~facility ~~may~~expiring ~~borrow,~~in March 2004 and a $280 million facility expiring in March 2005, both of which are ~~jointly~~used ~~and~~to ~~severally~~provide ~~liable~~liquidity tosupport ~~repay~~for ~~the~~its ~~loans~~commercial paper program.

54 The $250 million PSEG/Power joint and several facility provides liquidity support for the PSEG commercial paper program and can be used by either PSEG or Power as a source of short-term funding and to issue letters of credit. Under this facility, either PSEG or Power may borrow and both are joint and severally liable to repay the loans.

~~PSE&G~~64

PSE&G maintains credit facilities to provide backup for its $400 million commercial paper program.

InOn June 26, 2003, aPSE&G renewed its $200 million, 364-day credit facility. isIn ~~expiring.~~addition, PSE&G ~~intends~~has toa ~~renew~~$200 ~~this~~million 3-year credit facility expiring in aJune 2005. ~~similar~~The ~~amount~~purpose ~~during~~of ~~June~~both ~~2003~~facilities is to provide liquidity support for PSE&G's $400 million commercial paper program.

Power

Power has access to the $250 million, 364-day joint and several PSEG/Power credit facility and a separate $25 million credit facility, but primarily relies on PSEG for its short-term financing needs. For information regarding affiliate borrowings, see Note 1214. Related-Party Transactions of the Notes.

As of ~~March 31~~June 30, 2003, letters of credit issued by Power were outstanding in the amount of approximately $7486 million, including the $719 million drawn against its credit facilities, in support of various contractual obligations, environmental liabilities, and to satisfy trading collateral obligations.

Energy Holdings

Energy Holdings has a revolving and letter of credit ~~facilities~~facility totaling $~~695~~495 million that ~~are~~is used both as a source of short-term funding and to issue letters of credit. In May 2003, a $200 million facility isexpired ~~expiring~~ and itwas is not ~~anticipated that this facility will be~~ renewed as that level of short-term funding iswas ~~not~~deemed no longer necessary for Energy Holdings' financing needs. As of ~~March~~June 3130, 2003, in addition to amounts outstanding under Energy Holdings' credit facilities shown in the above table, subsidiaries of Global had $9667 million of non-recourse short-term financing at the project level. For information regarding affiliate borrowings, see Note 12 14. Related-Party Transactions of the Notes.

External Financings

PSEG

In 2002, PSEG began issuing shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Plan, rather than purchasing them on the open market. For the quarter ended ~~March~~June 3130, 2003, PSEG issued approximately ~~570~~504,000 shares for approximately $21 million pursuant to these plans. For the six months ended June 30, 2003, PSEG issued approximately 1,074,000 shares for approximately $42 million pursuant to these plans.

Dividend payments on common stock for the quarter ended March 31, 2003 were $0.54 per share and totaled approximately $122 million. Future dividends declared will be dependent upon PSEG's future earnings, cash flows, financial requirements, alternate investment opportunities and other factors. PSEG would consider increasing the dividend if the payout ratio approached 50% and could be sustained at that level.PSE&G

In January 2003, PSE&G issued $150 million of 5.00% Medium-Term Notes due 2013. The proceeds from this issuance were used to repay $150 million of 6.875% Series MM Mortgage Bonds which matured in January 2003.

InAlso in January 2003, ~~PSE&G~~PSEG ~~issued~~contributed $~~150~~170 million ~~of 5.00% Medium-Term Notes due 2013. The proceeds of approximately $149 million were used~~ to ~~repay $150 million of 6~~PSE&G.~~875% Series MM Mortgage Bonds which matured in January 2003.~~

~~Also~~In inJune ~~January~~ 2003, ~~PSEG contributed~~ $~~170~~150 million toof ~~PSE&G~~8.875% toSeries ~~offset~~DD aMortgage ~~2002~~Bonds ~~minimum pension liability charge to Other Comprehensive Income (OCI)~~matured.

During the ~~quarter~~six months ended ~~March 31~~June 30, 2003, Transition Funding, a wholly-owned subsidiary of PSE&G, repaid $3058 million of securitization bonds as scheduled.

Energy Holdings

During January and February of 2003, Sociedad Austral de Electricidad S.A. (SAESA) and Empresa Electrica de la Frontera S.A. (Frontel), two distribution companies in Chile, refinanced certain ~~non-recourse~~ short-term obligations through a combination of bonds, a syndicated bank facility and equity from Global. SAESA issued two series of local bonds in Chile equivalent to $117 million with final ~~maturity~~maturities in 2009 and 2023. Frontel executed a syndicated loan facility equivalent to $23 million with final maturity in 2010. In addition, during January 2003, Global made planned equity contributions to SAESA and Frontel totaling $55 million.

55 Part of the purchase price of Electroandes, a generation facility in Peru, was financed with a $100 million one-year bridge loan with an original maturity date in December 2002 that was subsequently

~~syndicated loan facility equivalent to $23 million with final maturity in 2010. In addition, during January 2003, Global made equity contributions to SAESA and Frontel totaling $55 million.~~65

extended to June 2003. In March 2003, Electroandes refinanced athe $100 million bridge loan with a $70 million seven-year amortizing facility and two $15 million one-year facilities (each guaranteed by Energy Holdings). Additionally, in June 2003, Electroandes sold $50 million of bonds in the local market. These bonds have a 6.4375% coupon and mature in 2013. The bonds include a 5-year grace period on principal payments. Proceeds from this bond issue were used to repay the two $15 million one-year facilities and $20 million of the $70 million seven-year facility. Electroandes expects to complete the refinancing of the seven-year facility from future bond issues.

In April 2003, Energy Holdings, in a private placement, issued $350 million of its 7.75% Senior Notes, due in 2007. ~~Proceeds~~The ofproceeds ~~$344~~were ~~million~~used ~~will~~in bepart ~~used~~to ~~for~~repay ~~general~~PSEG ~~corporate~~Capital ~~purposes~~Corporation's ~~including~~(PSEG ~~repayment~~Capital) ofremaining $252 million of 6.25% Medium-Term Notes atthat matured in May 2003. Energy Holdings does not plan to use PSEG Capital ~~that~~as ~~mature~~a financing vehicle in the future and is in the process of dissolving PSEG Capital. The remaining proceeds from the sale of the Senior Notes will be used for general corporate purposes and, with cash generated from operations and expected asset sales, to meet Energy Holdings' May 2004 Senior Notes maturity and maintain sufficient liquidity at Energy Holdings. In July 2003, Energy Holdings completed an exchange offer for its outstanding 7.75% Senior Notes due 2007.

In May 2003, GWF Power Systems, L.P. (GWF) and Hanford L.P. (Hanford), closed on $55 million in syndicated bank loans along with an additional $7 million letter of credit facility. Global and Harbert Power (Harbert) each own 50% of GWF and Hanford. GWF and Hanford used the net proceeds from the bank loan to pay back investments from Global and Harbert. Global received a cash distribution of approximately $27 million in May 2003 and reduced its investment in GWF to $66 million as of June 30, 2003.

Credit Risk

PSEG, PSE&G, Power and Energy Holdings

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

Power

Counterparties expose Power to credit losses in the event of non-performance or non-payment. Power has a credit management process which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power and its subsidiaries' financial condition, results of operations or net cash flows. As of ~~March~~June 3130, 2003, over 9395% of the credit exposure (mark -to -market plus net receivables and payables, less cash collateral) for Power's trading operations was with investment grade counterparties. As of ~~March~~June 3130, 2003, Power's trading operations had over ~~171~~150 active counterparties.

~~Energy~~ In ~~Holdings~~December 2001, Enron Corp. (Enron) and its subsidiaries filed for reorganization under Chapter 11 of the US Bankruptcy Code. Power had entered into a variety of energy trading contracts with Enron and its affiliates as part of its energy trading activities. As of December 31, 2002, Enron had made claims against Power and asserted that payment obligations of Enron Power Marketing to Power may not be offset against this amount. Power paid Enron approximately $36 million in July 2003 under a settlement for these claims.

Project cash flows at Texas Independent Energy L.P. (TIE) were insufficient to pay the loan installment of approximately $2 million due to Global on March 31, 2003 and Panda Energy International, Inc. (Panda)/Teco Power Services (Teco) failed to fund the 50% of the partnership cash call due from them in support of the March 31, 2003 debt service payment. Consequently, the loan due to Global is in default and the interest rate has increased to the default rate of 14%. If the default continues, Global has the right to foreclose on Panda/Teco's 50% interest in TIE, which has been pledged to secure the loans due to Global. As of May 1, 2003, Global has not received the March 31, 2003 loan repayment, including interest. Therefore, under the terms of the partnership agreement Global has gained significant control over TIE and it is expected that Global will consolidate TIE beginning in the second quarter of 2003. For additional information relating to this loan, see Note 12. Related-Party Transactions.66

CapitalEnergy RequirementsHoldings

Project cash flows at TIE were insufficient to pay the loan installment of approximately $2 million due to Global on March 31, 2003 and Panda Energy International, Inc. (Panda)/Teco Power Services (Teco) failed to fund the 50% of the partnership cash call due from them in support of the March 31, 2003 debt service payment. Consequently, the loan due to Global was in default and the interest rate increased to the default rate of 14%. If the default had continued, Global had the right to foreclose on Panda/Teco's 50% interest in TIE, which has been pledged to secure the loans due to Global. Global received the March 31, 2003 loan repayment, including interest, in June 2003, curing the default. For additional information relating to this loan, see Note 14. Related-Party Transactions of the Notes.

CAPITAL REQUIREMENTS

PSEG, PSE&G, Power and Energy Holdings

It is expected that the majority of PSE&G's, Power's and Energy Holdings' capital requirements will come from 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 presently expect to contribute additional equity to Energy Holdings.

PSE&G

During the ~~quarter~~six months ended ~~March 31~~June 30, 2003, PSE&G had net plant additions of $89229 million related to improvements in its transmission and distribution system, gas system and common facilities.

Power

During the ~~quarter~~six months ended ~~March 31~~June 30, 2003, Power made approximately $~~153~~330 million of capital expenditures, primarily related to developing the Lawrenceburg, Indiana, Waterford, Ohio and Bethlehem, NYNew York (Albany) sites and adding capacity to the Linden station in New Jersey.

Energy Holdings

During the quarter ended ~~March 31~~June 30, 2003, Energy Holdings made approximately $~~106~~169 million of capital expenditures, primarily related to equity investments in SAESA and ~~development~~the of Salalah, Oman and the GWF Energy Tracy plants.

AccountingACCOUNTING IssuesISSUES

SFAS No. 143, ''Accounting for Asset Retirement Obligations'' (SFAS 143)

PSEG, PSE&G, Power and Energy Holdings

Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company ~~shall~~is required to subsequently ~~allocate~~accrete that asset retirement cost to expense over its useful life. In periods subsequent to initial measurement, an entity ~~shall~~is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion will be charged to Operation and Maintenance expense on the Consolidated Statements of Operations, whereas changes due to the timing or amount of cash flows ~~shall~~will be an adjustment to the carrying amount of the related asset. See Note 3. Adoption of SFAS 143 of the Notes for additional information.

~~Emerging Issues Task Force (EITF) Issue No. 02-3, ''Accounting for Contracts Involved in Energy Trading and Risk Management Activities'' (EITF 02-3)~~67

Power

EITF 02-3 requires all gains and losses on energy trading derivatives to be reported on a net basis. Also, energy trading contracts that are not derivatives will no longer be marked to market. Instead, settlement accounting will be used. EITF 02-3 was effective October 25, 2002. Substantially all of Power's energy contracts qualify as derivatives under SFAS No. 133, ''Accounting for Derivative Instruments and Hedging Activities'' (SFAS 133) and will therefore continue to be marked to market. The impact of implementing these rules was not material to Power's results of operations.

Financial Interpretation (FIN) No. 46, ''Consolidation of Variable Interest Entities (VIE)'' (FIN 46)

PSEG, PSE&G, Power and Energy Holdings

FIN 46 ~~clarified~~clarifies the application of Accounting Research Bulletin No. 51, ''Consolidated Financial Statements'', to certain entities in which equity investors do not have the characteristics of a controlling financial interest. Because a controlling financial interest in an entity may be achieved through arrangements that do not involve voting interests, FIN 46 sets forth specific requirements with respect to consolidation, measurement and disclosure of such relationships. Disclosure requirements for existing qualifying entities are effective for financial statements issued after January 31, 2003. All enterprises with VIEs created after February 1, 2003, ~~shall~~are required to apply the provisions of FIN 46 no later than the beginning of the first interim period beginning after June 15, 2003. ~~The~~PSEG, ~~adoption~~PSE&G, ofPower and Energy ~~this~~Holdings ~~standard~~are isstill ~~not~~evaluating this guidance.

57SFAS No. 149, ''Amendment of Statement 133 on Derivative Instruments and Hedging Activities'' (SFAS 149)

expected to have a material impact on PSEG, PSE&G, Power and Energy Holdings' respective financial statements.

Additionally, SFAS 149 amends SFAS 133's criteria for electing the normal purchase and sale exception, which exempts certain derivatives that meet the normal purchase and sales criteria, from fair value reporting. The new guidance allows ''normal'' treatment for a power purchase or sale agreement (whether a forward, an option or combination of both) that is a capacity contract, as defined, even if the contract is closed out before maturity. However, any non-power commodity contract (e.g. gas contracts) and non-capacity power contract subject closed out before maturity will be ineligible for ''normal'' treatment and could result in those contracts being marked to market.

SFAS No. 150, ''Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity'' (SFAS 150)

PSEG and PSE&G

As of June 30, 2003, the following instruments are included with Preferred Securities on PSEG's and PSE&G's respective Consolidated Balance Sheets between Long-Term Debt and Common Equity.

	Shares Outstanding		As of June 30, 2003
			(Millions)
PSEG (Parent)
PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures
7.44%		9,000,000	$	225
Floating Rate		150,000		150
7.25%		6,000,000		150
8.75%		7,200,000		180
PSEG Participating Units 10.25%		9,200,000		460

Total PSEG (Parent)				1,165

PSE&G
PSE&G 8.00% Monthly Guaranteed Preferred Beneficial Interest in Subordinated Debentures		2,400,000		60
PSE&G Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's 8.125% Subordinated Debentures		3,800,000		95

Total PSE&G				155

Total PSEG Consolidated			$	1,320

Other

PSEG, PSE&G, Power and Energy Holdings

At the January 2003 EITF meeting, the Financial Accounting Standards Board (FASB) was requested to reconsider an interpretation of SFAS 133. The interpretation, which is contained in the Derivatives Implementation Group's C-11 guidance, relates to contracts that include broad market indices (e.g., CPI). That interpretation sets forth the guidelines under which the contract could qualify as a normal purchase or sale under SFAS 133. PSE&G, Power and Energy Holdings reevaluated their respective contracts and determined that there were no contracts impacted by this interpretation and accordingly there was no effect on the Consolidated Financial Statements. The FASB has agreed to reconsider the guidance under C-11. Although the ultimate outcome is uncertain, this potential change in guidance is not expected to have a material impact on PSEG, PSE&G, Power and Energy Holdings' respective financial statements.

Forward-Looking Statements

Except for the historical information contained herein, 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 ''will'', ''anticipate'', ''intend'', ''estimate'', ''believe'', ''expect'', ''plan'', ''hypothetical'', ''potential'', ''forecast'', ''projections'', variations of such words and similar expressions are intended to identify forward-looking statements. PSEG, PSE&G, Power and 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 of factors should not be construed as exhaustive.

PSEG, PSE&G, Power and Energy Holdings

• credit, commodity, interest rate, counterparty and other financial market risks; • liquidity and the ability to access capital and credit markets; • acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG's, PSE&G's, Power's and Energy Holdings' structure; • business combinations among competitors and major customers that could change the financial position, results of operations or net cash flows; • general economic conditions including inflation; • changes to accounting standards or generally accepted accounting principles, which may require adjustments to financial statements; • changes in tax laws and regulations which could affect cash flows and business prospects; • energy obligations, available supply and trading risks; • changes in the electric industry including changes to power pools; • regulation and availability of power transmission facilities that impact the ability to deliver output to customers; • growth in costs and expenses;

• environmental regulation that significantly impact operations; • changes in rates of return on overall debt and equity markets could have an adverse impact on the c value of pension assets and the Nuclear Decommissioning Trust Fund; • changes in political conditions, recession, acts of war or terrorism; • insufficient insurance coverage; • nvolvement in lawsuits including liability claims and commercial disputes could affect profits or the ability to sell and market products; • inability to attract and retain management and other key employees; • ability to service debt as a result of any of the aforementioned events; PSE&G and Energy Holdings • ability to obtain adequate and timely rate relief; • regulatory issues significantly impact operations; Power and Energy Holdings • adverse changes in the market place for energy prices; • excess supply due to overbuild in the industry; • generation operating performance may fall below projected levels; • substantial competition from well capitalized participants in the worldwide energy markets; • inability to effectively manage trading risk; • margin posting requirements; • availability of fuel at reasonable prices; • competitive position could be adversely affected by actions involving competitors or major customers; • changes in product or sourcing mix; • tardy or unsuccessful acquisition, construction and development; • changes in technology that make power generation assets less competitive; Power • changes in regulation and security measures at nuclear facilities; • determination by the BPU of the cost responsibility for nuclear decommissioning; Energy Holdings • adverse international developments that negatively impact its business; • changes in foreign currency exchange rates; • unavailability of leveraged lease investments with adequate returns at reasonable risk; • inadequate operating performance or legal protection of leveraged lease investments; • substandard operating performance or cash flow from investments could fall below projected levels, is adversely impacting the ability to service its debt; and • credit of lessees to service the leases.

prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each PSEG, PSE&G, Power and Energy Holdings expressly disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. In making any investment decision regarding PSEG, PSE&G, Power and Energy Holdings' securities, PSEG, PSE&G, Power and Energy Holdings is 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.

Item 3. Qualitative and Quantitative Disclosures About Market Risk

PSEG, PSE&G, Power and Energy Holdings

~~The~~In ~~market~~January ~~risk~~2001, ~~inherent in~~ PSEG's, PSE&G's, Power's and Energy Holdings' ~~market~~each ~~risk~~adopted ~~sensitive~~SFAS ~~instruments~~133. ~~and~~In ~~positions~~accordance iswith ~~the~~SFAS ~~potential~~133, ~~loss~~all ~~arising~~derivative ~~from~~instruments ~~adverse~~are ~~changes~~recognized inon ~~foreign~~the ~~currency~~balance ~~exchange~~sheet ~~rates,~~at ~~commodity~~their ~~prices,~~fair ~~equity~~values. ~~security~~In ~~prices~~relation ~~and~~to ~~interest~~this ~~rates~~standard, asthe ~~discussed~~Financial inAccounting ~~Note 7.~~Standards ~~Risk~~Board ~~Management~~(FASB) toDerivative ~~the~~Implementation ~~Notes~~Group to(DIG) ~~the~~issued ~~Consolidated~~certain ~~Financial~~interpretive ~~Statements. Each of PSEG~~guidance, ~~PSE&G,~~including ~~Power~~DIG ~~and~~Issue ~~Energy~~C-11 ~~Holdings'~~that ~~policy~~relates is to ~~use~~contracts ~~derivatives~~which toinclude ~~manage~~broad ~~risk~~market ~~consistent~~indices ~~with~~(e.g., ~~its~~Consumer ~~respective~~Price ~~business~~Index). ~~plans~~That ~~and~~interpretation ~~prudent~~sets ~~practices.~~forth ~~PSEG,~~the ~~PSE&G,~~guidelines ~~Power~~under ~~and~~which ~~Energy~~a ~~Holdings~~contract ~~use~~could qualify as a ~~Risk~~normal ~~Management~~purchase ~~Committee~~or ~~(RMC)~~sale ~~comprised~~under ofSFAS ~~executive~~133. ~~officers~~In ~~which~~2003, ~~utilize~~the anFASB ~~independent~~issued ~~risk~~DIG ~~oversight~~Issue ~~function~~C-20 to ~~ensure~~amend ~~compliance~~the ~~with~~previous ~~corporate~~interpretation ~~policies~~stating that the phrase ''not clearly and ~~prudent~~closely ~~risk~~related ~~management~~to ~~practices.~~the ~~Except~~asset asbeing ~~discussed~~sold ~~below,~~or ~~there~~purchased'' ~~were~~should ~~no material~~involve ~~changes~~an ~~from~~analysis ~~the~~of ~~disclosures~~both inqualitative ~~PSEG,~~and quantitative considerations. PSE&G, Power and Energy Holdings' ~~Annual~~have ~~Reports~~reviewed ontheir ~~Form 10-K~~respective ~~for~~contracts and each have determined that there will be no impact resulting from the ~~year~~adoption ~~ended~~of ~~December 31,~~this ~~2002~~interpretation.

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 Note 8. Risk Management of the Notes to the Consolidated Financial Statements. Each of PSEG, PSE&G, Power and Energy Holdings' policy is to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings use a Risk Management Committee (RMC) comprised of executive officers which utilize an independent risk oversight function

to ensure compliance with corporate policies and prudent risk management practices. Except as discussed below, there were no material changes from the disclosures in PSEG, PSE&G, Power and Energy Holdings' Annual Report on Form 10-K for the year ended December 31, 2002 or Quarterly Report on Form 10-Q for the quarter ended March 31, 2003.

Commodity Contracts

Power and Energy Holdings

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 and other events. To reduce price risk caused by market fluctuations, Power and Energy Holdings enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge their respective anticipated supply and demand differential. These contracts, in conjunction with owned electric generation capacity and demand obligations, make up the portfolio.

Power and Energy Holdings use a value-at-risk (VaR) model to assess the market risk of their respective commodity businesses. This model includes fixed price sales commitments, owned generation, load requirements, physical contracts 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 and Energy Holdings estimate VaR across their respective commodity businesses.

Power

~~VaR~~ The availability ~~Model~~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 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, to hedge its anticipated supply and demand differential. These contracts, in conjunction with owned electric generation capacity and demand obligations, make up the portfolio.

Power uses ~~manages~~a ~~its~~value-at-risk ~~exposure~~(VaR) atmodel to assess the ~~portfolio~~market ~~level~~risk of its commodity business. ~~Its~~The ~~portfolio~~model ~~consists~~for ofPower includes its owned generation, ~~load-serving~~and physical contracts, as ~~(both~~well ~~gas~~as fixed price sales requirements, load requirements and ~~electric)~~financial derivative instruments. VaR represents the potential gains or losses, ~~gas~~under ~~supply~~normal ~~contracts~~market conditions, ~~and~~for ~~energy~~instruments ~~derivatives~~or ~~designed~~portfolios due to ~~manage~~changes ~~the~~in ~~risk~~market ~~around~~factors, for ~~the~~a ~~differential~~specified ~~between~~time ~~generation~~period and ~~load~~confidence level. Power estimates VaR across its commodity business.

The RMC of PSEG established a VaR threshold of $50 million for a one-week (5 business days) holding period at a 95% (two-tailed) confidence level. The RMC will be notified if the VaR reaches $40 million and the portfolio will be closely monitored. The Board of Directors of PSEG is notified if a VaR threshold of $75 million is reached.Model

60 Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), gas supply contracts and energy derivatives designed to manage the risk around the differential between generation and load.

The ~~current~~RMC ~~modeling~~of ~~process~~PSEG ~~and~~established ~~methodology~~a ~~has~~VaR ~~previously~~threshold ~~been~~of ~~reviewed~~$50 bymillion for a ~~third~~one-week ~~party~~(5 ~~consulting~~business ~~firm.~~days) ~~This~~holding ~~review~~period ~~included~~at ~~analysis~~a ~~and~~95% ~~comparison~~(two-tailed) ofconfidence ~~Power's~~level. ~~current~~The ~~VaR~~RMC ~~process~~will ~~and~~be ~~methodology~~notified toif ~~other~~the ~~processes~~VaR ~~and~~reaches ~~methodologies~~$40 ~~used~~million inand the ~~energy~~portfolio ~~industry~~will be closely monitored. ~~PSEG~~The ~~believes~~Board ~~the~~of ~~evaluation~~Directors ~~indicates~~of ~~that~~PSEG ~~Power's~~is ~~methodology~~notified toif ~~calculate~~a VaR threshold of $75 million is ~~reasonable~~reached.

The ~~model~~current ismodeling anprocess ~~augmented~~and ~~variance/covariance~~methodology ~~model~~has ~~adjusted~~previously ~~for~~been ~~the~~reviewed ~~delta~~by ~~of positions with~~ a ~~95%~~third ~~two-tailed~~party ~~confidence~~consulting ~~level for a one-week holding period~~firm. ~~The~~This ~~model~~review isincluded ~~augmented~~analysis toand ~~incorporate~~comparison ~~the~~of ~~non~~Power's ~~log-normality~~current ofVaR ~~energy-related~~process ~~commodity~~and ~~prices,~~methodology ~~especially~~to ~~emissions~~other ~~and~~processes ~~capacity~~ and ~~the~~methodologies ~~non-stationary~~used ~~nature~~in ofthe energy ~~volatility~~industry. InPSEG ~~many~~believes ~~commodities~~ the ~~natural~~evaluation ~~log~~indicates ofthat ~~prices~~Power's ismethodology ~~normally~~to ~~distributed.~~calculate ~~This~~VaR is ~~not true of energy commodities which have a higher frequency of extreme events than would be predicted by a normal distribution~~reasonable. ~~The model also assumes no hedging activity throughout the holding period whereas Power actively manages its portfolio.~~

AsThe ofmodel ~~March 31,~~is ~~2003,~~an ~~VaR~~augmented ~~was~~variance/covariance ~~approximately~~model ~~$29~~adjusted ~~million,~~for ~~compared to~~ the ~~December 31,~~delta ~~2002, level~~ of $7positions ~~million.~~with ~~Previous~~a to95% ~~Power's~~two-tailed ~~obligation~~confidence ~~being~~level ~~determined by annual auctions, Power's load was considered an indefinite obligation; therefore,~~ for ~~consistency~~a ~~purposes~~one-week ~~Power~~holding ~~decided~~period. toThe model ~~both~~is ~~the~~augmented ~~cost~~ to ~~serve~~incorporate ~~its~~the ~~load~~non ~~obligation~~log-normality ~~and~~of ~~the~~energy-related ~~value~~commodity ofprices, ~~its~~especially ~~generation~~emissions ~~assets~~and oncapacity aand ~~rolling~~the 12non-~~month~~stationary ~~basis.~~nature Atof ~~present,~~energy ~~Power's~~volatility. ~~load~~In ~~obligation~~many iscommodities ~~determined by~~ the ~~results~~natural log of ~~the~~prices ~~annual~~is ~~BGS~~normally ~~auction~~distributed. ToThis ~~maintain~~is annot ~~actionable~~true ~~VaR,~~of ~~generation~~energy ~~and~~commodities ~~load~~which ~~(based~~have ona anhigher ~~assumed~~frequency ~~success~~of ~~rate~~extreme inevents ~~the~~than ~~auction)~~would ~~are~~be ~~both~~predicted ~~modeled~~by ata ~~100%~~normal ofdistribution. ~~their~~The ~~assumed~~model ~~value~~also ~~through~~assumes ~~May~~no ~~2004~~hedging ~~and~~activity atthroughout ~~one-third of~~ the ~~assumed~~holding ~~value~~period ofwhereas ~~each~~Power ~~from~~actively ~~June~~manages ~~2004~~its ~~through May 2006~~portfolio.

As of June 30, 2003, VaR was approximately $19 million, compared to the December 31, 2002, level of $7 million. At present, Power's load obligation is determined by the results of the annual BGS auction. To maintain an actionable VaR, ~~Associated~~generation ~~with~~and ~~Generating~~load ~~Assets~~(based on an assumed success rate in the auction) are both modeled at 100% of their assumed value through May 2004 and ~~Commodity~~at ~~Contracts~~one-third of the assumed value of each from June 2004 through May 2006.

For the Quarter Ended March 31, 2003	Total VAR
	(Millions)
95% Confidence Level, Five-Day Holding Period, Two-Tailed:
Period End	$	29
Average for the Period	$	21
High	$	34
Low	$	10
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End	$	17
Average for the Period	$	12
High	$	20
Low	$	6

Energy Holdings

For the Quarter Ended June 30, 2003	Total VaR
	(Millions)
95% Confidence Level, Five-Day Holding Period, Two-Tailed:
Period End	$	19
Average for the Period	$	23
High	$	31
Low	$	17
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End	$	11
Average for the Period	$	14
High	$	18
Low	$	10

VaR Model

For the Six Months Ended June 30, 2003	Total VaR
	(Millions)
95% Confidence Level, Five-Day Holding Period, Two-Tailed:
Period End	$	19
Average for the Period	$	22
High	$	35
Low	$	10
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End	$	11
Average for the Period	$	13
High	$	20
Low	$	6

In general, Energy Holdings manages its commodity exposure through power purchase agreements. One notable exception is its partial ownership of TIE, which owns two merchant energy plants that sell substantially all of their output in the day-ahead market.71

TheOther modelSupplemental isInformation aon variance/covariance model with a twoMark-tailed 95% confidence level for a oneto-weekMarket holding period. Expected energy output and fuel usage are modeled as forward obligations. The Electric Reliability Council of Texas (ERCOT) system is a closed system and is less liquid than Pennsylvania-New Jersey-Maryland Power Pool (PJM). This makes estimates of volatility and correlation less reliable.Activities

AsPSEG of March 31, 2003 and December 31, 2002, Energy Holdings' VaR was approximately $17 million and $4 million, respectively.Power

61 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.

EnergyNormal Holdings'Operations VaR Associated with Generating Assets and CommodityHedging ContractsActivities

For the Quarter Ended March 31, 2003	Total VAR
	(Millions)
95% Confidence Level, Five-Day Holding Period, Two-Tailed:
Period End	$	17
Average for the Period	$	11
High	$	25
Low	$	5
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End	$	10
Average for the Period	$	6
High	$	15
Low	$	3

Power enters into physical contracts, as well as derivative contracts, including forwards, futures, swaps and options designed to eliminate 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.

~~Item~~ Power's 4energy contracts are accounted for under SFAS 133. ~~Controls~~Most non-trading contracts qualify for the normal purchases and ~~Procedures~~normal sales exemption under SFAS 133. Changes in the fair value of qualifying hedge contracts are recorded in OCI, 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 on a current basis.

Trading

Power's objective for its trading activities is to produce net earnings from trading energy-related products around its owned electric generation assets, gas supply contracts and electric and gas supply obligations. These activities are marked-to-market in accordance with SFAS 133, with gains and losses recognized in earnings.

The following table describes the drivers of Power's energy trading and marketing activities and operating revenues included in its Consolidated Statements of Operations for the six months ended

June 30, 2003. 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, mark-to-market activities represent a small portion of the total Operating Revenues for Power. Accrual activities, including normal purchases and sales, account for the majority of the revenue. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices.

Operating Revenues
For the Quarter Ended June 30, 2003

Normal Operations and Hedging (A)

Trading

Total

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

FORM 10-Q

(Mark One)

FOR THE QUARTERLY PERIOD ENDED MARCHJUNE 3130, 2003

OR

FOR THE TRANSITION PERIOD FROM TO

TABLE OF CONTENTS

PARTFORWARD-LOOKING I FINANCIAL INFORMATIONSTATEMENTS

PSEG, PSE&G, Power and Energy Holdings

PSE&G and Energy Holdings

Power and Energy Holdings

Power

Energy Holdings

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF OPERATIONS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED BALANCE SHEETS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED BALANCE SHEETS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF CASH FLOWS

PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS

PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED BALANCE SHEETS

PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED BALANCE SHEETS

PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS

PSEG POWER LLC CONSOLIDATED STATEMENTS OF OPERATIONS

PSEG POWER LLC CONSOLIDATED BALANCE SHEETS

PSEG POWER LLC CONSOLIDATED STATEMENTS OF CASH FLOWS

PSEG ENERGY HOLDINGS LLC CONSOLIDATED STATEMENTS OF OPERATIONS

PSEG ENERGY HOLDINGS LLC CONSOLIDATED BALANCE SHEETS

PSEG ENERGY HOLDINGS LLC CONSOLIDATED BALANCE SHEETS

PSEG ENERGY HOLDINGS LLC CONSOLIDATED STATEMENTS OF CASH FLOWS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UnauditedUNAUDITED)

Note 1. Organization and Basis of Presentation

Organization

PSEG

PSE&G

Power

Energy Holdings

Basis of Presentation

Note 2. New Accounting Standards

Statement of Financial Accounting Standards (SFAS) No. 142, ''Goodwill and Other Intangible Assets'' (SFAS 142)

PSEG, PSE&G, Power and Energy Holdings

PSE&G

Power

Energy Holdings

Power and Energy Holdings

SFAS No. 143, ''Accounting for Asset Retirement Obligations'' (SFAS 143)

PSEG, PSE&G, Power and Energy Holdings

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Emerging Issues Task Force (EITF) Issue No. 02-3, ''Accounting for Contracts Involved in Energy Trading and Risk Management Activities'' (EITF 02-3)

PSEG and Power

Financial Interpretation (FIN) No. 46, ''Consolidation of Variable Interest Entities (VIE)'' (FIN 46)

PSEG, PSE&G, Power and Energy Holdings

SFAS No. 149, ''Amendment of Statement 133 on Derivative Instruments and Hedging Activities'' (SFAS 149)

PSEG, PSE&G, Power and Energy Holdings

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

SFAS No. 150, ''Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity'' (SFAS 150)

PSEG and PSE&G

Other

PSEG, PSE&G, Power and Energy Holdings

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 3. Adoption of SFAS 143

PSEG, PSE&G and Power

20NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

PSE&G

Energy Holdings

Effect on the NDT Fund

Power

Note 4. Discontinued OperationsPSEG

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 5. Discontinued Operations

Energy Holdings

Energy Technologies' Investments

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Tanir Bavi Power Company Ltd. (Tanir Bavi)

Old Dominion Electric Cooperative (ODEC)

23PSEG and PSE&G

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 7. Commitments and Contingent Liabilities

Guaranteed Obligations

Power

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

PART I.
FINANCIAL INFORMATION

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS

PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS

PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS

PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS

PSEG ENERGY HOLDINGS LLC
CONSOLIDATED STATEMENTS OF OPERATIONS

PSEG ENERGY HOLDINGS LLC
CONSOLIDATED BALANCE SHEETS

PSEG ENERGY HOLDINGS LLC
CONSOLIDATED BALANCE SHEETS

PSEG ENERGY HOLDINGS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS

Filing Compare · PSEG ENERGY HOLDINGS LLC