Edgar Filing: PUBLIC SERVICE ENTERPRISE GROUP INC

3B2 EDGAR HTML -- c49586.htm

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

FORM 10-Q

(Mark One)

S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2007
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO


Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza, P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com	22-2625848
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza, P.O. Box 570 Newark, New Jersey 07101-0570 973 430-7000 http://www.pseg.com	22-1212800
000-49614	PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza—T25 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com	22-3663480
000-32503	PSEG ENERGY HOLDINGS L.L.C. (A New Jersey Limited Liability Company) 80 Park Plaza—T20 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com	42-1544079

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

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


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

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

As of July 27, 2007, Public Service Enterprise Group Incorporated had outstanding 254,283,335 shares of its sole class of Common Stock, without par value.

As of July 27, 2007, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.

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

TABLE OF CONTENTS


		Page

FORWARD-LOOKING STATEMENTS			ii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated		1
	Public Service Electric and Gas Company		5
	PSEG Power LLC		9
	PSEG Energy Holdings L.L.C.		13
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation		17
	Note 2. Recent Accounting Standards		18
	Note 3. Discontinued Operations, Dispositions and Impairments		21
	Note 4. Earnings Per Share		24
	Note 5. Commitments and Contingent Liabilities		24
	Note 6. Financial Risk Management Activities		35
	Note 7. Comprehensive Income (Loss), Net of Tax		37
	Note 8. Changes in Capitalization		38
	Note 9. Other Income and Deductions		39
	Note 10. Pension and Other Postretirement Benefits (OPEB)		41
	Note 11. Income Taxes		42
	Note 12. Financial Information by Business Segments		44
	Note 13. Related-Party Transactions		45
	Note 14. Guarantees of Debt		47
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)		50
	Overview of 2007 and Future Outlook		50
	Results of Operations		55
	Liquidity and Capital Resources		64
	Capital Requirements		69
	Accounting Matters		70
Item 3.	Qualitative and Quantitative Disclosures About Market Risk		70
Item 4.	Controls and Procedures		76
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		77
Item 1A.	Risk Factors		78
Item 5.	Other Information		79
Item 6.	Exhibits		85
	Signatures		86

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings) undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The following review should not be construed as a complete list of factors that could affect forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

•

changes in energy policies and regulation, including market rules;

•

ability to attain satisfactory regulatory results;

•

ability to maintain operating performance and cash flow from investments at projected levels;

•

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

•

continued market based rate authority, including any necessary mitigation measures;

•

energy transmission constraints or lack thereof and the availability of transmission facilities;

•

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

•

changes in the electric industry, including changes to regional transmission organizations and power pools;

•

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

•

adverse or unanticipated weather conditions that significantly impact costs and/or operations;

•

environmental regulations that significantly impact operations;

•

governmental and industry responses to global climate change;

•

changes in demand including the effects of conservation efforts and energy efficiency;

•

timing and success of efforts to develop generation, transmission and distribution projects;

•

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

•

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

•

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

•

effectiveness of risk management and internal control systems;

•

ability to realize tax benefits and favorably resolve tax audit claims;

•

ability to attract and retain management and other key employees;

•

changes in political conditions;

•

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

•

continued availability of insurance coverage at commercially reasonable rates;

•

involvement in lawsuits, including liability claims and commercial disputes;

•

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

•

general economic conditions, including inflation or deflation;

•

changes in tax laws and regulations;

•

substantial competition in the domestic and worldwide energy markets;

•

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

•

availability of fuel and timely transportation at reasonable prices;

•

delays, cost escalations or unsuccessful construction and development;

•

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

•

changes in foreign currency exchange rates;

•

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

•

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

•

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

•

acts of war or terrorism.

Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, PSEG, PSE&G, Power and Energy Holdings or their respective business prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and Energy Holdings expressly disclaims any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. In making any investment decision regarding PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities, PSEG, PSE&G, Power and Energy Holdings are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

iii

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Quarters Ended June 30,								For the Six Months Ended June 30,
	2007				2006				2007				2006
	(Millions) (Unaudited)
OPERATING REVENUES		$	2,810			$	2,542			$	6,413			$	5,989
OPERATING EXPENSES
Energy Costs			1,389				1,338				3,427				3,483
Operation and Maintenance			592				576				1,198				1,149
Write-down of Project Investments			—				263				—				263
Depreciation and Amortization			195				201				390				401
Taxes Other Than Income Taxes			30				27				73				68

Total Operating Expenses			2,206				2,405				5,088				5,364

Income from Equity Method Investments			27				30				53				63

OPERATING INCOME			631				167				1,378				688
Other Income			58				51				129				101
Other Deductions			(37	)			(16	)			(73	)			(43	)
Interest Expense			(184	)			(197	)			(369	)			(388	)
Preferred Stock Dividends			(1	)			(1	)			(2	)			(2	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			467				4				1,063				356
Income Tax Expense			(174	)			(12	)			(436	)			(159	)

INCOME (LOSS) FROM CONTINUING OPERATIONS			293				(8	)			627				197
(Loss) Income from Discontinued Operations, including Gain on Disposal, net of tax benefit (expense) of $22, ($137), $27, and ($133) for the quarters and six months ended 2007 and 2006, respectively			(18	)			217				(23	)			215

NET INCOME		$	275			$	209			$	604			$	412

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC			253,631				251,474				253,263				251,331

DILUTED			254,034				252,084				253,697				252,075

EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS		$	1.16			$	(0.03	)		$	2.48			$	0.79
NET INCOME		$	1.09			$	0.83			$	2.39			$	1.64

DILUTED
INCOME FROM CONTINUING OPERATIONS		$	1.15			$	(0.03	)		$	2.47			$	0.79
NET INCOME		$	1.08			$	0.83			$	2.38			$	1.64

DIVIDENDS PAID PER SHARE OF COMMON STOCK		$	0.585			$	0.57			$	1.17			$	1.14

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2007				December 31, 2006
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	170			$	125
Accounts Receivable, net of allowances of $59 and $52 in 2007 and 2006, respectively			1,588				1,359
Unbilled Revenues			260				328
Fuel			670				847
Materials and Supplies			312				290
Prepayments			404				72
Restricted Funds			52				79
Derivative Contracts			59				128
Assets of Discontinued Operations			299				622
Assets Held for Sale			—				40
Other			83				45

Total Current Assets			3,897				3,935

PROPERTY, PLANT AND EQUIPMENT			19,346				18,698
Less: Accumulated Depreciation and Amortization			(6,067	)			(5,831	)

Net Property, Plant and Equipment			13,279				12,867

NONCURRENT ASSETS
Regulatory Assets			5,238				5,694
Long-Term Investments			3,836				3,868
Nuclear Decommissioning Trust (NDT) Funds			1,311				1,256
Other Special Funds			155				147
Goodwill			410				406
Intangibles			52				46
Derivative Contracts			20				55
Other			260				296

Total Noncurrent Assets			11,282				11,768

TOTAL ASSETS		$	28,458			$	28,570

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2007				December 31, 2006
	(Millions) (Unaudited)
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	1,010			$	849
Commercial Paper and Loans			345				381
Accounts Payable			1,022				960
Derivative Contracts			399				335
Accrued Interest			127				123
Accrued Taxes			104				149
Clean Energy Program			128				120
Liabilities of Discontinued Operations			133				134
Other			431				480

Total Current Liabilities			3,699				3,531

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)			4,223				4,447
Regulatory Liabilities			410				646
Asset Retirement Obligations			527				509
Other Postretirement Benefit (OPEB) Costs			1,093				1,089
Accrued Pension Costs			333				327
Clean Energy Program			73				133
Environmental Costs			403				421
Derivative Contracts			234				204
Long-Term Accrued Taxes			519				—
Other			154				170

Total Noncurrent Liabilities			7,969				7,946

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt			7,404				7,636
Securitization Debt			1,626				1,708
Project Level, Non-Recourse Debt			647				735
Debt Supporting Trust Preferred Securities			186				186

Total Long-Term Debt			9,863				10,265

SUBSIDIARIES’ PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2007 and 2006—795,234 shares			80				80

COMMON STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1 billion shares; issued; 2007—266,759,842 shares; 2006—266,372,440 shares			4,710				4,661
Treasury Stock, at cost; 2007—12,692,586 shares; 2006—13,727,032 shares			(479	)			(516	)
Retained Earnings			2,829				2,711
Accumulated Other Comprehensive Loss			(213	)			(108	)

Total Common Stockholders’ Equity			6,847				6,748

Total Capitalization			16,790				17,093

TOTAL LIABILITIES AND CAPITALIZATION		$	28,458			$	28,570

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For The Six Months Ended June 30,
	2007				2006
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	604			$	412
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations, net of tax			—				(228	)
Depreciation and Amortization			392				411
Amortization of Nuclear Fuel			48				48
Provision for Deferred Income Taxes (Other than Leases) and ITC			124				(11	)
Non-Cash Employee Benefit Plan Costs			93				117
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes			5				(3	)
(Gain) Loss on Sale of Investments			(14	)			255
Equity in Earnings of Affiliates Less than Dividends Received			14				(36	)
Foreign Currency Transaction Loss			2				2
Unrealized Losses (Gains) on Energy Contracts and Other Derivatives			19				(22	)
(Under) Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs			(74	)			45
Under Recovery of Societal Benefits Charge (SBC)			(17	)			(69	)
Cost of Removal			(18	)			(17	)
Net Realized Gains and Income from NDT Funds			(30	)			(36	)
Other Non-Cash Charges			3				3
Employee Benefit Plan Funding and Related Payments			(39	)			(49	)
Investment Income and Dividend Distributions from Partnerships			11				7
Net Change in Working Capital			(278	)			7
Other			(49	)			(38	)

Net Cash Provided By Operating Activities			796				798

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(659	)			(473	)
Proceeds from Sale of Discontinued Operations			325				494
Proceeds from Sale of Property, Plant and Equipment			40				—
Proceeds from the Sale of Investments and Return of Capital from Partnerships			7				187
Proceeds from NDT Funds Sales			883				720
Investment in NDT Funds			(904	)			(726	)
Restricted Funds			22				—
NDT Funds Interest and Dividends			25				19
Other			—				8

Net Cash (Used In) Provided By Investing Activities			(261	)			229

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans			(36	)			470
Issuance of Long-Term Debt			350				—
Issuance of Common Stock			68				34
Redemption of Long-Term Debt			(488	)			(1,131	)
Repayment of Non-Recourse Debt			(24	)			(25	)
Redemption of Securitization Debt			(78	)			(74	)
Redemption of Debt Underlying Trust Securities			—				(154	)
Cash Dividends Paid on Common Stock			(296	)			(286	)
Other			14				(21	)

Net Cash Used In Financing Activities			(490	)			(1,187	)

Effect of Exchange Rate Change			—				(2	)

Net Increase (Decrease) in Cash and Cash Equivalents			45				(162	)
Cash and Cash Equivalents at Beginning of Period			125				281

Cash and Cash Equivalents at End of Period		$	170			$	119

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	220			$	196
Interest Paid, Net of Amounts Capitalized		$	356			$	371

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For The Quarters Ended June 30,								For The Six Months Ended June 30,
	2007				2006				2007				2006
	(Millions) (Unaudited)
OPERATING REVENUES		$	1,748			$	1,490			$	4,234			$	3,783
OPERATING EXPENSES
Energy Costs			1,077				901				2,742				2,475
Operation and Maintenance			314				276				639				577
Depreciation and Amortization			143				150				288				302
Taxes Other Than Income Taxes			30				27				73				68

Total Operating Expenses			1,564				1,354				3,742				3,422

OPERATING INCOME			184				136				492				361
Other Income			5				8				10				12
Other Deductions			(1	)			(1	)			(2	)			(2	)
Interest Expense			(84	)			(83	)			(165	)			(168	)

INCOME BEFORE INCOME TAXES			104				60				335				203
Income Tax Expense			(41	)			(26	)			(140	)			(91	)

NET INCOME			63				34				195				112
Preferred Stock Dividends			(1	)			(1	)			(2	)			(2	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	62			$	33			$	193			$	110

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2007				December 31, 2006
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	33			$	28
Accounts Receivable, net of allowances of $54 in 2007 and $46 in 2006			861				805
Unbilled Revenues			260				328
Materials and Supplies			62				50
Prepayments			339				14
Restricted Funds			7				12
Derivative Contracts			1				2
Other			41				36

Total Current Assets			1,604				1,275

PROPERTY, PLANT AND EQUIPMENT			11,364				11,061
Less: Accumulated Depreciation and Amortization			(3,913	)			(3,794	)

Net Property, Plant and Equipment			7,451				7,267

NONCURRENT ASSETS
Regulatory Assets			5,238				5,694
Long-Term Investments			150				149
Other Special Funds			55				53
Other			116				115

Total Noncurrent Assets			5,559				6,011

TOTAL ASSETS		$	14,614			$	14,553

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2007			December 31, 2006
	(Millions) (Unaudited)
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	175		$	284
Commercial Paper and Loans			295			31
Accounts Payable			353			254
Accounts Payable—Affiliated Companies, net			338			645
Accrued Interest			55			55
Clean Energy Program			128			120
Derivative Contracts			11			2
Other			288			322

Total Current Liabilities			1,643			1,713

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC			2,428			2,517
Other Postretirement Benefit (OPEB) Costs			897			898
Accrued Pension Costs			133			133
Regulatory Liabilities			410			646
Clean Energy Program			73			133
Environmental Costs			350			367
Asset Retirement Obligations			227			221
Derivative Contracts			26			18
Long-Term Accrued Taxes due to Affiliate			59			—
Other			7			6

Total Noncurrent Liabilities			4,610			4,939

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt			3,352			3,003
Securitization Debt			1,626			1,708

Total Long-Term Debt			4,978			4,711

PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2007 and 2006—795,234 shares			80			80

COMMON STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding			892			892
Contributed Capital			170			170
Basis Adjustment			986			986
Retained Earnings			1,254			1,061
Accumulated Other Comprehensive Income			1			1

Total Common Stockholder’s Equity			3,303			3,110

Total Capitalization			8,361			7,901

TOTAL LIABILITIES AND CAPITALIZATION		$	14,614		$	14,553

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

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


	For The Six Months Ended June 30,
	2007				2006
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	195			$	112
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization			288				302
Provision for Deferred Income Taxes and ITC			(32	)			(39	)
Non-Cash Employee Benefit Plan Costs			70				83
Non-Cash Interest Expense			4				1
Employee Benefit Plan Funding and Related Payments			(30	)			(27	)
Over Recovery of Electric Energy Costs (BGS and NTC)			(23	)			—
(Under) Over Recovery of Gas Costs			(51	)			45
Under Recovery of SBC			(17	)			(69	)
Cost of Removal			(18	)			(17	)
Other Non-Cash Charges			(1	)			(2	)
Net Change in Working Capital:
Accounts Receivable and Unbilled Revenues			12				368
Materials and Supplies			(12	)			(4	)
Prepayments			(328	)			(249	)
Accrued Taxes			—				(25	)
Accrued Interest			—				(5	)
Accounts Payable			99				39
Accounts Receivable/Payable-Affiliated Companies, net			(172	)			(315	)
Other Current Assets and Liabilities			(35	)			(77	)
Other			(66	)			11

Net Cash (Used In) Provided By Operating Activities			(117	)			132

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(296	)			(259	)

Net Cash Used In Investing Activities			(296	)			(259	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt			264				391
Issuance of Long-Term Debt			350				—
Redemption of Securitization Debt			(78	)			(74	)
Redemption of Long-Term Debt			(113	)			(322	)
Deferred Issuance Costs			(3	)			—
Preferred Stock Dividends			(2	)			(2	)

Net Cash Provided by (Used In) Financing Activities			418				(7	)

Net Increase (Decrease) In Cash and Cash Equivalents			5				(134	)
Cash and Cash Equivalents at Beginning of Period			28				159

Cash and Cash Equivalents at End of Period		$	33			$	25

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	203			$	112
Interest Paid, Net of Amounts Capitalized		$	157			$	160

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

PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	For The Quarters Ended June 30,								For The Six Months Ended June 30,
	2007				2006				2007				2006
	(Millions) (Unaudited)
OPERATING REVENUES		$	1,305			$	1,129			$	3,454			$	3,096
OPERATING EXPENSES
Energy Costs			694				669				2,182				2,156
Operation and Maintenance			241				262				479				494
Depreciation and Amortization			34				36				68				67

Total Operating Expenses			969				967				2,729				2,717

OPERATING INCOME			336				162				725				379
Other Income			55				34				106				75
Other Deductions			(34	)			(14	)			(63	)			(33	)
Interest Expense			(39	)			(36	)			(76	)			(68	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES			318				146				692				353
Income Tax Expense			(131	)			(61	)			(286	)			(147	)

INCOME FROM CONTINUING OPERATIONS			187				85				406				206
Loss from Discontinued Operations, net of tax benefit of $1, $6, $6 and $12 for the quarters and six months ended 2007 and 2006, respectively			(3	)			(8	)			(9	)			(17	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	184			$	77			$	397			$	189

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

PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2007				December 31, 2006
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	6			$	13
Accounts Receivable			606				430
Accounts Receivable—Affiliated Companies, net			238				495
Short-Term Loan to Affiliate			214				—
Fuel			666				846
Materials and Supplies			213				202
Energy Trading Contracts			29				55
Derivative Contracts			2				56
Assets of Discontinued Operations			—				325
Assets Held for Sale			—				40
Other			21				26

Total Current Assets			1,995				2,488

PROPERTY, PLANT AND EQUIPMENT			6,158				5,868
Less: Accumulated Depreciation and Amortization			(1,728	)			(1,638	)

Net Property, Plant and Equipment			4,430				4,230

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds			1,311				1,256
Goodwill			16				16
Other Intangibles			38				35
Other Special Funds			43				42
Energy Trading Contracts			9				10
Derivative Contracts			1				19
Other			62				50

Total Noncurrent Assets			1,480				1,428

TOTAL ASSETS		$	7,905			$	8,146

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

PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2007				December 31, 2006
	(Millions) (Unaudited)
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts Payable		$	544			$	589
Short-Term Loan from Affiliate			—				54
Energy Trading Contracts			120				222
Derivative Contracts			246				90
Accrued Interest			34				34
Other			78				95

Total Current Liabilities			1,022				1,084

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)			126				48
Asset Retirement Obligations			298				287
Other Postretirement Benefit (OPEB) Costs			141				138
Accrued Pension Costs			107				106
Energy Trading Contracts			6				19
Derivative Contracts			189				151
Environmental Costs			53				54
Long-Term Accrued Taxes due to Affiliate			26				—
Other			13				18

Total Noncurrent Liabilities			959				821

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
LONG-TERM DEBT
Total Long-Term Debt			2,818				2,818

MEMBER’S EQUITY
Contributed Capital			2,000				2,000
Basis Adjustment			(986	)			(986	)
Retained Earnings			2,394				2,586
Accumulated Other Comprehensive Loss			(302	)			(177	)

Total Member’s Equity			3,106				3,423

TOTAL LIABILITIES AND MEMBER’S EQUITY		$	7,905			$	8,146

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

PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	For The Six Months Ended June 30,
	2007				2006
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	397			$	189
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization			68				75
Amortization of Nuclear Fuel			48				48
Interest Accretion on Asset Retirement Obligations			11				16
Provision for Deferred Income Taxes and ITC			174				38
Unrealized Losses (Gains) on Energy Contracts and Other Derivatives			16				(23	)
Non-Cash Employee Benefit Plan Costs			14				22
Net Realized Gains and Income from NDT Funds			(30	)			(36	)
Net Change in Working Capital:
Fuel, Materials and Supplies			169				164
Accounts Receivable			(176	)			279
Accrued Interest			—				(7	)
Accounts Payable			(40	)			(301	)
Accounts Receivable/Payable—Affiliated Companies, net			147				290
Other Current Assets and Liabilities			(12	)			47
Employee Benefit Plan Funding and Related Payments			(4	)			(18	)
Other			12				(62	)

Net Cash Provided By Operating Activities			794				721

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(323	)			(193	)
Proceeds from Sale of Discontinued Operations			325				—
Sales of Property, Plant and Equipment			40				—
Proceeds from NDT Funds Sales			883				720
NDT Funds Interest and Dividends			25				19
Investment in NDT Funds			(904	)			(726	)
Short-Term Loan—Affiliated Company, net			(214	)			—
Other			(4	)			13

Net Cash Used In Investing Activities			(172	)			(167	)

CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid			(575	)			—
Redemption of Long-term Debt			—				(500	)
Short-Term Loan—Affiliated Company, net			(54	)			(57	)

Net Cash Used In Financing Activities			(629	)			(557	)

Net Decrease in Cash and Cash Equivalents			(7	)			(3	)
Cash and Cash Equivalents at Beginning of Period			13				8

Cash and Cash Equivalents at End of Period		$	6			$	5

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid		$	74			$	79
Interest Paid, Net of Amounts Capitalized		$	84			$	83

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

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


	For The Quarters Ended June 30,								For The Six Months Ended June 30,
	2007				2006				2007				2006
	(Millions) (Unaudited)
OPERATING REVENUES
Electric Generation and Distribution Revenues		$	302			$	304			$	492			$	553
Income from Leveraged and Operating Leases			32				38				65				77
Other			5				11				25				21

Total Operating Revenues			339				353				582				651

OPERATING EXPENSES
Energy Costs			200				193				358				386
Operation and Maintenance			44				47				93				91
Write-down of Project Investments			—				263				—				263
Depreciation and Amortization			15				11				28				22

Total Operating Expenses			259				514				479				762

Income from Equity Method Investments			27				30				53				63

OPERATING INCOME (LOSS)			107				(131	)			156				(48	)
Other Income			3				10				18				17
Other Deductions			(3	)			—				(4	)			(7	)
Interest Expense			(39	)			(49	)			(80	)			(97	)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST			68				(170	)			90				(135	)
Income Tax (Expense) Benefit			(11	)			64				(31	)			54
Minority Interests in Earnings of Subsidiaries			2				(1	)			2				(1	)

INCOME (LOSS) FROM CONTINUING OPERATIONS			59				(107	)			61				(82	)
(Loss) Income from Discontinued Operations, net of tax benefit (expense) of $21, ($1), $21 and ($3) for the quarters and six months ended 2007 and 2006, respectively			(15	)			(3	)			(14	)			4
Gain on Disposal of Discontinued Operations, net of tax expense of $142 for the quarter and six months ended 2006			—				228				—				228

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED		$	44			$	118			$	47			$	150

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

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


	June 30, 2007				December 31, 2006
	(Millions) (Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents		$	65			$	83
Accounts Receivable:
Trade—net of allowances of $5 and $6 in 2007 and 2006, respectively			109				95
Other Accounts Receivable			11				28
Affiliated Companies			1				—
Notes Receivable:
Affiliated Companies			30				28
Other			38				—
Inventory			39				39
Restricted Funds			45				67
Assets of Discontinued Operations			299				297
Derivative Contracts			27				14
Other			6				9

Total Current Assets			670				660

PROPERTY, PLANT AND EQUIPMENT			1,597				1,553
Less: Accumulated Depreciation and Amortization			(307	)			(288	)

Net Property, Plant and Equipment			1,290				1,265

NONCURRENT ASSETS
Leveraged Leases, net			2,777				2,810
Corporate Joint Ventures and Partnership Interests			861				868
Goodwill			394				390
Other Intangibles			13				11
Derivative Contracts			10				26
Other			97				134

Total Noncurrent Assets			4,152				4,239

TOTAL ASSETS		$	6,112			$	6,164

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

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


	June 30, 2007			December 31, 2006
	(Millions) (Unaudited)
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		$	312		$	42
Accounts Payable:
Trade			69			52
Affiliated Companies			11			12
Derivative Contracts			18			16
Accrued Interest			26			26
Liabilities of Discontinued Operations			133			134
Other			59			66

Total Current Liabilities			628			348

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment and Energy Tax Credits			1,701			1,910
Derivative Contracts			9			11
Long-Term Accrued Taxes due to Affiliate			434			—
Other			94			97

Total Noncurrent Liabilities			2,238			2,018

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5)
MINORITY INTERESTS			25			26

LONG-TERM DEBT
Project Level, Non-Recourse Debt			647			735
Senior Notes			942			1,149

Total Long-Term Debt			1,589			1,884

MEMBER’S EQUITY
Ordinary Unit			1,047			1,193
Retained Earnings			463			592
Accumulated Other Comprehensive Income			122			103

Total Member’s Equity			1,632			1,888

TOTAL LIABILITIES AND MEMBER’S EQUITY		$	6,112		$	6,164

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

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


	For The Six Months Ended June 30,
	2007				2006
	(Millions) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income		$	47			$	150
Adjustments to Reconcile Net Income to Net Cash Flows from
Operating Activities:
Depreciation and Amortization			29				24
Demand Side Management Amortization			1				2
Deferred Income Taxes (Other than Leases)			(14	)			(9	)
Leveraged Lease Income, Adjusted for Rents Received and
Deferred Income Taxes			5				(3	)
Equity in Earnings of Affiliates Less than Dividends Received			14				(36	)
(Gain) Loss on Sale of Investments			(14	)			255
Gain on Sale of Discontinued Operations			—				(228	)
Unrealized Gain on Investments			(3	)			(1	)
Foreign Currency Transaction Loss			2				2
Change in Fair Value of Derivative Financial Instruments			3				1
Other Non-Cash Charges			(1	)			2
Net Changes in Working Capital:
Accounts Receivable			(18	)			2
Inventory			3				(3	)
Accounts Payable			8				(11	)
Accounts Receivable/Payable-Affiliated Companies, net			82				(110	)
Other Current Assets and Liabilities			(5	)			(38	)
Investment Income and Dividend Distributions from Partnerships			11				7
Other			1				2

Net Cash Provided By Operating Activities			151				8

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment			(29	)			(20	)
Proceeds from Sale of Discontinued Operations			—				494
Proceeds from the Sale of Investments			7				187
Proceeds from Sale of Other Assets			2				1
Short-Term Loan Receivable—Affiliated Company, net			(3	)			(299	)
Restricted Funds			22				(3	)
Other			2				(8	)

Net Cash Provided By Investing Activities			1				352

CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of Non-Recourse Long-Term Debt			(24	)			(25	)
Repayment of Senior Notes			—				(309	)
Return of Contributed Capital			(145	)			—
Other			(1	)			(1	)

Net Cash Used In Financing Activities			(170	)			(335	)

Effect of Exchange Rate Change			—				(2	)

Net (Decrease) Increase In Cash and Cash Equivalents			(18	)			23
Cash and Cash Equivalents at Beginning of Period			83				61

Cash and Cash Equivalents at End of Period		$	65			$	84

Supplemental Disclosure of Cash Flow Information:
Income Taxes Received		$	(59	)		$	(14	)
Interest Paid, Net of Amounts Capitalized		$	79			$	78

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no representations as to any other company.

Note 1. Organization and Basis of Presentation

Organization

PSEG

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

PSE&G

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

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

Power

Power is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management function through three principal direct wholly owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Nuclear and Fossil own and operate generation and generation-related facilities. ER&T is responsible for the day-to-day management of Power’s portfolio. Fossil, Nuclear and ER&T are subject to regulation by FERC, and certain Fossil subsidiaries are also subject to state regulation. Nuclear is also subject to regulation by the Nuclear Regulatory Commission (NRC).

Energy Holdings

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

Services

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Basis of Presentation

PSEG, PSE&G, Power and Energy Holdings

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective Annual Reports on Form 10-K for the year ended December 31, 2006 and Quarterly Reports on Form 10-Q and Form 10-Q/A for the quarter ended March 31, 2007.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2006.

Reclassifications

PSEG, PSE&G, Power and Energy Holdings

Certain reclassifications have been made to the prior quarter financial statements to conform to the current quarter presentation. The reclassifications relate primarily to PSE&G’s determination, during the fourth quarter of 2006, that the revenues and expenses related to one of its contracts that had been recorded on a gross basis would more appropriately be recorded on a net basis in Operating Revenues based upon the provisions of Emerging Issues Task Force (EITF) 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Therefore, prior amounts have been reclassified, resulting in reductions of $44 million and $101 million in both Operating Revenues and Energy Costs for the quarter and six months ended June 30, 2006, respectively, for PSEG and PSE&G, with no impact on Operating Income.

Note 2. Recent Accounting Standards

The following accounting standards were issued by the Financial Accounting Standards Board (FASB), but have not yet been adopted by PSEG, PSE&G, Power and Energy Holdings.

Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS 157)

PSEG, PSE&G, Power and Energy Holdings

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

This statement also nullifies the guidance in footnote 3 of EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). The guidance in footnote 3 applies to derivative instruments measured at fair value at initial recognition, and it precludes immediate recognition in earnings of an unrealized gain or loss, measured as the difference between the transaction price and the fair value of the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

instrument at initial recognition, if the fair value of the instrument is determined using significant unobservable inputs. Under EITF 02-3, an entity cannot recognize an unrealized gain or loss at inception of a derivative instrument unless the fair value of that instrument is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable current market transactions or based on a valuation technique incorporating observable market data. SFAS 157 requires that the principles of fair value measurement apply for derivatives and other financial instruments at initial recognition and in all subsequent periods.

SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. PSEG, PSE&G, Power and Energy Holdings are currently assessing the potential impact of SFAS 157 on their respective consolidated financial positions and results of operations.

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

PSEG, PSE&G, Power and Energy Holdings

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

The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and (b) between assets and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities.

SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative effect adjustment to the opening balance of Retained Earnings. PSEG, PSE&G, Power and Energy Holdings are currently assessing the potential impact of SFAS 159 on their respective consolidated financial positions and results of operations.

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

PSEG and Power

In April 2007, the FASB issued FSP 39-1, which permits an entity to offset cash collateral paid or received against fair value amounts recognized for derivative instruments held with the same counterparty under the same master netting arrangement. Currently, PSEG and Power offset derivative contracts under master netting arrangements in accordance with FIN 39, “Offsetting of Amounts Related to Certain Contracts,” but do not net these balances with cash collateral positions. Under this FSP, PSEG and Power would be required to net cash collateral with the corresponding net derivative balance or elect to show all fair values gross.

FSP 39-1 is effective for fiscal years beginning after November 15, 2007 and must be applied retroactively to all financial statements presented, unless it is impracticable to do so. PSEG and Power are currently evaluating the potential impact of FSP 39-1 on their respective financial positions. PSEG and Power expect no impact to their respective results of operations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The following new accounting standards were adopted by PSEG, PSE&G, Power and Energy Holdings during 2007.

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48)

PSEG, PSE&G, Power and Energy Holdings

In July 2006, the FASB issued FIN 48, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return. Under FIN 48, the financial statements reflect expected future tax consequences of such positions presuming the tax authorities’ full knowledge of the position and all relevant facts. FIN 48 permits recognition of the benefit of tax positions only when it is “more likely-than-not” that the position is sustainable based on the merits of the position. It further limits the amount of tax benefit to be recognized to the largest amount of benefit that is greater than 50% likely of being realized. FIN 48 also requires explicit disclosures about uncertainties in income tax positions, including a detailed roll-forward of unrecognized tax benefits taken that do not qualify for financial statement recognition.

FIN 48 was effective January 1, 2007. In general, companies recorded the change in net assets that resulted from the application of FIN 48 as an adjustment to Retained Earnings. However, for PSE&G, because any charges to income arising from the adoption of FIN 48 should be recoverable in future rates, the offset to any incremental PSE&G liability was recorded as a Regulatory Asset rather than Retained Earnings. The following table presents the impact at January 1, 2007 on the Condensed Consolidated Balance Sheets for PSEG and its subsidiaries as a result of implementing FIN 48:


	PSE&G			Power			Energy Holdings			PSEG Consolidated
Balance Sheet	(Millions)
Increase to Long-Term Accrued Taxes		$	26		$	21		$	355		$	402
Decrease to Accumulated Deferred Income Tax Liability		$	15		$	7		$	246		$	268
Increase to Regulatory Assets		$	11		$	—		$	—		$	11
Decrease to Retained Earnings		$	—		$	14		$	109		$	123

The after-tax expense resulting from the adoption of FIN 48 for the quarter and six months ended June 30, 2007 are summarized as follows:


	Quarter Ended June 30, 2007			Six Months Ended June 30, 2007
	(Millions)
PSEG		$	3		$	9
Power		$	2		$	3
Energy Holdings		$	1		$	6

There was no impact on earnings for PSE&G. For additional information relating to the impacts of FIN 48, see Note 11. Income Taxes.

In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. The adoption of this FSP did not have a material impact on the financial statements of PSEG, PSE&G, Power or Energy Holdings.

FSP No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP 13-2)

PSEG and Energy Holdings

In July 2006, the FASB issued FSP 13-2, which addressed how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the accounting by a lessor for that lease. The FSP amends SFAS 13, “Accounting for Leases,” stating that a change in the timing of the above referenced cash flows must be reviewed at least annually or more frequently, if events or circumstances indicate a change in timing is probable. If a change in timing has

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

occurred, or is projected to occur, the rate of return and the allocation of income to positive investment years must be recalculated from the inception of the lease.

The guidance in this FSP was adopted on January 1, 2007. The cumulative effect of applying the provisions of this FSP is reported as an adjustment to the beginning balance of Retained Earnings as of the date of adoption. As a result of implementing FSP 13-2, upon adoption PSEG and Energy Holdings each recognized a reduction in Investment in Leveraged Leases of $69 million, a reduction in Deferred Income Taxes of $2 million and a reduction in Retained Earnings of $67 million.

The impact to earnings resulting from the adoption of FSP 13-2 for the quarter and six months ended June 30, 2007 was an after-tax decrease of $3 million and $6 million, respectively, for both PSEG and Energy Holdings.

Note 3. Discontinued Operations, Dispositions and Impairments

Discontinued Operations

Power

Lawrenceburg Energy Center (Lawrenceburg)

On May 16, 2007, Power completed the sale of Lawrenceburg, a 1,096-megawatt, gas-fired combined cycle electric generating plant located in Lawrenceburg, Indiana, to AEP Generating Company, a subsidiary of American Electric Power Company, Inc.

The sale price for the facility and inventory was $325 million. The transaction resulted in an after-tax charge to Power’s earnings of approximately $208 million and was reflected as a charge to Discontinued Operations in the fourth quarter of 2006.

Lawrenceburg’s operating results for the quarter and six months ended June 30, 2007 and 2006, which were reclassified to Discontinued Operations, are summarized below:


	Quarters Ended June 30,								Six Months Ended June 30,
	2007				2006				2007				2006
	(Millions)
Operating Revenues		$	—			$	6			$	—			$	6
Loss Before Income Taxes		$	(4	)		$	(14	)		$	(15	)		$	(29	)
Net Loss		$	(3	)		$	(8	)		$	(9	)		$	(17	)

The carrying amounts of the assets of Lawrenceburg as of December 31, 2006 are summarized in the following table:


	As of December 31, 2006
	(Millions)
Current Assets		$	10
Noncurrent Assets			315

Total Assets of Discontinued Operations		$	325

Energy Holdings

Electroandes S.A. (Electroandes)

In March 2007, Global announced that it is exploring a potential sale of Electroandes, a hydro-electric generation and transmission company in Peru. Global owns approximately 100% of Electroandes. Electroandes owns and operates four hydro-generation plants with total capacity of 180 megawatts and 437 miles of electric transmission lines. In June 2007, based on the strong investor interest in this project as seen in the auction process to date, Energy Holdings reclassified the investment to Discontinued Operations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

It is anticipated that a sale will close by the end of 2007, subject to regulatory approvals. As of June 30, 2007, the book value of Electroandes was approximately $166 million.

The 2007 and 2006 operating results for Global’s assets in Electroandes have been reclassified to Discontinued Operations. In conjunction with the reclassification to Discontinued Operations, Electroandes recorded a $19 million income tax expense in the second quarter of 2007 related to the discontinuation of applying Accounting Principles Board (APB) Opinion No. 23, “Accounting for Income Taxes—Special Areas,” as the income generated by Electroandes is no longer expected to be indefinitely reinvested.

Electroandes’ operating results for the quarter and six months ended June 30, 2007 and 2006 are summarized below:


	Quarters Ended June 30,							Six Months Ended June 30,
	2007				2006			2007				2006
	(Millions)
Operating Revenues		$	13			$	15		$	24			$	29
Income Before Income Taxes		$	6			$	4		$	7			$	8
Net (Loss) Income		$	(15	)		$	2		$	(14	)		$	5

The carrying amounts of the assets of Electroandes as of June 30, 2007 and December 31, 2006 are summarized in the following table:


	As of June 30, 2007			As of December 31, 2006
	(Millions)
Current Assets		$	25		$	25
Noncurrent Assets			274			272

Total Assets of Discontinued Operations		$	299		$	297

Current Liabilities		$	8		$	9
Noncurrent Liabilities			125			125

Total Liabilities of Discontinued Operations		$	133		$	134

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

On May 29, 2006, Global completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. Proceeds, net of transaction costs, were $476 million, resulting in a gain of $228 million net of tax expense of $142 million. The 2006 operating results for Global’s assets in Poland have been reclassified to Discontinued Operations.

Elcho’s and Skawina’s operating results for the quarter and six months ended June 30, 2006 are summarized below:


	Quarter Ended June 30, 2006							Six Months Ended June 30, 2006
	Elcho				Skawina			Elcho				Skawina
	(Millions)
Operating Revenues		$	9			$	11		$	39			$	44
(Loss) Income Before Income Taxes		$	(6	)		$	—		$	(3	)		$	2
Net (Loss) Income		$	(5	)		$	—		$	(2	)		$	1

Dispositions

Power

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Energy Holdings

Global

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

On December 22, 2006, Global entered into an agreement to sell its 34.5% interest in Tracy Biomass for approximately $7 million. The sale closed on January 26, 2007 and resulted in a 2007 pre-tax gain of approximately $7 million ($6 million after-tax).

Rio Grande Energia S. A. (RGE)

On May 10, 2006, Global entered into an agreement with Companhia Paulista de Force Luz (CPFL) to sell its 32% ownership interest in RGE, a Brazilian electric distribution company. The transaction closed on June 23, 2006 and gross proceeds of $185 million were received. The transaction resulted in a pre-tax write-down of $263 million ($177 million after-tax), primarily related to the devaluation of the Brazilian Real subsequent to Global’s acquisition of its interests in RGE in 1997.

Impairment

Energy Holdings

Venezuela

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

During Global’s 2006 year-end review of its equity method investments, management concluded that due to the current political situation in Venezuela, it was probable that Global would not be able to recover all of its capitalized costs associated with its investments in Venezuela. Therefore, Global recorded a pre-tax impairment loss of approximately $7 million to write down these investments in the fourth quarter of 2006.

In January 2007, the Venezuelan government announced its intention to nationalize certain sectors of Venezuelan industry and commerce, including certain foreign-owned energy and communications companies. In a subsequent press release, Turboven was named as one of the companies that Venezuela intended to nationalize. Since these announcements, Venezuela has proceeded to nationalize certain companies. Global recently entered into preliminary valuation discussions with the government of Venezuela as part of the nationalization efforts. As of June 30, 2007, the book value of these investments was approximately $34 million. No assurances can be given as to whether Global can recover the current book value of the investments.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 4. Earnings Per Share (EPS)

PSEG

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


	Quarters Ended June 30,																Six Months Ended June 30,
	2007								2006								2007								2006
	Basic				Diluted				Basic				Diluted				Basic				Diluted				Basic			Diluted
EPS Numerator:
Earnings (Millions)
Continuing Operations		$	293			$	293			$	(8	)		$	(8	)		$	627			$	627			$	197		$	197
Discontinued Operations			(18	)			(18	)			217				217				(23	)			(23	)			215			215

Net Income		$	275			$	275			$	209			$	209			$	604			$	604			$	412		$	412

EPS Denominator (Thousands):
Weighted Average Common Shares Outstanding			253,631				253,631				251,474				251,474				253,263				253,263				251,331			251,331
Effect of Stock Options			—				403				—				519				—				397				—			653
Effect of Stock Performance Units			—				—				—				91				—				37				—			91

Total Shares			253,631				254,034				251,474				252,084				253,263				253,697				251,331			252,075

Earnings Per Share:
Continuing Operations		$	1.16			$	1.15			$	(0.03	)		$	(0.03	)		$	2.48			$	2.47			$	0.79		$	0.79
Discontinued Operations			(0.07	)			(0.07	)			0.86				0.86				(0.09	)			(0.09	)			0.85			0.85

Net Income		$	1.09			$	1.08			$	0.83			$	0.83			$	2.39			$	2.38			$	1.64		$	1.64

Note 5. Commitments and Contingent Liabilities

Guaranteed Obligations

Power

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

Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York) in commodity-related transactions to support current exposure, interest and other

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

costs on sums due and payable in the ordinary course of business. These payment guarantees are provided to counterparties in order to obtain credit. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. The face value of the guarantees outstanding as of June 30, 2007 and December 31, 2006 was approximately $1.6 billion.

In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T and Power New York would have to fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee and all of ER&T’s and Power New York’s contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). The probability of all contracts at ER&T and Power New York being simultaneously “out-of-the-money” is highly unlikely due to offsetting positions within the portfolio. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability to Power under these guarantees if ER&T and/or Power New York were to default. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $462 million and $518 million as of June 30, 2007 and December 31, 2006, respectively.

Power is subject to counterparty collateral calls related to commodity contracts and is subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s agreements. Changes in commodity prices, including fuel, emissions allowances and electricity, can have a material impact on margin requirements under such contracts. As of June 30, 2007 and December 31, 2006, Power had the following margin posted and received to satisfy collateral obligations and support various contractual and environmental obligations, which were primarily in the form of letters of credit:


	As of June 30, 2007			As of December 31, 2006
	(Millions)
Margin Posted		$	197		$	40
Margin Received		$	49		$	86

Power also routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, such future contracts require a deposit of cash margin, the amount of which is subject to change based on market movement and in accordance with exchange rules. As of June 30, 2007 and December 31, 2006, Power had deposited margin of approximately $220 million and $89 million, respectively. Exchange-traded transactions that are margined and monitored separately from physical trading activity may not be subject to change in the event of a downgrade to Power’s rating.

In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide further performance assurance. As of June 30, 2007, if Power were to lose its investment grade rating and, assuming all counterparties to which ER&T is “out-of- the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to approximately $580 million. Power believes that it has sufficient liquidity to post such collateral, if necessary.

Energy Holdings

Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects.

In 2006, Global sold its investments in Poland. As of June 30, 2007 and December 31, 2006, Global was still obligated for a $6 million equity commitment guarantee at Skawina. The guarantee expires in August 2007. If payments are required, such payments are indemnified by the purchaser in accordance with the purchase agreement.

Global also has a contingent guarantee expiring in April 2011 related to debt service obligations associated with Chilquinta Energia S.A., an energy distribution company in Chile in which Global owns 50%. As of June 30, 2007 and December 31, 2006, the contingent guarantee was approximately $25 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

In September 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies) and nearly all of its assets. However, Energy Holdings retained certain outstanding construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance companies for which exposure is adequately supported by the outstanding letters of credit for PSEG Energy Technologies Asset Management Company LLC. As of June 30, 2007 and December 31, 2006, there were $14 million of such bonds outstanding, which are related to uncompleted construction projects. As of June 30, 2007 and December 31, 2006, there was an additional $2 million of performance guarantees related to Energy Technologies.

As of June 30, 2007 and December 31, 2006, Energy Holdings and/or Global had various other guarantees amounting to $22 million and $30 million, respectively.

Environmental Matters

PSEG, PSE&G and Power

Hazardous Substances

The U.S. Environmental Protection Agency (EPA) has determined that a six-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). CERCLA and the New Jersey Spill Compensation and Control Act (Spill Act) authorize Federal and state trustees for natural resources to assess damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites.

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

In 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G and Power, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances had been released from the Essex Site and a former MGP located in Harrison, New Jersey (Harrison Site), which also includes facilities for PSE&G’s ongoing gas operations. The EPA estimated that its study would require five to eight years to complete and would cost approximately $20 million, of which it would seek to recover $10 million from the PRPs, including PSE&G and Power. In 2006, the EPA notified the PRPs that the cost of its study will greatly exceed the $20 million initially estimated and after discussion, approximately 70 PRPs, including PSE&G and Power, have agreed to assume responsibility for the study pursuant to an Administrative Order on Consent and to divide the associated costs among themselves according to a mutually agreed-upon formula. The percentage allocable to Power and PSE&G varies depending on the number of PRPs who have agreed to divide the costs. Currently, it is 6.25%. Power has provided notice to insurers concerning this potential claim.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The New Jersey Department of Environmental Protection (NJDEP) has regulations in effect concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. In 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that directed the PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP announced that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million.

On June 29, 2007, the State of New Jersey filed multiple lawsuits against parties, including PSE&G, who were alleged to be responsible for injuries to natural resources in New Jersey, including a site being remediated under PSE&G’s MGP program. PSE&G and Power have indicated to both the EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their respective claims. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River or natural resource damages. However, such costs could be material.

PSE&G

MGP Remediation Program

PSE&G is currently working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites (Remediation Program). To date, 38 sites have been identified as sites requiring some level of remedial action. In addition, the NJDEP has announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface water bodies that have been impacted by hazardous substances from adjoining sites. Specifically, in 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the 10 most significant sites for cleanup. One of the sites identified is a former MGP facility located in Camden. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based on regulatory requirements, experience with the program and available remediation technologies. Since the inception of the Remediation Program in 1988 through June 30, 2007, PSE&G has had expenditures of approximately $400 million.

Based on most recent estimates, the cost of remediating all sites to completion, as well as the anticipated costs to address MGP-related material discovered in two rivers adjacent to two former MGP sites, could range between $798 million and $838 million, including amounts spent to date. No amount within the range was considered to be most likely. Therefore, $398 million was accrued at June 30, 2007, which represents the difference between the low end of the total program cost estimate of $798 million and the total incurred costs through June 30, 2007 of $400 million. Of this amount, approximately $48 million was recorded in Other Current Liabilities and $350 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $398 million Regulatory Asset was recorded.

Costs for the MGP Remediation Program were approximately $42 million for 2006. PSE&G anticipates spending $47 million in 2007, $50 million in 2008, and an average of approximately $40 million per year each year thereafter through 2016.

Power

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

The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties of up to approximately $27,500 for each day of continued violation.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-burning units were implemented in accordance with applicable PSD/NSR regulations. In January 2002, Power reached an agreement with the NJDEP and the EPA to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur Dioxide (SO₂), Nitrogen Oxide (NO_x), particulate matter and mercury from the coal-burning units at the Mercer and Hudson generating stations to ensure compliance with PSD/NSR. Power also agreed to spend at least $6 million on supplemental environmental projects and pay a $1 million civil penalty. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operations to commence.

Power subsequently notified the EPA and the NJDEP that it was evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution control equipment and other necessary modifications to the unit. On November 30, 2006, Power reached an agreement with the EPA and the NJDEP on an amendment to its 2002 agreement intended to achieve the emissions reductions targets of this agreement while providing more time to assess the feasibility of installing additional advanced emissions controls at Hudson.

The amended agreement with the EPA and the NJDEP, which received final approval from the U.S. District Court in New Jersey in May 2007, allows Power to continue operating Hudson and extends for four years the deadline for installing environmental controls beyond the previous December 31, 2006 deadline. Power is required to undertake a number of technology projects (selective catalytic reductions (SCRs), scrubbers, baghouses, carbon injection)), plant modifications and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of NO_x, SO₂, particulate matter and mercury. In July 2007, Power notified the EPA and the NJDEP that it will proceed with the installation of the additional emissions controls at Hudson by the end of 2010.

Under the program, Power has installed SCRs at Mercer at a cost of approximately $115 million. The cost of implementing the balance of the amended agreement at Mercer and Hudson is estimated at approximately $475 million to $525 million for Mercer and at $700 million to $750 million for Hudson and will be incurred in the 2007–2010 timeframe. Pursuant to the agreement, Fossil purchased and retired emissions allowances by July 31, 2007, paid a $6 million civil penalty and will contribute approximately $3 million for programs to reduce particulate emissions from diesel engines in New Jersey. In addition, in March 2007, Fossil entered into an engineering, procurement and construction contract with a third party contractor to complete all back-end technology requirements for the Mercer station, as referenced above. A contract for the Hudson back-end technology construction was signed in July 2007.

As a result of the agreement, Power’s environmental reserves include approximately $3 million to account for the particulate matter reduction program. PSEG and Power recorded the charge in Other Deductions on their respective Condensed Consolidated Statements of Operations in the fourth quarter of 2006.

Mercury Regulation

New Jersey, and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The regulations in New Jersey require the units to meet certain emissions limits or reduce emissions by 90% by December 15, 2007.

Under the New Jersey regulations, companies that are parties to multi-pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012. With respect to Power’s New Jersey facilities, half of the reductions that are required by December 15, 2007 are expected to be achieved through the installation of carbon injection technology at Mercer. Installation of carbon injection technology was completed in January 2007 at both Mercer Units. If this does not meet the applicable limit, Power will apply for a facility-specific control plan. Power believes, but cannot guarantee, that this filing will allow for the continued operation of both Mercer Units while baghouses are installed. Installation of the baghouses is scheduled to be completed by the end of 2008. At its Hudson plant, Power anticipates compliance consisting of the installation of a baghouse by the end of 2010.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The mercury control technologies are also part of Power’s multi-pollutant reduction agreement, which resulted from the amended 2002 agreement that resolved issues arising out of the PSD and the NSR air pollution control programs, discussed above.

Connecticut requires coal-fired power plants in Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions effective in July 2008. Power anticipates compliance at its Bridgeport Harbor Station consisting of the installation of a baghouse by the end of 2007.

In February 2007, Pennsylvania finalized its “State-specific” requirements to reduce mercury emissions from coal-fired electric generating units. Currently, the regulations would not materially affect the costs already identified in Power’s capital expenditures forecast.

The estimated costs of technology believed to be capable of meeting these emissions limits at Power’s coal-fired unit in Connecticut and at its Mercer and Hudson Stations are included in Power’s capital expenditures forecast. Total estimated costs for each project are between $150 million and $200 million. The Mercer and Hudson expenditures are included in the PSD/NSR discussion above.

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applies to the sale of certain assets. Power had a $51 million liability as of June 30, 2007 and December 31, 2006, related to these obligations, which is included in Other Noncurrent Liabilities on Power’s Condensed Consolidated Balance Sheets and Environmental Costs on PSEG’s Condensed Consolidated Balance Sheets.

Permit Renewals

In June 2001, the NJDEP issued a renewed New Jersey Pollutant Discharge Elimination System (NJPDES) permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. A renewal application prepared in accordance with Federal Water Pollution Control Act (FWPCA) Section 316(b) and the Phase II 316(b) rule was filed in February 2006 with the NJDEP, which allows the station to continue operating under its existing NJPDES permit until a new permit is issued. Power’s application to renew Salem’s NJPDES permit demonstrates that the station satisfies FWPCA Section 316(b) and meets the Phase II 316(b) rule’s performance standards for reduction of impingement and entrainment through the station’s existing cooling water intake technology and operations plus implemented restoration measures. The application further demonstrates that even without the benefits of restoration, the station meets the Phase II 316(b) rule’s site-specific determination standards, both on a comparison of the costs and benefits of new intake technology as well as a comparison of the costs to implement the technology at the facility to the cost estimates prepared by the EPA.

The U.S. Court of Appeals for the Second Circuit issued a decision after Power filed its application that rejected the use of restoration and the site-specific cost-benefit test under the Phase II 316(b) rule.

On May 25, 2007 Power and other industry petitioners filed with the Second Circuit Court a request for a rehearing. In July 2007, the Second Circuit Court denied the request. The parties, including Power, may now request that the US Supreme Court review the matter. Although the rule applies to all of Power’s electric generating units that use surface waters for once-through cooling purposes, the impact of the rule and the decision of the court cannot be determined at this time for all of Power’s facilities. Depending on the outcome of any appeals, or actions by EPA to repromulgate the rule, this decision could have a material impact on Power’s ability to renew its New Jersey and Connecticut permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, New Haven and Bridgeport, without making significant upgrades to their existing intake structures and cooling systems. If the NJDEP and the Connecticut Department of Environmental Protection were to require installation of closed-cycle cooling or its equivalent at those five once-through cooled facilities, the related costs and impacts would be material to Power’s financial position, results of operations and net cash flows. For example, Power’s application to renew the permit, filed in February 2006 with the NJDEP, estimated the costs associated with cooling towers for Salem to be

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

approximately $1 billion, of which Power’s share would be approximately $575 million. Potential costs associated with any closed-cycle cooling requirements are not included in Power’s currently forecasted capital expenditures.

Energy Holdings

Bioenergie S.p.A. (Bioenergie)

In May 2006, Global became the majority shareholder of Bioenergie (formerly known as Prisma 2000 S.p.A). Among other holdings, Bioenergie holds 100% of the stock of San Marco Bioenergie S.p.A (San Marco), owner of a 20 MW biomass generation facility in Italy. Global also assumed operational responsibility for the facility in May 2006, which was previously operated by Carlo Gavazzi Green Power pursuant to a Services Agreement with a Global subsidiary. Global’s total investment in Bioenergie is approximately $70 million.

In August 2006, Global became aware that the Italian government was conducting a criminal investigation regarding allegations of violations of the San Marco facility’s air permit. The scope of the investigation was subsequently expanded to include alleged violations of the facility’s waste recycling and waste storage permits. The Italian government has named five individuals as targets of the criminal investigation, including three former San Marco employees and two former members of the facility’s Board of Directors. San Marco has not been named as a target.

In December 2006 and January 2007, the facility was served with orders suspending its operations. San Marco has fully cooperated with the Prosecuting Attorney regarding the ongoing investigation and has implemented the corrective actions designed to prevent recurrence of the violations. On April 26, 2007, the Prosecutor issued an order returning control of the plant to San Marco. One of the units resumed commercial operations in June 2007 with the second unit anticipated to resume commercial operations in August 2007.

Electroandes

In July 2005, Electroandes received a notice from Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, claiming past due taxes for 2002 totaling approximately $2 million related to certain interest deductions. Electroandes has taken similar interest deductions subsequent to 2002. The total cumulative estimated potential amount for past due taxes, including associated interest and penalties, is approximately $10 million through June 30, 2007. Electroandes believes it has valid legal defenses to these claims, and has filed an appeal with SUNAT with respect to which it has not yet received a response; however, no assurances can be given regarding the outcome of this matter. For additional information relating to Electroandes, see Note 3. Discontinued Operations, Dispositions and Impairments.

Luz del Sur S.A.A. (LDS)

In January 2007, SUNAT filed two tax assessments against LDS totaling approximately $18 million, of which Global’s share would be approximately $7 million based on its 38% interest in LDS. The assessments relate to deductions LDS claimed beginning in 2000 for certain operating fees it paid to International Technical Operators under a technical services agreement, for certain bad debt deductions and certain other matters. The assessments include interest and penalties claimed by SUNAT. LDS believes that most of such deductions were appropriate and filed an appeal in February 2007. LDS believes it has valid legal defenses to these claims and that it should be successful in contesting these material items/disallowances; however, no assurances can be given regarding the outcome of this matter.

New Generation and Development

Power

Power plans to modestly increase its generating capacity at Hope Creek in 2007 and Salem Unit 2 in 2008. Phase I of the Hope Creek turbine replacement increased the capacity by 10 MW in 2005, and Phase II

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

is expected to be completed in 2007 along with the thermal power uprate and is expected to add approximately 125 MW of capacity. Phase I of the Salem Unit 2 turbine upgrade increased Power’s share of the capacity by 14 MW in 2003. Phase II is currently scheduled for 2008, concurrent with steam generator replacement and is anticipated to increase Power’s share of the capacity by an additional 15 MW. Power’s expenditures to date for these projects approximate $187 million (including Interest Capitalized During Construction (IDC) of $21 million) with an aggregate estimated share of total costs for these projects of $213 million (including IDC of $23 million).

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

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

PSE&G and Power

PSE&G is required to obtain all electric supply requirements through the annual New Jersey BGS auctions for customers who do not purchase electric supply from third-party suppliers. PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions within three business days following the BPU’s approval. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s anticipated load requirements. The winners of the auction are responsible for fulfilling all the requirements of a PJM Interconnection, L.L.C. (PJM) Load Serving Entity (LSE) including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume any customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

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


Term	Term Ending
	May 2007(a)			May 2008(b)			May 2009(c)			May 2010(d)
	34 months			36 months			36 months			36 months
Load (MW)			2,840			2,840			2,882			2,758
$ per kWh		$	0.05515		$	0.06541		$	0.10251		$	0.09888

(a)

Prices set in the February 2004 BGS auction.

(b)

Prices set in the February 2005 BGS auction.

(c)

Prices set in the February 2006 BGS auction.

(d)

Prices set in the February 2007 BGS auction which became effective on June 1, 2007.

Power seeks to mitigate volatility in its results by contracting in advance for its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey Electric Distribution Companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. In addition to the BGS-related contracts, Power enters into firm supply contracts with EDCs, as well as other firm sales and commitments.

PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits recovery of the cost of gas hedging up to 115 billion cubic feet or approximately 80% of PSE&G’s residential gas supply annually through the BGSS tariff. For additional information, see Note 13. Related-Party Transactions.

The BPU is currently conducting an audit of the gas procurement practices of all four New Jersey gas utilities, including PSE&G. The outcome of this proceeding cannot be predicted.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Minimum Fuel Purchase Requirements

Power

Coal and Oil

Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. The coal purchase commitments through 2009 amount to approximately 91% of its average anticipated coal needs, including transportation. These commitments total approximately $882 million.

Nuclear Fuel

Power has several long-term purchase contracts for the supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations. Power has inventory and commitments to purchase sufficient quantities of uranium (concentrates and uranium hexafluoride) to meet 100% of its total estimated requirements through 2011. Additionally, Power has commitments covering approximately 48% of its estimated requirements for 2012 and 15% from 2013 through 2016. These commitments, based on current market prices, which have increased substantially over the past two to three years, total approximately $655 million ($466 million Power’s estimated share). Power’s policy is to maintain certain levels of concentrates and uranium hexafluoride in inventory and to make periodic purchases to support such levels. As such, the commitments referred to above include estimated quantities to be purchased that are in excess of contractual minimum quantities.

Power also has commitments that provide 100% of its uranium enrichment requirements through 2010 that total approximately $257 million ($186 million Power’s estimated share).

Power has commitments for the fabrication of fuel assemblies for reloads required through 2011 for Salem and through 2012 for Hope Creek that total approximately $148 million ($109 million Power’s estimated share).

Natural Gas

In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G. As of June 30, 2007, the total minimum requirements under these contracts were approximately $1 billion through 2016.

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

Energy Holdings

The Texas generation facilities have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of June 30, 2007, the plants have fuel purchase commitments totaling $189 million to support all of their contracted energy sales.

Operating Services Contract (OSC)

Power

On January 17, 2005, Nuclear entered into an OSC with Exelon Generation LLC (Exelon) relating to the operation of the Hope Creek and Salem nuclear generating stations. The OSC requires Exelon to provide key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement a management model that Exelon has used to manage its own nuclear facilities. Nuclear continues as the license holder with exclusive legal authority to operate and maintain the plants, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities. Exelon is entitled to receive reimbursement of its costs in discharging its obligations, an annual operating services fee of $3 million and incentive fees up to $12 million annually based on attainment of goals relating to safety, capacity factor and operation and maintenance expenses. On

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

October 27, 2006, Nuclear informed Exelon that it was electing to continue the OSC for up to two years beyond the initial January 2007 period.

In December 2006, Power announced its plans to resume direct management of the Salem and Hope Creek nuclear generating stations before the expiration of the OSC. As part of this plan, on January 1, 2007, the senior management team at Salem and Hope Creek, which consisted of three senior executives from Exelon, became employees of Power. Power has continued to recruit additional employees to build its organizational structure. Power is implementing a plan to fully resume functions that Exelon currently performs, which should put Power in a position to terminate the OSC by the end of 2007.

Maintenance Agreement

Power

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

Investment Tax Credits (ITC)

PSEG and PSE&G

As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings (PLRs) that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets’ regulatory lives, which for PSE&G, were terminated upon New Jersey’s electric industry deregulation. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC liability relating to PSE&G’s generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry in New Jersey. Subsequently, PSE&G was directed by the BPU to seek a PLR from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the tax normalization rules of the Internal Revenue Code. PSE&G filed a PLR request with the IRS in 2002.

On May 11, 2006, the IRS issued a PLR to PSE&G. The PLR concluded that none of the generation ITC could be passed to utility customers without violating the normalization rules. On May 16, 2006, the BPU voted in favor of a special investigation and hearing before the BPU concerning PSE&G’s actions leading up to receiving the PLR, specifically its failure to abide by a BPU order to withdraw the request. An order detailing such special investigation has not yet been issued and no investigation has begun.

On October 13, 2006, the Appellate Division of the Superior Court of New Jersey granted PSE&G’s motion to dismiss PSE&G’s appeal of the BPU’s order to withdraw the PLR since PSE&G has already received the PLR. The court also determined that if the BPU seeks to take future action against PSE&G based on the alleged violation of its order, PSE&G can restart the appeal.

While the holding in the PLR is favorable for PSE&G, an outstanding Treasury regulation project could overturn the holding in the PLR if the Treasury were to alter a position set out in certain December 21, 2005 proposed regulations. PSEG and PSE&G cannot determine the final outcome of this matter until the final Treasury regulations are issued.

BPU Deferral Audit

PSEG and PSE&G

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

While the consultant to the BPU found that the Phase II deferral balances complied in all material respects with the BPU Orders regarding such deferrals, the consultant noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. The amount in dispute is approximately $130 million.

On January 31, 2007, PSE&G requested that the matter be transmitted to the Office of Administrative Law for the development of an evidentiary record and an initial decision. The BPU granted the request on February 7, 2007. On May 25, 2007, PSE&G filed a Motion for Summary Judgment requesting dismissal of the matter which is pending. Briefs were filed by the New Jersey Public Advocate’s Division of Rate Counsel (Rate Counsel) and the BPU Staff on July 16, 2007 and July 17, 2007, respectively. In its filing, Rate Counsel opposed PSE&G’s motion and continued to support the refunding of the $130 million in dispute with customers. The BPU Staff also asserts that $130 million should be refunded to ratepayers. PSE&G’s Reply Brief is due August 24, 2007.

While PSE&G believes the MTC methodology it used was fully litigated and resolved, without exception, by the BPU and other intervening parties in its previous electric base rate case, deferral audit and deferral proceeding that were approved by the BPU in its order on April 22, 2004, and that such order is non-appealable, PSE&G cannot predict the impact of the outcome of this proceeding.

New Jersey Clean Energy Program

PSE&G

The BPU has approved a funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The sum of PSE&G’s electric and gas funding requirement was $62 million and $50 million for the six months ended June 30, 2007 and 2006, respectively. The remaining liability has been recorded at a discounted present value with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the SBC. The liability for the funding requirement as of June 30, 2007 and December 31, 2006 was $201 million and $253 million, respectively.

Leveraged Lease Investments

PSEG and Energy Holdings

On November 16, 2006, the IRS issued a report with respect to its audit of PSEG’s corporate tax returns for tax years 1997 through 2000, which disallowed all deductions associated with certain of Resources’ lease transactions that are similar to a type that the IRS publicly announced its intention to challenge. In addition, the IRS imposed a 20% penalty for substantial understatement of tax liability. In February 2007, PSEG filed a protest to the Office of Appeals of the IRS. As of June 30, 2007 and December 31, 2006, Resources’ total gross investment in such transactions was approximately $1.5 billion.

If all deductions associated with these lease transactions, entered into by PSEG between 1997 and 2002, are successfully challenged by the IRS, it could have a material adverse impact on PSEG’s and Energy Holdings’ financial position, results of operations and net cash flows and could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law and will aggressively contest the IRS’ disallowance. PSEG believes that it is more likely than not that it will prevail with respect to the IRS’ challenge, although no assurances can be given.

If the IRS’ disallowance of tax benefits associated with all of these lease transactions was sustained, approximately $828 million of PSEG’s deferred tax liabilities that have been recorded under leveraged lease accounting through June 30, 2007 would become currently payable. In addition, as of June 30, 2007 interest of approximately $145 million, after-tax, and penalties of $160 million may become payable, with potential additional interest and penalties of approximately $16 million accruing quarterly. Energy Holdings’ management has assessed the probability of various outcomes to this matter and recorded the tax effect to be realized in accordance with FIN 48.

For additional information and guidance for leveraged leases, see Note 2. Recent Accounting Standards.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6. Financial Risk Management Activities

PSEG, PSE&G, Power and Energy Holdings

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

Derivative Instruments and Hedging Activities

Commodity Contracts

Power

Power actively transacts in energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil and emission allowances in the spot, forward and futures markets, primarily in the Northeastern and Mid Atlantic United States.

Power maintains a strategy of entering into positions to optimize the value of its portfolio and reduce earnings volatility of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy seeking to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options, futures and FTRs. During the six months ended June 30, 2007, higher market prices for electricity and capacity have resulted in additional unrealized losses on many of these contracts leading to an increase in Accumulated Other Comprehensive Loss (OCL). Power marks its derivative energy- related contracts to market in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (SFAS 133) with changes in fair value charged to the Condensed Consolidated Statements of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.

Cash Flow Hedges

Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of June 30, 2007, the fair value of these hedges was $(432) million and resulted in $(254) million after-tax recorded in OCL. As of December 31, 2006, the fair value of these hedges was $(166) million. These hedges, along with realized losses on hedges of $(19) million retained in OCL, resulted in a $(108) million after-tax balance in OCL. The increase of $146 million in OCL during the six months ended June 30, 2007 was caused mainly by higher electricity market prices. During the 12 months ending June 30, 2008, $144 million after-tax of net unrealized losses on these commodity derivatives is expected to be reclassified to earnings. Approximately $83 million of after-tax unrealized losses on these commodity derivatives in OCL is expected to be reclassified to earnings for the 12 months ending June 30, 2009. Ineffectiveness associated with these hedges, as defined in SFAS 133, was $(2) million at June 30, 2007. The expiration date of the longest dated cash flow hedge is in 2010.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Other Derivatives

Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. These contracts are used primarily for fuel purchases for generation and BGSS requirements and for electricity purchases for contractual sales obligations and a minor portion is used in Power’s Nuclear Decommissioning Trust Funds. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs, Operating Revenues, Other Income or Other Deductions, as appropriate, on the Condensed Consolidated Statements of Operations. The net fair value of these instruments as of June 30, 2007 was $(18) million. The net fair value of these instruments as of December 31, 2006 was $(2) million.

Energy Holdings

Other Derivatives

The Texas generation facilities enter into electricity forward and capacity sales contracts to sell portions of their 2,000 MW capacity through 2010, with the balance sold into the daily spot market. The Texas generation facilities also enter into gas purchase contracts to specifically match the generation requirements to support the electricity forward sales contracts. Although these contracts fix the amount of revenue, fuel costs and cash flows, and thereby provide financial stability to the Texas generation facilities, these contracts are, based on their terms, derivatives that do not meet the specific accounting criteria in SFAS 133 to qualify for the normal purchases and normal sales exception, or to be designated as a hedge for accounting purposes. As a result, these contracts must be recorded at fair value. The net fair value of the open positions was approximately $34 million and $38 million as of June 30, 2007 and December 31, 2006, respectively.

Interest Rates

PSEG, PSE&G, Power and Energy Holdings

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

Fair Value Hedges

PSEG and Power

In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009. PSEG used an interest rate swap to convert Power’s fixed-rate debt into variable-rate debt. The interest rate swap is designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of June 30, 2007 and December 31, 2006, the fair value of the hedge was $(8) million and $(9) million, respectively.

Cash Flow Hedges

PSEG, PSE&G and Energy Holdings

PSEG, PSE&G and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives used are designated and effective as cash flow hedges. Except for PSE&G’s cash flow hedges, the fair value changes of these derivatives are initially recorded in Accumulated Other Comprehensive Income/Loss. As of June 30, 2007, the fair value of these cash flow hedges was $(2) million and $2 million at PSE&G and Energy Holdings, respectively. As of December 31, 2006, the fair value of these cash flow hedges was $(4) million, primarily at PSE&G. The $(2) million and $(4) million at PSE&G as of June 30, 2007 and December 31, 2006, respectively, is not included in Accumulated Other Comprehensive Income/Loss, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G’s customers. During the next 12 months, less than $1 million of unrealized losses (net of taxes) on interest rate derivatives in OCL is expected to be reclassified at PSEG. As of June 30, 2007, there was no hedge ineffectiveness associated with these hedges.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Foreign Currencies

Energy Holdings

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

Although the Chilean Peso and the Peruvian Nuevo Sol had originally depreciated relative to the U.S. Dollar after Global’s initial investments, the currencies have appreciated significantly over the past few years. The net cumulative foreign currency revaluations have increased the total amount of Energy Holdings’ Member’s Equity by $151 million as of June 30, 2007.

Hedges of Net Investments in Foreign Operations

Energy Holdings

In March 2004 and April 2004, Energy Holdings entered into four cross-currency interest rate swap agreements. The swaps are designed to hedge the net investment in a foreign subsidiary associated with the exposure in the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross-currency swaps was $(26) million and $(25) million as of June 30, 2007 and December 31, 2006, respectively. The change in fair value of the majority of the swaps is recorded in Cumulative Translation Adjustment within OCL. As a result, Energy Holdings’ Member’s Equity was reduced by $24 million as of June 30, 2007.

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


	PSE&G			Power				Energy Holdings			Other(A)				Consolidated Total
	(Millions)
For the Quarter Ended June 30, 2007:
Net Income (Loss)		$	63		$	184			$	44		$	(16	)		$	275
Other Comprehensive Income			—			30				28			1				59

Comprehensive Income (Loss)		$	63		$	214			$	72		$	(15	)		$	334

For the Quarter Ended June 30, 2006:
Net Income (Loss)		$	34		$	77			$	118		$	(20	)		$	209
Other Comprehensive Income (Loss)			—			46				189			(1	)			234

Comprehensive Income (Loss)		$	34		$	123			$	307		$	(21	)		$	443

For the Six Months Ended June 30, 2007:
Net Income (Loss)		$	195		$	397			$	47		$	(35	)		$	604
Other Comprehensive (Loss) Income			—			(125	)			19			1				(105	)

Comprehensive Income (Loss)		$	195		$	272			$	66		$	(34	)		$	499

For the Six Months Ended June 30, 2006:
Net Income (Loss)		$	112		$	189			$	150		$	(39	)		$	412
Other Comprehensive Income			—			179				191			—				370

Comprehensive Income (Loss)		$	112		$	368			$	341		$	(39	)		$	782

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Accumulated Other Comprehensive Income (Loss)


	Balance as of December 31, 2006				PSE&G			Power				Energy Holdings			Other (A)				Balance as of June 30, 2007
	(Millions)
For the Six Months Ended June 30, 2007:
Derivative Contracts		$	(114	)		$	—		$	(145	)		$	2		$	(1	)		$	(258	)
Pension and OPEB Plans			(214	)			—			6				—			1				(207	)
Currency Translation Adjustment			110				—			—				17			—				127
NDT Funds			108				—			14				—			—				122
Other			2				—			—				—			1				3

		$	(108	)		$	—		$	(125	)		$	19		$	1			$	(213	)


	Balance as of December 31, 2005				PSE&G			Power			Energy Holdings			Other (A)			Balance as of June 30, 2006
	(Millions)
For the Six Months Ended June 30, 2006:
Derivative Contracts		$	(626	)		$	—		$	179		$	59		$	—		$	(388	)
Pension and OPEB Plans			(11	)			—			—			—			—			(11	)
Currency Translation Adjustment			(44	)			—			—			132			—			88
NDT Funds			72				—			—			—			—			72
Other			—				—			—			—			—			—

		$	(609	)		$	—		$	179		$	191		$	—		$	(239	)

(A)

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

Note 8. Changes in Capitalization

PSEG

On May 15, 2007, PSEG redeemed the outstanding $375 million of its Floating Rate Notes Due 2008 at 100% of the principal amount.

For the six months ended June 30, 2007, PSEG issued 837,788 shares of its common stock in connection with settling stock options for approximately $36 million.

For the six months ended June 30, 2007, PSEG issued 387,402 shares of its common stock under its Dividend Reinvestment Program and its Employee Stock Purchase Program for approximately $32 million.

PSE&G

On January 2, 2007, PSE&G repaid at maturity $113 million of its 6.25% Series WW First and Refunding Mortgage Bonds.

On May 14, 2007, PSE&G issued $350 million of 5.80% Secured Medium Term Notes Series E due 2037. The proceeds were used to reduce short-term debt.

In June 2007 and March 2007, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $36 million and $38 million, respectively, of its transition bonds.

In June 2007, PSE&G Transition Funding II LLC (Transition Funding II) repaid approximately $4 million of its transition bonds.

Power

In March and June 2007, Power paid cash dividends to PSEG of $125 million and $450 million, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Energy Holdings

In March 2007, Energy Holdings made a cash distribution to PSEG of $145 million in the form of a return of capital.

During the first six months of 2007, Energy Holdings’ subsidiaries repaid approximately $24 million of non-recourse debt, including $22 million by Global, primarily related to the Texas generation facilities, $1 million by Resources and $1 million by EGDC.

Note 9. Other Income and Deductions


	PSE&G			Power			Energy Holdings			Other(A)				Consolidated Total
	(Millions)
Other Income:
For the Quarter Ended June 30, 2007:
Interest and Dividend Income		$	3		$	10		$	2		$	(7	)		$	8
NDT Fund Realized Gains			—			31			—			—				31
NDT Interest and Dividend Income			—			13			—			—				13
Minority Interest			—			—			—			2				2
Other			2			1			1			—				4

Total Other Income		$	5		$	55		$	3		$	(5	)		$	58

For the Quarter Ended June 30, 2006:
Interest and Dividend Income		$	3		$	3		$	7		$	(1	)		$	12
NDT Fund Realized Gains			—			22			—			—				22
NDT Interest and Dividend Income			—			9			—			—				9
Change in Derivative Fair Value			—			—			1			—				1
Other			5			—			2			—				7

Total Other Income		$	8		$	34		$	10		$	(1	)		$	51

For the Six Months Ended June 30, 2007:
Interest and Dividend Income		$	6		$	15		$	5		$	(7	)		$	19
NDT Fund Realized Gains			—			65			—			—				65
NDT Interest and Dividend Income			—			25			—			—				25
Arbitration Award (Konya-Ilgin)			—			—			9			—				9
Change in Derivative Fair Value			—			—			1			—				1
Minority Interest			—			—			—			2				2
Other			4			1			3			—				8

Total Other Income		$	10		$	106		$	18		$	(5	)		$	129

For the Six Months Ended June 30, 2006:
Interest and Dividend Income		$	6		$	7		$	9		$	(3	)		$	19
NDT Fund Realized Gains			—			49			—			—				49
NDT Interest and Dividend Income			—			19			—			—				19
Foreign Currency Gains			—			—			2			—				2
Change in Derivative Fair Value			—			—			2			—				2
Other			6			—			4			—				10

Total Other Income		$	12		$	75		$	17		$	(3	)		$	101

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	PSE&G			Power			Energy Holdings				Other(A)				Consolidated Total
	(Millions)
Other Deductions:
For the Quarter Ended June 30, 2007:
NDT Fund Realized Losses and Expenses		$	—		$	19		$	—			$	—			$	19
Other-Than-Temporary Impairment of Investments			—			14			—				—				14
Foreign Currency Losses			—			—			2				—				2
Change in Derivative Fair Value			—			—			1				—				1
Loss on Disposition of Assets			—			1			—				—				1
Other			1			—			—				(1	)			—

Total Other Deductions		$	1		$	34		$	3			$	(1	)		$	37

For the Quarter Ended June 30, 2006:
Donations		$	1		$	—		$	—			$	—			$	1
NDT Fund Realized Losses and Expenses			—			13			—				—				13
Foreign Currency Losses			—			—			2				—				2
Change in Derivative Fair Value			—			—			1				—				1
Minority Interest			—			—			—				1				1
Loss on Disposition of Assets			—			1			—				—				1
Other			—			—			(3	)			—				(3	)

Total Other Deductions		$	1		$	14		$	—			$	1			$	16

For the Six Months Ended June 30, 2007:
Donations		$	1		$	—		$	—			$	5			$	6
NDT Fund Realized Losses and Expenses			—			36			—				—				36
Other-Than-Temporary Impairment of Investments			—			24			—				—				24
Foreign Currency Losses			—			—			3				—				3
Change in Derivative Fair Value			—			—			1				—				1
Loss on Disposition of Assets			—			2			—				—				2
Other			1			1			—				(1	)			1

Total Other Deductions		$	2		$	63		$	4			$	4			$	73

For the Six Months Ended June 30, 2006:
Donations		$	2		$	—		$	—			$	—			$	2
NDT Fund Realized Losses and Expenses			—			32			—				—				32
Foreign Currency Losses			—			—			3				—				3
Change in Derivative Fair Value			—			—			3				—				3
Minority Interest			—			—			—				1				1
Loss on Disposition of Assets			—			1			—				—				1
Other			—			—			1				—				1

Total Other Deductions		$	2		$	33		$	7			$	1			$	43

(A)

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 10. Pension and Other Postretirement Benefits (OPEB)

PSEG

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


	Pension Benefits								OPEB								Pension Benefits								OPEB
	Quarters Ended June 30,								Quarters Ended June 30,								Six Months Ended June 30,								Six Months Ended June 30,
	2007				2006				2007				2006				2007				2006				2007				2006
	(Millions)
Components of Net Periodic Benefit Costs:
Service Cost		$	21			$	22			$	4			$	4			$	42			$	43			$	8			$	9
Interest Cost			54				52				18				17				108				105				36				34
Expected Return on Plan Assets			(72	)			(67	)			(3	)			(3	)			(144	)			(134	)			(7	)			(6	)
Amortization of Net
Transition Obligation			—				—				7				7				—				—				14				14
Prior Service Cost			3				2				3				3				6				5				6				6
Loss			5				14				2				2				10				27				4				4

Net Periodic Benefit Costs			11				23				31				30				22				46				61				61
Effect of Regulatory Asset			—				—				5				5				—				—				10				10

Total Benefit Costs		$	11			$	23			$	36			$	35			$	22			$	46			$	71			$	71

PSE&G, Power, Energy Holdings and Services

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


	Pension Benefits						OPEB						Pension Benefits						OPEB
	Quarters Ended June 30,						Quarters Ended June 30,						Six Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006			2007			2006			2007			2006
	(Millions)
PSE&G		$	5		$	11		$	30		$	30		$	10		$	23		$	60		$	60
Power			3			7			4			4			6			14			8			8
Energy Holdings			1			1			—			—			1			1			—			—
Services			2			4			2			1			5			8			3			3

Total PSEG Consolidated Benefit Costs		$	11		$	23		$	36		$	35		$	22		$	46		$	71		$	71

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 11. Income Taxes

An analysis of the tax provision expense is as follows:


	PSE&G				Power				Energy Holdings				Other (A)				Consolidated Total
	(Millions)
For the Quarter Ended June 30, 2007:
Income (Loss) Before Income Taxes		$	104			$	318			$	68			$	(23	)		$	467
Tax Computed at the Statutory Rate			36				111				24				(8	)			163
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit			8				18				—				(1	)			25
Rate Differential between Foreign/Domestic Operations			—				—				(13	)			—				(13	)
Uncertain Tax Positions			—				2				1				—				3
Other			(3	)			—				(1	)			—				(4	)

Total Income Tax Expense (Benefit)		$	41			$	131			$	11			$	(9	)		$	174

Effective Income Tax Rate			39.4	%			41.2	%			16.2	%			39.1	%			37.3	%

For the Quarter Ended June 30, 2006:
Income (Loss) Before Income Taxes		$	60			$	146			$	(170	)		$	(32	)		$	4
Tax Computed at the Statutory Rate			21				51				(59	)			(11	)			2
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit			4				9				(3	)			(2	)			8
Rate Differential between Foreign/Domestic Operations			—				—				(4	)			—				(4	)
Plant-Related Items			5				—				—				—				5
Other			(4	)			1				2				2				1

Total Income Tax Expense (Benefit)		$	26			$	61			$	(64	)		$	(11	)		$	12

Effective Income Tax Rate			43.3	%			41.8	%			37.6	%			34.4	%			N/A

For the Six Months Ended June 30, 2007:
Income (Loss) Before Income Taxes		$	335			$	692			$	90			$	(54	)		$	1,063
Tax Computed at the Statutory Rate			117				242				32				(19	)			372
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit			24				41				(2	)			(3	)			60
Rate Differential between Foreign/Domestic Operations			—				—				(4	)			—				(4	)
Uncertain Tax Positions			—				3				6				—				9
Other			(1	)			—				(1	)			1				(1	)

Total Income Tax Expense (Benefit)		$	140			$	286			$	31			$	(21	)		$	436

Effective Income Tax Rate			41.8	%			41.3	%			34.4	%			38.9	%			41.0	%

For the Six Months Ended June 30, 2006:
Income (Loss) Before Income Taxes		$	203			$	353			$	(135	)		$	(65	)		$	356
Tax Computed at the Statutory Rate			71				124				(47	)			(23	)			125
Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments:
State Income Taxes after Federal Benefit			15				21				(5	)			(3	)			28
Rate Differential between Foreign/Domestic Operations			—				—				(4	)			—				(4	)
Plant-Related Items			8				—				—				—				8
Other			(3	)			2				2				1				2

Total Income Tax Expense (Benefit)		$	91			$	147			$	(54	)		$	(25	)		$	159

Effective Income Tax Rate			44.8	%			41.6	%			40.0	%			38.5	%			44.7	%

(A)

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

PSEG, PSE&G, Power and Energy Holdings adopted FIN 48 effective January 1, 2007, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that it has taken or expects to take on a tax return. For additional information, see Note 2. Recent Accounting Standards. Upon adoption, PSEG, PSE&G, Power and Energy Holdings recorded the following amounts related to their respective uncertain tax positions:


	PSE&G				Power				Energy Holdings				Other (B)			PSEG Consolidated
Unrecognized Tax Benefits (A)		$	55			$	21			$	408			$	1		$	485
Accumulated Deferred Income Taxes associated with Unrecognized Tax Benefits			(15	)			(7	)			(246	)			—			(268	)
Regulatory Asset-Unrecognized Tax Benefits			(11	)			—				—				—			(11	)

Unrecognized Tax Benefits that, if recognized, would impact the effective tax rate (A)		$	29			$	14			$	162			$	1		$	206

Interest and Penalties Accrued		$	4			$	3			$	82			$	—		$	89

(A)

Includes interest and penalties

(B)

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

There were no material changes to the amounts above during the quarter ended June 30, 2007. Net income for PSEG, Power and Energy Holdings could be impacted by changes to FIN 48 liabilities as determined by changes in substantive tax law and tax audit results. PSEG, PSE&G, Power and Energy Holdings include all accrued interest and penalties required to be recorded under FIN 48 as income tax expense.

Income tax years for PSEG, PSE&G, Power and Energy Holdings that remain subject to examination by material jurisdictions, where an examination has not already concluded, are as follows:


	PSE&G	Power	Energy Holdings	PSEG Consolidated
United States
Federal	2001-2006	2001-2006	2001-2006	2001-2006
New Jersey	2001-2006	N/A	1997-2006	1997-2006
Pennsylvania	2003-2006	N/A	2003-2006	2003-2006
Connecticut	N/A	N/A	N/A	2003-2006
Texas	N/A	N/A	2006	2006
California	N/A	N/A	2002-2006	2002-2006
Indiana	N/A	N/A	N/A	2003-2006
Ohio	N/A	N/A	N/A	2003-2005
Foreign
Chile	N/A	N/A	2004-2006	2004-2006
Peru	N/A	N/A	2002-2006	2002-2006

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 12. Financial Information by Business Segments

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


	PSE&G				Power				Energy Holdings											Other (B)				Consolidated Total
									Resources			Global				Other (A)
	(Millions)
For the Quarter Ended June 30, 2007:
Total Operating Revenues		$	1,748			$	1,305			$	35		$	302			$	2			$	(582	)		$	2,810
Income (Loss) from Continuing Operations			63				187				15			44				—				(16	)			293
Loss from Discontinued Operations, net of tax			—				(3	)			—			(15	)			—				—				(18	)
Net Income (Loss)			63				184				15			29				—				(16	)			275
Preferred Securities Dividends			(1	)			—				—			—				—				1				—
Segment Earnings (Loss)			62				184				15			29				—				(15	)			275
Gross Additions to Long-Lived Assets			166				197				—			12				1				8				384
For the Quarter Ended June 30, 2006:
Total Operating Revenues		$	1,490			$	1,129			$	46		$	304			$	3			$	(430	)		$	2,542
Income (Loss) from Continuing Operations			34				85				19			(125	)			(1	)			(20	)			(8	)
Loss from Discontinued Operations, net of tax			—				(8	)			—			(3	)			—				—				(11	)
Gain on Disposal of Discontinued Operations, net of tax			—				—				—			228				—				—				228
Net Income (Loss)			34				77				19			100				(1	)			(20	)			209
Preferred Securities Dividends			(1	)			—				—			—				—				1				—
Segment Earnings (Loss)			33				77				19			100				(1	)			(19	)			209
Gross Additions to Long-Lived Assets			151				75				—			6				—				1				233
For the Six Months Ended June 30, 2007:
Total Operating Revenues		$	4,234			$	3,454			$	79		$	499			$	4			$	(1,857	)		$	6,413
Income (Loss) from Continuing Operations			195				406				31			31				(1	)			(35	)			627
Loss from Discontinued Operations, net of tax			—				(9	)			—			(14	)			—				—				(23	)
Net Income (Loss)			195				397				31			17				(1	)			(35	)			604
Preferred Securities Dividends			(2	)			—				—			—				—				2				—
Segment Earnings (Loss)			193				397				31			17				(1	)			(33	)			604
Gross Additions to Long Lived Assets			296				323				—			28				1				11				659
For the Six Months Ended June 30, 2006:
Total Operating Revenues		$	3,783			$	3,096			$	93		$	553			$	5			$	(1,541	)		$	5,989
Income (Loss) from Continuing Operations			112				206				38			(118	)			(2	)			(39	)			197
(Loss) Income from Discontinued Operations, net of tax			—				(17	)			—			4				—				—				(13	)
Gain on Disposal of Discontinued Operations, net of tax			—				—				—			228				—				—				228
Net Income (Loss)			112				189				38			114				(2	)			(39	)			412
Preferred Securities Dividends			(2	)			—				—			—				—				2				—
Segment Earnings (Loss)			110				189				38			114				(2	)			(37	)			412
Gross Additions to Long Lived Assets			259				193				—			19				1				1				473

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	PSE&G			Power			Energy Holdings									Other (B)				Consolidated Total
	PSE&G			Power			Resources			Global			Other (A)			Other (B)				Consolidated Total
	(Millions)
As of June 30, 2007:
Total Assets		$	14,614		$	7,905		$	2,929		$	3,089		$	94		$	(173	)		$	28,458
Investments in Equity Method Subsidiaries		$	—		$	18		$	9		$	810		$	—		$	—			$	837
As of December 31, 2006:
Total Assets		$	14,553		$	8,146		$	2,969		$	3,095		$	100		$	(293	)		$	28,570
Investments in Equity Method Subsidiaries		$	—		$	16		$	5		$	817		$	—		$	—			$	838

(A)

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

(B)

PSEG’s other activities include amounts applicable to PSEG (as parent 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 BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 13. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at PSEG, as parent corporation.

Note 13. Related-Party Transactions

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

BGS and BGSS Contracts

PSE&G and Power

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

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


	Power’s Billings for the
	Quarters Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(Millions)
BGS		$	263		$	163		$	480		$	264
BGSS		$	315		$	257		$	1,364		$	1,260

As of June 30, 2007 and December 31, 2006, Power had net receivables from PSE&G of approximately $200 million and $370 million, respectively, primarily related to the BGS and BGSS contracts. In addition, as of June 30, 2007 and December 31, 2006, PSE&G had a payable to Power of approximately $67 million and $174 million, respectively, related to gas supply hedges Power entered into for BGSS.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Services

PSE&G, Power and Energy Holdings

Services provides and bills administrative services to PSE&G, Power and Energy Holdings. In addition, PSE&G, Power and Energy Holdings have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. The billings for administrative services and payables are presented below:


	Services’ Billings for the
	Quarters Ended June 30,						Six Months Ended June 30,						Payable to Services as of
	2007			2006			2007			2006			June 30, 2007			December 31, 2006
	(Millions)
PSE&G		$	58		$	53		$	107		$	108		$	30		$	41
Power		$	34		$	33		$	67		$	70		$	17		$	21
Energy Holdings		$	5		$	4		$	10		$	9		$	2		$	2

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

Tax Sharing Agreements

PSEG, PSE&G, Power and Energy Holdings

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


	Payable to PSEG as of
	June 30, 2007			December 31, 2006
	(Millions)
PSE&G		$	45		$	63
Power		$	18		$	28
Energy Holdings		$	9		$	10

As a result of the adoption of FIN 48, PSE&G, Power and Energy Holdings each recorded payables to PSEG related to uncertain tax positions. See Note 2. Recent Accounting Standards. Such amounts as of June 30, 2007 were as follows:


	Payable to PSEG as of June 30, 2007
	(Millions)
PSE&G		$	59
Power		$	26
Energy Holdings		$	434

Affiliate Loans and Advances

PSEG and Power

As of June 30, 2007, Power had a demand note receivable of $214 million due from PSEG. As of December 31, 2006, Power had a demand note payable to PSEG of approximately $54 million for short- term funding needs.

PSEG and Energy Holdings

As of June 30, 2007 and December 31, 2006, Energy Holdings had a demand note receivable due from PSEG of $30 million and $28 million, respectively. These notes reflect the investment of Energy Holdings’ excess cash with PSEG.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

PSE&G and Services

As of each of June 30, 2007 and December 31, 2006, PSE&G had advanced working capital to Services of approximately $33 million. This amount is included in Other Noncurrent Assets on PSE&G’s Condensed Consolidated Balance Sheets.

Power and Services

As of each of June 30, 2007 and December 31, 2006, Power had advanced working capital to Services of approximately $17 million. This amount is included in Other Noncurrent Assets on Power’s Condensed Consolidated Balance Sheets.

Other

PSEG and PSE&G

As of June 30, 2007 and December 31, 2006, PSE&G had net receivables from PSEG of approximately $4 million and $3 million, respectively, related to amounts that PSEG had collected on PSE&G’s behalf.

PSEG and Power

As of June 30, 2007 and December 31, 2006, Power had net receivables from PSEG of approximately $5 million and $1 million, respectively, related to amounts that PSEG had collected on Power’s behalf.

Energy Holdings and PSE&G

As of each of June 30, 2007 and December 31, 2006, Energy Holdings had a receivable of approximately $1 million related to efficiency incentive initiatives performed for PSE&G’s customers. Energy Holdings recorded revenues for such services of approximately $1 million and $3 million for the quarters ended June 30, 2007 and 2006, respectively, and approximately $2 million and $7 million for the six months ended June 30, 2007 and 2006, respectively.

Note 14. Guarantees of Debt

Power

Each series of Power’s Senior Notes and Pollution Control Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries.


	Power				Guarantor Subsidiaries				Other Subsidiaries				Consolidating Adjustments				Consolidated Total
For the Quarter ended June 30, 2007
Revenues		$	—			$	1,558			$	27			$	(280	)		$	1,305
Operating Expenses			—				1,223				28				(282	)			969

Operating Income (Loss)			—				335				(1	)			2				336
Equity Earnings (Losses) of Subsidiaries			188				(10	)			—				(178	)			—
Other Income			52				65				—				(62	)			55
Other Deductions			(1	)			(34	)			—				1				(34	)
Interest Expense			(55	)			(33	)			(12	)			61				(39	)
Income Tax (Expense)/Benefit			—				(135	)			6				(2	)			(131	)
Loss on Discontinued Operations, Including Loss on Disposal, net of Tax Benefit			—				—				(3	)			—				(3	)

Net Income (Loss)		$	184			$	188			$	(10	)		$	(178	)		$	184

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power				Guarantor Subsidiaries				Other Subsidiaries				Consolidating Adjustments				Consolidated Total
	(millions)
For the Quarter ended June 30, 2006
Revenues		$	—			$	1,389			$	37			$	(297	)		$	1,129
Operating Expenses			1				1,233				31				(298	)			967

Operating (Loss) Income			(1	)			156				6				1				162
Equity Earnings (Losses) of Subsidiaries			85				(12	)			—				(73	)			—
Other Income			42				44				1				(53	)			34
Other Deductions			—				(13	)			(1	)			—				(14	)
Interest Expense			(54	)			(24	)			(11	)			53				(36	)
Income Tax Benefit/(Expense)			5				(67	)			1				—				(61	)
Loss on Discontinued Operations			—				1				(9	)			—				(8	)

Net Income (Loss)		$	77			$	85			$	(13	)		$	(72	)		$	77

For the Six Months ended June 30, 2007
Revenues		$	—			$	3,959			$	54			$	(559	)		$	3,454
Operating Expenses			—				3,237				52				(560	)			2,729

Operating Income			—				722				2				1				725
Equity Earnings (Losses) of Subsidiaries.			405				(22	)			—				(383	)			—
Other Income			101				131				—				(126	)			106
Other Deductions			(1	)			(63	)			—				1				(63	)
Interest Expense			(109	)			(68	)			(23	)			124				(76	)
Income Tax Benefit/(Expense)			1				(295	)			9				(1	)			(286	)
Loss on Discontinued Operations			—				—				(9	)			—				(9	)

Net Income (Loss)		$	397			$	405			$	(21	)		$	(384	)		$	397

For the Six Months ended June 30, 2006
Revenues		$	—			$	3,583			$	70			$	(557	)		$	3,096
Operating Expenses			1				3,217				57				(558	)			2,717

Operating (Loss) Income			(1	)			366				13				1				379
Equity Earnings (Losses) of Subsidiaries.			198				(23	)			—				(175	)			—
Other Income			82				89				1				(97	)			75
Other Deductions			—				(32	)			(1	)			—				(33	)
Interest Expense			(97	)			(46	)			(22	)			97				(68	)
Income Tax Benefit/(Expense)			7				(156	)			2				—				(147	)
Loss on Discontinued Operations			—				1				(18	)			—				(17	)

Net Income (Loss)		$	189			$	199			$	(25	)		$	(174	)		$	189

For the Six Months ended June 30, 2007
Net Cash Provided By (Used In) Operating Activities		$	145			$	942			$	(41	)		$	(252	)		$	794
Net Cash Provided By (Used In) Investing Activities		$	430			$	(189	)		$	(36	)		$	(377	)		$	(172	)
Net Cash (Used In) Provided By Financing Activities		$	(575	)		$	(759	)		$	77			$	628			$	(629	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


	Power				Guarantor Subsidiaries				Other Subsidiaries				Consolidating Adjustments				Consolidated Total
	(millions)
For the Six Months ended June 30, 2006
Net Cash Provided By (Used In) Operating Activities		$	1,841			$	(767	)		$	(7	)		$	(346	)		$	721
Net Cash (Used In) Provided By Investing Activities		$	(1,341	)		$	747			$	7			$	420			$	(167	)
Net Cash (Used In) Provided By Financing Activities		$	(500	)		$	17			$	—			$	(74	)		$	(557	)
As of June 30, 2007
Current Assets		$	2,339			$	3,293			$	345			$	(3,982	)		$	1,995
Property, Plant and Equipment, net			150				3,400				879				1				4,430
Investment in Subsidiaries			3,609				187				—				(3,796	)			—
Noncurrent Assets			182				1,556				34				(292	)			1,480

Total Assets		$	6,280			$	8,436			$	1,258			$	(8,069	)		$	7,905

Current Liabilities		$	73			$	3,945			$	984			$	(3,980	)		$	1,022
Noncurrent Liabilities			283				883				86				(293	)			959
Long-Term Debt			2,818				—				—				—				2,818
Member’s Equity			3,106				3,608				188				(3,796	)			3,106

Total Liabilities and Member’s Equity		$	6,280			$	8,436			$	1,258			$	(8,069	)		$	7,905

As of December 31, 2006
Current Assets		$	1,982			$	3,416			$	531			$	(3,441	)		$	2,488
Property, Plant and Equipment, net			150				3,226				854				—				4,230
Investment in Subsidiaries			4,287				201				—				(4,488	)			—
Noncurrent Assets			173				1,398				79				(222	)			1,428

Total Assets		$	6,592			$	8,241			$	1,464			$	(8,151	)		$	8,146

Current Liabilities		$	97			$	3,179			$	1,251			$	(3,443	)		$	1,084
Noncurrent Liabilities			253				776				12				(220	)			821
Long-Term Debt			2,818				—				—				—				2,818
Member’s Equity			3,424				4,286				201				(4,488	)			3,423

Total Liabilities and Member’s Equity		$	6,592			$	8,241			$	1,464			$	(8,151	)		$	8,146

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 2006 Annual Report on Form 10-K affecting the consolidated financial condition and the results of operations. This discussion refers to the Condensed Consolidated Financial Statements (Statements) and the related Notes to Condensed Consolidated Financial Statements (Notes) and should be read in conjunction with such Statements and Notes.

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

OVERVIEW OF 2007 AND FUTURE OUTLOOK

PSEG, PSE&G, Power and Energy Holdings

PSEG’s business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C. (Resources). The following discussion relates to the markets in which PSEG’s subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets, significant events that have occurred during the first half of 2007 and future outlook for PSE&G, Power and Energy Holdings, as well as the key factors that will drive the future performance of these businesses.

PSE&G

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

Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. On November 9, 2006, PSE&G reached settlement agreements in the Gas Base Rate Case and Electric Distribution Financial Review, which were approved by the BPU. The settlement in the Gas Base Rate Case provides for an annual increase in gas revenues of $40 million, an adjustment to lower book depreciation expense for PSE&G by approximately $26 million annually and the amortization of accumulated cost of removal that will further reduce depreciation and amortization expense by $13 million annually for five years. The electric settlement authorizes a reduction in the former excess depreciation rate credit to $22 million, resulting in additional revenue to PSE&G of approximately $47 million annually based on current sales volumes.

PSE&G believes that the decisions in November 2006 for both gas and electric base rates position it to earn reasonable returns on its investments. The full year impact of these decisions combined with an anticipated return to more normal weather conditions is expected to improve PSE&G’s margins for 2007 and beyond. Currently, PSE&G’s authorized rates of return on electric and gas rate base are 8.18% and 7.96%, respectively. PSE&G must file a joint electric and gas petition for any future base rate increases, with no base rate changes becoming effective before November 15, 2009.

Overview and Future Outlook

In February 2007, the BPU approved the results of New Jersey’s annual Basic Generation Service (BGS)-Fixed Price (FP) and BGS-Commercial and Industrial Energy Price (CIEP) auctions and PSE&G successfully secured contracts to provide the electricity requirements for the majority of its customers’ needs.

On April 19, 2007, PSE&G filed a plan with the BPU designed to spur investment in solar power in New Jersey and meet energy goals under the New Jersey Energy Master Plan. Under the plan, PSE&G would invest approximately $100 million over two years to help finance the installation of solar systems throughout its service area. An initial working group meeting was held with interested parties on July 18, 2007, with continued discussions expected through August 2007.

On June 8, 2007, PSE&G endorsed the construction of three new 500 kV transmission lines intended to significantly improve the reliability of the electrical grid serving New Jersey customers. PJM’s Board of Managers approved construction of one of the proposed lines and assigned construction responsibility to PSE&G, Pennsylvania Power and Light (PPL) and FirstEnergy Corporation (FirstEnergy) for their respective service territories. PSE&G currently expects to spend between $550 million and $650 million in connection with the construction of its portion of this new transmission line. PSE&G’s portion of this project will go into transmission rate base, and can be expected to have a positive impact on revenues and earnings for PSE&G.

The two other lines which PSE&G has endorsed have not yet been submitted to PJM for approval, as required by FERC rules, but PSE&G believes that construction of these lines, which would follow existing transmission rights-of-way, are needed to enhance the reliability of the transmission system and to relieve congestion within New Jersey.

PSE&G has increased its forecasted capital expenditures to include the above noted amounts for the investment in solar power and construction of the approved new transmission lines. See Capital Requirements for additional information.

The risks to PSE&G’s business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically the BPU and FERC. PSE&G’s success will depend, in part, on its ability to attain a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels, continue recovery of the regulatory assets it has deferred and attain an adequate return on the investments it plans to make in its electric and gas transmission and distribution system and the level of recovery of distribution revenues in light of customer demand and conservation efforts. FERC’s recent ruling regarding PJM long-term transmission rate design, discussed in Part II.—Item 5. Other Information—Federal Regulation, is also expected to have a positive impact as PSE&G’s current transmission rate structure will remain in place. Since PSE&G earns no margin on the commodity portion of its electric and gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G; however, commodity costs continue to put upward pressure on customer charges. On June 1, 2007, new electric Basic Generation Service (BGS)-Fixed Price (FP) rates went into effect with an expected increase of approximately 12% to residential customers’ bills. Also on June 1, 2007, PSE&G filed for a 2% increase in the BGSS gas rate effective October 1, 2007.

Power

Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market in the Northeast and Mid Atlantic U.S. Power’s principal operating subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Certain subsidiaries of Fossil are subject to state regulation and Nuclear is also subject to regulation by the NRC. Through its subsidiaries, Power seeks to produce low-cost energy through efficient operations of its nuclear, coal and gas-fired generation facilities, balance its generation production, fuel requirements and supply obligations through energy portfolio management and pursue disciplined growth. In addition to the electric generation business, Power’s revenues include gas supply sales under the Basic Gas Supply Service (BGSS) contract with PSE&G.

As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, the availability of Power’s diverse fleet of generation units to produce these products as well as the prices of commodities, such as electricity, gas, nuclear fuel, coal and emissions, can have a material effect on Power’s profitability. In recent years, the prices at which transactions are entered into for future delivery of these products, as evidenced through the market for forward contracts at points such as PJM West, have escalated considerably over historical prices. Broad market price increases such as these are expected to have a positive effect on Power’s results. Historically, Power’s nuclear and coal-fired facilities have produced over 50% and 25% of Power’s production, respectively. With the vast majority of its power sourced from these lower-cost units, the rise in electric prices is anticipated to yield higher near-term margins for Power. Over a longer- term horizon, if these higher prices are sustained at levels reflective of what the current forward markets indicate, Power would have an attractive environment in which to contract for the sale of its anticipated output, allowing for potentially sustained higher profitability than recognized in prior years. These prices also increase the cost of replacement power, thereby placing incremental risk on the

operations of the generating units to produce these products. Further, changes in the operation of Power’s generating facilities, fuel and capacity prices, expected contract prices, capacity factors or other assumptions could materially affect its ability to meet earnings targets and/or liquidity requirements.

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

Power seeks to sell a portion of its anticipated low-cost nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of approximately two to three years. By contrast, Power takes a more opportunistic approach in hedging its anticipated natural gas-fired generation. The generation from these units is less predictable, as these units are generally dispatched only when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units generally provide a lower contribution to the margin of Power than either the nuclear or coal units. Power will generally purchase natural gas as gas-fired generation is required to supply forward sale commitments.

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

Overview and Future Outlook

During the first half of 2007, Power continued to benefit from strong energy markets and sustained improvement in the performance of its generating facilities. Going forward, Power expects margin improvements to continue in 2007 as higher prices for its nuclear and coal-fired generation output are realized due to the rolling nature of its forward hedge positions and the expiration of older power contracts.

In April 2007, Power completed the sale of four turbines to a third party and received proceeds of $40 million, which approximated the recorded book value. On May 16, 2007, Power closed on the sale of the Lawrenceburg facility at a sale price of $325 million.

The improvement in margins coupled with these asset sales allowed Power to make dividend payments to PSEG of $125 million in March 2007 and $450 million in June 2007. In May 2007, PSEG used a portion of the dividends to redeem the outstanding $375 million of its Senior Floating Rate Notes Due 2008.

In PJM, the Reliability Pricing Model (RPM) provides generators with capacity payments for the reliability provided by their respective facilities. The Forward Capacity Market (FCM) in the New England Power Pool provides for similar reliability-based capacity payments. FERC has approved the market changes in each of these markets, beginning on June 1, 2007 for the RPM transition period and on December 1, 2006 for the FCM transition period. Power believes that this redesign in capacity markets will lead to changes in the value of the majority of its generating capacity and could result in incremental margin of $125 million to $175 million in 2007, with higher increases in future years as the full year impact is realized and existing capacity contracts expire.

On April 13, 2007 and on July 13, 2007, respectively, PJM announced the results of its first base residual auction for the 2007–2008 delivery year and its second base residual auction for the 2008-2009 delivery year. The prices received by generation assets, including those of Power, located within the Eastern Mid Atlantic Area Council (MAAC) zone and PJM other than within the Eastern and Southwest MAAC zones (rest of Pool) cleared at the prices listed in the following table.


	Delivery Year
Zones	June 1, 2007 to May 31, 2008						June 1, 2008 to May 31, 2009
	MW-day			kW-yr			MW-day			kW-yr
Eastern MAAC		$	197.67		$	72.15		$	148.80		$	54.31
Other PJM		$	40.80		$	14.89		$	111.92		$	40.85

The capacity price that will be charged to load serving entities for obligations in the Eastern MAAC zone is $177.51/MW-day ($65/kW-yr) in the 2007–2008 delivery year and $143.51/MW-day ($56/kW- yr) in the 2008–2009 delivery year.

Only a portion of Power’s capacity was open to realize prices in the recent RPM auctions in PJM since a significant portion of Power’s capacity was contracted as part of the three-year BGS auctions in which Power had won 11 tranches in 2005, 20 tranches in 2006 and 19 tranches in 2007, as well as other contracting activity. On average, each of these fixed price BGS tranches requires approximately 120 MW of capacity on a daily basis.

The balance of Power’s PJM capacity has obtained price certainty through May 31, 2009 from the first two RPM auctions. Power has obtained price certainty for all of its capacity in New England through May 31, 2010 as a result of the fixed price nature of the transitional FCM auction.

Existing capacity hedges support Power’s forecast year-over-year improvement in capacity margin for 2007 of $125 million to $175 million with similar incremental improvement forecasted for in 2008. Power expects to have increasing amounts of capacity available to realize prices in future years.

On a prospective basis, many factors will affect the pricing for capacity in PJM, including but not limited to:

•

changes in demand;

•

changes in available generating capacity (including retirements, additions, derates, forced outage rates, etc.);

•

increases in transmission capability between zones; and

•

changes to the pricing mechanism created by PJM, including increasing the potential number of zones in future years, as well as other potential changes that PJM may propose over time.

Management cannot predict what pricing will result from future auctions.

As a normal part of its contracting strategy, Power enters into contracts to sell capacity for future delivery. One such contract is New Jersey’s BGS contract, which is fixed rate and includes several energy-related components, one of which is capacity. As a result, only a portion of Power’s total PJM capacity was available to realize prices that resulted from the RPM auctions for 2007–2008 and 2008–2009. However, Power anticipates increasing capacity amounts available to realize auction prices for future years as its existing contracts roll off.

A key factor in Power’s ability to achieve its objectives is its ability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to satisfy its obligations. Power’s ability to achieve its objectives will also depend on the continuation of reasonable capacity markets. Power must also be able to effectively manage its construction projects and continue to economically operate its generation facilities under increasingly stringent environmental requirements, including legislation, regulation and voluntary restrictions to address:

•

the control of carbon emissions to reduce the effects of global climate change and greenhouse gas;

•

other emissions such as NO_x, SO₂ and mercury; and

•

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

In addition, with an increase in competition and market complexity and constantly changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While these increases may have a potentially significant beneficial impact on margins, they could also raise any replacement power costs that Power may incur in the event of unanticipated outages, and could also further increase liquidity requirements as a result of contract obligations. Power could also be impacted by a number of market and regulatory events, including but not limited to, the lack of consistent rules in markets outside of PJM, rate-regulated utility ownership of generation and other regulatory actions favoring non-competitive markets, and regulatory policies favoring the construction of west-to-east rate based transmission that may result in increased imports of generation into areas served by Power’s generation assets. For additional information on liquidity requirements, see Liquidity and Capital Resources.

Energy Holdings

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

Global

Global owns investments in power producers and distributors that own and operate electric generation and distribution facilities in select domestic and international markets.

Approximately 68% of Global’s investments are in Chile and Peru, with another 25% in the United States. Other modest-sized investments in Italy, India and Venezuela comprise the remaining 7% of Global’s portfolio. The above investment percentage for Chile and Peru includes Electroandes as a sale has not been completed. Global’s investments in Chile and Peru (excluding Electroandes) and in the United States account for 38% and 32%, respectively, of Energy Holdings’ earnings for the six months ended June 30, 2007. As such, Global’s success is driven by the energy markets in Texas and the economic and efficient operation of its electric distribution companies in Chile and Peru, including its ability to achieve reasonable rates and meet expected growth in demand. The value of Global’s foreign investments will also depend on stable political, regulatory and economic policies, including foreign currency exchange rates and interest rates, particularly for Chile and Peru.

Global’s domestic operations continue to perform well and provide the opportunity for growth. As a merchant generation business with a load-following asset profile, the results of Global’s Texas generation facilities are driven by changes in market conditions, particularly projected market heat rates and weather. Its results are also impacted by the recognition of unrealized mark-to-market (MTM) gains and losses on fixed-price contracts that expire in 2010.

Resources

Resources primarily has invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments. Resources’ investments, net of deferred taxes, are approximately $1.1 billion, approximately 90% of which relates to energy-related leveraged leases. Resources also continues to own interests in three airplanes, which are under lease to Northwest Airlines for an aggregate book value investment of approximately $39 million. Northwest exited bankruptcy in May 2007. Northwest and the bankruptcy court have agreed to Resources’ claims related to the amended leases, valued at approximately $18 million, with an expected recovery of approximately $10 million, pre-tax, in the form of a Northwest stock distribution. The recovery will be recorded as a gain upon receipt of the stock distribution of which approximately $7 million was received in July 2007.

Resources’ future performance is also subject to tax risks related to its lease transactions. See Note 5. Commitments and Contingent Liabilities of the Notes for further discussion.

Overview and Future Outlook

Energy Holdings expects decreased margins at Global in 2007 primarily relating to the anticipated absence of MTM gains at the Texas generation facilities and scheduled maintenance outages at the Texas generation facilities that were completed in the first half of 2007. Also contributing to the expected decrease are higher taxes due to the impact of adopting Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48) and related standards and lower earnings due to asset sales.

Energy Holdings continues to review Global’s portfolio, with a focus on optimizing operations at its distribution companies to improve earnings and increase value and will consider opportunistic monetizations, as appropriate, based on valuations and potential alternate uses of capital. Consistent with this strategy, and in conjunction with the market’s increasing recognition of the value of distribution companies in the high-growth Chilean and Peruvian markets, Global is more actively exploring its strategic options for these investments.

With respect to Global’s international generation investments, in March 2007, Global announced that it was exploring a potential sale of Electroandes S.A. (Electroandes), its 180 MW hydro-electric generation and transmission company in Peru. In June 2007, based on the strong investor interest in this project as evidenced

in the auction process to date and the expected close by the end of the year, subject to regulatory approvals, Energy Holdings reclassified the investment to Discontinued Operations. As of June 30, 2007, the book value of Electroandes was approximately $166 million. Energy Holdings will evaluate the use of the proceeds, including potential debt reduction, loans and/or dividends to PSEG, new investments in domestic generation and general corporate purposes.

Global is also exploring options for its aggregate $140 million equity investment in three other international generation projects, Bioenergie S.p.A. (Bioenergie) in Italy, Turboven Company Inc. (Turboven) in Venezuela and Power Generating Company Limited (PPN) in India. In June 2007, Global restarted Bionergie’s San Marco biomass generation facility after a seven-month outage due to a criminal investigation regarding allegations of violations of the facility’s air permit. With respect to Global’s investment in Turboven, Global recently entered into preliminary valuation discussions with the government of Venezuela as part of the nationalization efforts. No assurances can be given as to whether Global can recover the current book value of the investments in Venezuela. Global’s investment in India is currently more stable than in prior years as evidenced by dividend payments of $3 million in 2007 and $4 million in 2006.

Energy Holdings faces risks related to the tax treatment of uncertain tax positions which will be impacted by new accounting guidance under FIN 48 and FASB Staff Position No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FAS 13-2), both of which were effective as of January 1, 2007. Based on its evaluation of this new guidance, Energy Holdings recorded a reduction to its opening 2007 Retained Earnings of approximately $176 million. In addition, this new guidance will have an impact on Energy Holdings’ future earnings, including an anticipated earnings after-tax reduction of $29 million in 2007, which represents the majority of the anticipated impact on PSEG. Energy Holdings’ future earnings could also be impacted by changes to FIN 48 liabilities as determined by changes in substantive tax law and tax audit results, including resolution of tax audit claims associated with Resources’ leveraged lease transactions. See Note 2. Recent Accounting Standards and Note 5. Commitments and Contingent Liabilities of the Notes for further discussion.

RESULTS OF OPERATIONS

The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and six months ended June 30, 2007 and 2006 are presented below:


	Earnings (Losses)
	Quarters Ended June 30,								Six Months Ended June 30,
	2007				2006				2007				2006
	(Millions)
PSE&G		$	63			$	34			$	195			$	112
Power			187				85				406				206
Energy Holdings:
Global			44				(125	)			31				(118	)
Resources			15				19				31				38
Other (A)			—				(1	)			(1	)			(2	)

Total Energy Holdings			59				(107	)			61				(82	)
Other (B)			(16	)			(20	)			(35	)			(39	)

PSEG Income (Loss) from Continuing Operations			293				(8	)			627				197
(Loss) Income from Discontinued Operations, including Gain in 2006 on Disposal (C)			(18	)			217				(23	)			215

PSEG Net Income		$	275			$	209			$	604			$	412


	Earnings Per Share (Diluted)
	Quarters Ended June 30,								Six Months Ended June 30,
	2007				2006				2007				2006
PSEG Income from Continuing Operations		$	1.15			$	(0.03	)		$	2.47			$	0.79
Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal (C)			(0.07	)			0.86				(0.09	)			0.85

PSEG Net Income		$	1.08			$	0.83			$	2.38			$	1.64

(A)

Other activities include non-segment amounts of Energy Holdings and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings.

(B)

Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include preferred securities dividends for PSE&G in 2007 and 2006, merger expenses in 2006, interest on certain financing transactions and certain other administrative and general expenses at PSEG (as parent company) in 2007 and 2006.

(C)

Includes Discontinued Operations of Electroandes and Lawrenceburg in 2007 and 2006 and the Gain on Disposal of Skawina and Elcho and their Discontinued Operations in 2006. See Note 3. Discontinued Operations, Dispositions and Impairments of the Notes.

As shown in the table above, PSEG had Income from Continuing Operations of $293 million, or $1.15 per share for the quarter ended June 30, 2007, as compared to a Loss from Continuing Operations of $8 million, or $(0.03) per share for the same quarter in 2006. PSEG’s Net Income for the quarter ended June 30, 2007 was $275 million or $1.08 per share, as compared to Net Income of $209 million, or $0.83 per share for the second quarter of 2006.

PSEG had Income from Continuing Operations of $627 million, or $2.47 per share for the six months ended June 30, 2007, as compared to $197 million, or $0.79 per share for the same period in 2006. PSEG’s Net Income for the six months ended June 30, 2007 was $604 million or $2.38 per share, as compared to Net Income of $412 million, or $1.64 per share for the same period in 2006.

The changes in PSEG’s Income from Continuing Operations and Net Income primarily relate to changes in Net Income for PSE&G, Power and Energy Holdings, discussed below.

PSEG


	For the Quarters Ended June 30,								Increase (Decrease)				%			For the Six Months Ended June 30,								Increase (Decrease)				%
	2007				2006				Increase (Decrease)				%			2007				2006				Increase (Decrease)				%
					(Millions)															(Millions)
Operating Revenues		$	2,810			$	2,542			$	268			11			$	6,413			$	5,989			$	424			7
Energy Costs		$	1,389			$	1,338			$	51			4			$	3,427			$	3,483			$	(56	)		(2	)
Operation and Maintenance		$	592			$	576			$	16			3			$	1,198			$	1,149			$	49			4
Write-down of Project Investment		$	—			$	263			$	(263	)		(100	)		$	—			$	263			$	(263	)		(100	)
Depreciation and Amortization		$	195			$	201			$	(6	)		(3	)		$	390			$	401			$	(11	)		(3	)
Income from Equity Method Investments		$	27			$	30			$	(3	)		(10	)		$	53			$	63			$	(10	)		(16	)
Other Income and Deductions		$	21			$	35			$	(14	)		(40	)		$	56			$	58			$	(2	)		(3	)
Interest Expense		$	(184	)		$	(197	)		$	(13	)		(7	)		$	(369	)		$	(388	)		$	(19	)		(5	)
Income Tax Expense		$	(174	)		$	(12	)		$	162			N/A			$	(436	)		$	(159	)		$	277			N/A
(Loss) Income from Discontinued Operations, including Gain on Disposal in 2006, net of tax		$	(18	)		$	217			$	(235	)		N/A			$	(23	)		$	215			$	(238	)		N/A

PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings, excluding changes related to intercompany transactions, which are eliminated in consolidation, and certain financing costs at the parent company. For additional information on intercompany transactions, see Note 13. Related-Party Transactions of the Notes. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for PSE&G, Power and Energy Holdings that follow.

PSE&G

For the quarter ended June 30, 2007, PSE&G had Net Income of $62 million, an increase of $29 million as compared to the quarter ended June 30, 2006. For the six months ended June 30, 2007, PSE&G had Net Income of $193 million, an increase of $83 million as compared to the same period in 2006. These increases were primarily due to increased volumes due to weather and price increases resulting from the electric and gas base rate cases settled in November 2006. For the quarter as compared to the same period in 2006, gas delivery volumes increased 21% and electric delivery volumes increased 2%. For the six months as compared

to the same period in 2006, gas delivery volumes increased 12% and electric delivery volumes increased 2%. The weather was the primary cause of the increases as degree days increased 17%.

The detail for the variances is discussed below:


	For the Quarters Ended June 30,								Increase (Decrease)				%			For the Six Months Ended June 30,								Increase (Decrease)				%
	2007				2006				Increase (Decrease)				%			2007				2006				Increase (Decrease)				%
					(Millions)															(Millions)
Operating Revenues		$	1,748			$	1,490			$	258			17			$	4,234			$	3,783			$	451			12
Energy Costs		$	1,077			$	901			$	176			20			$	2,742			$	2,475			$	267			11
Operation and Maintenance		$	314			$	276			$	38			14			$	639			$	577			$	62			11
Depreciation and Amortization		$	143			$	150			$	(7	)		(5	)		$	288			$	302			$	(14	)		(5	)
Other Income and Deductions		$	4			$	7			$	(3	)		43			$	8			$	10			$	(2	)		(20	)
Interest Expense		$	(84	)		$	(83	)		$	1			1			$	(165	)		$	(168	)		$	(3	)		(2	)
Income Tax Expense		$	(41	)		$	(26	)		$	15			58			$	(140	)		$	(91	)		$	49			54

Operating Revenues

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

PSE&G makes no margin on gas commodity sales as the costs are passed through to customers. The difference between the gas costs paid under the requirements contract for residential customers and the revenues received from residential customers is deferred and collected from or returned to customers in future periods. Gas commodity prices fluctuate monthly for commercial and industrial customers and annually through the BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual BGSS proceedings.

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

The $258 million increase for the quarter ended June 30, 2007, as compared to the same period in 2006, was due to increases of $177 million in commodity revenues and $78 million in delivery revenues, described below and $3 million in other operating revenues, primarily related to appliance service contracts.

The $451 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was due to increases of $268 million in commodity revenues and $177 million in delivery revenues, described below and $6 million in other operating revenues, primarily related to appliance service contracts.

Commodity

The $177 million increase in commodity related revenues for the quarter ended June 30, 2007, as compared to the same period in 2006, was due to increases in electric revenues of $124 million and gas revenues of $53 million. The increase in electric revenues was primarily due to $121 million in higher BGS and electric non-utility generation transition charge (NGC) revenues (higher auction prices of $112 million and increased sales of $9 million) and $3 million in higher Non-Utility Generation (NUG) revenues (higher prices of $7 million offset by decreased sales of $4 million). The increase in gas revenues was primarily due to $3 million in higher BGSS prices and $50 million in increased sales due to weather.

The $268 million increase in commodity related revenues for the six months ended June 30, 2007, as compared to the same period in 2006, was due to increases in electric revenues of $244 million and gas revenues of $24 million. The increase in electric revenues was primarily due to $250 million in higher BGS

and NGC revenues (higher auction prices of $202 million and increased sales of $48 million) offset by $6 million in lower NUG revenues (decreased sales of $12 million offset by higher prices of $6 million). The increase in gas revenues was primarily due to $142 million in increased sales due to weather offset by $118 million in lower BGSS prices.

Delivery

The $78 million increase in delivery revenues for the quarter ended June 30, 2007, as compared to the same period in 2006, was due to a $45 million increase in electric and a $33 million increase in gas revenues. The electric increase was due primarily to $23 million for increased Societal Benefits Clause (SBC) rates, $11 million from a rate increase effective November 9, 2006 and $11 million in increased sales and demand primarily due to weather. PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses below. The gas increase was due to $21 million in increased sales primarily due to weather, $9 million due to the SBC rate increases November 1, 2006 and March 9, 2007 and $6 million due to rate relief effective November 9, 2006.

The $177 million increase in delivery revenues for the six months ended June 30, 2007, as compared to the same period in 2006, was due to a $102 million increase in gas and a $75 million increase in electric revenues. The gas increase was due to $49 million in increased sales primarily due to weather, $27 million due to the SBC rate increases on November 1, 2006 and March 9, 2007 and $25 million due to rate relief effective November 9, 2006. The electric increase was due primarily to $26 million for increased SBC rates, $22 million from a rate increase effective November 9, 2006 and $27 million in increased sales and demands primarily due to weather. PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses below.

Operating Expenses

Energy Costs

The $176 million increase for the quarter ended June 30, 2007, as compared to the same period in 2006, was comprised of an increase of $124 million in electric costs and $52 million in gas costs. The increase in electric costs was due to a $117 million or 22% in higher prices for BGS and NUG purchases and $14 million or 2% in higher BGS volumes due to weather offset by $7 million or 7% in lower NUG volumes. The increase in gas costs was caused by a $47 million or 19% increase in sales volumes due primarily to weather and $6 million or 7% in higher prices.

The $267 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was comprised of increases of $245 million in electric costs and $22 million in gas costs. The increase in electric costs was due to $218 million or 23% in higher prices for BGS and NUG purchases and $46 million or 5% in higher BGS volumes due to weather, offset by $19 million or 10% in lower NUG volumes. The increase in gas costs was caused by a $137 million or 11% increase in sales volumes due primarily to weather offset by $115 million or 1% in lower prices.

Operation and Maintenance

The $38 million increase for the quarter ended June 30, 2007, as compared to the same period in 2006, was due primarily to increased SBC expenses of $32 million, resulting from rate increases in November 2006 and March 2007. The balance of the increase, $6 million, was due to higher labor costs and storm-related power restoration work.

The $62 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was due primarily to increased SBC expenses of $56 million, resulting from rate increases in November 2006 and March 2007. The balance of the increase, $6 million, was due to higher gas bad debt expense and storm-related power restoration work.

Depreciation and Amortization

The $7 million decrease for the quarter ended June 30, 2007, as compared to the same period in 2006, was due primarily to decreases of $9 million due to revised plant depreciation rates and $3 million due to

lower cost of removal rates, both resulting from the November 2006 rate case. This was offset by increases of $3 million due to amortization of regulatory assets and $2 million due to additional plant in service.

The $14 million decrease for the six months ended June 30, 2007, as compared to the same period in 2006, was due primarily to decreases of $18 million due to revised plant depreciation rates and $7 million due to lower cost of removal rates, both resulting from the November 2006 rate case. This was offset by increases of $7 million due to amortization of regulatory assets and $4 million due to additional plant in service.

Other Income

The $3 million and $2 million decreases for the quarter and six months ended June 30, 2007, respectively, as compared to the same periods in 2006, were primarily due to an income tax gross-up on contributions in aid of construction (CIAC) in 2006. CIAC are taxable and PSE&G recognizes the gross-up as income when collected.

Income Taxes

The $15 million increase for the quarter ended June 30, 2007, as compared to the same period in 2006, was primarily due to increased taxes of $18 million on higher pre-tax income offset by $3 million in various tax adjustments.

The $49 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was primarily due to increased taxes of $54 million on higher pre-tax income offset by $5 million in various tax adjustments.

Power

For the quarter ended June 30, 2007, Power had Net Income of $184 million, an increase of $107 million as compared to the same period in the prior year. For the six months ended June 30, 2007, Power had Net Income of $397 million, an increase of $208 million as compared to the same period in the prior year. The primary reasons for the increases were higher prices realized from new contracts combined with higher sales volumes and lower generation costs. Improved margins and higher sales volumes under the BGSS contract due to a colder winter heating season and more favorable fuel pricing in 2007 also contributed to the increase. The increase for the quarter was partially offset by the recognition of MTM losses of approximately $16 million in 2007 as compared to $2 million of gains in the same quarter in 2006. MTM losses for the six months of $17 million were the same as in the comparable period in 2006.

The detail for the variances is discussed below:


	For the Quarters Ended June 30,								Increase (Decrease)				%			For the Six Months Ended June 30,								Increase (Decrease)				%
	2007				2006				Increase (Decrease)				%			2007				2006				Increase (Decrease)				%
					(Millions)															(Millions)
Operating Revenues		$	1,305			$	1,129			$	176			16			$	3,454			$	3,096			$	358			12
Energy Costs		$	694			$	669			$	25			4			$	2,182			$	2,156			$	26			1
Operation and Maintenance		$	241			$	262			$	(21	)		(8	)		$	479			$	494			$	(15	)		(3	)
Depreciation and Amortization		$	34			$	36			$	(2	)		(6	)		$	68			$	67			$	1			1
Other Income and Deductions		$	21			$	20			$	1			5			$	43			$	42			$	1			2
Interest Expense		$	(39	)		$	(36	)		$	3			8			$	(76	)		$	(68	)		$	8			12
Income Tax Expense		$	(131	)		$	(61	)		$	70			115			$	(286	)		$	(147	)		$	139			95
Loss from Discontinued Operations, net of tax benefit		$	(3	)		$	(8	)		$	(5	)		(63	)		$	(9	)		$	(17	)		$	(8	)		(47	)

Operating Revenues

The $176 million increase for the quarter ended June 30, 2007, as compared to the same period in 2006, was due to increases of $119 million in generation revenues and $65 million in gas supply revenues partially offset by a decrease of $8 million in trading revenues.

The $358 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was due to increases of $213 million in generation revenues and $167 million in gas supply revenues partially offset by a decrease of $22 million in trading revenues.

Generation

Generation revenues increased $119 million for the quarter ended June 30, 2007, as compared to the same period in 2006, primarily due to higher revenues of approximately $82 million from increased volumes and higher prices on BGS fixed-price contracts, $31 million from increased sales volumes at the Bethlehem Energy Center (BEC) and $23 million from higher capacity prices. These increases were partially offset by a decrease of $26 million due to the roll off of wholesale power contracts.

Generation revenues increased $213 million for the six months ended June 30, 2007, as compared to the same period in 2006, primarily due to higher revenues of approximately $141 million from higher prices on BGS fixed-price contracts, partially offset by reduced load being served under the BGS contracts, $55 million from increased sales volumes at the BEC, $35 million from higher energy pool prices and $31 million from higher capacity prices. These increases were partially offset by $49 million of wholesale power contracts rolling off and lower generation due to outages at the Hudson and Salem units.

Gas Supply

Gas supply revenues increased $65 million for the quarter ended June 30, 2007, as compared to the same period in 2006, principally comprised of $42 million of higher sales volumes under the BGSS contract, largely due to colder average temperatures in April 2007 as compared to April 2006 and $20 million of higher prices under the BGSS contract.

Gas supply revenues increased $167 million for the six months ended June 30, 2007, as compared to the same period in 2006, principally due to $208 million of higher sales volumes under the BGSS contract, largely due to colder average temperatures in the 2007 winter heating season partially offset by lower prices of $39 million under the BGSS contract.

Trading Revenues

Trading revenues decreased $8 million and $22 million for the quarter and six months ended June 30, 2007, as compared to the same periods in 2006, due primarily to the absence in 2007 of realized gains in 2006 from sales of excess emissions credits.

Operating Expenses

Energy Costs

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

Energy Costs increased approximately $25 million for the quarter ended June 30, 2007, as compared to the same period in 2006, primarily due to an increase in gas costs of $51 million, reflecting a higher volume of gas purchased to satisfy Power’s BGSS obligations. Generation costs decreased $26 million, reflecting $89 million in lower pool prices and lower load obligations somewhat offset by higher prices for gas and an increased volume of gas fuel purchases.

Energy Costs increased approximately $26 million for the six months ended June 30, 2007, as compared to the same period in 2006, primarily due to an increase in gas costs of $88 million, reflecting a $148 million increase due to a higher volume of gas purchased to satisfy Power’s BGSS obligations partially offset by lower gas prices of $65 million. Generation costs decreased $62 million due to lower pool prices and lower load obligations somewhat offset by higher volumes of oil and gas fuel purchases.

Operation and Maintenance

Operation and Maintenance expense decreased $21 million for the quarter ended June 30, 2007, as compared to the same period in 2006, primarily due to higher maintenance costs in 2006 related to a scheduled refueling outage at the Hope Creek nuclear facility.

Operation and Maintenance expense decreased $15 million for the six months ended June 30, 2007, as compared to the same period in 2006, due to the aforementioned refueling outage in 2006 partly offset by costs incurred in 2007 related to projects at certain fossil stations, mainly Hudson and Mercer.

Depreciation and Amortization

The $2 million decrease for the quarter ended June 30, 2007, as compared to the same period in 2006, was primarily due to the extension of the depreciable lives of certain of the coal-fired generation facilities resulting from continuous investment in replacements and upgrades of production equipment.

The $1 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was primarily due to an increase from the Linden facility being placed into service in May 2006.

Other Income and Deductions

Other Income and Deductions increased $1 million for the quarter ended June 30, 2007, as compared to the same period in 2006, as increases in other income of $14 million attributable to higher realized gains, interest and dividend income related to the Nuclear Decommissioning Trust (NDT) Funds and $7 million in interest earned on increased loans to PSEG were nearly offset by $20 million of other-than-temporary impairments, realized losses and management fees associated with the NDT Funds.

Other Income and Deductions increased $1 million for the six months ended June 30, 2007, as compared to the same period in 2006, as a result of the aforementioned reasons for the quarter. Increases in Other Income of $23 million and $7 million related to the NDT Funds and interest earned on loans to PSEG, respectively, were nearly offset by expenses of $29 million related to the NDT Funds.

Interest Expense

Interest Expense increased $3 million for the quarter ended June 30, 2007, as compared to the same period in 2006, due primarily to lower capitalized interest costs in 2007 related to commencement of operations of the Linden facility in May 2006.

Interest expense increased $8 million for the six months ended June 30, 2007, as compared to the same period in 2006, due to an $18 million increase due to lower IDC related to BEC partly offset by a reduction of $10 million due to the maturity in April 2006 of $500 million of 6.875% Senior Notes.

Income Taxes

Income Taxes increased $70 million and $139 million for the quarter and six months ended June 30, 2007, as compared to the same periods in 2006, primarily due to higher pre-tax income.

Loss from Discontinued Operations, net of tax

On December 29, 2006, Power entered into an agreement to sell its Lawrenceburg generation facility for approximately $325 million and recognized an estimated loss on disposal of $208 million, net of tax, in December 2006 for the initial write-down of the carrying amount of Lawrenceburg to its fair value less cost to sell. The transaction closed in May 2007. Losses from Discontinued Operations were $3 million and $8 million for the quarters ended June 30, 2007 and 2006, respectively and $9 million and $17 million for the six months ended June 30, 2007 and 2006, respectively.

Energy Holdings

For the quarter ended June 30, 2007, Energy Holdings had Income from Continuing Operations of $59 million, as compared to a Loss from Continuing Operations of $107 million in the same period in 2006. For the six months ended June 30, 2007, Energy Holdings had Income from Continuing Operations of $61 million, as compared to a Loss from Continuing Operations of $82 million in the same period in 2006. The increases of $166 million and $143 million for the quarter and six months ended June 30, 2007, respectively, as compared to the same periods in 2006 were primarily due to the absence of a $263 million write-down of project investments and the associated tax benefit of $86 million ($177 million, net) related to the sale of Global’s indirect ownership interest in Rio Grande Energia (RGE) in June 2006.

Excluding the write-down and the associated tax benefit, Income from Continuing Operations decreased $11 million for the quarter ended June 30, 2007, as compared to the same period in 2006. The decrease was primarily due to the shut-down of the two San Marco units at Bioenergie, one of which was restarted in June 2007, lower income from the Texas generation facilities due to lower spark spread (the difference between the market price of electricity and the cost of natural gas fuel), and lower leveraged lease income primarily

due to the adoption of certain accounting pronouncements in 2007. These decreases were partially offset by the recognition of MTM gains of $25 million in 2007 as compared to $20 million in 2006 from the Texas generation facilities, an increase in dividends from Global’s cost method investments, lower general and administrative and interest costs and a decrease in income taxes due to lower pre-tax earnings and a lower effective tax rate.

Excluding the write-down and the associated tax benefit, Income from Continuing Operations decreased $34 million for the six months ended June 30, 2007, as compared to the same period in 2006. The decrease was primarily due to lower income from the Texas generation facilities due to the recognition of MTM losses of $4 million in 2007 as compared to $14 million of MTM gains in 2006, and lower spark spread and a scheduled maintenance outage at the Texas generation facilities’ Guadalupe plant. Also contributing to the variance was the shut-down of the San Marco facility, the absence of equity earnings from RGE, lower leveraged lease income primarily due to the adoption of certain accounting pronouncements in 2007 and lower Demand Side Management (DSM) revenue. These decreases were partially offset by improved operations at Sociedad Austral de Electricidad S.A. (SAESA), a gain on the sale of the Tracy project, a gain on settlement of an investment in a collateralized bond fund, an award related to an arbitration proceeding regarding the construction of a power plant in the Konya-Ilgin region of Turkey, lower general and administrative and interest costs and an increase in dividends from Global’s cost method investments.

See Note 5. Commitments and Contingent Liabilities of the Notes for additional information regarding Bioenergie.

The variances are discussed in detail below:


	For the Quarters Ended June 30,								Increase (Decrease)				%			For the Six Months Ended June 30,								Increase (Decrease)				%
	2007				2006				Increase (Decrease)				%			2007				2006				Increase (Decrease)				%
					(Millions)															(Millions)
Operating Revenues		$	339			$	353			$	(14	)		(4	)		$	582			$	651			$	(69	)		(11	)
Energy Costs		$	200			$	193			$	7			4			$	358			$	386			$	(28	)		(7	)
Operation and Maintenance		$	44			$	47			$	(3	)		(6	)		$	93			$	91			$	2			2
Write-down of Project Investments		$	—			$	263			$	(263	)		(100	)		$	—			$	263			$	(263	)		(100	)
Depreciation and Amortization		$	15			$	11			$	4			36			$	28			$	22			$	6			27
Income from Equity Method Investments		$	27			$	30			$	(3	)		(10	)		$	53			$	63			$	(10	)		(16	)
Other Income and Deductions		$	—			$	10			$	(10	)		(100	)		$	14			$	10			$	4			40
Interest Expense		$	(39	)		$	(49	)		$	(10	)		(20	)		$	(80	)		$	(97	)		$	(17	)		(18	)
Income Tax (Expense) Benefit		$	(11	)		$	64			$	75			N/A			$	(31	)		$	54			$	85			N/A
(Loss) Income from Discontinued Operations, including Gain on Disposal, net of tax		$	(15	)		$	225			$	(240	)		N/A			$	(14	)		$	232			$	(246	)		N/A

The classification of the results of Global’s investments on Energy Holdings’ Condensed Consolidated Financial Statements is dependent upon Global’s ownership percentage in the underlying investment which determines whether the investment is consolidated into Energy Holdings’ Condensed Consolidated Financial Statements or if it is accounted for under the equity method of accounting. Global’s investments in Texas generation facilities, SAESA and Bioenergie are consolidated. As a result, the revenues, expenses, assets and liabilities of those investments are reflected on Energy Holdings’ Condensed Consolidated Financial Statements. Global’s investments in Chilquinta Energia S.A. (Chilquinta), Luz del Sur S.A.A. (LDS), GWF Power Systems, L.P., GWF Energy LLC, Kalaeloa Partners, L.P. (Kalaeloa) and several other smaller investments are accounted for under the equity method or cost method of accounting, as appropriate. Therefore, Energy Holdings only records its share of the net income from these projects as Income from Equity Method Investments on its Condensed Consolidated Statements of Operations.

Operating Revenues

The $14 million decrease for the quarter ended June 30, 2007, as compared to the same period in 2006, was due to lower revenues at Resources of $11 million, which was primarily due to a $6 million decrease in leveraged lease income due to the adoption of FIN 48 and FSP 13-2, a $3 million decrease in investment distributions and a $2 million decrease in Demand Side Management revenue due to contract expirations. In addition, there were lower revenues at Global of $2 million, which was primarily the net result of decreased

revenues consisting of an $11 million decrease at the Texas generation facilities mainly due to a reduction in average price per MWh partially offset by higher unrealized MTM gains on contracts; and a $7 million decrease at Bioenergie due to the shut-down of the San Marco facility. These decreases were partially offset by an $18 million increase at SAESA due to increased energy sales volume.

The $69 million decrease for the six months ended June 30, 2007, as compared to the same period in 2006, was due to lower revenues at Global of $54 million, which was primarily the net result of decreased revenues consisting of an $88 million decrease at the Texas generation facilities mainly due to a reduction in average price per MWh and unrealized MTM losses on contracts in 2007 as opposed to unrealized MTM gains in 2006; and a $7 million decrease at Bioenergie due to the shut-down of the San Marco facility. These decreases were partially offset by a $39 million increase at SAESA due to increased tariff rates and energy sales volume and a $7 million increase due to a gain on sale of Global’s interest in Tracy Biomass. In addition, there were lower revenues at Resources of $14 million, primarily due to a $12 million decrease in leveraged lease income due to the adoption of FIN 48 and FSP 13-2, a $3 million decrease in investment distributions and a $5 million decrease in DSM revenue due to contract expirations, partially offset by a $6 million gain on settlement of its investment in a collateralized bond fund.

Operating Expenses

Energy Costs

The $7 million increase for the quarter ended June 30, 2007, as compared to the same period in 2006, was primarily due to a $15 million increase at SAESA due to higher energy purchase price and volume, partially offset by a $4 million decrease at the Texas generation facilities due to a reduction in fuel consumption and a $2 million decrease at Bioenergie due to the shut-down of the San Marco facility.

The $28 million decrease for the six months ended June 30, 2007, as compared to the same period in 2006, was primarily due to a $53 million decrease at the Texas generation facilities primarily due to MTM unrealized gains on gas contracts in 2007 as opposed to unrealized MTM losses in 2006 and a reduction in fuel consumption, and a $2 million decrease at Bioenergie due to the shut-down of the San Marco facility, partially offset by a $30 million increase at SAESA due to higher energy purchase price and volume.

Operation and Maintenance

The $3 million decrease for the quarter ended June 30, 2007, as compared to the same period in 2006, was primarily due to a $2 million decrease at SAESA due to repairs of a gas turbine in 2006 partially offset by a $1 million increase at Bioenergie due to the shut-down of the San Marco Facility.

The $2 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was primarily due to an $8 million increase at the Texas generation facilities due to a scheduled maintenance outage at the Texas generation facilities’ Guadalupe plant and a $3 million increase due to the consolidation of Bioenergie in May 2006, partially offset by a $6 million decrease due to lower general and administrative costs and a $1 million decrease at SAESA due to repairs of a gas turbine in 2006.

Write-down of Project Investments

The $263 million write-down of project investments relates to Global’s sale of its 32% indirect ownership interest in RGE to its partner in May 2006. See Note 3. Discontinued Operations, Dispositions and Impairments of the Notes for additional information.

Depreciation and Amortization

The $4 million and $6 million increase for the quarter and six months ended June 30, 2007, respectively, as compared to the same periods in 2006, was primarily due to the consolidation of Bioenergie in May 2006.

Income from Equity Method Investments

The $3 million and $10 million decrease for the quarter and six months ended June 30, 2007, respectively, as compared to the same periods in 2006, was primarily due to the absence of equity earnings from RGE which was sold in June 2006.

Other Income and Deductions

The $10 million decrease for the quarter ended June 30, 2007, as compared to the same period in 2006, was primarily due to a decrease in interest and dividend income.

The $4 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was primarily due to a $9 million pre-tax gain in 2007 from an arbitration award received relating to the Konya-Ilgin dispute, partially offset by a $3 million decrease in interest and dividend income.

Interest Expense

The $10 million and $17 million decrease for the quarter and six months ended June 30, 2007, respectively, as compared to the same periods in 2006, was primarily due to a decrease in debt outstanding.

Income Taxes

The $75 million increase for the quarter ended June 30, 2007, as compared to the same period in 2006, was primarily due to the absence of an $86 million tax benefit related to the sale of Global’s interest in RGE in June 2006, partially offset by a higher effective tax rate due to the adoption of FIN 48.

The $85 million increase for the six months ended June 30, 2007, as compared to the same period in 2006, was primarily due to the absence of an $86 million tax benefit related to the sale of Global’s interest in RGE in June 2006, asset sales, an arbitration award received relating to the Konya-Ilgin dispute and the fact that interest and penalties are expensed under FIN 48 guidance.

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

In June 2007, Energy Holdings reclassified its investment in Electroandes to Discontinued Operations. In conjunction with the reclassification to Discontinued Operations, Global recorded a $19 million income tax expense in the second quarter of 2007 related to the discontinuation of applying APB 23, as the income generated by Electroandes is no longer expected to be indefinitely reinvested. (Loss) Income from Discontinued Operations for the quarter ended June 30, 2007 and 2006 was $(15) million and $2 million, respectively. (Loss) Income from Discontinued Operations for the six months ended June 30, 2007 and 2006 was $(14) million and $5 million, respectively.

In May 2006, Energy Holdings completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale resulted in an after-tax gain of $228 million. Loss from Discontinued Operations related to Elcho and Skawina for the quarter and six months ended June 30, 2006 was $5 million and $1 million, respectively, net of tax.

See Note 3. Discontinued Operations, Dispositions and Impairments of the Notes for additional information.

LIQUIDITY AND CAPITAL RESOURCES

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

Operating Cash Flows

PSEG

PSEG’s operating cash flow decreased by approximately $2 million from $798 million for the six months ended June 30, 2006 to $796 million for the six months ended June 30, 2007 due to changes from its subsidiaries as discussed below. Excess cash is currently being used to reduce debt and beginning in mid-2008, it is expected that excess cash will be available for new investments, increasing dividends and/or repurchasing shares.

PSE&G

PSE&G’s operating cash flow decreased approximately $249 million from $132 million to $(117) million for the six months ended June 30, 2007, as compared to the same period in 2006, primarily due to a $(357) million change in customer receivables. The June 2007 receivable balance was 12% higher than the prior year primarily due to commodity and base rate increases. The December 2006 receivable balance was 16% lower than the prior year due to warmer than normal conditions late in 2006 and a post Katrina peak in gas prices in late 2005. Offsetting the change in receivables was a positive $143 million change in Accounts Payable–Affiliated Companies. The primary reason for the change was a large decrease in the gas payable in the first six months of 2006 ($358 million) compared to a smaller decline in the same period in 2007 ($227 million). The unit cost of gas declined significantly early in 2006 from the post-Katrina peak in the fall of 2005.

Power

Power’s operating cash flow increased approximately $73 million from $721 million to $794 million for the six months ended June 30, 2007, as compared to the same period in 2006. The major reasons for the increase were higher net income of $208 million partly offset by a decrease of $153 million in working capital due to an increase in margin receivables related to higher collateral requirements. For the first six months of 2007, cash margin requirements increased $135 million as compared to a decrease of $69 million in the comparable period in the prior year.

Energy Holdings

Energy Holdings’ operating cash flow increased approximately $143 million from $8 million to $151 million for the six months ended June 30, 2007, as compared to the same period in 2006. The increase was mainly attributable to the timing of tax payments related to Resources and Global’s sales of Elcho, Skawina and RGE in 2006 and higher distributions in 2007 from equity method investments in Global’s GWF and Hanford projects.

Common Stock Dividends

PSEG

Dividend payments on common stock for the quarters ended June 30, 2007 and 2006 were $0.585 and $0.57 per share, respectively, and totaled approximately $148 million and $143 million, respectively. Dividend payments on common stock for the six months ended June 30, 2007 and 2006 were $1.17 and $1.14 per share, respectively, and totaled approximately $296 million and $286 million, respectively. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, new investment opportunities and other factors. Improved earnings would cause PSEG’s dividend payout ratio to decline, providing PSEG the flexibility to raise its dividend at a rate higher than its prior dividend increases. On July 17, 2007, PSEG’s Board of Directors approved a common stock dividend of $0.585 per share for the third quarter of 2007, reflecting an indicated annual dividend rate of $2.34 per share.

Short-Term Liquidity

PSEG, PSE&G, Power and Energy Holdings

As of June 30, 2007, PSEG and its subsidiaries had a total of approximately $3.6 billion of committed credit facilities with approximately $3.1 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted as to availability and use to the specific companies as listed below. PSEG, PSE&G, Power and Energy Holdings believe sufficient liquidity exists to fund their respective short-term cash needs.


Company	Expiration Date	Total Facility			Primary Purpose	Usage as of June 30, 2007				Available Liquidity as of June 30, 2007
	(Millions)
PSEG:
5-year Credit Facility	Dec 2011		$	1,000	CP Support/Funding/ Letters of Credit		$	51			$	949
Uncommitted Bilateral Agreement	N/A			N/A	Funding		$	—			$	N/A
PSE&G:
5-year Credit Facility	June 2011		$	600	CP Support/Funding/ Letters of Credit		$	270			$	330
Uncommitted Bilateral Agreement	N/A			N/A	Funding		$	26				N/A
Power:
5-year Credit Facility	Dec 2011		$	1,600	Funding/Letters of Credit		$	198	(B)		$	1,402
Bilateral Credit Facility	March 2010		$	100	Funding/Letters of Credit		$	54	(B)		$	46
Bilateral Credit Facility	March 2008		$	200	Funding/Letters of Credit		$	—			$	200
Energy Holdings:
5-year Credit Facility (A)	June 2010		$	150	Funding/Letters of Credit		$	15	(B)		$	135

(A)

Energy Holdings/Global/Resources joint and several co-borrower facility.

(B)

These amounts relate to letters of credit outstanding.

Power

As of June 30, 2007, Power had loaned $214 million to PSEG in the form of an intercompany loan.

On June 25, 2007, Power refinanced the $200 million PSEG/Power joint and several co-borrower bilateral credit facility. The maturity was extended to March 2008 and terms were modified so that Power is the sole borrower under this facility.

During the quarter ending June 30, 2007, Power’s required margin postings for sales contracts entered into in the normal course of business increased slightly. The required margin postings will fluctuate based on volatility in commodity prices. Should commodity prices rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract obligations are fulfilled, liquidity requirements are reduced.

In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit rating to below investment grade, which represents at least a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide performance assurance, generally in the form of a letter of credit or cash. Providing this support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset portfolio. Power believes it has sufficient liquidity to meet any required posting of collateral likely to result from a credit rating downgrade. See Note 5. Commitments and Contingent Liabilities of the Notes for further information.

Energy Holdings

Energy Holdings and its subsidiaries had $65 million in cash, including $15 million invested offshore as of June 30, 2007. In addition, as of June 30, 2007, Energy Holdings had an outstanding demand loan receivable from PSEG of $30 million.

External Financings

PSEG, PSE&G, Power and Energy Holdings

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

Debt Covenants

PSEG, PSE&G, Power and Energy Holdings

PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective credit agreements may contain maximum debt to equity ratios, minimum cash flow tests and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon the respective future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to which no assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as financial performance or liquidity measures. The debt underlying the preferred securities of PSEG, which is presented in Long-Term Debt in accordance with FIN 46 “Consolidation of Variable Interest Entities,” is not included as debt when calculating these ratios, as provided for in the various credit agreements.

Energy Holdings’ credit agreement also contains customary provisions under which the lender could refuse to advance loans in the event of a material adverse change in the borrower’s business or financial condition.

PSEG

Financial covenants contained in PSEG’s credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans, certain letters of credit not related to collateral postings for commodity/energy contracts and similar instruments) to total capitalization (including preferred securities outstanding and excluding any impacts for Accumulated Other Comprehensive Income/Loss adjustments related to marking energy contracts to market and equity reductions from the funded status of pensions or benefit plans associated with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”) covenant. This covenant requires that such ratio not be more than 70.0%. As of June 30, 2007, PSEG’s ratio of debt to capitalization (as defined above) was 50.3%.

PSE&G

Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total capitalization covenant. This covenant requires that such ratio will not be more than 65.0%. As of June 30, 2007, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 49.8%.

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of June 30, 2007, PSE&G’s Mortgage coverage ratio was 4.5 to 1 and the Mortgage would permit up to approximately $2.1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements.

Power

Financial covenants contained in Power’s credit facility include a ratio of debt to total capitalization covenant. The Power ratio is the same debt to total capitalization calculation as set forth above for PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Condensed Consolidated Balance Sheets). This covenant requires that such ratio will not exceed 65.0%. As of June 30, 2007, Power’s ratio of debt to total capitalization (as defined above) was 39.0%.

Energy Holdings

Energy Holdings’ bank revolving credit agreement has a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than or equal to 1.75. As of June 30, 2007, Energy Holdings’ coverage under this covenant was 3.38. Additionally, the bank revolving credit agreement has a covenant requiring that Energy Holdings maintain a ratio of net debt

(recourse debt offset by funds loaned to PSEG) to EBITDA of less than 5.25. As of June 30, 2007, Energy Holdings’ ratio under this covenant was 2.95. Energy Holdings is a co-borrower under this facility with Global and Resources, which are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfaction of certain financial covenants. Net cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts under the credit agreement. Net cash proceeds from asset sales during any 12-month period in excess of 10% of total assets must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources.

Energy Holdings’ indenture with respect to its senior notes does not permit liens securing indebtedness in excess of 10% of consolidated net tangible assets as calculated under the terms of the indenture. The terms of Energy Holdings’ Senior Notes allow the holders to demand repayment if a transaction or series of related transactions causes the assets of Resources to be reduced by 20% or more and as a direct result there is a downgrade of ratings.

Credit Ratings

PSEG, PSE&G, Power and Energy Holdings

On June 22, 2007, S&P revised its outlook for the credit ratings of each of PSEG, PSE&G and Power from negative (Neg) to stable and upgraded its rating for the commercial paper of PSEG & PSE&G from A3 to A2.

If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities and serve to materially increase those companies’ cost of capital and limit their access to capital. Outlooks assigned to ratings are as follows: stable, Neg or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

The credit ratings of PSEG and its subsidiaries are shown in the table below.


	Moody’s (A)	S&P (B)	Fitch (C)
PSEG:
Outlook	Neg	Stable	Pos
Preferred Securities	Baa3	BB+	BBB–
Commercial Paper	P2	A2	F2
Senior Unsecured Debt	Baa2	BBB–	BBB
PSE&G:
Outlook	Neg	Stable	Pos
Mortgage Bonds	A3	A–	A
Preferred Securities	Baa3	BB+	BBB+
Commercial Paper	P2	A2	F2
Power:
Outlook	Stable	Stable	Pos
Senior Notes	Baa1	BBB	BBB
Energy Holdings:
Outlook	Neg	Neg	Pos
Senior Notes	Ba3	BB–	BB

(A)

Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P-1 (highest) to NP (lowest) for short-term securities.

(B)

S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A-1 (highest) to D (lowest) for short-term securities.

(C)

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

Other Comprehensive Income/Loss

PSEG, PSE&G, Power and Energy Holdings

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

CAPITAL REQUIREMENTS

PSEG, PSE&G, Power and Energy Holdings

It is expected that the majority of funding for capital requirements of PSE&G, Power and Energy Holdings will come from their respective internally generated funds. The balance will be provided by the issuance of debt at the respective subsidiary or project level and, for PSE&G and Power, equity contributions from PSEG. PSEG does not expect to contribute any additional equity to Energy Holdings. Projected construction and investment amounts have been revised subsequent to the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2006. The revised amounts reflect a total increase of approximately $1.1 billion over the period for PSE&G, a little more than half of which is for PSE&G’s portion of transmission lines, including the approved transmission line which is expected to be in service in 2012. Other investments include solar power and other carbon reduction initiatives, installation of a new customer service system, and other expenditures to support continued reliability of the transmission and distribution systems. The increase of approximately $217 million over the period for Power reflects updates to its estimates for costs to construct pollution control equipment at the Mercer and Hudson coal-fired stations and expenditures for pursuing options for new investments in nuclear generation. The current projected construction and investment expenditures, excluding nuclear fuel purchases, for PSEG’s subsidiaries for the next five years are presented in the table below. These amounts are subject to change, based on various factors.


	2007			2008			2009			2010			2011			2007- 2011 Total
	(Millions)
*PSE&G:*
Facility Support		$	73		$	143		$	74		$	52		$	60		$	402
Environmental/Regulatory			35			94			84			85			86			384
Facility Replacement			191			185			186			187			188			937
System Reinforcement			149			217			269			446			485			1,566
New Business			168			164			152			149			152			785

*Total PSE&G*			616			803			765			919			971			4,074

*Power:*
Hudson Environmental			93			215			280			230			—			818
Mercer Environmental			186			214			96			15			—			511
Other Non-Recurring			253			232			61			58			40			644
Recurring			123			155			143			138			136			695

*Total Power*			655			816			580			441			176			2,668
*Energy Holdings*			38			31			40			30			31			170
*Other*			34			31			23			24			23			135

*Total PSEG*		$	1,343		$	1,681		$	1,408		$	1,414		$	1,201		$	7,047

PSE&G

During the six months ended June 30, 2007, PSE&G made approximately $296 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $296 million does not include expenditures for cost of removal, net of salvage, of approximately $18 million, which are included in operating cash flows.

Power

During the six months ended June 30, 2007, Power made approximately $273 million of capital expenditures (excluding $50 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear.

Energy Holdings

During the six months ended June 30, 2007, Energy Holdings made approximately $29 million of capital expenditures, primarily related to upgrades and expansions of SAESA’s transmission and distribution systems and expenditures at Electroandes.

ACCOUNTING MATTERS

PSEG, PSE&G, Power and Energy Holdings

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

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

PSEG, PSE&G, Power and Energy Holdings

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

Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG and its subsidiaries’ financial condition, results of operations or net cash flows.

Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2006 or Quarterly Reports on Form 10-Q for the quarter ended March 31, 2007.

Commodity Contracts

Power

The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. As part of its overall risk management strategy to reduce price risk due to market fluctuations, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with demand obligations, help reduce risk and optimize the value of owned electric generation capacity.

Normal Operations, Hedging and Trading Activities

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

Under SFAS 133, changes in the fair value of qualifying cash flow hedge transactions are recorded in Accumulated Other Comprehensive Income/Loss, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings.

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

In addition, Power has non-asset based trading activities. These contracts involve financial transactions, including swaps, options and futures. These activities are marked to market in accordance with SFAS 133 with gains and losses recognized in earnings.

Value-at-Risk (VaR) Models

Power

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

Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and its hedges. Non-trading mark-to-market (MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading VaR.

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

Reduced trading activities by Power during 2006 and 2007 have resulted in less trading risk. As of each of June 30, 2007 and December 31, 2006, trading VaR was less than $1 million.


	Trading VaR			Non-Trading MTM VaR
	(Millions)
For the Quarter Ended June 30, 2007
95% Confidence Level, One-Day Holding Period, One-Tailed:
Period End		$	—		$	38
Average for the Period		$	—		$	36
High		$	—		$	49
Low		$	—		$	26
99% Confidence Level, One-Day Holding Period, Two-Tailed:
Period End		$	—		$	59
Average for the Period		$	—		$	56
High		$	1		$	77
Low		$	—		$	41

Other Supplemental Information Regarding Market Risk

Power

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

The following table describes the drivers of Power’s energy trading and marketing activities and Operating Revenues included in its Condensed Consolidated Statement of Operations for the quarter and six months ended June 30, 2007. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale market. As the information in this table highlights, MTM activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices.

Operating Revenues
For the Quarter Ended June 30, 2007


	Normal Operations and Hedging (A)				Trading				Total
	(Millions)
MTM Activities:
Unrealized MTM Gains (Losses)
Changes in Fair Value of Open Positions		$	(14	)		$	3			$	(11	)
Realization at Settlement of Contracts			(3	)			(1	)			(4	)

Total Change in Unrealized Fair Value			(17	)			2				(15	)
Realized Net Settlement of Transactions Subject to MTM			3				1				4

Net MTM (Losses) Gains			(14	)			3				(11	)
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			1,316				—				1,316

Total Operating Revenues		$	1,302			$	3			$	1,305

(A)

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

Operating Revenues
For the Six Months Ended June 30, 2007


	Normal Operations and Hedging (A)				Trading			Total
	(Millions)
MTM Activities:
Unrealized MTM Gains (Losses)
Changes in Fair Value of Open Positions		$	(9	)		$	1		$	(8	)
Origination Unrealized Gain at Inception			—				—			—
Changes in Valuation Techniques and Assumptions			—				—			—
Realization at Settlement of Contracts			(12	)			—			(12	)

Total Change in Unrealized Fair Value			(21	)			1			(20	)
Realized Net Settlement of Transactions Subject to MTM			12				—			12

Net MTM (Losses) Gains			(9	)			1			(8	)
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			3,462				—			3,462

Total Operating Revenues		$	3,453			$	1		$	3,454

The following table indicates Power’s energy trading assets and liabilities, as well as Power’s hedging activity related to ABTs and derivative instruments that qualify for hedge accounting under SFAS 133. This table presents amounts segregated by portfolio which are then netted for those counterparties with whom Power has the right to offset and therefore, are not necessarily indicative of amounts presented on the Condensed Consolidated Balance Sheets since balances with many counterparties are subject to offset and are shown net on the Condensed Consolidated Balance Sheets regardless of the portfolio in which they are included.

Energy Contract Net Assets/Liabilities
As of June 30, 2007


	Normal Operations and Hedging				Trading				Total
	(Millions)
MTM Energy Assets
Current Assets		$	6			$	23			$	29
Noncurrent Assets			4				4				8

Total MTM Energy Assets		$	10			$	27			$	37

MTM Energy Liabilities
Current Liabilities		$	(332	)		$	(32	)		$	(364	)
Noncurrent Liabilities			(191	)			(2	)			(193	)

Total MTM Current Liabilities		$	(523	)		$	(34	)		$	(557	)

Total MTM Energy Contract Net Liabilities		$	(513	)		$	(7	)		$	(520	)

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

Maturity of Net Fair Value of MTM Energy Trading Contracts
As of June 30, 2007


	Maturities within
	2007				2008				2009-2011				Total
	(Millions)
Trading		$	(8	)		$	1			$	—			$	(7	)
Normal Operations and Hedging			(169	)			(278	)			(66	)			(513	)

Total Net Unrealized Losses on MTM Contracts		$	(177	)		$	(277	)		$	(66	)		$	(520	)

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

Energy Holdings

The following table describes the drivers of Global’s marketing activities and Operating Revenues included in its Condensed Consolidated Statement of Operations for the quarter and six months ended June 30, 2007. Normal operations and hedging activities represent the marketing of electricity available from Global’s owned generation sold into the market. Activities accounted for under the accrual method account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices.

Operating Revenues
For the Quarter Ended June 30, 2007


	Normal Operations and Hedging(A)
	(Millions)
MTM Activities:
Unrealized MTM Gains
Changes in Fair Value of Open Position		$	28
Realization at Settlement of Contracts			10

Total Change in Unrealized Fair Value			38
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			264

Total Operating Revenues		$	302

Operating Revenues
For the Six Months Ended June 30, 2007


	Normal Operations and Hedging(A)
	(Millions)
MTM Activities:
Unrealized MTM (Losses) Gains
Changes in Fair Value of Open Position		$	(5	)
Realization at Settlement of Contracts			3

Total Change in Unrealized Fair Value			(2	)
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications			501

Total Operating Revenues		$	499

(A)

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

The following table indicates Global’s energy trading liabilities.

Energy Contract Net Assets
As of June 30, 2007


	Normal Operations and Hedging
	(Millions)
MTM Energy Assets
Current Assets		$	27
Noncurrent Assets			28

Total MTM Energy Assets		$	55

MTM Energy Liabilities
Current Liabilities		$	(3	)
Noncurrent Liabilities			(18	)

Total MTM Energy Liabilities		$	(21	)

Net MTM Energy Assets		$	34

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

Maturity of Net Fair Value of MTM Energy Trading Contracts
As of June 30, 2007


	Maturities within
	2007			2008			2009- 2010			Total
	(Millions)
Total Net Unrealized Losses on MTM Contracts		$	13		$	15		$	6		$	34

PSEG, Power and Energy Holdings

The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss (OCL), a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights (FTRs) contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG, Power

and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. The table also provides an estimate of the losses that are expected to be reclassified out of OCL and into earnings over the next 12 months.

Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
As of June 30, 2007


	Accumulated Other Comprehensive Loss				Portion Expected to be Reclassified in next 12 months
	(Millions)
Commodities		$	(254	)		$	(144	)
Interest Rates			—				—
Foreign Currency			—				—

Net Cash Flow Hedge Loss Included in Accumulated Other Comprehensive Loss		$	(254	)		$	(144	)

Power

Credit Risk

The following table provides information on Power’s credit exposure, net of collateral, as of June 30, 2007. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties.

Schedule of Credit Risk Exposure on Energy Contracts Net Assets
As of June 30, 2007


Rating	Current Exposure			Securities Held as Collateral			Net Exposure			Number of Counterparties >10%			Net Exposure of Counterparties >10%
				(Millions)						(Millions)
Investment Grade—External Rating		$	377		$	44		$	377		2	(A)		$	298
Non-Investment Grade—External Rating			—			—			—		—				—
Investment Grade—No External Rating			4			—			4		—				—
Non-Investment Grade—No External Rating			15			—			15		—				—

Total		$	396		$	44		$	396		2			$	298

(A)

PSE&G is a counterparty with net exposure of $229 million.

The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. When letters of credit are posted, exposure is not reduced; it is shifted to a more creditworthy entity. As of June 30, 2007, Power had 129 active counterparties.

ITEM 4. CONTROLS AND PROCEDURES

PSEG, PSE&G, Power and Energy Holdings

Disclosure Controls and Procedures

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

Internal Controls

PSEG, PSE&G, Power and Energy Holdings continually review their respective disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting. There have been no changes in internal control over financial reporting that occurred during the second quarter of 2007 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Certain information reported under Item 3 of Part I of the 2006 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 is updated below.

PSE&G

Electric Discount and Energy Competition Act (Competition Act)

March 31, 2007 Form 10-Q, page 66. On April 23, 2007, PSE&G and Transition Funding were served with a copy of a purported class action complaint (Complaint) challenging the constitutional validity of certain provisions of New Jersey’s Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the transition bond charge (TBC) of PSE&G Transition Funding, as well as recovery of TBC amounts previously collected. Notice of the filing of the Complaint was also provided to New Jersey’s Attorney General. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional. On July 9, 2007, the same plaintiff filed an amended complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected and also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same charges. Preliminary review indicates the claim is without merit. PSE&G and Transition Funding filed a motion to dismiss the amended complaint (or in the alternative for summary judgment) on July 30, 2007, and will vigorously defend the matter.

Con Edison

2006 Form 10-K, Page 46 and March 31, 2007 Form 10-Q, page 66. In November 2001, Consolidated Edison Company of New York, Inc. (Con Edison) filed a complaint against PSE&G, PJM and NYISO with FERC asserting a failure to comply with agreements between PSE&G and Con Edison covering 1,000 MW of transmission. PSE&G denied the allegations set forth in the complaint. An Initial Decision issued by an ALJ in April 2002 upheld PSE&G’s claim in part but also accepted Con Edison’s contentions in part. In December 2002, FERC issued an order modifying the Initial Decision and remanding a number of issues to the ALJ for additional hearings, including issues related to the development of protocols to implement the findings of the order and regarding Phase II of the complaint. The ALJ issued an Initial Decision on the Phase II issues in June 2003 and in August 2004, FERC issued its decision on Phase II issues. While those decisions were largely favorable to PSE&G, PSE&G sought rehearing as to certain issues, as did Con Edison. On April 19, 2007, the FERC rejected the rehearing requests of both Con Edison and PSE&G, while granting PSE&G’s requested clarification that 400 MW of the 1000 MW at issue will have higher priority over other non-firm transactions only if Con Ed agrees to pay congestion costs. Both Con Edison and PSE&G have appealed the FERC’s rulings on both Phase I and Phase II issues to the Court of Appeals; thus, it is difficult to predict the final outcome of this proceeding at this time.

The August 2004 order required that PJM, NYISO, Con Edison and PSE&G meet for the purpose of developing operational protocols to implement FERC’s directives. On February 18, 2005, NYISO, PJM and PSE&G submitted a joint compliance filing pursuant to FERC’s August 2004 decision. FERC approved the joint proposals on May 18, 2005 and they took effect on July 1, 2005. In subsequent filings to FERC regarding the efficacy of these protocols, Con Edison continued to claim that the obligations under the agreements as interpreted by the FERC’s orders were not being met. In December 30, 2005 and January 19, 2007 filings with FERC, Con Edison claimed to have incurred $111 million in damages, and requested FERC to require refunds of this amount. On April 19, 2007, however, the FERC issued an order rejecting Con Edison’s claim for a refund. FERC also rejected Con Edison’s request for interim remedies and directed that no further informational filings regarding the protocols would be required. On May 21, 2007, Con Edison sought rehearing of the April 19, 2007 order; thus, the final outcome of this proceeding cannot be predicted. It is anticipated, nonetheless, that additional meetings will be held for the purpose of attempting to resolve issues associated with the operating protocols.

PSEG, PSE&G, Power and Energy Holdings

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



(1)		Page 26. (PSE&G) Investigation Directive of NJDEP dated September 19, 2003 and additional investigation Notice dated September 15, 2003 by the EPA regarding the Passaic River site. NJDEP Docket No. EX93060255; EPA CERCLA Docket No. 02-2007-2009.
(2)		Page 27. (PSE&G) New Jersey Department of Environmental Protection v. BFI Waste Systems of New Jersey, Inc. et al., filed with New Jersey Superior Court on June 29, 2007.
(3)		Page 27. (PSE&G) New Jersey Department of Environmental Protection v. Public Service Electric and Gas Co., et al., filed with New Jersey Superior Court on June 29, 2007. Docket No. L-3337-07.
(4)		Page 27. (PSE&G) PSE&G’s MGP Remediation Program instituted by NJDEP’s Coal Gasification Facility Sites letter dated March 25, 1988.
(5)		Page 27. (PSE&G) Prevention of Significant Deterioration (PSD)/New Source Review (NSR). Completed Docket No. Civil Action 02-CV-340.
(6)		Page 29. (Power) Power’s Petition for Review filed in the United States Court of Appeals for the District of Columbia Circuit on July 30, 2004 challenging the final rule of the United States Environmental Protection Agency entitled National Pollutant Discharge Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake Structures at Phase II Existing Facilities, now transferred to and venued in the United States Court of Appeals for the Second Circuit with Docket No. 04-6696-ag.
(7)		Page 30. (Energy Holdings) Italian government investigation regarding allegations of violations of Bioenergie S.p.A’s air permit for the San Marco facility.
(8)		Page 33. (PSE&G) Deferral Proceeding filed with the BPU on August 28, 2002, Docket No.EX02060363, and Deferral Audit beginning on October 2, 2002 at the BPU, Docket No. EA02060366. Transferred to the OAL on February 7, 2007, Docket No. PUC 03127-07.
(9)		Page 79. (PSEG, PSE&G and Power) FERC proceeding relating to PJM Long-Term Transmission Rate Design, Docket No. EL05-121-000.
(10)		Page 80. (PSE&G) FERC proceeding related to PJM Reliability Pricing Model. Docket ER05-1410-002, EL05-148-002, ER05-1410-003, EL05-148-003, ER05-1410-000, et al.
(11)		Page 82. (PSE&G) PSE&G’s BGSS Commodity filing with the BPU on May 28, 2004, Docket No. GR04050390.
(12)		Page 83. (PSE&G) Remediation Adjustment Clause filing with the BPU on February 13, 2007, Docket No. ER07020104.
(13)		Page 83. (PSE&G) BPU issued RFP to solicit bids proposals in preparation for the gas purchasing strategies audit. Docket No. GA05121062.

ITEM 1A. RISK FACTORS

The following additional risk factors are added to the Risk Factors disclosed beginning on page 34 of the 2006 Form 10-K under the subheadings “Regulatory issues significantly impact operations and profitability” and “Environmental regulations could limit operations”:

Power’s revenues are substantially dependent on its Market Based Rate (MBR) Authority.

PSEG, Power and Energy Holdings

Power’s subsidiary, ER&T, which markets all of Power’s electric generation output, has been granted MBR from FERC, as have PSE&G, Power Connecticut and Energy Holdings’ subsidiary GWF Energy. Recent changes to FERC’s rules regarding the criteria for qualifying for MBR, including consideration of sub-markets within an ISO in determining MBR eligibility (specifically mentioning three submarkets in which Power operates), could increase the risk that Power may not be able to maintain its MBR unless it adopts mitigation measures. The extent of any such mitigation measures, if required, cannot be determined at this time. Failure to maintain MBR eligibility, or the effects of any severe mitigation measures that may be required, could have a material adverse effect on PSEG’s and Power’s financial position, results of operations and net cash flows.

Governmental and industry responses to global climate change could significantly impact Power’s operations.

PSEG, PSE&G, Power and Energy Holdings

Federal and state legislation and other regulation designed to address environmental concerns with global climate change through the reduction of greenhouse gas emissions could significantly impact Power. Recent legislation enacted in New Jersey establishes aggressive goals for the reduction of carbon emissions

over a 40-year period. Expenses, including the potential need to purchase carbon emission allowances, and modifications to operations, that may be needed to meet new regulatory requirements could have a material adverse impact on Power’s financial position, results of operations and net cash flows.

ITEM 5. OTHER INFORMATION

Certain information reported under the 2006 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2006 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2007. References are to the related pages on the Form 10-K and March 31, 2007 Form 10-Q as printed and distributed.

Federal Regulation

Compliance

PSEG, PSE&G, Power and Energy Holdings

Reliability Standards

2006 Form 10-K, Page 14 and March 31, 2007 Form 10-Q, page 69. Pursuant to the Energy Policy Act (EP Act), FERC designated the North American Electric Reliability Corporation (NERC) as a single, national Electric Reliability Organization (ERO) responsible for the implementation and enforcement of mandatory reliability standards.

On March 15, 2007, FERC issued a Final Rule which approved 83 NERC reliability standards and required mandatory compliance by June 4, 2007, which date was subsequently extended to June 18, 2007. FERC has the ability to impose penalties of up to $1 million a day per violation for violations of these Standards. These Standards are applicable to transmission owners and generation owners, and thus PSEG, PSE&G, Power and Energy Holdings (or their subsidiaries) are obligated to comply with the Standards. PSEG, PSE&G, Power and Energy Holdings (or their subsidiaries) were all in compliance with the Standards by the FERC-required date and will actively monitor the requirements contained in the Standards to ensure continuing compliance.

Transmission Rates and Cost Allocation

PSE&G

PJM Long-Term Transmission Rate Design

2006 Form 10-K, Page 16 and March 31, 2007 Form 10-Q, page 70. On April 19, 2007, FERC issued an order addressing the recovery of costs for transmission upgrades designated through PJM’s Regional Transmission Expansion Planning (RTEP) process. Specifically, the FERC reversed a previous ALJ decision and found that there was no basis upon which to conclude that the current zonal rate design for existing transmission facilities, under which transmission customers pay rates for existing transmission within the particular transmission zone in which they take service, was unjust and unreasonable. The April 19, 2007 order also held that (1) for new facilities at the voltage level of 500 kV or higher, 100% of the costs of these new transmission facilities will be socialized to all PJM customers; (2) for new facilities at a voltage level below 500 kV, costs will be allocated on a “cost causation” basis through the PJM Schedule 12 (“beneficiary pays”) methodology; and (3) for existing facilities, costs will continue to be allocated using PJM’s current zonal rate design.

This rate design order is a positive outcome for PSE&G, which had argued for continuation of the zonal rate design, as PSE&G’s current rate structure will remain in place. The order also minimizes cost allocation to PSE&G’s customers through socialization of the costs of new 500 kV facilities in PJM. The April 19, 2007 order is subject to rehearing and several parties have sought rehearing of the FERC order; thus, it is difficult to predict a final outcome of this proceeding at this time.

PSEG, PSE&G and Power

FERC Order 888/890

March 31, 2007 Form 10-Q, Page 71. On May 18, 2006, FERC issued a NOPR seeking comments from the industry on whether reforms are needed to the protections that FERC established in its previously-issued Order 888 to prevent undue discrimination and preference in the provision of transmission service. These reforms would be reflected in revisions to FERC’s pro forma Open Access Transmission Tariff, which has been incorporated into the tariffs of Transmission Providers and governs the terms and conditions under which transmission owners must provide transmission service to all eligible customers. On February 16, 2007, FERC issued Final Rule 890 in this proceeding. The Final Rule covers many transmission-related topics and emphasizes the issues of transmission planning and cost allocation associated with the construction of transmission projects. On March 19, 2007, PSE&G filed a Request for Rehearing and Clarification of the Final Rule, arguing that FERC, among other things, erred in appearing to mandate Transmission Provider planning for economic transmission projects and in establishing cost allocation principles for these projects. The Final Rule requires Transmission Providers, including PJM, NYISO and ISO-NE, to demonstrate compliance with open access principles, including having a transparent planning process. Moreover, PSE&G and Power are actively working with PJM, the NYISO and ISO-NE, to develop appropriate Order 890 compliance proposals in the area of transmission planning and cost allocation; these proposals are expected to be filed with FERC in December 2007. The final outcome of this proceeding and the resulting impact on PSEG, PSE&G and Power cannot be determined at this time.

Market Power, Market Design and Capacity Issues

PSEG, PSE&G, Power and Energy Holdings

Market Power

2006 Form 10-K, Page 17 and March 31, 2007 Form 10-Q, page 71. Under FERC regulations, public utilities may sell power at cost-based rates or apply to FERC for authority to sell at market-based rates (MBR). FERC requires that holders of MBR tariffs file an update every 3 years demonstrating that they continue to lack market power. On June 21, 2007, the FERC issued a Final Rule codifying new market-based rate regulations and announcing changes to its market power test. Specifically, the regulations adopt a revised, two-pronged horizontal and vertical market power analysis. Moreover, with respect to the use of a relevant geographic market for evaluating whether an entity possesses horizontal market power, the FERC has now established that, in circumstances where there has been a specific finding of a relevant sub-market within an RTO, the sub-market may become the geographic market. PJM-East (Eastern MAAC), PSEG North and southwestern Connecticut are all mentioned in the Final Rule as submarkets in PJM and the ISO-New England. While the use of these markets for the market power analysis is rebuttable–one can demonstrate that their use is not appropriate–the possibility exists that a small sub-market of Eastern MAAC, PSEG North or southwestern Connecticut, in which Power holds a concentration of generation assets, could be used in evaluating whether the Power generation assets possess market power. In this case, Power would likely be required to file mitigation measures with FERC. The Final Rule provides for certain categories of cost-based, behavioral mitigation measures but also allows an applicant to propose an alternate mitigation plan. Under the schedule set forth in the Final MBR Rule, it is likely that PSE&G and ER&T (with respect to the PJM assets) will be required to file an updated market power study with FERC in December 2007, with Power Connecticut filing an updated market power study in June 2008. Energy Holdings’ subsidiary GWF Energy LLC, which sells power at market-based rates, will also be required to file an updated market power study. On July 23, 2007, PSE&G and Power filed a request for rehearing with FERC. The outcome of these proceedings cannot be predicted.

PJM Reliability Pricing Model (RPM)

2006 Form 10-K, Page 18 and March 31, 2007 Form 10-Q, page 72. On August 31, 2005, PJM filed its RPM with FERC. The RPM constitutes a locational installed capacity market design for the PJM region, including a forward auction for installed capacity priced according to a downward-sloping demand curve and a transitional implementation of the market design. Parties to the FERC proceeding reached a settlement, which was filed with FERC on September 29, 2006. On December 22, 2006, FERC issued an order approving the September 29 settlement, with certain conditions. The final revenue impact on Power of the settlement approved in the December 22, 2006 FERC order could result in incremental margin of $125 million to $175

million in 2007, with higher increases in future years as the full year impact is realized and existing capacity contracts expire. On January 22, 2007, PSEG as well as other parties to the proceeding filed for rehearing of the December 22, 2006 order and on June 25, 2007, the FERC issued an order denying rehearing with respect to both the April 20, 2006 order and the December 22, 2006 order while granting limited clarifications. PSEG is considering filing an appeal with the U.S. Court of Appeals and thus is unable to predict the outcome of this proceeding.

For additional information, see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Power—Overview and Future Outlook.

Transmission Infrastructure

PSEG, PSE&G and Power

RTEP

2006 Form 10-K, Page 19. On June 8, 2007, PSE&G endorsed the construction of several new 500 kV transmission lines intended to significantly improve the reliability of the electrical grid serving New Jersey customers. Specifically, a 500 kV line running west to east from Susquehenna, Pennsylvania to PSE&G’s Roseland, New Jersey substation has been approved by PJM’s Board of Managers, and construction responsibility has been assigned to PSE&G, PPL and FirstEnergy. Pursuant to the FERC’s April 19, 2007 long-term transmission rate design order, discussed above, the costs of this 500 kV project will now be allocated to all transmission customers in PJM under a FERC-approved cost allocation mechanism. PSE&G currently expects to spend between $550 million and $650 million in connection with its construction of a portion of the Susquehanna-Roseland transmission line, though this amount may change depending upon the scope of PSE&G’s construction responsibilities. PSE&G customers will pay roughly 7.5 percent of these project costs under FERC-approved transmission rates.

PSE&G has also endorsed the construction of two additional 500 kV lines in New Jersey, one running from PSE&G’s Branchburg station to its Roseland station, and the other running south-to-north from PSE&G’s New Freedom station to PSE&G’s Deans station. Neither of these transmission lines has yet been incorporated into PJM’s RTEP, but PSE&G believes that construction of these lines, which would follow existing transmission rights-of-way, are needed to enhance the reliability of the transmission system and to relieve congestion within New Jersey.

Also approved by the PJM Board as part of PJM’s latest RTEP is a west-to-east transmission project being constructed by AEP. The scope of the project has significantly changed from that originally proposed. The line terminates in Kemptown, Maryland rather than at PSE&G’s Deans station in New Jersey.

It is anticipated that both transmission and generation will continue to be needed in New Jersey to satisfy electric demand and to ensure reliability. The resulting impact on PSEG, PSE&G and Power cannot be determined at this time.

DOE Congestion Study

2006 Form 10-K, Page 19 and March 31, 2007 Form 10-Q, page 72. On August 8, 2006, the DOE issued a National Electric Transmission Congestion Study (Congestion Study), as directed by Congress in the EP Act. This Congestion Study identified two areas in the U.S. as “critical congestion areas;” one of the areas is the region between New York and Washington, D.C. Under the EP Act, the DOE has the ability to designate transmission corridors in these “critical congestion areas,” to which FERC back-stop eminent domain authority will attach. Thus, corridor designation may facilitate the construction of transmission projects to address congestion in these corridors.

On April 26, 2007, the DOE issued a report which proposed the Mid-Atlantic Area National Corridor as a draft corridor designation covering most of PJM and bounded by Ohio in the west and the Atlantic shoreline in the east. Specifically, it appears that the proposed corridor will encompass all of New Jersey, as well as portions of West Virginia, Pennsylvania, Maryland, Virginia, the District of Columbia, Delaware, Ohio and New York. This corridor has been proposed in draft form only, and parties have been given an opportunity to comment on the designation. Thus, the precise scope and route of the corridor may change. Public meetings were held in May to discuss DOE’s proposal and comments on the draft corridor

designations were filed with DOE on July 6, 2007. The outcome of this proceeding and its impact on PSE&G cannot be predicted at this time.

State Regulation

PSEG, PSE&G, Power and Energy Holdings

New Jersey Energy Master Plan

2006 Form 10-K, Page 22 and March 31, 2007 Form 10-Q, page 73. The Governor of New Jersey has recently directed the BPU, in partnership with other New Jersey agencies, to develop an Energy Master Plan (EMP). State law in New Jersey requires that an EMP be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. In the Governor’s directive regarding the EMP, the Governor established three specific goals: (1) reduce the State’s projected energy use by 20% by the year 2020; (2) supply 20% of the State’s electricity needs with certain renewable energy sources by 2020; and (3) emphasize energy efficiency, conservation and renewable energy resources to meet future increases in New Jersey electric demand without increasing New Jersey’s reliance on non-renewable resources. In November 2006, PSE&G submitted a number of strategies designed to improve efficiencies in customer use and increase the level of renewable generation. During January and February 2007, PSE&G has been actively involved in the broad-based constituent working groups created to develop specific strategies to achieve the goals and objectives. A draft EMP is expected to be released in the fall of 2007, and a final plan is expected to be completed around year-end. The outcome of this proceeding and its impact on PSEG, PSE&G and Power cannot be predicted at this time.

On April 19, 2007, PSE&G filed a plan with the BPU designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. Under the plan, PSE&G would invest approximately $100 million for two years following BPU approval of the plan to help finance the installation of solar systems throughout its service area. If approved by the BPU, the initiative could begin by the end of 2007 and support 30 MW of solar power in the following two years, fulfilling approximately 50% of the BPU’s Renewal Portfolio Standard (RPS) requirements in PSE&G’s service area for 2009 and 2010. On July 12, 2007, the BPU established a schedule for consideration of this issue, with evidentiary hearings, if necessary, scheduled for December 2007.

PSE&G

BGSS Filings

2006 Form 10-K, Page 23 and March 31, 2007 Form 10-Q, page 73. PSE&G made its 2006/2007 BGSS filing on May 26, 2006. The parties entered into a Stipulation to make the filed BGSS rate effective October 1, 2006 on a provisional basis. However, since the time of the filing, prices of gas futures have dropped significantly and as a result, additional BGSS data has been requested by and provided to the BPU. Settlement discussions with the BPU Staff were completed and a new Stipulation, dated October 27, 2006, was executed by the parties. This new Stipulation was approved by the BPU and resulted in a decrease in annual BGSS revenues of approximately $120 million, which is approximately a 6% reduction in a typical residential gas customer’s bill. The new BGSS rate became effective on November 9, 2006. The Stipulation did not include any change in the Balancing Charge, which is a charge for the difference between the amount of gas delivered to customers and the amount of gas used.

The parties entered into a second Stipulation, which addresses the Balancing Charge only. The BPU Staff recommended a lower Balancing Charge than proposed by PSE&G and received agreement from Rate Counsel. The parties executed the Stipulation for the lower rate and BPU approval was received on January 17, 2007.

The parties entered into a third Stipulation to make both the BGSS rate and the Balancing Charge, which were previously approved on a provisional basis, final. In addition, the Stipulation included agreement between the parties on the following two items: 1) PSE&G agreed to consider, on a prospective basis, some suggested changes to the gas hedging program; and 2) PSE&G agreed to increase the gas reservation charge from 27.4 cents per dekatherm (DTh) to 42.5 cents per DTh to be effective the first month after final BPU

approval. This Stipulation was approved by the Administrative Law Judge on May 21, 2007 and then by the BPU at its Agenda Meeting of June 14, 2007.

PSE&G made its 2007/2008 BGSS filing on June 1, 2007. In the filing, PSE&G requested an increase in annual BGSS revenues of approximately $38.8 million, excluding Sales and Use Tax, to be effective October 1, 2007. This increase amounts to approximately 2% for a typical residential customer. No other changes were included in the filing. On July 2, 2007, the BPU transferred the case to the Office of Administrative Law (OAL) for its initial decision.

Remediation Adjustment Clause (RAC) Filing

2006 Form 10-K, Page 23 and March 31, 2007 Form 10-Q, page 74. PSE&G is engaged in a program to address potential environmental concerns regarding its former Manufactured Gas Plant (MGP) properties in cooperation with and under the supervision of NJDEP. The costs of the program are recovered through the Remediation Adjustment Clause (RAC). The RAC addresses costs in annual periods ending July 31st of each year. The expenditures in each RAC period are recovered over seven years. The costs of the program, including interest, are deferred and amortized as collected in revenues.

In February 2007, PSE&G submitted its RAC-13 and RAC-14 filings with the BPU. In these filings, PSE&G seeks an order finding that the $71 million of RAC program costs incurred during the two-year period, August 1, 2004 through July 31, 2006, are reasonable and are available for recovery. If the costs are approved as filed, the annual requirement for the RAC program will decline from $36 million to $18 million effective July 1, 2007. The decline is primarily the result of an overcollection over the past two years. Amortization of the program costs is equal to revenues with no impact on Net Income.

On April 18, 2007, the BPU transferred the case to the OAL for its initial decision. A pre-hearing conference was held and hearings, if necessary, were scheduled for mid-October, 2007.

Societal Benefits Clause (SBC) Filing

2006 Form 10-K, Page 24 v and March 31, 2007 Form 10-Q, page 74. On May 7, 2007, PSE&G filed a motion with the BPU seeking approval of changes in its electric and gas SBC rates and its electric non-utility generation transition charge (NGC) rates. For electric customers, the rates proposed were designed to recover approximately $271 million in SBC/NGC revenues beginning January 1, 2008. For gas, the rates proposed were designed to recover approximately $76 million in SBC/NGC revenues. On June 7, 2007, the BPU transferred this matter to the OAL for its initial decision and the discovery process has begun. SBC costs are deferred when incurred and amortized to expense when recovered in revenues, resulting in no impact on Net Income.

Gas Purchasing Strategies Audit

2006 Form 10-K, Page 2 and March 31, 2007 Form 10-Q, page 74. In January 2007, the BPU issued an RFP to solicit bid proposals to engage a contractor to perform an analysis of the gas purchasing practices and hedging strategies of the four New Jersey gas distribution companies (GDCs), including PSE&G. The primary focus will be to examine and compare the financial and physical hedging policies and practices of each GDC and to provide recommendations for improvements to these policies and practices. The BPU has selected a consulting firm for this project and the matter is proceeding. The goal of the consultants is to have a report of major recommendations by the end of the year. PSE&G cannot predict the outcome of this process.

Universal Service Fund (USF) Filing

The USF is an energy assistance program mandated by the BPU under the Competition Act to provide payment assistance to low-income customers. The Lifeline program is also a mandated energy assistance program to provide payment assistance to elderly and disabled customers. On June 29, 2007, PSE&G filed a compliance filing on behalf of all of the State’s electric and gas public utilities to reset statewide rates for the Permanent Universal Service Fund and the Lifeline program. The filed rates are set to recover $172 million on a statewide basis. Of this amount, the revised electric rates would recover $95 million while the revised gas rates would recover $77 million. As part of this filing, the proposed rates for the Lifeline program are expected to recover a total of $77 million, $50 million for the electric program and $27 million for the gas

program. These revisions are proposed to become effective on October 1, 2007. PSE&G earns no margin on the collection of the USF and Lifeline programs, resulting in no impact on Net Income.

Environmental Matters

PSEG, Power and Energy Holdings

Air Pollution Control

2006 Form 10-K, Page 28. Multiple states, primarily in the Northeastern U.S., are developing state-specific or regional legislative initiatives to stimulate CO₂ emissions reductions in the electric power industry. New York initiated the Regional Greenhouse Gas Initiative (RGGI) in April 2003. Currently, in the RGGI, Ten Northeastern states have signed a memorandum of understanding (MOU) intended to cap and reduce CO₂ emissions from the electric power sector in the RGGI region. The model rule contemplates the creation of a CO₂ allowance allocation and/or auction whereby CO₂ generators in the electric power industry would be expected to acquire through allocation, or purchase through an auction, CO₂ allowances in an amount corresponding to each facility’s emissions. A final model rule was issued on August 15, 2006 that includes MOU commitments and makes recommendations for states to move forward.

In July 2007, New Jersey adopted the Global Warming Response Act, which adopted goals for the reduction of greenhouse gas emissions in New Jersey. The Act specifically calls for stabilizing greenhouse gas emissions to 1990 levels by 2020, followed by a further reduction of greenhouse emissions to 80% below 2006 levels by 2050. These provisions set forth in an Executive Order that the Governor signed in February. To reach this goal, the New Jersey Department of Environmental Protection, the BPU, other state agencies and stakeholders are required to evaluate methods to meet and exceed the emission reduction targets, taking into account their economic benefits and costs. The act also provides for the development of an emissions portfolio standard to address “leakage” of carbon emissions from electric generation facilities that sell their electricity in New Jersey but are located in a state that does not have requirements for the control of greenhouse gasses. PSEG supported the legislation and intends to work with the New Jersey agencies and other stakeholders in developing the methods to achieve the greenhouse gas reduction goals. The act also authorizes the BPU to require the disclosure on customer bills of the environmental characteristics of the energy used, an interim renewable energy portfolio standard, a requirement for net metering, and electric and gas energy efficiency portfolio standards.

The outcome of this initiative cannot be determined at this time; however, adoption of stringent CO₂ emissions reduction requirements in the Northeast, including the allocation of allowances to PSEG’s facilities and the prices of allowances available through auction, could materially impact Power’s operation of its fossil fuel-fired electric generating units.

Water Pollution Control

2006 Form 10-K, Page 29. For information on Water Pollution Control and related permit renewals, see Note 5. Commitments and Contingent Liabilities of the Notes.

ITEM 6. EXHIBITS

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


a.	PSEG:
	Exhibit 12:	Computation of Ratios of Earnings to Fixed Charges
	Exhibit 31:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
	Exhibit 31.1:	Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
	Exhibit 32:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 32.1:	Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
b.	PSE&G:
	Exhibit 12.1:	Computation of Ratios of Earnings to Fixed Charges
	Exhibit 12.2:	Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
	Exhibit 31.2:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
	Exhibit 31.3:	Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
	Exhibit 32.2:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 32.3:	Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
c.	Power:
	Exhibit 12.3:	Computation of Ratios of Earnings to Fixed Charges
	Exhibit 31.4:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
	Exhibit 31.5:	Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
	Exhibit 32.4:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 32.5:	Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
d.	Energy Holdings:
	Exhibit 12.4:	Computation of Ratios of Earnings to Fixed Charges
	Exhibit 31.6:	Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
	Exhibit 31.7:	Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
	Exhibit 32.6:	Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
	Exhibit 32.7:	Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

SIGNATURE

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

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: August 1, 2007

SIGNATURE

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: August 1, 2007

SIGNATURE

PSEG POWER LLC
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: August 1, 2007

SIGNATURE

PSEG ENERGY HOLDINGS L.L.C.
(Registrant)

By:

/s/ DEREK M. DIRISIO

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

Date: August 1, 2007