Edgar Filing: PUBLIC SERVICE ELECTRIC & GAS CO

As of
June 30,

As of
December 31,

Current Assets

Noncurrent Assets

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED June 30, 2010

¨ 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	22-2625848
	(A New Jersey Corporation)
	80 Park Plaza, P.O. Box 1171
	Newark, New Jersey 07101-1171
	973 430-7000
	http://www.pseg.com
001-34232	PSEG POWER LLC	22-3663480
	(A Delaware Limited Liability Company)
	80 Park Plaza—T25
	Newark, New Jersey 07102-4194
	973 430-7000
	http://www.pseg.com
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY	22-1212800
	(A New Jersey Corporation)
	80 Park Plaza, P.O. Box 570
	Newark, New Jersey 07101-0570
	973 430-7000
	http://www.pseg.com

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

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).


Public Service Enterprise Group Incorporated	Yes x	No ¨
PSEG Power LLC	Yes ¨	No ¨
Public Service Electric and Gas Company	Yes ¨	No ¨

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Public Service Enterprise Group Incorporated	Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨

PSEG Power LLC	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨

Public Service Electric and Gas Company	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨

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

As of July 15, 2010, Public Service Enterprise Group Incorporated had outstanding 505,962,783 shares of its sole class of Common Stock, without par value.

As of July 15, 2010, 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 Public Service Electric and Gas Company 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. Each is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.


		Page
FORWARD-LOOKING STATEMENTS		ii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated	1
	PSEG Power LLC	5
	Public Service Electric and Gas Company	9
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation	13
	Note 2. Recent Accounting Standards	14
	Note 3. Variable Interest Entities	15
	Note 4. Asset Dispositions	16
	Note 5. Available-for-Sale Securities	17
	Note 6. Pension and Other Postretirement Employee Benefits (OPEB)	20
	Note 7. Commitments and Contingent Liabilities	22
	Note 8. Changes in Capitalization	34
	Note 9. Financial Risk Management Activities	34
	Note 10. Fair Value Measurements	41
	Note 11. Other Income and Deductions	49
	Note 12. Income Taxes	50
	Note 13. Comprehensive Income, Net of Tax	52
	Note 14. Earnings Per Share (EPS)	53
	Note 15. Financial Information by Business Segments	54
	Note 16. Related-Party Transactions	55
	Note 17. Guarantees of Debt	57
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	60
	Overview of 2010 and Future Outlook	60
	Results of Operations	64
	Liquidity and Capital Resources	75
	Capital Requirements	77
	Accounting Matters	78
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	78
Item 4.	Controls and Procedures	79
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	80
Item 1A.	Risk Factors	80
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	80
Item 5.	Other Information	80
Item 6.	Exhibits	84
	Signatures	85

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. These include, but are not limited to, future performance, revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical. 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,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial Statements—Note 7. Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to:

•

adverse changes in energy industry law, policies and regulation, including market structures, transmission planning and rules and reliability standards,

•

any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators,

•

changes in federal and state environmental regulations that could increase our costs or limit operations of our generating units,

•

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

•

actions or activities at one of our nuclear units located on a multi-unit site that might adversely affect our ability to continue to operate that unit or other units located at the same site,

•

any inability to balance our energy obligations, available supply and trading risks,

•

any deterioration in our credit quality,

•

availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs,

•

any inability to realize anticipated tax benefits or retain tax credits,

•

changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units,

•

delays in receipt of necessary permits and approvals for our construction and development activities,

•

delays or unforeseen cost escalations in our construction and development activities,

•

increase in competition in energy markets in which we compete,

•

adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in discount rates and funding requirements, and

•

changes in technology and customer usage patterns.

Additional information concerning these factors is set forth in Part II under Item 1A. Risk Factors.

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report only apply as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change, unless otherwise required by applicable securities laws.

The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	For The Three Months Ended June 30,						For The Six Months Ended June 30,
	2010			2009			2010			2009
OPERATING REVENUES	$	2,455		$	2,560		$	6,135		$	6,480
OPERATING EXPENSES
Energy Costs		1,147			1,067			2,915			3,135
Operation and Maintenance		610			627			1,314			1,301
Depreciation and Amortization		233			203			465			410
Taxes Other Than Income Taxes		28			26			70			70

Total Operating Expenses		2,018			1,923			4,764			4,916

OPERATING INCOME		437			637			1,371			1,564
Income from Equity Method Investments		5			1			8			11
Other Income		47			91			90			162
Other Deductions		(12	)		(44	)		(28	)		(99	)
Other-Than-Temporary Impairments		(5	)		(1	)		(6	)		(61	)
Interest Expense		(120	)		(133	)		(236	)		(278	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		352			551			1,199			1,299
Income Tax (Expense) Benefit		(128	)		(240	)		(484	)		(544	)

NET INCOME	$	224		$	311		$	715		$	755

WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING (THOUSANDS):
BASIC		506,109			505,990			506,030			505,988

DILUTED		507,091			506,936			507,119			506,812

EARNINGS PER SHARE:
BASIC	$	0.44		$	0.61		$	1.41		$	1.49

DILUTED	$	0.44		$	0.61		$	1.41		$	1.49

DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.3425		$	0.3325		$	0.6850		$	0.6650

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	June 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	57		$	350
Accounts Receivable, net of allowances of $66 and $79 in 2010 and 2009, respectively		1,251			1,229
Unbilled Revenues		313			411
Fuel		677			806
Materials and Supplies, net		367			361
Prepayments		443			161
Derivative Contracts		269			243
Other		108			85

Total Current Assets		3,485			3,646

PROPERTY, PLANT AND EQUIPMENT		22,833			22,069
Less: Accumulated Depreciation and Amortization		(6,876	)		(6,629	)

Net Property, Plant and Equipment		15,957			15,440

NONCURRENT ASSETS
Regulatory Assets		4,220			4,402
Regulatory Assets of Variable Interest Entities (VIEs)		1,257			1,367
Long-Term Investments		1,939			2,032
Nuclear Decommissioning Trust (NDT) Funds		1,175			1,199
Other Special Funds		153			149
Goodwill		16			16
Other Intangibles		132			123
Derivative Contracts		169			123
Restricted Cash of VIEs		21			17
Other		218			216

Total Noncurrent Assets		9,300			9,644

TOTAL ASSETS	$	28,742		$	28,730

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	June 30,			December 31,
	2010			2009
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	799		$	323
Securitization Debt of VIEs Due Within One Year		202			198
Commercial Paper and Loans		390			530
Accounts Payable		996			1,081
Derivative Contracts		119			201
Accrued Interest		106			102
Accrued Taxes		35			90
Clean Energy Program		181			166
Obligation to Return Cash Collateral		96			95
Other		325			428

Total Current Liabilities		3,249			3,214

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		4,171			4,139
Regulatory Liabilities		524			397
Regulatory Liabilities of VIEs		8			7
Asset Retirement Obligations		455			439
Other Postretirement Benefit (OPEB) Costs		1,088			1,095
Accrued Pension Costs		700			1,094
Clean Energy Program		305			400
Environmental Costs		701			704
Derivative Contracts		31			40
Long-Term Accrued Taxes		480			538
Other		149			140

Total Noncurrent Liabilities		8,612			8,993

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		6,680			6,481
Securitization Debt of VIEs		1,049			1,145
Project Level, Non-Recourse Debt		17			19

Total Long-Term Debt		7,746			7,645

SUBSIDIARY’S PREFERRED STOCK WITHOUT MANDATORY REDEMPTION		0			80

STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2010 and 2009—533,556,660 shares		4,786			4,788
Treasury Stock, at cost, 2010—27,593,877 shares; 2009—27,567,030 shares		(593	)		(588	)
Retained Earnings		5,072			4,704
Accumulated Other Comprehensive Loss		(139	)		(116	)

Total Common Stockholders’ Equity		9,126			8,788
Noncontrolling Interest		9			10

Total Stockholders’ Equity		9,135			8,798

Total Capitalization		16,881			16,523

TOTAL LIABILITIES AND CAPITALIZATION	$	28,742		$	28,730

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For the Six Months Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	715		$	755
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		465			410
Amortization of Nuclear Fuel		68			57
Provision for Deferred Income Taxes (Other than Leases) and ITC		72			139
Non-Cash Employee Benefit Plan Costs		158			173
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes		(172	)		(364	)
Net Gain on Lease Investments		(16	)		(99	)
Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		2			(71	)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		(2	)		8
Over (Under) Recovery of Societal Benefits Charge (SBC)		1			47
Market Transition Charge Refund		122			0
Cost of Removal		(32	)		(23	)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(48	)		(3	)
Net Change in Certain Current Assets and Liabilities		(364	)		307
Employee Benefit Plan Funding and Related Payments		(464	)		(409	)
Other		15			(138	)

Net Cash Provided By (Used In) Operating Activities		520			789

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(911	)		(816	)
Proceeds from the Sale of Capital Leases and Investments		161			510
Proceeds from NDT Funds Sales		426			1,475
Investment in NDT Funds		(439	)		(1,491	)
Restricted Funds		(2	)		108
Other		10			4

Net Cash Provided By (Used In) Investing Activities		(755	)		(210	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans		(141	)		314
Issuance of Long-Term Debt		1,194			209
Redemption of Long-Term Debt		(548	)		(320	)
Repayment of Non-Recourse Debt		(2	)		(283	)
Redemption of Securitization Debt		(91	)		(87	)
Cash Dividends Paid on Common Stock		(347	)		(336	)
Redemption of Preferred Securities		(80	)		0
Other		(43	)		(4	)

Net Cash Provided By (Used In) Financing Activities		(58	)		(507	)

Net Increase (Decrease) in Cash and Cash Equivalents		(293	)		72
Cash and Cash Equivalents at Beginning of Period		350			321

Cash and Cash Equivalents at End of Period	$	57		$	393

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	645		$	613
Interest Paid, Net of Amounts Capitalized	$	227		$	254

See Notes to Condensed Consolidated Financial Statements.

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	For The Three Months Ended June 30,						For The Six Months Ended June 30,
	2010			2009			2010			2009
OPERATING REVENUES	$	1,358		$	1,363		$	3,661		$	3,827
OPERATING EXPENSES
Energy Costs		687			627			2,018			2,158
Operation and Maintenance		269			281			554			555
Depreciation and Amortization		48			53			96			104

Total Operating Expenses		1,004			961			2,668			2,817

OPERATING INCOME		354			402			993			1,010
Other Income		43			86			82			156
Other Deductions		(13	)		(44	)		(27	)		(94	)
Other-Than-Temporary Impairments		(5	)		0			(6	)		(60	)
Interest Expense		(42	)		(39	)		(82	)		(88	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		337			405			960			924
Income Tax (Expense) Benefit		(133	)		(159	)		(392	)		(363	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	204		$	246		$	568		$	561

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

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	June 30, 2010			December 31, 2009
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	8		$	64
Accounts Receivable		425			425
Accounts Receivable—Affiliated Companies, net		326			459
Short-Term Loan to Affiliate		276			0
Fuel		677			806
Materials and Supplies, net		281			290
Derivative Contracts		246			231
Prepayments		56			64
Other		0			3

Total Current Assets		2,295			2,342

PROPERTY, PLANT AND EQUIPMENT		8,836			8,579
Less: Accumulated Depreciation and Amortization		(2,333	)		(2,194	)

Net Property, Plant and Equipment		6,503			6,385

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds		1,175			1,199
Goodwill		16			16
Other Intangibles		125			114
Other Special Funds		30			30
Derivative Contracts		103			118
Long-Term Accrued Taxes		5			39
Other		87			90

Total Noncurrent Assets		1,541			1,606

TOTAL ASSETS	$	10,339		$	10,333


LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	650		$	0
Accounts Payable		486			622
Short-Term Loan from Affiliate		0			194
Derivative Contracts		119			201
Accrued Interest		41			43
Other		109			163

Total Current Liabilities		1,405			1,223

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		679			644
Asset Retirement Obligations		234			226
Other Postretirement Benefit (OPEB) Costs		163			158
Derivative Contracts		31			26
Accrued Pension Costs		224			344
Environmental Costs		51			52
Other		87			72

Total Noncurrent Liabilities		1,469			1,522

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
LONG-TERM DEBT
Total Long-Term Debt		2,804			3,121

MEMBER’S EQUITY
Contributed Capital		2,028			2,028
Basis Adjustment		(986	)		(986	)
Retained Earnings		3,705			3,486
Accumulated Other Comprehensive Loss		(86	)		(61	)

Total Member’s Equity		4,661			4,467

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	10,339		$	10,333

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

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For the Six Months Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	568		$	561
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		96			104
Amortization of Nuclear Fuel		68			57
Provision for Deferred Income Taxes and ITC		83			79
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		2			(71	)
Non-Cash Employee Benefit Plan Costs		36			39
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(48	)		(3	)
Impairment of Emissions Allowances		15			0
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies		138			190
Margin Deposit Asset		(8	)		(60	)
Margin Deposit Liability		(68	)		114
Accounts Receivable		(18	)		288
Accounts Payable		(50	)		(190	)
Accounts Receivable/Payable-Affiliated Companies, net		118			250
Other Current Assets and Liabilities		(56	)		(49	)
Employee Benefit Plan Funding and Related Payments		(130	)		(111	)
Other		8			(13	)

Net Cash Provided By (Used In) Operating Activities		754			1,185

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(328	)		(429	)
Proceeds from NDT Funds Sales		426			1,475
Investment in NDT Funds		(439	)		(1,491	)
Short-Term Loan—Affiliated Company, net		(276	)		(87	)
Restricted Funds		2			107
Other		20			16

Net Cash Provided By (Used In) Investing Activities		(595	)		(409	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt		594			209
Contributed Capital		0			223
Cash Dividend Paid		(350	)		(680	)
Redemption of Long-Term Debt		(248	)		(250	)
Redemption of Non-Recourse Long-Term Debt		0			(280	)
Short-Term Loan—Affiliated Company, net		(194	)		0
Cash Payment for Debt Exchange		(13	)		0
Other		(4	)		0

Net Cash Provided By (Used In) Financing Activities		(215	)		(778	)

Net Increase (Decrease) in Cash and Cash Equivalents		(56	)		(2	)
Cash and Cash Equivalents at Beginning of Period		64			40

Cash and Cash Equivalents at End of Period	$	8		$	38

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	404		$	312
Interest Paid, Net of Amounts Capitalized	$	78		$	85

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

[THIS PAGE INTENTIONALLY LEFT BLANK]

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	For the Three Months Ended June 30,						For The Six Months Ended June 30,
	2010			2009			2010			2009
OPERATING REVENUES	$	1,536		$	1,643		$	3,980		$	4,378
OPERATING EXPENSES
Energy Costs		917			979			2,457			2,838
Operation and Maintenance		343			344			757			739
Depreciation and Amortization		177			144			354			293
Taxes Other Than Income Taxes		28			26			70			70

Total Operating Expenses		1,465			1,493			3,638			3,940

OPERATING INCOME		71			150			342			438
Other Income		3			4			8			5
Other Deductions		0			(1	)		(1	)		(2	)
Interest Expense		(80	)		(80	)		(157	)		(159	)

INCOME (LOSS) BEFORE INCOME TAXES		(6	)		73			192			282
Income Tax (Expense) Benefit		9			(29	)		(71	)		(114	)

NET INCOME		3			44			121			168
Preferred Stock Dividends		0			(1	)		(1	)		(2	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	3		$	43		$	120		$	166

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	June 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	19		$	240
Accounts Receivable, net of allowances of $65 in 2010 and $78 in 2009, respectively		808			800
Unbilled Revenues		313			411
Materials and Supplies		85			70
Prepayments		340			86
Deferred Income Taxes		46			52
Other		19			3

Total Current Assets		1,630			1,662


PROPERTY, PLANT AND EQUIPMENT		13,436			12,933
Less: Accumulated Depreciation and Amortization		(4,283	)		(4,187	)

Net Property, Plant and Equipment		9,153			8,746


NONCURRENT ASSETS
Regulatory Assets		4,220			4,402
Regulatory Assets of Variable Interest Entities (VIEs)		1,257			1,367
Long-Term Investments		218			204
Other Special Funds		52			51
Derivative Contracts		45			5
Restricted Cash of VIEs		21			17
Other		86			79

Total Noncurrent Assets		5,899			6,125

TOTAL ASSETS	$	16,682		$	16,533

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	June 30,		December 31,
	2010		2009
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	0	$	300
Securitization Debt of VIEs Due Within One Year		202		198
Commercial Paper and Loans		223		0
Accounts Payable		415		337
Accounts Payable —Affiliated Companies, net		239		496
Accrued Interest		62		56
Accrued Taxes		3		4
Clean Energy Program		181		166
Obligation to Return Cash Collateral		95		95
Other		192		210

Total Current Liabilities		1,612		1,862


NONCURRENT LIABILITIES
Deferred Income Taxes and ITC		2,759		2,710
Other Postretirement Benefit (OPEB) Costs		873		887
Accrued Pension Costs		333		565
Regulatory Liabilities		524		397
Regulatory Liabilities of VIEs		8		7
Clean Energy Program		305		400
Environmental Costs		650		652
Asset Retirement Obligations		218		211
Long-Term Accrued Taxes		113		96
Other		27		29

Total Noncurrent Liabilities		5,810		5,954


COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)

CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		3,869		3,271
Securitization Debt of VIEs		1,049		1,145

Total Long-Term Debt		4,918		4,416

Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2009—795,234 shares		0		80


STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2010 and 2009—132,450,344 shares		892		892
Contributed Capital		420		420
Basis Adjustment		986		986
Retained Earnings		2,038		1,918
Accumulated Other Comprehensive Income		6		5

Total Stockholder’s Equity		4,342		4,221

Total Capitalization		9,260		8,717

TOTAL LIABILITIES AND CAPITALIZATION	$	16,682	$	16,533

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For The Six Months Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	121		$	168
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		354			293
Provision for Deferred Income Taxes and ITC		(29	)		51
Non-Cash Employee Benefit Plan Costs		108			118
Cost of Removal		(32	)		(23	)
Market Transition Charge (MTC) Refund		122			0
Over (Under) Recovery of Electric Energy Costs (BGS and NTC)		(34	)		(45	)
Over (Under) Recovery of Gas Costs		32			53
Over (Under) Recovery of SBC		1			47
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		90			184
Materials and Supplies		(15	)		(8	)
Prepayments		(254	)		(346	)
Accounts Payable		52			(9	)
Accounts Receivable/Payable-Affiliated Companies, net		(220	)		(316	)
Other Current Assets and Liabilities		(10	)		(1	)
Employee Benefit Plan Funding and Related Payments		(287	)		(255	)
Other		(20	)		(6	)

Net Cash Provided By (Used In) Operating Activities		(21	)		(95	)

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(530	)		(379	)
Solar Loan Investments		(11	)		(9	)
Restricted Funds		(4	)		0

Net Cash Provided By (Used In) Investing Activities		(545	)		(388	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt		223			314
Issuance of Long-Term Debt		600			0
Redemption of Long-Term Debt		(300	)		(60	)
Redemption of Securitization Debt		(91	)		(87	)
Redemption of Preferred Securities		(80	)		0
Contributed Capital		0			250
Deferred Issuance Costs		(6	)		0
Preferred Stock Dividends		(1	)		(2	)

Net Cash Provided By (Used In) Financing Activities		345			415

Net Increase (Decrease) In Cash and Cash Equivalents		(221	)		(68	)
Cash and Cash Equivalents at Beginning of Period		240			91

Cash and Cash Equivalents at End of Period	$	19		$	23

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	82		$	41
Interest Paid, Net of Amounts Capitalized	$	153		$	153

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. Power and PSE&G each is only responsible for information about itself and its subsidiaries.

Note 1. Organization and Basis of Presentation

Organization

PSEG is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid Atlantic United States and in other select markets. PSEG’s four principal direct wholly owned subsidiaries are:

•

Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management functions through three principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the states in which they operate.

•

PSE&G—which is an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC. Pursuant to applicable BPU orders, PSE&G is also investing in the development of solar generation projects and energy efficiency programs within its service territory.

•

PSEG Energy Holdings L.L.C. (Energy Holdings)—which owns and operates primarily domestic projects engaged in the generation of energy and has invested in energy-related leveraged leases through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings is also investing in solar generation projects and exploring opportunities for other investments in renewable generation.

•

PSEG Services Corporation (Services)—which provides management and administrative and general services to PSEG and its subsidiaries.

Basis of Presentation

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in the Annual Report on Form 10-K for the year ended December 31, 2009 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2010.

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, 2009.

Reclassifications

Certain reclassifications have been made to the prior period financial statements to conform to the current presentation.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As a result of new guidance adopted in 2010 on Variable Interest Entities (VIEs), we are required to present certain consolidated amounts related to VIEs separately on the face of our Condensed Consolidated Balance Sheets for PSEG and PSE&G with prior period amounts being reclassified as appropriate. See Note 2. Recent Accounting Standards for additional information.

On October 1, 2009, Energy Holdings distributed the outstanding equity of PSEG Texas, LP (PSEG Texas) to PSEG. PSEG, in turn, contributed it to Power as an additional equity investment. This transaction was accounted for as a noncash transfer of equity interest between entities under common control with prior period financial statements for Power being retrospectively adjusted to include the earnings related to PSEG Texas. As a result, Power’s Operating Revenues for the three months and six months ended June 30, 2009 increased by $62 million and $152 million, respectively. Power’s Net Income for the three months and six months ended June 30, 2009 decreased by $11 million and $14 million, respectively.

Note 2. Recent Accounting Standards

New Standards Adopted during 2010

During 2010, we have adopted the following new accounting standards. The new standards did not have a material impact on our financial statements. The following is a summary of the requirements and impacts of the new standards.

Accounting for VIEs

This accounting standard amends the criteria used to determine which enterprise has a controlling financial interest in a VIE. The amended standard includes the following provisions:

•

requires an enterprise to qualitatively assess whether it should consolidate a VIE based on whether it has (i) the power to direct the activities of a VIE that most significantly impact the economic performance of a VIE and (ii) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,

•

requires an ongoing reconsideration of the primary beneficiary,

•

amends the VIE reconsideration events (triggering events), and

•

requires additional disclosures for the enterprise that consolidates a VIE (the primary beneficiary)—to present separately on the face of the consolidated balance sheet (i) assets of the consolidated VIE that can be used only to settle obligations of the consolidated VIE and (ii) liabilities of a consolidated VIE for which creditors have no recourse to the general credit of the primary beneficiary.

We adopted the standard on January 1, 2010 and there was no impact on our financial statements upon initial adoption, other than presentation. In accordance with the guidance, we continually assess the primary beneficiaries of VIEs for which we have a variable interest. See Note 3. Variable Interest Entities for further information.

Improving Disclosures about Fair Value Measurements

•

requires disclosure of transfers between Level 1 and Level 2 and reasons for transfer,

•

requires disaggregation beyond the financial statement line item when disclosing fair value instruments in the hierarchy table, and

•

requires gross presentation in Level 3 rollforward (purchases, sales, issuances and settlements) effective January 1, 2011.

We adopted the standard on January 1, 2010. We disclose the fair value instruments by appropriate classes, as required by this standard, and we do not have any transfers between Levels 1 and 2. See Note 10. Fair Value Measurements for further information.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

New Accounting Standards Issued But Not Yet Adopted

Disclosures about Credit Quality of Financing Receivables and Allowance for Credit Losses

This accounting standard update has been issued to provide greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables by requiring:

•

quantitative and qualitative information about the credit quality of financing receivables,

•

description of accounting policies and methodology used to estimate the allowance for credit losses, and

•

an analysis of financing receivables on “nonaccrual” or “past due” status.

We will adopt this new guidance effective December 31, 2010 and expect to enhance disclosure related to leveraged lease receivables.

Note 3. Variable Interest Entities

VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary of and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which is pledged as collateral to the trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.

The assets and liabilities of these VIEs are presented separately on the face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the Transition Funding and Transition Funding II assets are restricted and can only be used to settle their respective obligations. The Transition Funding and Transition Funding II creditors do not have any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding and Transition Funding II, respectively.

PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of June 30, 2010 and December 31, 2009. The risk of actual loss to PSE&G is considered remote. PSE&G did not provide any financial support to Transition Funding or Transition Funding II during the first half of 2010 or in 2009. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding and Transition Funding II.

Other VIE

PSE&G has a long-term electricity and capacity purchase agreement with a potential VIE. We have requested the information necessary to determine whether the entity was a VIE and whether PSE&G is the primary beneficiary; however, the information has not been made available. Since the counterparty has not supplied PSE&G with electricity or capacity during the first six months of 2010 or at any time during 2009, we have not been required to make any payments. PSE&G is not subject to any risk of loss.

VIE for which Energy Holdings is the Primary Beneficiary

Energy Holdings has a variable interest through its equity investment in a project for renewable energy where it is also the primary beneficiary. Energy Holdings has the power to direct the activities of the entity that most significantly impact the entity’s economic performance. Energy Holdings also has the obligation to fund up to $15 million in operating losses of the VIE through 2011. As of June 30, 2010, $7 million had been extended in the form of a note receivable.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As a result, Energy Holdings consolidates the assets and liabilities of this project which are disclosed below (excluding intercompany balances which are eliminated in consolidation):

Other than the $15 million obligation to fund operating losses through 2011, Energy Holdings does not have any contractual or other obligation to provide additional financial support to the VIE. There are no third party debt obligations for this VIE.

Note 4. Asset Dispositions

Dispositions

Leveraged Leases

During the first six months of 2010, Energy Holdings sold its interest in three leveraged leases, including two international leases for which the Internal Revenue Service (IRS) has indicated its intention to disallow certain tax deductions taken in prior years.

During the first six months of 2009, Energy Holdings sold its interest in nine leveraged leases, including seven international leases for which the IRS has indicated its intention to disallow certain tax deductions taken in prior years.


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	Millions
Proceeds from Sales	$	55	$	320	$	161	$	460
Gain (Loss) on the Sales, after-tax	$	4	$	23	$	12	$	35

Proceeds from the sales of the international leases were used to reduce the tax exposure related to these lease investments. For additional information see Note 7. Commitments and Contingent Liabilities.

GWF Energy LLC (GWF Energy)

In May 2009, Energy Holdings entered into a Memorandum of Understanding under which it will sell, in two separate transactions, its 60% ownership interest in GWF Energy, an equity method investment, for a total purchase price of $70 million. As a result, Energy Holdings recorded an after-tax impairment charge of $3 million.

Energy Holdings completed the first stage of the sale in June 2009, selling a 10.1% interest in GWF Energy for approximately $7 million. The sale of Energy Holdings’ remaining 49.9% interest is expected to close in the third quarter of 2010.

PPN Power Generating Company Limited (PPN)

In May 2009, Energy Holdings sold its 20% ownership interest in PPN, which owns and operates a 330 MW generation facility in India for approximately book value.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Other

In May 2009, Energy Holdings sold its 6.5% interest in the Midland Cogeneration Venture LP for an after-tax gain of $2 million.

Note 5. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Funds

Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisors who operate under investment guidelines developed by Power. Power classifies investments in the NDT Funds as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Funds:


	As of June 30, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	487	$	116	$	(21	)	$	582

Debt Securities
Government Obligations		304		10		(1	)		313
Other Debt Securities		234		13		(2	)		245

Total Debt Securities		538		23		(3	)		558
Other Securities		35		0		0			35

Total Available-for-Sale Securities	$	1,060	$	139	$	(24	)	$	1,175


	As of December 31, 2009
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	475	$	180	$	(5	)	$	650

Debt Securities
Government Obligations		296		4		(3	)		297
Other Debt Securities		209		10		(3	)		216

Total Debt Securities		505		14		(6	)		513
Other Securities		37		0		(1	)		36

Total Available-for-Sale Securities	$	1,017	$	194	$	(12	)	$	1,199

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table shows the value of securities in the NDT Funds that have been in an unrealized loss position for less than and greater than 12 months:


	As of June 30, 2010									As of December 31, 2009
	Less Than 12					Greater Than 12				Less Than 12					Greater Than 12
	Months					Months				Months					Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
Equity Securities(A)	$	178	$	(21	)	$	0	$	0	$	61	$	(5	)	$	0	$	0

Debt Securities
Government Obligations(B)		26		(1	)		10		0		78		(2	)		15		(1	)
Other Debt Securities(C)		41		(2	)		0		0		59		(3	)		0		0

Total Debt Securities		67		(3	)		10		0		137		(5	)		15		(1	)

Other Securities		1		0			0		0		1		(1	)		0		0

Total Available-for-Sale Securities	$	246	$	(24	)	$	10	$	0	$	199	$	(11	)	$	15	$	(1	)

(A)

Equity Securities—Investments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over several hundred companies with limited impairment durations and a severity that is generally less than ten percent of cost. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2010.

(B)

Debt Securities (Government)—Unrealized losses on Power’s NDT investments in US Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the US government or an agency of the US government, it is not expected that these securities will settle for less than their amortized cost basis, assuming Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2010.

(C)

Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily with investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of June 30, 2010.

The proceeds from the sales of and the net realized gains on securities in the NDT Funds were:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
		Millions
Proceeds from Sales	$	245		$	917		$	426		$	1,475

Net Realized Gains (Losses):
Gross Realized Gains	$	32		$	82		$	60		$	127
Gross Realized Losses		(11	)		(65	)		(23	)		(111	)

Net Realized Gains	$	21		$	17		$	37		$	16

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions on Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $57 million (after-tax)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

were recognized in Accumulated Other Comprehensive Loss on Power’s Condensed Consolidated Balance Sheet as of June 30, 2010.

The available-for-sale debt securities held as of June 30, 2010 had the following maturities:


Time Frame	Fair Value
	Millions
Less than one year	$	6
1 - 5 years		124
6 - 10 years		155
11 - 15 years		65
16 - 20 years		8
Over 20 years		200

	$	558

The cost of these securities was determined on the basis of specific identification.

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (OCI). In 2010, other-than-temporary impairments of $6 million were recognized on securities in the NDT Funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

Rabbi Trusts

PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in grantor trusts commonly known as “Rabbi Trusts.”

PSEG classifies investments in the Rabbi Trusts as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trusts:


	As of June 30, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	9	$	4	$	0	$	13
Debt Securities		101		23		0		124
Other Securities		16		0		0		16

Total PSEG Available-for-Sale Securities	$	126	$	27	$	0	$	153

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	As of December 31, 2009
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	10	$	3	$	0	$	13
Debt Securities		101		21		0		122
Other Securities		14		0		0		14

Total PSEG Available-for-Sale Securities	$	125	$	24	$	0	$	149

The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. In the six months ended June 30, 2010 and 2009, proceeds from sales, realized gains and realized losses related to Rabbi Trusts were immaterial.

The cost of these securities was determined on the basis of specific identification.

The estimated fair value of the Rabbi Trusts related to PSEG, Power and PSE&G are detailed as follows:


	As of June 30, 2010		As of December 31, 2009
	As of June 30, 2010		As of December 31, 2009
	Millions
Power	$	30	$	30
PSE&G		52		51
Other		71		68

Total PSEG Available-for-Sale Securities	$	153	$	149

Note 6. Pension and Other Postretirement Employee Benefits (OPEB)

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. New federal health care legislation enacted in March 2010 eliminates the tax deductibility of retiree health care costs beginning in 2013, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. See Note 12. Income Taxes for additional information.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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


	Pension Benefits Three Months Ended June 30,						OPEB Three Months Ended June 30,						Pension Benefits Six Months Ended June 30,						OPEB Six Months Ended June 30,
	2010			2009			2010			2009			2010			2009			2010			2009
	Millions
Components of Net Periodic Benefit Cost:
Service Cost	$	22		$	19		$	4		$	3		$	44		$	38		$	8		$	6
Interest Cost		57			59			18			18			115			118			36			36
Expected Return on Plan Assets		(66	)		(54	)		(3	)		(3	)		(133	)		(108	)		(7	)		(6	)
Amortization of Net
Transition Obligation		0			0			7			7			0			0			14			14
Prior Service Cost		0			2			3			3			0			4			6			7
Actuarial Loss		31			28			2			(1	)		61			56			4			(2	)

Net Periodic Benefit Cost	$	44		$	54		$	31		$	27		$	87		$	108		$	61		$	55
Effect of Regulatory Asset		0			0			5			5			0			0			10			10

Total Benefit Costs, Including Effect of Regulatory Asset	$	44		$	54		$	36		$	32		$	87		$	108		$	71		$	65


	Pension Benefits Three Months Ended June 30,				OPEB Three Months Ended June 30,				Pension Benefits Six Months Ended June 30,				OPEB Six Months Ended June 30,
	2010		2009		2010		2009		2010		2009		2010		2009
	Millions
Power	$	14	$	17	$	5	$	3	$	27	$	33	$	9	$	6
PSE&G		24		30		30		29		48		60		60		58
Other		6		7		1		0		12		15		2		1

Total Benefit Costs	$	44	$	54	$	36	$	32	$	87	$	108	$	71	$	65

During the six months ended June 30, 2010, PSEG contributed its planned contributions for the year 2010 of $415 million and $11 million into its pension and postretirement healthcare plans, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 7. Commitments and Contingent Liabilities

Guaranteed Obligations

Power’s 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 with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.

Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to

•

support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and

•

obtain credit.

Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.

In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to

•

fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and

•

all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).

Power believes the probability of this is unlikely. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Power is subject to

•

counterparty collateral calls related to commodity contracts, and

•

certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The face value of outstanding guarantees, current exposure and margin positions as of June 30, 2010 and December 31, 2009 are shown below:


	As of June 30, 2010			As of December 31, 2009
	As of June 30, 2010			As of December 31, 2009
	Millions
Face Value of Outstanding Guarantees	$	1,925		$	1,783
Exposure under Current Guarantees	$	375		$	403
Letters of Credit Margin Posted	$	149		$	122
Letters of Credit Margin Received	$	129		$	123

Cash Deposited and Received
Counterparty Cash Margin Deposited	$	2		$	0
Counterparty Cash Margin Received		(24	)		(90	)
Net Broker Balance Received		(24	)		(31	)
In the event Power were to lose its investment grade rating:
Additional Collateral that could be Required	$	880		$	986
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	2,537		$	2,368
Additional Amounts Posted:
Other Letters of Credit	$	95		$	52

Power nets receivables and payables with the corresponding net energy contract balances. See Note 9. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Payable.

In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

In addition to amounts for outstanding guarantees, current exposure and margin positions, Power had posted letters of credit to support various other non-energy contractual and environmental obligations.

Environmental Matters

Passaic River

Historic operations by PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex.

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)

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 CERCLA and the EPA has determined to perform a study of the entire 17-mile tidal reach of the lower Passaic River.

PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former Manufactured Gas Plant (MGP) sites. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 69 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G’s former MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim.

In 2007, the EPA released a draft “Focused Feasibility Study” that proposes six options to address the contamination cleanup of the lower eight miles of the Passaic River. The estimated costs range from $1.3 billion to $3.7 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study may be released in 2011.

In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

New Jersey Spill Compensation and Control Act (Spill Act)

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRP’s discharge of hazardous substances into the Passaic River. In February 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances they allegedly discharged into the Passaic River. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. PSEG’s answers to the complaint were filed in June 2010. Power and PSE&G believe they have good and valid defenses to the allegations contained in the third party complaints and will vigorously assert those defenses.

Natural Resource Damage Claims

In 2003, the NJDEP directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the NJ Spill Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing in 2010.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study that OCC was conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG is participating in and partially funding this study.

PSEG, Power and PSE&G cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River, the NJDEP Litigation, the Newark Bay Study Area or with respect to natural resource damages claims; however, such costs could be material.

MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. The NJDEP has also announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface water bodies that have been impacted by hazardous substances from adjoining sites. In 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the ten most significant sites for cleanup. One of the sites identified was PSE&G’s former Camden Coke facility.

During the second quarter of 2009, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $704 million and $804 million from June 30, 2009 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $704 million on its Condensed Consolidated Balance Sheet as of June 30, 2009. Subsequent expenditures reduced the liability to $685 million as of June 30, 2010. Of this amount, $35 million was recorded in Other Current Liabilities and $650 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $685 million Regulatory Asset with respect to these costs.

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

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

In November 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Power’s generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of sulfur dioxide (SO₂), nitrogen oxide (NO_x), particulate matter and mercury. The remaining projects necessary to implement this program are expected to be completed by the end of 2010 at an estimated cost of $200 million to $250 million for Mercer and $750 million to $800 million for Hudson, of which $867 million has been spent on both projects as of June 30, 2010.

In January 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.

Mercury Regulation

In 2005, the EPA established a limit for nickel emissions from oil fired electric generating units and a cap-and-trade program for mercury emissions from coal fired electric generating units.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In 2008, the United States Court of Appeals for the District of Columbia Circuit rejected the EPA’s mercury emissions program and required the EPA to develop standards for mercury and nickel emissions that adhere to the Maximum Available Control Technology (MACT) provisions of the Clean Air Act. In 2009, the EPA indicated that it intended to move forward with a rule-making process to develop MACT standards consistent with the Court’s ruling and agreed to finalize them by November 2011.

The full impact to PSEG of these developments is uncertain. It is expected that new MACT requirements will require more stringent control than the cap-and-trade program struck down by the D.C. Circuit Court; however, the costs of compliance with mercury MACT standards will have to be compared with the existing state level mercury control requirements, as described below.

Pennsylvania

In 2007, Pennsylvania finalized its “state-specific” requirements to reduce mercury emissions from coal fired electric generating units. These requirements were more stringent than the EPA’s vacated Clean Air Mercury Rule but not as stringent as would be required by a MACT process. In 2009, the Commonwealth Court of Pennsylvania struck down the state rule, indicating that the rule violated Pennsylvania law because it was inconsistent with the Clean Air Act. In December 2009, the Commonwealth Court’s decision was affirmed by the Supreme Court of Pennsylvania. Unless the law in Pennsylvania is changed requiring the regulation of mercury by the Pennsylvania Department of Environmental Protection, then our Pennsylvania generating stations likely will be subject to regulation under the EPA’s MACT rule. It is uncertain whether the Keystone and Conemaugh generating stations will be able to achieve the necessary reductions at these stations with currently planned capital projects under a MACT regulation.

Connecticut

Mercury emissions control standards were effective in July 2008 and require coal fired power plants to achieve either an emissions limit or 90% mercury removal efficiency through technology installed to control mercury emissions. With the recently installed activated carbon injection and baghouse at Bridgeport Unit 3, Power has demonstrated that it complies with the mercury limits in these standards.

New Jersey

New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.

Power has achieved or will achieve the required reductions with mercury control technologies that are part of Power’s multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

NO_x Reduction

New Jersey

In April 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel fired electric generation units. The rule has a significant impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generation units (approximately 800 MW) by April 30, 2015.

Power has been working with the NJDEP throughout the development of this rulemaking to minimize financial impact and to provide for transitional lead time for it to address the retirement of electric generation units. Power cannot predict the financial impact resulting from compliance with this rulemaking.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Connecticut

Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NO_x emission limitations that were incorporated into the facilities’ operating permits. On April 30, 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability related to these obligations, which was included in Environmental Costs on Power’s and PSEG’s Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009.

Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NJPDES) permits expire within five years of their effective date. In order to renew these permits, but allow the plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. Power has filed or will be filing applications for permits in a variety of states that require discharge.

Pursuant to a consent decree with environmental groups, the EPA was required to promulgate rules governing cooling water intake structures under Section 316(b) of the FWPCA. In 2004, the EPA published a rule which did not mandate the use of cooling towers at large existing generating plants. Rather, the rule provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.

One of the most significant NJPDES permits governing cooling water intake structures at Power is for Salem. In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the Phase II 316(b) rules published in 2004, which govern cooling water intake structures at large electric generating facilities. Power had historically used restoration and/or a site-specific cost-benefit test in applications it had filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer. However, the 316(b) rules would also have been applicable to Bridgeport, and possibly, the Sewaren and New Haven stations. In addition to the Salem renewal application, permit renewal applications have been submitted to the NJDEP for Hudson and Sewaren and to the Connecticut Department of Environmental Protection for Bridgeport.

Portions of the 316(b) rule were challenged by certain northeast states, environmentalists and industry groups. In January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision that remanded major portions of the regulations and determined that Section 316(b) of the FWPCA does not support the use of restoration and the site-specific cost-benefit test. In April 2009, the U.S. Supreme Court reversed the Second Circuit’s opinion, concluding that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations. The matter was sent back to the Second Circuit for further proceedings consistent with the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Supreme Court’s opinion. In September 2009, the Second Circuit issued an order remanding the matter to the EPA in light of the Supreme Court’s opinion.

The Supreme Court’s ruling allows the EPA to continue to use the site-specific cost-benefit test in determining best technology available for minimizing adverse environmental impact. However, the results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants could be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Power’s share would have been approximately $575 million. These costs have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

The EPA has stated that it anticipates proposing a rule in September 2010, and publishing a final rule in July 2012. Until a new rule governing cooling water intake structures at existing power generating stations is finalized, the EPA and states implementing the FWPCA have been instructed to issue permits on a case-by-case basis using the agency’s best professional judgment.

In addition to the anticipated EPA rulemaking, several states have begun setting policies that may require closed cycle cooling including California and New York. It is unknown how these policies will ultimately impact the EPA’s rulemaking.

In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that company’s nuclear generating station located in New Jersey. The draft permit is subject to public comment and review prior to being finalized by the NJDEP. We cannot predict at this time the final outcome of the NJDEP decision and the impact, if any, such a decision would have on any of Power’s once-through cooled generating stations.

Stormwater

In October 2008, the NJDEP notified Power that it must apply for an individual stormwater discharge permit for its Hudson generating station. Hudson stores its coal in an open air pile and, as a result, it is exposed to precipitation. Discharge of stormwater from Hudson has been regulated pursuant to a Basic Industrial Stormwater General Permit, authorization of which has been previously approved by the NJDEP. The NJDEP has determined that Hudson is no longer eligible to utilize this general permit and must apply for an individual NJPDES permit for stormwater discharges. While the full extent of these requirements remains unclear, to the extent Power may be required to reduce or eliminate the exposure of coal to stormwater, or be required to construct technologies preventing the discharge of stormwater to surface water or groundwater, those costs could be material.

New Generation and Development

Nuclear

Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at Peach Bottom Units 2 and 3. Completion of these upgrades is expected to result in an increase of Power’s share of nominal capacity by 32 MW (14 MW at Unit 3 in 2011 and 18 MW at Unit 2 in 2012). Total expenditures through June 30, 2010 were $29 million and are expected to continue through 2012.

Power has begun expenditures in pursuit of additional output through an extended power uprate of its co-owned Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power’s share of the increased capacity is expected to be 133 MW with an anticipated cost of approximately $400 million. Total expenditures through June 30, 2010 were $8 million and are expected to continue through 2016.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Connecticut

Power has been selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval has been received and construction is expected to commence in June 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $130 million to $140 million. Total capitalized expenditures through June 30, 2010 were $15 million, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Final approval has been received and construction is expected to commence in the second quarter of 2011. The project is expected to be in service by June 2012. In addition, capacity in the amount of 89 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 period. Final approval has been received, and the project is expected to be in service by June 2013. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through June 30, 2010 were $9 million which are included in Property, Plant and Equipment on Power’s and PSEG’s Condensed Consolidated Balance Sheets.

PSE&G—Solar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&G’s commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units. PSE&G’s remaining 2010 expenditures for these solar units are anticipated to be approximately $33 million, with additional purchases made on a quarterly basis during the remaining two-year term of the purchase agreement.

In January 2010, PSE&G announced that it had entered into contracts with four developers for 12 MW of solar capacity to be developed on land it owns in Edison, Linden, Trenton and Hamilton. The projects represent an investment of approximately $50 million. Construction has started on the Trenton and Edison projects, which are expected to be commercially operational in the fourth quarter of 2010. Construction on the Linden and Hamilton projects are expected to start later in the third quarter of 2010 following receipt of necessary approvals.

Solar Source

Energy Holdings has developed a solar project in western New Jersey and has acquired two additional solar projects in Florida and Ohio, which together have a total capacity of approximately 29 MW. The western New Jersey and Ohio projects are complete and the Florida project is expected to be completed in the third quarter of 2010. Energy Holdings issued guarantees to cover the construction costs of the Florida and Ohio projects and as of June 30, 2010 has $12 million of future payment obligations related to construction milestones to be achieved in the near future. By the end of the third quarter 2010, it is expected that these payment obligations will be zero. The total investment for the three projects is expected to be approximately $114 million.

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

PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

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

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


	Auction Year
	2007	2008	2009	2010
36-Month Terms Ending	May 2010	May 2011	May 2012	May 2013	(A)
Load (MW)	2,758	2,800	2,900	2,800
$ per kWh	0.09888	0.11150	0.10372	0.09577

(A)	Prices set in the 2010 BGS auction became effective on June 1, 2010 when the 2007 BGS auction agreements expired.

PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. For additional information, see Note 16. Related-Party Transactions. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements.

Minimum Fuel Purchase Requirements

Power has various long-term fuel purchase commitments for coal and oil to support its fossil generation stations and for supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations and for firm transportation and storage capacity for natural gas.

Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.

Power’s strategy is to maintain certain levels of uranium concentrates and uranium hexafluoride in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below may include estimated quantities to be purchased that deviate from contractual nominal quantities.

Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2011 and a portion for 2012, 2013 and 2014 at Salem, Hope Creek and Peach Bottom.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of June 30, 2010, the total minimum purchase requirements included in these commitments were as follows:


Fuel Type	Commitments through 2014		Power’s Share
		Millions
Nuclear Fuel
Uranium	$	640	$	382
Enrichment	$	576	$	359
Fabrication	$	215	$	138
Natural Gas	$	803	$	803
Coal/Oil	$	757	$	757

Included in the $757 million commitment for coal and oil above is $523 million related to a certain coal contract under which Power can cancel contractual deliveries at minimal cost. There have been no cancellations in 2010.

The Texas generation facilities also have a contract for low BTU content gas which commenced in late 2009 with a term of 15 years and a minimum volume of approximately 13 MMBTUs per year. The gas must meet an availability and quality specifications. Power has the right to cancel delivery of the gas at a minimal cost.

Regulatory Proceedings

Competition Act

In April 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

In July 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In July 2007, PSE&G filed a motion to dismiss the amended Complaint, which was granted in October 2007. In November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court. In February 2009, the New Jersey Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division’s decision.

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G’s motion to dismiss.

BPU Deferral Audit

The BPU Energy and Audit Division conducts audits of deferred balances under various adjustment clauses. A draft Deferral Audit Phase II report relating to the 12-month period ended July 31, 2003 was released to the BPU in April 2005.

That report, which addresses Societal Benefits Charges (SBC), Market Transition Charge (MTC) and non-utility generation (NUG) deferred balances, found that the Phase II deferral balances complied in all material respects with applicable BPU Orders. It also noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G had employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. The matter was referred to the Office of Administrative Law.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In January 2009, the administrative law judge (ALJ) issued a decision which upheld PSE&G’s central contention that the 2004 BPU Order approving the Phase I settlement resolved the issues being raised by the Staff and the NJ Division of Rate Counsel, and that these issues should not be subject to re-litigation in respect of the first three years of the transition period. The ALJ’s decision stated that the BPU could elect to convene a separate proceeding to address the fourth and final year reconciliation of MTC recoveries.

In September 2009, the BPU rejected the ALJ’s initial decision and elected to maintain jurisdiction over the matter. In June 2010, the BPU approved a settlement agreement resolving the MTC issue. Under the agreement, PSE&G will refund $122 million to electric customers over a two-year period through a new component of the NUG charge. As a result, during the second quarter of 2010, PSE&G recorded a pre-tax charge of $122 million, which is included in Operating Revenues and the corresponding Regulatory Liability.

Retail Gas Transportation Rates

In July 2010, as part of PSE&G’s gas base rate proceeding, the BPU ordered a supplemental and expedited review of certain issues related to the gas transportation rate that PSE&G charges to Power, including:

•

whether the current rate charged to Power should be changed prospectively,

•

whether any retroactive relief is warranted with respect to these charges to Power since 2002,

•

whether the SBC and other clause charges are applicable, and

•

whether the Transportation Service Gas-Nonfirm (TSG-NF) rate should apply to Power and other electric generation customers in PSE&G’s service territory.

In the event that the BPU were to find that the rate charged to Power was not proper and order refunds, the results could be material. PSE&G believes such refunds would constitute retroactive ratemaking and be prohibited under applicable law. However, the outcome of the regulatory proceeding cannot be predicted. In July, a complaint was filed by an independent power generator against Power at FERC related to the gas transportation rate. The complaint asserts that the existing rate charged to Power violates FERC’s affiliate rules and Power’s market-based rate authority. The complaint requests, among other things, that Power’s market-based rate authority be revoked. While Power views revocation of its market-based rate authority as unlikely, it is not possible to predict the outcome of this proceeding. PSEG believes that the rates charged to Power were and continue to be lawful and appropriate, and intends to assert this position vigorously.

Consolidated Tax Adjustments

Another generic proceeding regarding consolidated tax adjustments is expected to begin later in 2010, pending our filing of a petition within 60 days of the BPU’s issuance of the final base rate case order on July 9, 2010. New Jersey is one of five states that make consolidated tax adjustments. These adjustments are intended to share tax benefits realized by non-regulated subsidiaries with utility customers under certain circumstances. The generic proceeding will address the appropriateness of the adjustment and the methodology and mechanics of the calculation. The policy adopted by the BPU will influence the non-regulated investments made by PSEG in the future.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&G’s share is $705 million. PSE&G has recorded a discounted liability of $486 million as of June 30, 2010. Of this amount, $181 million was recorded as a current liability and $305 million as a noncurrent liability. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the SBC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Leveraged Lease Investments

The IRS has issued reports with respect to its audits of PSEG’s consolidated federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.

PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, six cases have been decided at the trial court level, four of which were decided in favor of the government. An appeal of one of these decisions was affirmed. The fifth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer.

In order to reduce the cash tax exposure related to these leases, Energy Holdings is pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds. Energy Holdings has terminated a total of 15 of these leasing transactions since December 2008 and reduced the related cash tax exposure by $800 million. As of June 30, 2010 and December 31, 2009, PSEG’s total gross investment in such transactions was $232 million and $347 million, respectively.

Cash Impact

As of June 30, 2010, an aggregate of approximately $550 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, reducing its potential cash exposure to $230 million. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. Penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure will grow at the rate of $6 million per quarter during 2010. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $60 million to $80 million of tax would be due for tax positions through June 30, 2010.

PSEG currently anticipates that it may be required to pay between $110 million and $290 million in tax, interest and penalties for the tax years 1997-2000 during 2010 and subsequently commence litigation to recover those amounts. It is possible that an additional payment of between $210 million and $530 million could be required during 2010 for tax years 2001-2003 followed by further litigation to recover those amounts. Any potential claims PSEG would make to recover such amounts would include the deposit noted above.

Earnings Impact

PSEG’s current reserve position represents its view of the earnings impact that could result from a settlement related to these transactions, although a total loss, consistent with the broad settlement offer proposed by the IRS, would result in an additional earnings charge of $120 million to $140 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 8. Changes in Capitalization

The following capital transactions occurred in the first six months of 2010:

Power

•

issued $300 million of 2.50% unsecured Senior Notes due April 2013 in April,

•

issued $250 million of 5.125% unsecured Senior Notes due April 2020 in April,

•

redeemed $161 million of 6.50% Medium-Term Notes (MTNs) due 2014 in April,

•

redeemed $48 million of 6.00% MTNs due 2013 in April,

•

exchanged an aggregate principal amount of $195 million of 7.75% Senior Notes due 2011 for $208 million comprised of $156 million in newly issued 5.125% Senior Notes due April 2020 and cash payments of $52 million. Since the debt exchange was treated as a debt modification, the resulting premium of $13 million was deferred and will be amortized over the term of the newly issued debt. The deferred amount is reflected as an offset to Long-Term Debt on Power’s Condensed Consolidated Balance Sheet.

•

converted $44 million of its Senior Notes servicing and securing the 4.00% Pollution Control Bonds of the Pennsylvania Economic Development Authority (PEDFA) to variable rate in January 2009 when the PEDFA Bonds were converted to variable rate demand bonds. Power reacquired the PEDFA Bonds in December 2009. In January 2010, Power caused the PEDFA Bonds to be converted from Alternative Minimum Tax (AMT) to non-AMT status and to be remarketed as variable rate demand bonds backed by a letter of credit expiring in January 2011.

•

paid cash dividends of $350 million to PSEG.

PSE&G

•

issued $300 million of 2.70% MTNs, Series G due May 2015 in May,

•

redeemed all of its $80 million of outstanding preferred stock in March,

•

paid $300 million of floating rate (Libor + .875%) First and Refunding Mortgage Bonds at maturity in March,

•

issued $300 million of 5.50% MTNs, Series G due March 2040 in March,

•

paid $86 million of Transition Funding’s securitization debt, and

•

paid $5 million of Transition Funding II’s securitization debt.

Energy Holdings

•

paid $2 million of nonrecourse project debt.

Note 9. Financial Risk Management Activities

The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Commodity Prices

The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power uses physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Derivative contracts that do not qualify for hedge accounting or normal purchases/normal sales treatment are marked to market with changes in fair value recorded in the income statement. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists.

Cash Flow Hedges

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

•

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

•

the price of fuel to meet its fuel purchase requirements.

These derivative transactions are designated and effective as cash flow hedges. As of June 30, 2010 and December 31, 2009, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:


	As of June 30, 2010		As of December 31, 2009
		Millions
Fair Value of Cash Flow Hedges	$	293	$	286
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	180	$	184

The expiration date of the longest-dated cash flow hedge at Power is in 2012. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the 12 months ending June 30, 2011 and June 30, 2012 are $124 million and $56 million, respectively. Ineffectiveness associated with these hedges was $(2) million at June 30, 2010.

Trading Derivatives

In general, the main purpose of Power’s wholesale marketing operation is to optimize the value of the output of the generating facilities via various products and services available in the markets we serve. Power does engage in some trading of electricity and energy-related products where such transactions are not associated with the output or fuel purchase requirements of our facilities. This trading consists mostly of energy supply contracts where we secure sales commitments with the intent to supply the energy services from purchases in the market rather than from our owned generation. Such trading activities represent approximately one percent of Power’s gross margin.

Other Derivatives

Power enters into other contracts that are derivatives, but do not qualify for cash flow hedge accounting. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Prior to June 2009, some of the derivative contracts were also used in Power’s NDT Funds. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of June 30, 2010 and December 31, 2009 was $32 million and $8 million, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Interest Rates

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

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. In January 2010, we entered into a series of interest rate swaps totaling $600 million converting $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and $300 million of Power’s $600 million of 6.95% of Senior Notes due June 2012 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying debt. In 2009 PSEG had entered into three interest rate swaps also designated as fair value hedges. As of June 30, 2010 and December 31, 2009, the fair value of all the underlying hedges was $38 million and $(3) million, respectively.

Cash Flow Hedges

PSEG, Power, PSE&G and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of June 30, 2010, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of June 30, 2010 and December 31, 2009. The Accumulated Other Comprehensive Loss related to interest rate derivatives designated as cash flow hedges was $(3) million and $(4) million as of each of June 30, 2010 and December 31, 2009, respectively.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets:


Balance Sheet Location	As of June 30, 2010
	Power												PSE&G		PSEG		Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges		Fair Value Hedges		Total Derivatives
	Energy- Related Contracts			Energy- Related Contracts			Netting (A)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
		Millions
Derivative Contracts
Current Assets	$	318		$	1,180		$	(1,252	)	$	246		$	6	$	17	$	269
Noncurrent Assets	$	195		$	263		$	(355	)	$	103		$	45	$	21	$	169

Total Mark-to-Market Derivative Assets	$	513		$	1,443		$	(1,607	)	$	349		$	51	$	38	$	438

Derivative Contracts
Current Liabilities	$	(122	)	$	(1,185	)	$	1,188		$	(119	)	$	0	$	0	$	(119	)
Noncurrent Liabilities	$	(98	)	$	(252	)	$	319		$	(31	)	$	0	$	0	$	(31	)

Total Mark-to-Market Derivative (Liabilities)	$	(220	)	$	(1,437	)	$	1,507		$	(150	)	$	0	$	0	$	(150	)

Total Net Mark-to-Market Derivative Assets (Liabilities)	$	293		$	6		$	(100	)	$	199		$	51	$	38	$	288

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	As of December 31, 2009
	Power												PSE&G		PSEG			Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges		Fair Value Hedges			Total Derivatives
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts			Netting (A)			Total Power			Energy- Related Contracts		Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	357		$	1,083		$	(1,209	)	$	231		$	1	$	11		$	243
Noncurrent Assets	$	321		$	255		$	(458	)	$	118		$	5	$	0			123

Total Mark-to-Market Derivative Assets	$	678		$	1,338		$	(1,667	)	$	349		$	6	$	11		$	366

Derivative Contracts
Current Liabilities	$	(219	)	$	(1,124	)	$	1,142		$	(201	)	$	0	$	0		$	(201	)
Noncurrent Liabilities	$	(173	)	$	(235	)	$	382		$	(26	)	$	0	$	(14	)		(40	)

Total Mark-to-Market Derivative (Liabilities)	$	(392	)	$	(1,359	)	$	1,524		$	(227	)	$	0	$	(14	)	$	(241	)

Total Net Mark-to-Market Derivative Assets (Liabilities)	$	286		$	(21	)	$	(143	)	$	122		$	6	$	(3	)	$	125

(A)

Represents the netting of fair value balances with the same counterparty and the application of collateral. As of June 30, 2010 and December 31, 2009, net cash collateral received of $100 million and $143 million, respectively, was netted against the corresponding net derivative contract positions. Of the $100 million as of June 30, 2010, cash collateral of $(132) million and $(67) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $68 million and $31 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $143 million as of December 31, 2009, cash collateral of $(114) million and $(109) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $47 million and $33 million were netted against current liabilities and noncurrent liabilities, respectively.

The aggregate fair value of derivative contracts in a liability position as of June 30, 2010 that contain triggers for additional collateral was $531 million. This potential additional collateral is included in the $880 million discussed in Note 7. Commitments and Contingent Liabilities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following shows the effect on the Condensed Consolidated Statements of Operations and Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended June 30, 2010 and 2009:


Derivatives in SFAS 133 Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)						Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)						Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Three Months Ended June 30,							Three Months Ended June 30,							Three Months Ended June 30,
	2010			2009				2010			2009				2010			2009
	Millions
PSEG(A)
Energy-Related Contracts	$	(99	)	$	121		Operating Revenue	$	42		$	138		Operating Revenue	$	(1	)	$	(1	)
Energy-Related Contracts		3			(15	)	Energy Costs		(1	)		(37	)			0			0
Interest Rate Swaps		0			0		Interest Expense		(1	)		(1	)			0			0

Total PSEG	$	(96	)	$	106			$	40		$	100			$	(1	)	$	(1	)

PSEG Power
Energy-Related Contracts	$	(99	)	$	121		Operating Revenue	$	42		$	138		Operating Revenue	$	(1	)	$	(1	)
Energy-Related Contracts		3			(15	)	Energy Costs		(1	)		(37	)			0			0

Total Power	$	(96	)	$	106			$	41		$	101			$	(1	)	$	(1	)

PSE&G
Interest Rate Swaps	$	0		$	0		Interest Expense	$	0		$	(1	)		$	0		$	0

Total PSE&G	$	0		$	0			$	0		$	(1	)		$	0		$	0

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the six months ended June 30, 2010 and 2009:


Derivatives in SFAS 133 Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)						Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Six Months Ended June 30,						Six Months Ended June 30,							Six Months Ended June 30,
	2010		2009				2010			2009				2010			2009
	Millions
PSEG(A)
Energy-Related Contracts	$	109	$	503		Operating Revenue	$	118		$	294		Operating Revenue	$	(3	)	$	7
Energy-Related Contracts		1		(43	)	Energy Costs		(2	)		(63	)			0			0
Interest Rate Swaps		0		0		Interest Expense		(1	)		(5	)			0			0

Total PSEG	$	110	$	460			$	115		$	226			$	(3	)	$	7

PSEG Power
Energy-Related Contracts	$	109	$	503		Operating Revenue	$	118		$	294		Operating Revenue	$	(3	)	$	7
Energy-Related Contracts		1		(43	)	Energy Costs		(2	)		(63	)			0			0
Interest Rate Swaps		0		0		Interest Expense		0			(4	)			0			0

Total Power	$	110	$	460			$	116		$	227			$	(3	)	$	7

PSE&G
Interest Rate Swaps	$	0	$	0		Interest Expense	$	0		$	(1	)		$	0		$	0

Total PSE&G	$	0	$	0			$	0		$	(1	)		$	0		$	0

(A)	Includes amounts for PSEG Parent.

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


Accumulated Other Comprehensive Income	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2009	$	305		$	180
Gain Recognized in AOCI (Effective Portion)		206			122
Less: Gain Reclassified into Income (Effective Portion)		(75	)		(44	)

Balance as of March 31, 2010	$	436		$	258

Loss Recognized in AOCI (Effective Portion)	$	(96	)	$	(57	)
Less: Gain Reclassified into Income (Effective Portion)	$	(40	)	$	(24	)

Balance as of June 30, 2010	$	300		$	177

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months and six months ended June 30, 2010 and 2009:


Derivatives Not Designated as Hedges	Location of Pre-tax Gain (Loss) Recognized in Income on Derivatives	Pre-tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,					Six Months Ended June 30,
		2010			2009		2010			2009
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	(79	)	$	49	$	34		$	180
Energy-Related Contracts	Energy Costs		1			1		(18	)		(85	)
Interest Rate Swaps	Interest Expense		0			0		0			(1	)
Derivatives in NDT Funds	Other Income		0			6		0			13

Total PSEG and Power		$	(78	)	$	56	$	16		$	107

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of these contracts are marked to market. The tables above do not include contracts for which Power has elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.

In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges for the three months and the six months ended June 30, 2010 was to reduce interest expense by approximately $6 million and $12 million, respectively.

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2010 and December 31, 2009:


Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2010
Natural Gas	Dth	1,104	0	890	214
Electricity	MWh	226	0	226	0
Capacity	MW days	1	0	1	0
Financial Transmission Rights (FTRs)	MWh	46	0	46	0
Emissions Allowances	Tons	0	0	0	0
Oil	Barrels	1	0	1	0
Renewable Energy Credits	MWh	1	0	1	0
Interest Rate Swaps	US Dollars	1,150	1,150	0	0
As of December 31, 2009
Natural Gas	Dth	842	0	613	229
Electricity	MWh	194	0	194	0
Capacity	MW days	1	0	1	0
FTRs	MWh	23	0	23	0
Emissions Allowances	Tons	1	0	1	0
Oil	Barrels	0	0	0	0
Renewable Energy Credits	MWh	1	0	1	0
Interest Rate Swaps	US Dollars	550	550	0	0

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Credit Risk

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

In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s financial condition, results of operations or net cash flows. As of June 30, 2010, 97% of the credit exposure (MTM plus net receivables and payables, less cash collateral) for Power’s operations was with investment grade counterparties.

The following table provides information on Power’s credit risk from others, net of collateral, as of June 30, 2010. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of 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 quality of the company’s credit risk by credit rating of the counterparties.


	Current		Securities held as		Net		Number of Counterparties		Net Exposure of Counterparties
Rating	Exposure		Collateral		Exposure		>10%		>10%
	Millions								Millions
Investment Grade—External Rating	$	1,085	$	91	$	1,062	$	2	$	539	(A)
Non-Investment Grade—External Rating		29		0		29		0		0
Investment Grade—No External Rating		35		0		35		0		0
Non-Investment Grade—No External Rating		4		1		4		0		0

Total	$	1,153	$	92	$	1,130	$	2	$	539

(A)	Includes net exposure of $376 million with PSE&G. The remaining net exposure of $163 million is with a nonaffiliated power purchaser which is a regulated investment grade counterparty.

The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would be no exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of June 30, 2010, Power had 206 active counterparties.

Note 10. Fair Value Measurements

PSEG, Power and PSE&G adopted accounting guidance for “Fair Value Measurements” for financial assets and liabilities effective January 1, 2008 and for nonrecurring fair value measurements of non-financial assets and liabilities effective January 1, 2009. The fair value measurements guidance defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities.

Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist mainly of various financial transmission rights, certain full requirements contracts, other longer term capacity and transportation contracts and certain commingled securities.

In addition to establishing a measurement framework, the fair value measurement guidance nullified the prior guidance which did not allow an entity to recognize an unrealized gain or loss at the inception of a derivative instrument unless the fair value of that instrument was obtained from a quoted market price in an active market or was otherwise evidenced by comparison to other observable current market transactions or based on a valuation technique incorporating observable market data.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following tables present information about PSEG’s, Power’s and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis at June 30, 2010 and December 31, 2009, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.


	Recurring Fair Value Measurements as of June 30, 2010
				Cash Collateral			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	Total			Netting(E)			(Level 1)		(Level 2)			(Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	400		$	(199	)	$	0	$	337		$	262
Interest Rate Swaps(B)	$	38		$	0		$	0	$	38		$	0
NDT Funds:(C)
Equity Securities	$	582		$	0		$	582	$	0		$	0
Debt Securities—Government Obligations	$	313		$	0		$	0	$	313		$	0
Debt Securities—Other	$	245		$	0		$	0	$	245		$	0
Other Securities	$	35		$	0		$	1	$	28		$	6
Rabbi Trusts—Mutual Funds(C)	$	153		$	0		$	13	$	124		$	16
Other Long-Term Investments(D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(150	)	$	99		$	0	$	(166	)	$	(83	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	349		$	(199	)	$	0	$	337		$	211
NDT Funds:(C)
Equity Securities	$	582		$	0		$	582	$	0		$	0
Debt Securities—Government Obligations	$	313		$	0		$	0	$	313		$	0
Debt Securities—Other	$	245		$	0		$	0	$	245		$	0
Other Securities	$	35		$	0		$	1	$	28		$	6
Rabbi Trusts—Mutual Funds(C)	$	30		$	0		$	3	$	24		$	3
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(150	)	$	99		$	0	$	(166	)	$	(83	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	51		$	0		$	0	$	0		$	51
Rabbi Trusts—Mutual Funds(C)	$	52		$	0		$	5	$	42		$	5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Recurring Fair Value Measurements as of December 31, 2009
Description	Total			Cash Collateral Netting(E)			Quoted Market Prices of Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	355		$	(223	)	$	0	$	415		$	163
Interest Rate Swaps(B)	$	11		$	0		$	0	$	11		$	0
NDT Funds:(C)
Equity Securities	$	650		$	0		$	650	$	0		$	0
Debt Securities-Government
Obligations	$	297		$	0		$	0	$	297		$	0
Debt Securities-Other	$	216		$	0		$	0	$	216		$	0
Other Securities	$	36		$	0		$	0	$	27		$	9
Rabbi Trusts—Mutual Funds(C)	$	149		$	0		$	14	$	121		$	14
Other Long-Term Investments(D)	$	2		$	0		$	2	$	0		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(227	)	$	80		$	0	$	(267	)	$	(40	)
Interest Rate Swaps(B)	$	(14	)	$	0		$	0	$	(14	)	$	0
Power
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	349		$	(223	)	$	0	$	415		$	157
NDT Funds:(C)
Equity Securities	$	650		$	0		$	650	$	0		$	0
Debt Securities-Government
Obligations	$	297		$	0		$	0	$	297		$	0
Debt Securities-Other	$	216		$	0		$	0	$	216		$	0
Other Securities	$	36		$	0		$	0	$	27		$	9
Rabbi Trusts—Mutual Funds(C)	$	30		$	0		$	3	$	24		$	3
Liabilities:
Derivative Contracts:
Energy-Related Contracts(A)	$	(227	)	$	80		$	0	$	(267	)	$	(40	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts(A)	$	6		$	0		$	0	$	0		$	6
Rabbi Trusts—Mutual Funds(C)	$	51		$	0		$	5	$	41		$	5

(A)

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average midpoint from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.

(B)

Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(C)

The NDT Funds maintain investments in various equity and fixed income securities classified as “available for sale.” These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the NDT funds are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or in some cases midpoint, bid or ask price (primarily Level 1).

Power’s investments in fixed income securities are primarily with investment grade corporate bonds and US Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities. (primarily Level 2). Short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3).

The Rabbi Trust mutual funds are mainly invested in a US bond index fund, an S&P 500 index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).

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

(E)	Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under the accounting guidance for Offsetting of Amounts Related to Certain Contracts.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for three months and six months ended June 30, 2010 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Three Months Ended June 30, 2010


	Balance as of April 1, 2010		Total Gains or (Losses) Realized/Unrealized					Purchases, (Sales) and Settlements			Balance as of June 30, 2010
Description	Balance as of April 1, 2010		Included in Income(A)			Included in Regulatory Assets/ Liabilities(B)		Purchases, (Sales) and Settlements			Balance as of June 30, 2010
	Millions
PSEG
Net Derivative Assets	$	256	$	(87	)	$	0	$	10		$	179
NDT Funds	$	13	$	0		$	0	$	(7	)	$	6
Rabbi Trust Funds	$	16	$	0		$	0	$	0		$	16
Power
Net Derivative Assets	$	205	$	(87	)	$	0	$	10		$	128
NDT Funds	$	13	$	0		$	0	$	(7	)	$	6
Rabbi Trust Funds	$	3	$	0		$	0	$	0		$	3
PSE&G
Net Derivative Assets	$	51	$	0		$	0	$	0		$	51
Rabbi Trust Funds	$	5	$	0		$	0	$	0		$	5

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Six Months Ended June 30, 2010


	Balance as of January 1, 2010		Total Gains or (Losses) Realized/Unrealized				Purchases, (Sales) and Settlements			Balance as of June 30, 2010
Description	Balance as of January 1, 2010		Included in Income(C)		Included in Regulatory Assets/ Liabilities(B)		Purchases, (Sales) and Settlements			Balance as of June 30, 2010
	Millions
PSEG
Net Derivative Assets	$	123	$	30	$	45	$	(19	)	$	179
NDT Funds	$	9	$	0	$	0	$	(3	)	$	6
Rabbi Trust Funds	$	14	$	0	$	0	$	2		$	16
Power
Net Derivative Assets	$	117	$	30	$	0	$	(19	)	$	128
NDT Funds	$	9	$	0	$	0	$	(3	)	$	6
Rabbi Trust Funds	$	3	$	0	$	0	$	0		$	3
PSE&G
Net Derivative Assets	$	6	$	0	$	45	$	0		$	51
Rabbi Trust Funds	$	5	$	0	$	0	$	0		$	5

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for three months and six months ended June 30, 2009 follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended June 30, 2009


	Balance as of March 31, 2009			Total Gains or (Losses) Realized/Unrealized					Purchases, (Sales) and Settlements			Balance as of June 30, 2009
Description	Balance as of March 31, 2009			Included in Income(A)			Included in Regulatory Assets/ Liabilities(B)		Purchases, (Sales) and Settlements			Balance as of June 30, 2009
	Millions
PSEG
Net Derivative Assets	$	144		$	(44	)	$	17	$	33		$	150
NDT Funds	$	22		$	(2	)	$	0	$	10		$	30
Rabbi Trust Funds	$	15		$	0		$	0	$	(1	)	$	14
Power
Net Derivative Assets	$	198		$	(44	)	$	0	$	33		$	187
NDT Funds	$	22		$	(2	)	$	0	$	10		$	30
Rabbi Trust Funds	$	3		$	0		$	0	$	0		$	3
PSE&G
Net Derivative Liabilities	$	(54	)	$	0		$	17	$	0		$	(37	)
Rabbi Trust Funds	$	5		$	0		$	0	$	0		$	5

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Six Months Ended June 30, 2009


	Balance as of December 31, 2008			Total Gains or (Losses) Realized/Unrealized					Purchases, (Sales) and Settlements			Balance as of June 30, 2009
Description	Balance as of December 31, 2008			Included in Income(C)			Included in Regulatory Assets/ Liabilities(B)		Purchases, (Sales) and Settlements			Balance as of June 30, 2009
	Millions
PSEG
Net Derivative Assets	$	32		$	84		$	27	$	7		$	150
NDT Funds	$	41		$	(2	)	$	0	$	(9	)	$	30
Rabbi Trust Funds	$	14		$	0		$	0	$	0		$	14
Power
Net Derivative Assets	$	96		$	84		$	0	$	7		$	187
NDT Funds	$	41		$	(2	)	$	0	$	(9	)	$	30
Rabbi Trust Funds	$	3		$	0		$	0	$	0		$	3
PSE&G
Net Derivative Liabilities	$	(64	)	$	0		$	27	$	0		$	(37	)
Rabbi Trust Funds	$	5		$	0		$	0	$	0		$	5

(A)

PSEG’s and Power’s gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(81) million and $(35) million are included in Operating Income and $(6) million and $(9) million are included in OCI in 2010 and 2009, respectively. Of the $(81) million in Operating Income in 2010, $(91) million is unrealized and $10 million is realized. The $(35) million in Operating Income in 2009 is unrealized.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

(C)

PSEG’s and Power’s gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $16 million and $65 million are included in Operating Income and $14 million and $19 million are included in OCI in 2010 and 2009, respectively. Of the $16 million in Operating Income in 2010, $(18) million is unrealized and $34 million is realized. Of the $65 million in Operating Income in 2009, $51 million is unrealized and $14 million is realized.

As of June 30, 2010, PSEG carried approximately $1.6 billion of net assets that are measured at fair value on a recurring basis, of which approximately $200 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no transfers between levels during the three months and six months ended June 30, 2010.

As of June 30, 2009, PSEG carried approximately $1.2 billion of net assets that are measured at fair value on a recurring basis, of which approximately $200 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no transfers between levels during the three months and six months ended June 30, 2009.

Non-recurring Fair Value Measurements:

•

Due to a significant decline in market prices at June 30, 2010, Power assessed the recoverability of its SO₂ emission allowances not expected to be consumed. As a result of this evaluation, Power recorded a pre-tax impairment charge of $15 million related to its forecasted excess SO₂ allowances during the quarter ended June 30, 2010, which is included in Energy Costs on the Condensed Consolidated Statements of Operations. The fair value of remaining excess SO₂ emission allowances of $6 million was determined based on a comparison of quoted market prices where available for each vintage year to the carrying value of the related allowances (Level 2 measurement within the fair value hierarchy). Due to the lack of observable prices beyond certain vintage years, significant internal assumptions were used in the valuation of approximately $2 million of those allowances (Level 3 measurement within the fair value hierarchy).

•

As a result of the execution of a new lease, Energy Holdings assessed the recoverability of existing property located in Michigan. As a result of the evaluation, Energy Holdings recorded a pre-tax impairment of $10 million during the quarter ended June 30, 2010, which is included in Operating Revenues on the Condensed Consolidated Statements of Operations. The fair value of the property ($6 million) was determined using an internal model based on a discounted cash flow analysis (income approach valuation technique) with significant unobservable inputs (Level 3).

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Value of Debt

The estimated fair values were determined using market quotations or values of instruments with similar terms, credit ratings, remaining maturities, and redemptions as of June 30, 2010 and December 31, 2009.


	June 30, 2010				December 31, 2009
	Carrying Amount		Fair Value(A)		Carrying Amount			Fair Value(A)
	Millions
Long-Term Debt:
PSEG (Parent)	$	6	$	39	$	(38	)	$	(3	)
Power -Recourse Debt		3,454		3,857		3,121			3,473
PSE&G		3,869		4,331		3,571			3,807
Transition Funding (PSE&G)		1,190		1,372		1,276			1,449
Transition Funding II (PSE&G)		61		66		67			71
Energy Holdings:
Senior Notes		127		130		127			134
Project Level, Non-Recourse Debt		40		40		42			42

	$	8,747	$	9,835	$	8,166		$	8,973

(A)	Fair value excludes unamortized discounts, including amounts related to the Debt Exchange between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company.

Note 11. Other Income and Deductions


	Power		PSE&G		Other(A)		Consolidated
	Millions
Other Income
Three Months Ended June 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	42	$	0	$	0	$	42
Other		1		3		1		5

Total Other Income	$	43	$	3	$	1	$	47

Three Months Ended June 30, 2009
NDT Fund Gains, Interest, Dividend and Other Income	$	85	$	0	$	0	$	85
Other		1		4		1		6

Total Other Income	$	86	$	4	$	1	$	91

Six Months Ended June 30, 2010
NDT Fund Gains, Interest, Dividend and Other Income	$	80	$	0	$	0	$	80
Other		2		8		0		10

Total Other Income	$	82	$	8	$	0	$	90

Six Months Ended June 30, 2009
NDT Fund Gains, Interest, Dividend and Other Income	$	152	$	0	$	0	$	152
Other		4		5		1		10

Total Other Income	$	156	$	5	$	1	$	162

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Power		PSE&G		Other (A)			Consolidated
	Millions
Other Deductions
Three Months Ended June 30, 2010
NDT Fund Losses and Expenses	$	13	$	0	$	0		$	13
Other		0		0		(1	)		(1	)

Total Other Deductions	$	13	$	0	$	(1	)	$	12

Three Months Ended June 30, 2009
NDT Fund Losses and Expenses	$	43	$	0	$	0		$	43
Other		1		1		(1	)		1

Total Other Deductions	$	44	$	1	$	(1	)	$	44

Six Months Ended June 30, 2010
NDT Fund Losses and Expenses	$	26	$	0	$	0		$	26
Other		1		1		0			2

Total Other Deductions	$	27	$	1	$	0		$	28

Six Months Ended June 30, 2009
NDT Fund Losses and Expenses	$	89	$	0	$	0		$	89
Other		5		2		3			10

Total Other Deductions	$	94	$	2	$	3		$	99

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

Note 12. Income Taxes


	Three Months Ended June 30,				Six Months Ended June 30,
Effective Tax Rate	2010		2009		2010		2009
PSEG	36.4	%	43.6	%	40.4	%	41.9	%
Power	39.5	%	39.3	%	40.8	%	39.3	%
PSE&G	150.0	%	39.7	%	37.0	%	40.4	%

For the quarter ended June 30, 2010, the change in the effective tax rate for PSEG was due primarily to

•

reevaluating PSEG’s reserves for uncertain tax positions primarily related to Power’s manufacturer’s deductions under the American Jobs Creation Act of 2004,

•

the impact of taxes recorded in 2009 resulting from the sales of leveraged lease assets, and

•

the flow-through of tax benefits at PSE&G, primarily related to uncollectible accounts, as a percentage of a much lower pre-tax income.

For the period ended June 30, 2010, the change in the effective tax rate for PSEG was due primarily to

•

reevaluating PSEG’s reserves for uncertain tax positions primarily related to Power’s manufacturer’s deductions under the American Jobs Creation Act of 2004,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

•

the impact of taxes recorded in 2009 resulting from the sales of leveraged lease assets, and

•

the impacts of new health care legislation enacted in March 2010.

The new legislation includes various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. Although this change does not take effect immediately, the accounting impact was required to be recognized when the legislation was signed. As a result, in the first quarter of 2010, PSEG recorded noncash after tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&G’s income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.


Unrecognized Tax Benefits	As of June 30, 2010
		Millions
PSEG	$	756
PSE&G	$	42
Tax Deposits Associated with Disputed Tax Assessments	$	320
Possible Increase in Unrecognized Benefits Related to Leasing Tax Issue	$	273
Possible Decrease in Unrecognized Benefits Related to Leasing Tax Issue	$	560


Possible Increase (Decrease) in Total Unrecognized Tax Benefits Including Interest	Over the next 12 Months
		Millions
PSEG	$	3
Power		15
PSE&G		(2	)
Energy Holdings		(130	)
Services		(27	)

	$	(141	)

PSEG and PSE&G had unrecognized tax benefits as of June 30, 2010. PSEG made tax deposits with the IRS to defray interest costs associated with disputed tax assessments associated with certain lease investments. The deposits are fully refundable and are recorded as a reduction to the Long-Term Accrued Taxes on PSEG’s Condensed Consolidated Balance Sheets, but are not reflected in the PSEG unrecognized tax benefits. PSEG materially reduced its unrecognized tax benefits by terminating some leases involved in the IRS lease issue. (see Note 7. Commitments and Contingent Liabilities).

It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 7. Commitments and Contingent Liabilities will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase or decrease. It is not possible to predict the magnitude, timing or direction of any such change.

It is reasonably possible that the total unrecognized tax benefits (including interest) at PSEG will decrease within the next 12 months due to either agreement with various taxing authorities upon audit or the expiration of the Statute of Limitations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 13. Comprehensive Income, Net of Tax

Comprehensive Income


	Power(A)			PSE&G		Other(B)		Consolidated
						Millions
Three Months Ended June 30, 2010
Net Income	$	204		$	3	$	17	$	224
Other Comprehensive Income (Loss)		(116	)		1		0		(115	)

Comprehensive Income	$	88		$	4	$	17	$	109

Three Months Ended June 30, 2009
Net Income	$	246		$	44	$	21	$	311
Other Comprehensive Income (Loss)		28			1		2		31

Comprehensive Income	$	274		$	45	$	23	$	342

Six Months Ended June 30, 2010
Net Income	$	568		$	121	$	26	$	715
Other Comprehensive Income (Loss)		(25	)		1		1		(23	)

Comprehensive Income	$	543		$	122	$	27	$	692

Six Months Ended June 30, 2009
Net Income	$	561		$	168	$	26	$	755
Other Comprehensive Income (Loss)		172			1		4		177

Comprehensive Income	$	733		$	169	$	30	$	932

(A)	Changes at Power primarily relate to changes in unrealized gains and losses on derivative contracts that qualify for hedge accounting in 2010 and to NDT Fund activity in 2009, as detailed below.

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

Accumulated Other Comprehensive Income (Loss)


	Balance as of December 31, 2009			Power			PSE&G		Other		Balance as of June 30, 2010
	Millions
Derivative Contracts	$	180		$	(4	)	$	0	$	1	$	177
Pension and OPEB Plans		(400	)		13			0		0		(387	)
NDT Funds		91			(34	)		0		0		57
Other		13			0			1		0		14

Accumulated Other Comprehensive Income (Loss)	$	(116	)	$	(25	)	$	1	$	1	$	(139	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Balance as of December 31, 2008			Power		PSE&G		Other		Balance as of June 30, 2009
	Millions
Derivative Contracts	$	172		$	138	$	0	$	1	$	311
Pension and OPEB Plans		(371	)		10		0		2		(359	)
NDT Funds (A)		18			22		0		0		40
Other		4			2		1		1		8

Accumulated Other Comprehensive Income (Loss)	$	(177	)	$	172	$	1	$	4	$	0

(A)	Includes reclassification of $12 million of non-credit losses, net of tax, from Retained Earnings to Accumulated Other Comprehensive Income (Loss) recorded upon adoption of accounting guidance for determining whether an available-for-sale debt security is other-than-temporarily impaired.

Note 14. Earnings Per Share (EPS)

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


	Three Months Ended June 30,								Six Months Ended June 30,
	2010				2009				2010				2009
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator: (Millions)
Net Income	$	224	$	224	$	311	$	311	$	715	$	715	$	755	$	755

EPS Denominator: (Thousands)
Weighted Average Common Shares Outstanding		506,109		506,109		505,990		505,990		506,030		506,030		505,988		505,988
Effect of Stock Options		0		137		0		186		0		139		0		189
Effect of Stock Performance Share Units		0		707		0		677		0		848		0		575
Effect of Restricted Stock Units		0		138		0		83		0		102		0		60

Total Shares		506,109		507,091		505,990		506,936		506,030		507,119		505,988		506,812

EPS:
Net Income	$	0.44	$	0.44	$	0.61	$	0.61	$	1.41	$	1.41	$	1.49	$	1.49

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Three Months Ended June 30,				Six Months Ended June 30,
Dividend Payments on Common Stock	2010		2009		2010		2009
Per Share	$	0.3425	$	0.3325	$	0.6850	$	0.6650
in Millions	$	173	$	168	$	347	$	336

Note 15. Financial Information by Business Segments


	Power		PSE&G			Energy Holdings		Other(A)			Consolidated
	Millions
Three Months Ended June 30, 2010
Operating Revenues	$	1,358	$	1,536		$	20	$	(459	)	$	2,455
Net Income (Loss)		204		3			12		5			224
Preferred Securities Dividends		0		0			0		0			0
Segment Earnings (Loss)		204		3			12		5			224
Gross Additions to Long-Lived Assets		154		348			14		3			519

Three Months Ended June 30, 2009
Operating Revenues	$	1,363	$	1,643		$	95	$	(541	)	$	2,560
Net Income (Loss)		246		44			21		0			311
Preferred Securities Dividends		0		(1	)		0		1			0
Segment Earnings (Loss)		246		43			21		1			311
Gross Additions to Long-Lived Assets		221		185			7		1			414

Six Months Ended June 30, 2010
Operating Revenues	$	3,661	$	3,980		$	56	$	(1,562	)	$	6,135
Net Income (Loss)		568		121			19		7			715
Preferred Securities Dividends		0		(1	)		0		1			0
Segment Earnings (Loss)		568		120			19		8			715
Gross Additions to Long-Lived Assets		328		530			49		4			911

Six Months Ended June 30, 2009
Operating Revenues	$	3,827	$	4,378		$	139	$	(1,864	)	$	6,480
Net Income (Loss)		561		168			31		(5	)		755
Preferred Securities Dividends		0		(2	)		0		2			0
Segment Earnings (Loss)		561		166			31		(3	)		755
Gross Additions to Long-Lived Assets		429		379			9		(1	)		816

As of June 30, 2010
Total Assets	$	10,339	$	16,682		$	2,457	$	(736	)	$	28,742
Investments in Equity Method Subsidiaries	$	32	$	0			180	$	0		$	212

As of December 31, 2009
Total Assets	$	10,333	$	16,533		$	2,605	$	(741	)	$	28,730
Investments in Equity Method Subsidiaries	$	36	$	0		$	176	$	0		$	212

(A)

Other activities include amounts applicable to PSEG (as parent company), Services and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are priced in accordance with applicable regulations, including affiliate pricing rules, or at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 16. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 16. Related-Party Transactions

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

Power

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


	Three Months Ended June 30,						Six Months Ended June 30,
Related Party Transactions	2010			2009			2010			2009
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS(A)	$	166		$	213		$	984		$	1,183
Billings to PSE&G through BGS(A)		286			319			559			663

Total Revenue from Affiliates	$	452		$	532		$	1,543		$	1,846

Expense Billings from Affiliates:
Administrative Billings from Services(B)	$	(36	)	$	(37	)	$	(72	)	$	(77	)

Total Expense Billings from Affiliates	$	(36	)	$	(37	)	$	(72	)	$	(77	)


Related Party Transactions	June 30, 2010			December 31, 2009
	Millions
Receivables from PSE&G through BGS and BGSS Contracts(A)	$	167		$	404
Receivables from PSE&G Related to Gas Supply Hedges for BGSS(A)		94			120
Payable to Services(B)		(20	)		(27	)
Tax Sharing Receivable from (Payable to) PSEG(C)		71			(28	)
Current Unrecognized Tax Receivable from PSEG(C)		15			3
Payable to PSEG		(1	)		(13	)

Accounts Receivable—Affiliated Companies, net	$	326		$	459

Short-Term Loan to (from) Affiliate (Demand Note to (from) PSEG)(D)	$	276		$	(194	)

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

Long-Term Accrued Taxes Receivable(C)	$	5		$	39

PSE&G

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


	Three Months Ended June 30,						Six Months Ended June 30,
Related Party Transactions	2010			2009			2010			2009
	Millions
Expense Billings from Affiliates:
Billings From Power through BGSS(A)	$	(166	)	$	(213	)	$	(984	)	$	(1,183	)
Billings From Power through BGS(A)		(286	)		(319	)		(559	)		(663	)
Administrative Billings from Services(B)		(54	)		(63	)		(104	)		(129	)

Total Expense Billings from Affiliates	$	(506	)	$	(595	)	$	(1,647	)	$	(1,975	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


Related Party Transactions	June 30, 2010			December 31, 2009
	Millions
Payable to Power through BGS and BGSS Contracts(A)	$	(167	)	$	(404	)
Payable to Power Related to Gas Supply Hedges for BGSS(A)		(94	)		(120	)
Payable to Power for SREC Liability(F)		(7	)		(7	)
Payable to Services(B)		(43	)		(42	)
Tax Sharing Receivable from (Payable to) PSEG(C)		(2	)		13
Current Unrecognized Tax Receivable from PSEG(C)		71			61
Receivable from PSEG		3			3

Accounts Payable—Affiliated Companies, net	$	(239	)	$	(496	)

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

Long-Term Accrued Taxes Payable(C)	$	(113	)	$	(96	)

(A)

PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 31, 2012 and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.

(B)

Services provides and bills administrative services to Power and PSE&G at cost. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. Power and PSE&G believe that the costs of services provided by Services approximate market value for such services.

(C)

PSEG files a consolidated Federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.

PSEG and its subsidiaries adopted the accounting guidance for “Accounting for Uncertainty in Income Taxes” effective January 1, 2007, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that it has taken or expects to take on a tax return.

(D)	Short-term loans are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

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

(F)

In January 2008 the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. The N.J. Division of Rate Counsel filed an appeal of the BPU decision and the Appellate Division of the Superior Court affirmed the BPU order in November 2009. However, the N.J. Supreme Court granted the N.J. Division of Rate Counsel’s Petition for Certification and the matter is pending before the Supreme Court. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million and $15 million as of June 30, 2010 and December 31, 2009, respectively, including

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies. Under current guidance, Power is unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G’s liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG’s Condensed Consolidated Balance Sheet as of June 30, 2010 and December 31, 2009.

Note 17. Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). The following table presents condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries.


	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Three Months Ended June 30, 2010
Operating Revenues	$	0		$	1,562		$	121		$	(325	)	$	1,358
Operating Expenses		2			1,207			120			(325	)		1,004

Operating Income (Loss)		(2	)		355			1			0			354
Equity Earnings (Losses) of Subsidiaries		213			(4	)		0			(209	)		0
Other Income		9			44			0			(10	)		43
Other Deductions		0			(13	)		0			0			(13	)
Other-Than-Temporary Impairments		0			(5	)		0			0			(5	)
Interest Expense		(34	)		(12	)		(6	)		10			(42	)
Income Tax Benefit (Expense)		18			(152	)		1			0			(133	)

Net Income (Loss)	$	204		$	213		$	(4	)	$	(209	)	$	204


Three Months Ended June 30, 2009
Operating Revenues	$	0		$	1,596		$	93		$	(326	)	$	1,363
Operating Expenses		3			1,174			110			(326	)		961

Operating Income (Loss)		(3	)		422			(17	)		0			402
Equity Earnings (Losses) of Subsidiaries		247			(15	)		0			(232	)		0
Other Income		14			91			0			(19	)		86
Other Deductions		0			(44	)		0			0			(44	)
Other-Than-Temporary Impairments		0			0			0			0			0
Interest Expense		(36	)		(15	)		(7	)		19			(39	)
Income Tax Benefit (Expense)		25			(192	)		8			0			(159	)

Net Income (Loss)	$	247		$	247		$	(16	)	$	(232	)	$	246

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Six Months Ended June 30, 2010
Operating Revenues	$	0		$	4,036		$	266		$	(641	)	$	3,661
Operating Expenses		0			3,029			280			(641	)		2,668

Operating Income (Loss)		0			1,007			(14	)		0			993
Equity Earnings (Losses) of Subsidiaries		590			(18	)		0			(572	)		0
Other Income		18			85			0			(21	)		82
Other Deductions		(1	)		(26	)		0			0			(27	)
Other-Than-Temporary Impairments		0			(6	)		0			0			(6	)
Interest Expense		(65	)		(26	)		(12	)		21			(82	)
Income Tax Benefit (Expense)		26			(426	)		8			0			(392	)

Net Income (Loss)	$	568		$	590		$	(18	)	$	(572	)	$	568


Six Months Ended June 30, 2010
Net Cash Provided By (Used In) Operating Activities	$	45		$	1,297		$	(13	)	$	(575	)	$	754
Net Cash Provided By (Used In) Investing Activities	$	(29	)	$	(885	)	$	0		$	319		$	(595	)
Net Cash Provided By (Used In) Financing Activities	$	(17	)	$	(421	)	$	(33	)	$	256		$	(215	)

Six Months Ended June 30, 2009
Operating Revenues	$	0		$	4,256		$	214		$	(643	)	$	3,827
Operating Expenses		6			3,224			230			(643	)		2,817

Operating Income (Loss)		(6	)		1,032			(16	)		0			1,010
Equity Earnings (Losses) of Subsidiaries		575			(25	)		0			(550	)		0
Other Income		37			173			0			(54	)		156
Other Deductions		0			(94	)		0			0			(94	)
Other-Than-Temporary Impairments		0			(60	)		0			0			(60	)
Interest Expense		(89	)		(32	)		(21	)		54			(88	)
Income Tax Benefit (Expense)		44			(419	)		12			0			(363	)

Net Income (Loss)	$	561		$	575		$	(25	)	$	(550	)	$	561


Six Months Ended June 30, 2009
Net Cash Provided By (Used In) Operating Activities	$	104		$	1,806		$	(49	)	$	(676	)	$	1,185
Net Cash Provided By (Used In) Investing Activities	$	(263	)	$	(1,438	)	$	149		$	1,143		$	(409	)
Net Cash Provided By (Used In) Financing Activities	$	159		$	(369	)	$	(102	)	$	(466	)	$	(778	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated Total
	Millions
As of June 30, 2010
Current Assets	$	3,568	$	6,108	$	521	$	(7,902	)	$	2,295
Property, Plant and Equipment, net		62		5,013		1,428		0			6,503
Investment in Subsidiaries		4,768		1,076		0		(5,844	)		0
Noncurrent Assets		208		1,427		48		(142	)		1,541

Total Assets	$	8,606	$	13,624	$	1,997	$	(13,888	)	$	10,339

Current Liabilities	$	734	$	7,814	$	758	$	(7,901	)	$	1,405
Noncurrent Liabilities		407		1,045		160		(143	)		1,469
Long-Term Debt		2,804		0		0		0			2,804
Member’s Equity		4,661		4,765		1,079		(5,844	)		4,661

Total Liabilities and Member’s Equity	$	8,606	$	13,624	$	1,997	$	(13,888	)	$	10,339

As of December 31, 2009
Current Assets	$	3,039	$	5,614	$	560	$	(6,871	)	$	2,342
Property, Plant and Equipment, net		61		4,872		1,452		0			6,385
Investment in Subsidiaries		4,865		1,093		0		(5,958	)		0
Noncurrent Assets		253		1,452		52		(151	)		1,606

Total Assets	$	8,218	$	13,031	$	2,064	$	(12,980	)	$	10,333

Current Liabilities	$	107	$	7,167	$	818	$	(6,869	)	$	1,223
Noncurrent Liabilities		522		1,002		150		(152	)		1,522
Long-Term Debt		3,121		0		0		0			3,121
Member’s Equity		4,468		4,862		1,096		(5,959	)		4,467

Total Liabilities and Member’s Equity	$	8,218	$	13,031	$	2,064	$	(12,980	)	$	10,333

ITEM 2.

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

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

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

•

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

•

PSE&G, our public utility company which provides transmission and distribution of electric energy and gas in New Jersey; implements demand response and energy efficiency programs and invests in solar generation, and

•

Energy Holdings, which owns our energy-related leveraged leases and other investments.

Our business discussion in Part I Item 1 Business of our 2009 Annual Report on Form 10-K provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets. The following supplements that discussion and the discussion included in the Overview of 2009 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2010 and any changes to the key factors that we expect will drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This information should be read in conjunction with such Statements, Notes and the 2009 Annual Report on Form 10-K.

OVERVIEW OF 2010 AND FUTURE OUTLOOK

During 2010, our business continues to face many of the same challenges experienced in 2009. Lower natural gas prices and current economic conditions have had a significant impact on our results.

Lower natural gas prices have a number of effects on our business. As a major input to electricity generation, lower gas prices tend to reduce the market price for electricity, which is based upon the cost of generation on the margin, which in the eastern part of PJM is usually fueled by gas. This reduces the margin we see on sales from our units in the eastern part of PJM, as nuclear and coal fuel costs have not declined similarly. Current economic conditions have also lowered demand for electricity, which has put downward pressure on our revenues. Lower demand for electricity also tends to reduce congestion, thereby reducing the hours that higher priced units in the eastern part of PJM are called to operate. Lower market prices for electricity also tend to create a greater incentive for customers to choose an independent electric supplier rather than remain under our Basic Generation Service (BGS) contracts, as the current market prices are lower than the BGS contract energy price components which were set when forward prices were higher. We experienced an increasing level of this “migration” away from BGS contracts beginning toward the second half of last year which has continued into 2010. Migration has had a negative impact on our results, which could continue as volumes that were previously sold to satisfy obligations under the BGS contracts are replaced with other contract sales or spot market sales at potentially lower prices.

Current economic conditions have resulted in reduced customer usage and have also caused deterioration in certain customer payment patterns resulting in a higher portion of our accounts receivable balances remaining outstanding for more than 180 days. Customer payment patterns have modestly improved during 2010 with such balances representing 12% of total customer accounts receivable as of June 30, 2010 as compared to 14% at the end of 2009. We continue to focus our efforts on the oldest and largest accounts to expedite collections. We believe we have adequate bad debt reserves and have sufficient liquidity to manage these delays in customer payments.

Our gas sales volumes were also lower in the first half of 2010 due primarily to warmer weather. Heating degree days, as a measure of winter weather in 2010, were 13.5% lower than in 2009. The weather, the economy, migration and other factors all contributed to an overall reduction of approximately 10% in Power’s Basic Gas Supply Service (BGSS) sales volumes and PSE&G’s gas delivery volumes as compared to the same period in 2009. However the warmer weather had a favorable impact on our electric sales volumes at Power and PSE&G in the second quarter of 2010, which partially offset the impacts of migration and the economy.

In June 2010, the New Jersey Board of Public Utilities (BPU) accepted and approved a settlement agreement reached by the parties to our base rate case proceeding. The final settlement agreement included an increase of $73.5 million and $26.5 million in annual electric and gas revenues, respectively, with a return on equity of 10.3%. The new rates and rate designs were effective on June 7, 2010 for the electric portion and July 9, 2010 for gas. The BPU also approved PSE&G’s gas weather normalization clause and provisionally approved the stipulated Transportation Service Gas—Nonfirm (TSG-NF) rate subject to refund pending the outcome of a decision by the BPU regarding objections to the gas transportation rate charged by PSE&G to Power and related issues.

In the event that the BPU were to find that the rate charged to Power was not proper and order refunds, the results could be material. We believe such refunds would constitute retroactive ratemaking and be prohibited under applicable law. However, the outcome of the regulatory proceeding cannot be predicted. In July 2010, a complaint was filed against Power at Federal Regulatory Energy Commission (FERC) related to the gas transportation rate. The complaint asserts that the existing rate charged to Power violates FERC’s affiliate rules and Power’s market-based rate authority. The complaint requests, among other things, that Power’s market-based rate authority be revoked. While we view revocation of our market-based rate authority as unlikely, it is not possible to predict the outcome of this proceeding. We believe that the rates charged to Power were and continue to be lawful and appropriate, and intend to assert this position vigorously.

Also in June 2010, the BPU approved a separate agreement under which PSE&G will refund $122 million to electric customers during the next two years to resolve an issue regarding the Market Transition Charge (MTC) which was part of the New Jersey’s deregulation law implemented in 1999. For additional information, see Note 7. Commitments and Contingent Liabilities.

Another generic proceeding regarding consolidated tax adjustments is expected to begin later in 2010. These adjustments are intended to share tax benefits realized by non-regulated subsidiaries with utility customers under certain circumstances. The policy adopted by the BPU will influence the non-regulated investments made by PSEG in the future.

Following the completion of the rate case, PSE&G initiated a business planning effort to establish long-term financial plans designed to achieve its allowed return and continue to provide safe and reliable service to customers. Action plans could include reductions of capital expenditures and operations and maintenance. This is part of an effort to make New Jersey more competitive and attract new customers to the state.

There have also been other significant regulatory and legislative developments during the year which may affect our operations in the future as new rules and regulations are adopted.

•

In March 2010, new legislation was passed which includes various health care related provisions that will go into effect over the next several years including, but not limited to, expanding insurance coverage eligibility, prohibiting denial of coverage based on pre-existing conditions and prohibiting restrictive annual and lifetime coverage limits. This legislation also eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, which resulted in additional deferred tax liabilities being recorded in the first quarter. For additional information, see Note 12. Income Taxes. We are still evaluating the other potential impacts of this legislation as well as any actions we could take.

•

In July 2010, new legislation was passed in an attempt to increase control over the financial markets and prevent future financial crises and market issues such as those experienced recently. As part of this new legislation, the SEC and the Commodity Futures Trading Commission will be implementing new

rules to enact stricter regulation over derivatives since many of the issues experienced were caused by derivative trading in connection with mortgage loans. We will carefully monitor these new rules as they are developed to analyze the potential impact on our derivatives transactions, including any potential increase in our collateral requirements.

•

Another new issue has arisen in the context of a pending FERC rulemaking proceeding, in which FERC has proposed to significantly change its transmission planning rules to (i) make it easier to plan transmission for “public policy” considerations and (ii) open up the construction of transmission projects to companies that are not franchised utilities or that seek to build outside of their franchised service territory.

•

In June 2010, the U.S. Environmental Protection Agency (EPA) formally published a proposed rule offering three main options for the management of coal combustion residuals to limit impacts on human health and the environment. The outcome of the EPA rulemaking can not be predicted. For additional information, see Item 5. Other Information.

•

In July 2010, the EPA released the proposed Clean Air Transport Rule to limit emissions in 32 states that contribute to the ability of downwind states to attain and/or maintain air quality standards. By 2014, the EPA estimates that this rule, along with other concurrent state and EPA actions, would reduce power plant sulfur dioxide (SO₂) emissions by 71% and nitrogen oxide (NO_X) emissions by 52% as compared to 2005 levels. For additional information, see Item 5. Other Information.

•

During the second quarter, the Governor of New Jersey directed the BPU to review the State’s current Energy Master Plan (EMP). The purpose of the EMP is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. The current EMP was issued in October 2008 and identified a number of the actions to improve energy efficiency, increase the use of renewable resources, ensure a reliable supply of energy and stimulate investment in clean energy technologies. We expect the BPU to release a new draft EMP in the third quarter of 2010 with a final plan expected to be completed by the end of the year. We cannot predict what modifications or new goals will be included in the new EMP or the potential impacts to our businesses.

Our future success will also depend on our ability to respond to the challenges and opportunities presented by these and other regulatory and legislative initiatives.

Operational Excellence

The reduction in sales volumes at Power resulting from migration were partially offset with sales under new contracts. Also offsetting the impacts of migration were higher sales in the spot market as we saw increased demands driven primarily by hotter than normal weather in the second quarter, which has continued into July. As a result, generation volumes at Power in 2010 were approximately 13% higher than in 2009, primarily at our combined cycle facilities. A seventeen day unplanned outage at our Salem 1 Nuclear plant reduced generation volumes in July, partially offsetting the weather impacts in the period. These reduced volumes were replaced with comparatively higher cost generation to satisfy our obligations and meet the increased demands resulting from hotter weather in the month. We expect that the outage will lower the overall capacity factor for our nuclear generating facilities by 0.5% for the full year.

Our generating capacity continues to receive pricing recognizing the locational value of our assets through the Reliability Pricing Model (RPM) auction. Under the most recent auction for the 2013-2014 period, the prices set for all of our generation assets in PJM were over $225 per MW-day, which is significantly higher than prices set for previous periods.

During 2010, PSE&G has demonstrated its commitment to system reliability by limiting customer outages. However, in mid-March, PSE&G experienced the worst storm in its history. The storm caused severe damage to our system downing more than 1,000 poles throughout our service territory and disrupting service to about 635,000 customers. With the assistance of mutual aid crews from other utilities, PSE&G’s associates worked to fully restore service to all of its customers within one week. PSE&G has deferred the incremental storm related costs and will be seeking recovery.

We have also maintained our focus on reducing our cash tax exposure related to certain leveraged leases by pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds. Energy Holdings has terminated a total of 15 of these leasing transactions since December 2008, including two this year, and reduced the related cash tax exposure by $800 million. As of June 30, 2010, an aggregate of approximately $550 million would become currently payable if we conceded all deductions taken through that date. We have deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, reducing our potential cash exposure to $230 million. See Note 7. Commitments and Contingent Liabilities for additional information.

We have looked, and are continuing to look, for ways to reduce our operating costs at each of our businesses while maintaining our safety, reliability and compliance standards.

Financial Strength

Our businesses continued to generate strong cash from operations in 2010. We used these funds combined with external financing to:

•

contribute over $400 million into our qualified pension plans,

•

fund our capital expenditures, and

•

continue funding our shareholder dividends.

The Board of Directors has also approved an increase in the quarterly dividends from $0.3325 per share to $0.3425 per share of Common Stock for each of the first three quarters of 2010 resulting in an indicated annual dividend of $1.37 per share.

We also completed several financing transactions during 2010, including paying our maturing debt obligations, redeeming PSE&G’s preferred stock and completing a debt exchange at Power to manage long-term debt maturities. See Note 8. Changes in Capitalization for additional information.

Disciplined Investment

We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include responding to climate change, upgrading critical energy infrastructure and providing new energy supplies in markets with growing demand. We also have several projects where we are investing to continue to improve our operational performance and meet environmental commitments.

•

We are continuing to pursue obtaining the necessary regulatory approvals for the estimated $750 million Susquehanna-Roseland transmission project but have incurred delays in obtaining environmental approvals. This failure to obtain these approvals on a timely basis will delay the project’s construction and completion date. Development activities for the Branchburg to Hudson project are currently on hold pending further guidance from PJM as to the need for and in-service date of the line. Delays in the construction schedules of these projects could impact the timing of expected transmission revenues. (See Part II, Item 5. Other Information, State Regulation.)

•

We made additional investments in our solar initiatives. As of June 30, 2010, we have provided $55 million in loans for 102 projects representing 15 MW under our solar loan program to date. As of June 30, 2010, 7 MW of solar panels had been installed on distribution poles under our Solar 4 All program to date, with total expenditures of over $50 million. In January 2010, we announced that we had entered into contracts with four developers for 12 MW of solar capacity to be developed on land we own in Edison, Linden, Trenton and Hamilton. The projects represent an investment of over $50 million. Construction has started on the Trenton and Edison projects, which are expected to be commercially operational in the fourth quarter of 2010. Construction on the Linden and Hamilton projects are expected to start later in the third quarter of 2010 following receipt of necessary approvals.

•

We made additional expenditures under our Capital Economic Stimulus and Energy Efficiency Economic Stimulus programs. As of June 30, 2010, total expenditures since inception of these projects were $354 million and $44 million, respectively.

•

We continued various construction activities at Power, including installation of back end technology at our Mercer and Hudson stations, a steam path retrofit and extended power uprate at Peach Bottom and construction of new gas fired peaking at Kearny and in Connecticut (see Note 7. Commitments and Contingent Liabilities for additional information). This additional capacity at Kearny was bid into and has cleared the RPM capacity auction for the 2012-2013 period. An additional 90 MW was bid into and has cleared the RPM capacity auction for the 2013-2014 period.

•

We filed an application for an Early Site Permit for a new nuclear generating station to be located at the current site of the Salem and Hope Creek generating stations.

•

Our solar project in Ohio has commenced commercial operations and our Florida project is expected to be completed in the third quarter of 2010. The two projects total 27 MW. (See Note 7. Commitments and Contingent Liabilities for additional information).

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

We receive immediate recovery of our transmission investments and costs through our FERC-approved formula transmission rate. The formula rate mechanism provides for an annual setting of our transmission rates, as well as an annual true up, to ensure timely recovery of the actual costs of providing transmission service and PSE&G’s approved return on equity. Our 2010 transmission rates were accepted, resulting in approximately $23 million of increased revenues.

RESULTS OF OPERATIONS

The results for PSEG, PSE&G, Power and Energy Holdings for the three months and six months ended June 30, 2010 and 2009 are presented below:


	Three Months Ended June 30,				Six Months Ended June 30,
Earnings (Losses)	2010		2009		2010		2009
		Millions
Power	$	204	$	246	$	568	$	561
PSE&G		3		44		121		168
Energy Holdings		12		21		19		31
Other		5		0		7		(5	)

PSEG Income from Continuing Operations		224		311		715		755

PSEG Net Income	$	224	$	311	$	715	$	755

Three Months Ended
June 30,

Six Months Ended
June 30,

Earnings Per Share (Diluted)

2010

2009

2010

2009

PSEG Income from Continuing Operations

0.44

0.61

1.41

1.49

PSEG Net Income

0.44

0.61

1.41

1.49

Our results include the realized gains, losses and earnings on Power’s NDT Funds and other related activity. This includes the net realized gains and other-than-temporary impairments, as well as interest and dividend income and other costs related to the NDT Funds which are recorded in Other Income and Deductions. This also includes the interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO), which is recorded in Operation and Maintenance Expense and the Depreciation related to the ARO.

Our results also include the after-tax impacts of non-trading mark-to-market (MTM) activity.

The quarter-over-quarter and six month-over-six month variances in our Income from Continuing Operations include the changes related to NDT and MTM shown in the chart below:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010		2009
		In Millions, after tax
NDT Fund Income (Expense)	$	10		$	17		$	20	$	(6	)
Non-Trading Mark-to-Market Gains (Losses)	$	(45	)	$	(24	)	$	11	$	(39	)

In addition to the changes in NDT and MTM, our decreases in our Income from Continuing Operations for the three and six months ended June 30, 2010 were driven by:

•

higher priced sales under our BGS contracts were replaced with comparatively lower priced sales into the various power pools and under new wholesale contracts entered into during 2010,

•

a $122 million charge recorded in June related to our agreement to refund previous MTC collections during the next two years,

•

losses on certain wholesale electric energy supply contracts, and

•

lower gas sales volumes and pricing due to milder weather and economic conditions,

•

partially offset by higher electric sales volumes due primarily to warmer weather.

PSEG

Our results of operations are comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, donations and general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 16. Related-Party Transactions. For an explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings that follow the table below.


	Three Months Ended June 30,				Increase/ (Decrease)					Six Months Ended June 30,				Increase/ (Decrease)
	2010		2009		2010 vs 2009					2010		2009		2010 vs 2009
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	2,455	$	2,560	$	(105	)	(4	)	$	6,135	$	6,480	$	(345	)	(5	)
Energy Costs		1,147		1,067		80		7			2,915		3,135		(220	)	(7	)
Operation and Maintenance		610		627		(17	)	(3	)		1,314		1,301		13		1
Depreciation and Amortization		233		203		30		15			465		410		55		13
Income from Equity Method Investments		5		1		4		N/A			8		11		(3	)	(27	)
Other Income and (Deductions)		35		47		(12	)	(26	)		62		63		(1	)	(2	)
Other-Than-Temporary Impairments		5		1		4		N/A			6		61		(55	)	(90	)
Interest Expense		120		133		(13	)	(10	)		236		278		(42	)	(15	)
Income Tax Expense		128		240		(112	)	(47	)		484		544		(60	)	(11	)

Power

As discussed in Note 1. Organization and Basis of Presentation, Power’s results have been retrospectively adjusted to include the earnings related to PSEG Texas for prior periods.


	Three Months Ended June 30,				Increase/ (Decrease)			Six Months Ended June 30,				Increase/ (Decrease)
	2010		2009		2010 vs 2009			2010		2009		2010 vs 2009
		Millions
Income from Continuing Operations	$	204	$	246	$	(42	)	$	568	$	561	$	7
Net Income	$	204	$	246	$	(42	)	$	568	$	561	$	7

For the three months ended June 30, 2010, the primary reasons for the $42 million decrease in Income from Continuing Operations were

•

unfavorable amounts related to our NDT and MTM activity discussed previously, and

•

unfavorable results of financial transactions related to the generation of electricity and reduced volumes sold under BGS contracts,

•

lower gas sales volumes under the BGSS contract due to above normal temperatures in 2010 and economic conditions,

•

a $15 million impairment charge in 2010 related to forecasted excess SO₂emissions allowances, and

•

losses on certain wholesale electric energy supply contracts,

•

partially offset by increased volumes being sold into the various power pools at generally higher market prices and under new wholesale contracts entered into in 2010, and

•

also offset by lower maintenance costs due to lower planned nuclear outage costs in 2010.

For the six months ended June 30, 2010, the primary reasons for the $7 million increase in Income from Continuing Operations were

•

favorable amounts related to our NDT and MTM activity discussed previously,

•

higher volumes of generation sales sold at higher market prices in the various power pools and new wholesale contracts entered into in 2010 partly offset by reduced volumes sold under BGS contracts, and

•

lower depreciation and amortization expense due to the extension of the useful lives of certain of our fossil stations due to plant upgrades,

•

partially offset by lower gas sales volumes and pricing due to above normal temperatures in 2010 and economic conditions, and

•

also offset by losses on certain wholesale electric energy supply contracts.

The quarter and year-to-date details for these variances are discussed below:


	Three Months Ended June 30,				Increase/ (Decrease)					Six Months Ended June 30,				Increase/ (Decrease)
	2010		2009		2010 vs 2009					2010		2009		2010 vs 2009
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	1,358	$	1,363	$	(5	)	(0	)	$	3,661	$	3,827	$	(166	)	(4	)
Energy Costs		687		627		60		10			2,018		2,158		(140	)	(6	)
Operation and Maintenance		269		281		(12	)	(4	)		554		555		(1	)	(0	)
Depreciation and Amortization		48		53		(5	)	(9	)		96		104		(8	)	(8	)
Other Income and (Deductions)		30		42		(12	)	(29	)		55		62		(7	)	(11	)
Other-Than-Temporary Investments		5		0		5		N/A			6		60		(54	)	(90	)
Interest Expense		42		39		3		8			82		88		(6	)	(7	)
Income Tax Expense		133		159		(26	)	(16	)		392		363		29		8

For the three months ended June 30, 2010 as compared to 2009

Operating Revenues decreased $5 million due to

Gas Supply Revenues decreased $43 million

•

including a net decrease of $48 million resulting from lower volumes of sales under the BGSS contract caused mainly by above normal temperatures in 2010,

•

partially offset by a net increase of $5 million due to higher average gas prices on sales to third party customers.

Trading Revenues decreased $15 million due primarily to losses on certain electric energy supply contracts partially offset by gains on certain gas supply contracts.

Generation Revenues increased $53 million due primarily to

•

higher revenues of $32 million resulting from higher volumes of generation sold at higher prices in the various power pools, partially offset by less favorable results from financial hedging transactions,

•

an increase of $31 million from higher sales volumes under wholesale contracts and new wholesale load contracts commencing in 2010,

•

increased revenues of $9 million from operating reserves mainly in the PJM and NE regions and various ancillary services, and $10 million of higher capacity payments largely due to changes in PJM’s capacity market,

•

partially offset by a net decrease of $20 million due to a lower volume of electricity sold under our BGS contracts partially offset by higher average prices, and

•

a decrease of $8 million due to lower auction revenue rights in PJM and migration of customers to alternative suppliers in 2010.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased by $60 million due to

•

Generation costs increased by $105 million due to $123 million of higher fossil fuel costs, primarily reflecting the utilization of higher volumes of both coal and natural gas and higher average natural gas prices, $17 million of increased power purchases and a $15 million impairment charge in 2010 related to forecasted excess SO₂emissions allowances, partly offset by net gains of $45 million from financial hedging transactions.

•

Gas costs decreased $45 million, reflecting a net decrease of $50 million related to Power’s obligations under the BGSS contract, reflecting lower demand due mainly to above normal temperatures in 2010 and a net increase of $5 million for higher inventory costs related to sales to third parties.

Operation and Maintenance decreased $12 million due primarily to

•

a $24 million net decrease largely due to lower nuclear plant planned outage costs and reduced labor and fringe benefit costs,

•

partially offset by a net increase of $10 million due to higher planned outage costs in 2010 at the Linden and Conemaugh fossil stations in New Jersey and Pennsylvania, respectively, partly mitigated by lower planned maintenance at certain of our other fossil stations.

Depreciation and Amortization decreased $5 million primarily due to an extension of the remaining useful lives of the Mercer and Hudson generating facilities resulting from significant plant upgrades.

Other Income and (Deductions)-Net Other Income decreased $12 million due primarily to lower net gains in our NDT Fund.

Other-Than-Temporary Impairments increased $5 million due to charges in 2010 related to the NDT Fund securities.

Interest Expense increased $3 million due primarily to

•

a $13 million increase related primarily to two note issuances aggregating $550 million in April 2010 and $303 million of senior notes issued in September 2009 as part of a debt exchange with Energy Holdings,

•

partly offset by lower interest expense of $4 million due to the early redemption of the two medium-term note obligations and a note exchange that all occurred in April 2010 (see Note. 8. Changes in Capitalization), and

•

higher capitalized interest of $6 million due primarily to an increased level of projects under construction in 2010.

Income Tax Expense decreased $26 million in 2010 due primarily to

•

a decrease of $28 million due to lower pre-tax income, and

•

a decrease of $9 million related to the absence in 2010 of a prior year state audit settlement and lower earnings related to the NDT Funds,

•

partially offset by an increase of $11 million due to reevaluating uncertain tax positions primarily related to manufacturer’s deductions under the American Jobs Creation Act of 2004.

For the six months ended June 30, 2010 as compared to 2009

Operating Revenues decreased $166 million due to

Gas Supply Revenues decreased $288 million

•

including a net decrease of $263 million resulting from sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales caused by milder weather in 2010 and lower net gains on financial hedging transactions in 2010, and

•

a net decrease of $25 million due to reduced sales volumes to third party customers.

Trading Revenues decreased $40 million due primarily to net losses on certain electric energy supply contracts partly offset by gains on certain gas supply contracts.

Generation Revenues increased $162 million due primarily to

•

higher revenues of $152 million resulting from higher volumes of generation sold at higher prices in PJM the NY and Texas (ERCOT) power pools, partially offset by less favorable results from financial hedging transactions and a lower volume of generation sold in the NE power pool,

•

a net increase of $72 million from new wholesale load contracts in PJM commencing in 2010 partially offset by lower volumes sold at lower prices under wholesale load contracts in the NE region,

•

$24 million of increased revenues from operating reserves mainly in the NE and PJM regions and various ancillary services, and $22 million of higher capacity payments largely due to changes in PJM’s capacity market,

•

partially offset by a net decrease of $94 million due to a lower volume of electricity sold under our BGS contracts partially offset by higher average prices, and

•

a decrease of $17 million in auction revenue rights reflecting lower rates in PJM and migration of customers to alternative suppliers in 2010.

Operating Expenses

•

Gas costs decreased $280 million, reflecting net decreases of $267 million and $13 million related to Power’s obligations under the BGSS contract and costs of sales to third party customers, respectively, reflecting lower demand due mainly to warmer average temperatures in 2010 and lower inventory costs.

•

Generation costs increased by $140 million due to $186 million of higher fossil fuel costs, primarily reflecting the utilization of higher volumes of natural gas and coal at higher purchase prices, a net increase of $44 million for increased power purchases and a $15 million impairment charge in 2010 related to forecasted excess SO₂emissions allowances, partly offset by net gains of $101 million from financial hedging transactions.

Operation and Maintenance decreased $1 million due primarily to

•

a net decrease of $27 million due primarily to lower nuclear outage costs, lower ARO accretion and reduced labor and fringe benefit costs,

•

partially offset by a net increase of $33 million due to planned outage costs in 2010 at the Guadalupe, Linden and Bethlehem Energy Center fossil stations in Texas, New Jersey and New York, respectively, partially mitigated by lower planned maintenance at certain of our other fossil stations.

Depreciation and Amortization decreased $8 million due to

•

a decrease of $11 million due to an extension of the remaining useful lives of the Mercer and Hudson generating facilities resulting from significant plant upgrades as well as revisions in assumptions regarding the decommissioning of these plants,

•

partially offset by an increase of $5 million due to pollution control equipment being placed into service in October 2009 at our Keystone station.

Other Income and (Deductions)-Net Other Income decreased $7 million due primarily to lower earnings in our NDT Fund.

Other-Than-Temporary Impairments decreased $54 million due to the lower charges in 2010 related to the NDT Fund securities.

Interest Expense decreased $6 million due to

•

higher capitalized interest of $13 million due primarily to an increased level of projects under construction in 2010, partially offset by

•

higher net interest costs of $4 million related to the debt issuances, redemptions and exchanges discussed previously in the second quarter-over-quarter Interest Expense variance as well the inclusion of the effect of the redemption of Texas project loans in February 2009 and the maturity of $250 million of Senior Notes in April 2009, and

•

an increase of $2 million in credit facility fees.

Income Tax Expense increased $29 million in 2010 due primarily to

•

an increase of $15 million due to higher pre-tax income,

•

an increase of $9 million due to reevaluating uncertain tax positions primarily related to manufacturer’s deductions under the American Jobs Creation Act of 2004,

•

an increase of $8 million due to the impacts of new health care legislation (see Note 12. Income Taxes), and

•

an increase of $2 million due to higher earnings related to the NDT Funds.

•

partially offset by a decrease of $5 million related to the absence in 2010 of a prior year state audit settlement.

PSE&G


	Three Months Ended June 30,				Increase/ (Decrease)			Six Months Ended June 30,				Increase/ (Decrease)
	2010		2009		2010 vs 2009			2010		2009		2010 vs 2009
		Millions
Income from Continuing Operations	$	3	$	44	$	(41	)	$	121	$	168	$	(47	)
Net Income	$	3	$	44	$	(41	)	$	121	$	168	$	(47	)

For the three months ended June 30, 2010, the primary reasons for the $41 million decrease in Income from Continuing Operations were

•

a $122 million charge recorded in June related to our agreement to refund previous MTC collections during the next two years,

•

partially offset by higher electric delivery revenues due to our base rate increase and higher volumes due primarily to warmer weather, and

•

an increase in our transmission formula rates.

For the six months ended June 30, 2010, the primary reasons for the $47 million decrease in Income from Continuing Operations were

•

the $122 million charge related to our agreement to refund previous MTC collections, and

•

lower gas sales volumes due to milder winter weather,

•

partially offset by higher electric delivery revenues due to our base rate increase and higher volumes due primarily to warmer weather, and

•

an increase in our transmission formula rates.

The quarter and year-to-date details for these variances are discussed below:


	Three Months Ended June 30,					Increase/ (Decrease)					Six Months Ended June 30,				Increase/ (Decrease)
	2010			2009		2010 vs 2009					2010		2009		2010 vs 2009
		Millions					Millions		%			Millions				Millions		%
Operating Revenues	$	1,536		$	1,643	$	(107	)	(7	)	$	3,980	$	4,378	$	(398	)	(9	)
Energy Costs		917			979		(62	)	(6	)		2,457		2,838		(381	)	(13	)
Operation and Maintenance		343			344		(1	)	(0	)		757		739		18		2
Depreciation and Amortization		177			144		33		23			354		293		61		21
Other Income and (Deductions)		3			3		0		0			7		3		4		N/A
Interest Expense		80			80		0		0			157		159		(2	)	(1	)
Income Tax (Benefit) Expense		(9	)		29		(38	)	N/A			71		114		(43	)	(38	)

For the three months ended June 30, 2010 as compared to 2009

Operating Revenues decreased $107 million due primarily to

Clause Revenues decreased by $88 million due to the MTC refund of $122 million. This was partially offset by higher Securitization Transition Charges (STC) of $24 million, higher Societal Benefits Charges (SBC) of $4 million and higher Regional Greenhouse Gas Initiative (RGGI) revenues of $6 million. The increased STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) into Operation and Maintenance and Depreciation and Amortization. PSE&G earns no margins on SBC or STC collections.

Commodity Revenue decreased $62 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS.

•

Gas revenues decreased $35 million due to lower BGSS volumes of $25 million due to weather and economic conditions and decreased BGSS prices of $10 million. The average price of gas was 4% lower in 2010 than 2009.

•

Electric revenues decreased $27 million due primarily to lower BGS volumes, partially offset by higher prices. BGS sales were down 5% due primarily to large customer migration to Third Party Suppliers (TPS); in contrast delivery sales were up 8% due to the weather.

Delivery Revenues increased $37 million due primarily to an increase in sales volumes and prices for electric distribution and transmission partially offset by a decrease in gas distribution.

•

Electric distribution revenues were up $37 million due primarily to higher sales volumes of $23 million due to weather, rate increases of $7 million and stimulus revenue increases of $7 million.

•

Transmission revenues were up $7 million due to net rate increases.

•

Gas distribution revenues were down $7 million due to lower sales volumes of $9 million, partially offset by increased revenues from our capital stimulus program of $2 million.

Other Operating Revenues increased $6 million due primarily to increased revenues from our appliance repair business.

Energy Costs decreased $62 million. This was entirely offset by Commodity Revenue. Details are as follows:

•

Gas costs decreased $35 million due to $25 million or 11% in lower sales volumes due primarily to weather and economic conditions and $10 million or 4% in lower prices.

•

Electric costs decreased $27 million due to $41 million or 5% in lower BGS and Non-Utility Generation (NUG) volumes due to large customer migration to TPS, weather and economic conditions, partially offset by $14 million in higher BGS and NUG prices.

Operation and Maintenance decreased $1 million due to

•

a $14 million write-off relating to iPower deferred costs that will not be recovered,

•

offset by $14 million in lower labor and fringe expenses.

Depreciation and Amortization increased $33 million due to

•

an increase of $30 million for amortization of regulatory assets, and

•

an increase of $3 million for additional plant in service.

Income Tax Expense decreased by $38 million due primarily to lower pre-tax income and flow-through tax benefits primarily related to uncollectible accounts.

For the six months ended June 30, 2010 as compared to 2009

Operating Revenues decreased $398 million due primarily to

Commodity Revenue decreased $381 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS.

•

Gas revenues decreased $224 million due to decreased BGSS prices of $124 million and lower BGSS volumes of $100 million due to weather and economic conditions. The average price of gas was 11% lower in 2010 than 2009.

•

Electric revenues decreased $157 million due primarily to $161 million in lower BGS revenues, partially offset by $4 million in higher NUG revenue due primarily to higher prices. BGS sales were down 11% due primarily to large customer migration to TPS; in contrast delivery sales were up 4% due to weather.

Clause Revenues decreased by $77 million due primarily to the MTC refund of $122 million. In addition, SBC were $7 million lower, STC were $38 million higher and RGGI revenues were $14 million higher. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in Operation and Maintenance and Depreciation and Amortization. PSE&G earns no margins on SBC or STC collections.

Delivery Revenues increased $51 million due primarily to an increase in prices for electric distribution and transmission partially offset by a decrease in gas distribution.

•

Electric distribution revenues were up $44 million due primarily to higher sales volumes of $19 million, stimulus revenue increases of $14 million and rate increases of $11 million.

•

Transmission revenues were up $20 million due primarily to net rate increases.

•

Gas distribution revenues were down $13 million due primarily to lower sales volumes of $23 million partially offset by an increased capital stimulus program of $10 million.

Other Operating Revenues increased $9 million due primarily to increased revenues from our appliance repair business.

Energy Costs decreased $381 million. This is entirely offset by Commodity Revenue. Details are as follows:

•

Gas costs decreased $224 million due to $124 million or 10% in lower prices and by $100 million or 8% in lower sales volumes due primarily to weather and economic conditions.

•

Electric costs decreased $157 million due to $165 million or 10% in lower BGS and NUG volumes due to large customer migration to TPS, weather and economic conditions, partially offset by $8 million of higher BGS and NUG prices.

Operation and Maintenance increased $18 million due primarily to

•

higher expenses related to RGGI and Capital Adjustment Charges of $25 million, and

•

a $14 million write-off relating to iPower deferred costs that will not be recovered,

•

partially offset by a decrease of $15 million in electric and gas Universal Service Fund (USF) expenses, and

•

$6 million in lower various other expenses.

Depreciation and Amortization increased $61 million due primarily to

•

an increase of $53 million for amortization of regulatory assets,

•

an increase of $6 million for additional plant in service, and

•

an increase of $2 million in software amortization.

Other Income and (Deductions)-Net Other Income increased $4 million due primarily to higher investment income.

Interest Expense decreased by $2 million due primarily to lower average debt balances.

Income Tax Expense decreased by $43 million due primarily to lower pre-tax income and flow-through tax benefits primarily related to uncollectible accounts.

Energy Holdings


	Three Months Ended June 30,				Increase/ (Decrease)			Six Months Ended June 30,				Increase/ (Decrease)
	2010		2009		2010 vs 2009			2010		2009		2010 vs 2009
		Millions
Income from Continuing Operations	$	12	$	21	$	(9	)	$	19	$	31	$	(12	)
Net Income	$	12	$	21	$	(9	)	$	19	$	31	$	(12	)

For the three and six months ended June 30, 2010, the primary reasons for the $9 million and $12 million decreases in Income from Continuing Operations were

•

lower gains on the sales of leveraged lease assets, and

•

an asset impairment charge (see Note 10. Fair Value Measurements),

•

partially offset by lower interest expense due primarily to lower debt balances following the debt exchange with Power in 2009.

The quarter and year-to-date details for these variances are discussed below:


	Three Months Ended June 30,				Increase/ (Decrease)					Six Months Ended June 30,				Increase/ (Decrease)
	2010		2009		2010 vs 2009					2010		2009		2010 vs 2009
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	20	$	95	$	(75	)	(79	)	$	56	$	139	$	(83	)	(60	)
Operation and Maintenance		9		10		(1	)	(10	)		22		23		(1	)	(4	)
Depreciation and Amortization		3		2		1		50			6		5		1		20
Income from Equity Method Investments		5		1		4		N/A			8		11		(3	)	(27	)
Other Income and (Deductions)		1		2		(1	)	(50	)		2		5		(3	)	(60	)
Interest Expense		2		12		(10	)	(83	)		4		25		(21	)	(84	)
Income Tax Expense		0		53		(53	)	(100	)		15		71		(56	)	(79	)

For the three months ended June 30, 2010 as compared to 2009

Operating Revenues decreased $75 million due primarily to lower gains on the sale and termination of leveraged lease assets, the resultant loss of revenues previously generated by such assets and the pre-tax impairment recorded during the quarter ended June 30, 2010.

See Note 7. Commitments and Contingent Liabilities and Note 10. Fair Value Measurements for additional information.

Operation and Maintenance experienced no material change.

Depreciation and Amortization experienced no material change.

Income from Equity Method Investments increased $4 million due primarily to the absence of an impairment related to GWF Energy recorded in the second quarter of 2009. See Note 4. Asset Dispositions for additional information.

Other Income and (Deductions) experienced no material change.

Interest Expense decreased $10 million due primarily to lower debt balances following the debt exchange with Power.

Income Tax Expense decreased $53 million due primarily to lower gains on sales of leveraged lease assets.

For the six months ended June 30, 2010 as compared to 2009

Operating Revenues decreased $83 million due primarily to lower gains on the sale and termination of leveraged lease assets, the resultant loss of revenues previously generated by such assets and pre-tax impairment recorded during the quarter ended June 30, 2010.

See Note 7. Commitments and Contingent Liabilities and Note 10. Fair Value Measurements for additional information.

Operation and Maintenance experienced no material change.

Depreciation and Amortization experienced no material change.

Income from Equity Method Investments decreased $3 million due primarily to lower earnings at GWF Power and higher reserves recorded against GWF Energy in 2010 partially offset by the absence of an impairment related to GWF Energy recorded in the second quarter of 2009. See Note 4. Asset Dispositions for additional information.

Other Income and (Deductions)-Net Other Income decreased by $3 million due primarily to lower interest and dividend income.

Interest Expense decreased $21 million due primarily to lower debt balances following the debt exchange with Power.

Income Tax Expense decreased $56 million due primarily to lower gains on sales of leveraged lease assets.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our three direct operating subsidiaries.

Operating Cash Flows

Our operating cash flows combined with cash on hand and financing activities are expected to be sufficient to fund capital expenditures and shareholder dividend payments.

For the six months ended June 30, 2010, our operating cash flow decreased by $269 million as compared to the same period in 2009. The net change was due primarily to net changes from Power, PSE&G and Energy Holdings as discussed below.

Power

Power’s operating cash flow decreased $431 million from $1,185 million to $754 million for the six months ended June 30, 2010, as compared to the same period in 2009, due primarily to lower margins realized on generation and gas sales combined with a decrease of $130 million related to our net cash collateral outflow in 2010 as compared to net cash collateral receipts in the prior year. Also contributing to the decrease was a reduction of $52 million related primarily to lower volumes and pricing of fuel inventories used to satisfy our gas supply obligations.

PSE&G

PSE&G’s operating cash flow increased $74 million from $(95) million to $(21) million for the six months ended June 30, 2010, as compared to the same period in 2009, due primarily to higher delivery margins realized due to higher customer demand and our base rate increase. Also contributing to the increase were lower prepayments for sales tax in 2010.

Energy Holdings

Energy Holdings’ operating cash flow declined by $112 million due primarily to lower tax payments in 2010 due to more lease sale activity in 2009 and the $140 million additional tax deposit made with the IRS in June 2009.

Short-Term Liquidity

We have been managing our liquidity to assure that we continue to have sufficient access to cash to operate our businesses. The commitments under PSEG’s credit facilities are provided by a diverse bank group. As of June 30, 2010, no single institution represented more than 11% of the total commitments in our credit facilities.

Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of June 30, 2010 were as follows:


	As of June 30, 2010
Company/Facility	Total Facility		Usage			Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility (A)	$	1,000	$	182	(C)	$	818	Dec 2012	Commercial Paper (CP) Support/Funding/Letters of Credit

Total PSEG	$	1,000	$	182		$	818

Power
5-year Credit Facility (A)	$	1,600	$	231	(C)	$	1,369	Dec 2012	Funding/Letters of Credit
2-year Credit Facility		350					350	July 2011	Funding

Total Power	$	1,950	$	231		$	1,719

PSE&G
5-year Credit Facility (B)	$	600	$	214		$	386	June 2012	CP Support/Funding/Letters of Credit
Uncommitted Bilateral Agreement		0		9			0	N/A	Funding

Total PSE&G	$	600	$	223		$	386

Total	$	3,550				$	2,923

(A)	In December 2011, these facilities will be reduced by $47 million and $75 million, for PSEG and Power, respectively.

(B)	In June 2011, this facility will be reduced by $28 million.

(C)	Includes amounts related to letters of credit outstanding.

On March 16, 2010, a $100 million bilateral credit facility at Power expired. We continually monitor our available liquidity and seek to add capacity as needed to meet our liquidity requirements. As of June 30, 2010, our total credit facility capacity continued to be in excess of our anticipated maximum liquidity requirements through 2010.

Long-Term Debt Financing

For a discussion of our long-term debt transactions during 2010, see Note 8. Changes in Capitalization.

Common Stock Dividends and Repurchases

Dividend payments on common stock for the three months ended June 30, 2010 were $0.3425 per share and totaled $173 million. Dividend payments on common stock for the three months ended June 30, 2009 were $0.3325 per share and totaled $168 million.

Dividend payments on common stock for the six months ended June 30, 2010 were $0.6850 per share and totaled $347 million. Dividend payments on common stock for the six months ended June 30, 2009 were $0.6650 per share and totaled $336 million.

We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. In March 2010, S&P affirmed the ratings and outlooks of PSEG, Power and PSE&G.


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

(A)	Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.

(B)	S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

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

CAPITAL REQUIREMENTS

As part of its business planning efforts which were initiated following the completion of the base rate case proceedings, PSE&G has reduced certain of its projected capital expenditures for distribution through 2012 by approximately $140 million per year, as compared to the amounts disclosed in our Form 10-K for the year ended December 31, 2009. With respect to transmission capital spending through 2012, including the Susquehanna-Roseland transmission project and other previously projected capital expenditures, delays associated with these projects as described in Item 5. Other Information – Federal Regulation – FERC, and State Regulation – Energy Policy may impact the projected capital expenditures or the timing of these capital expenditures. PSE&G continues to assess the overall timing and level of our capital spending to meet the transmission needs of the region. It is possible that this assessment will result in no significant reduction in overall capital expenditures for transmission; however, it is premature to make this determination about the timing of or level of such transmission capital expenditures at this time.

There were no material changes to our projected capital expenditures at Power or Energy Holdings as compared to amounts disclosed in the 2009 Form 10-K.

We expect that the majority of funding for our capital requirements over the next three years will come from a combination of internally generated funds and external financings. These amounts are subject to change, based on various factors.

Power

During the six months ended June 30, 2010, Power made $291 million of capital expenditures (excluding $37 million for nuclear fuel), related primarily to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 7. Commitments and Contingent Liabilities.

PSE&G

During the six months ended June 30, 2010, PSE&G made $541 million of capital expenditures, including $530 million of investment in plants, primarily for reliability of transmission and distribution systems and $11 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $32 million, which are included in operating cash flows.

Energy Holdings

During the six months ended June 30, 2010, Energy Holdings made $49 million of capital expenditures, primarily related to construction of its two solar projects in Florida and Ohio.

ACCOUNTING MATTERS

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The market risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.

Commodity Contracts

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with demand obligations, help reduce risk and optimize the value of owned electric generation capacity.

Value-at-Risk (VaR) Models

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

We manage our exposure at the portfolio level, which consists of owned generation, electric load-serving contracts, fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While we manage our risk at the portfolio level, we also monitor separately the risk of our trading activities and hedges. Non-trading mark-to-market (MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The non-trading MTM VaR calculation does

not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities. The MTM derivatives that are not hedges are included in the trading VaR.

The VaR models used are variance/covariance models adjusted for the change of positions with a 95% confidence level and a one-day holding period for the MTM trading and non-trading activities, and a 95% confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.

As of June 30, 2010 and December 31, 2009, trading VaR was $1 million.


For the Three Months Ended June 30, 2010	Trading VaR		Non-Trading MTM VaR
For the Three Months Ended June 30, 2010	Trading VaR		Non-Trading MTM VaR
	Millions
95% Confidence level,
Loss could exceed VaR one day in 20 days
Period End	$	1	$	11
Average for the Period	$	1	$	13
High	$	2	$	15
Low	$	1	$	8
99.5% Confidence level,
Loss could exceed VaR one day in 200 days
Period End	$	1	$	18
Average for the Period	$	2	$	21
High	$	2	$	23
Low	$	1	$	13

See Note 9. Financial Risk Management Activities for a discussion of credit risk.

ITEM 4.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Controls

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the second quarter of 2010 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the respective 2009 Annual Reports on Form 10-K of PSEG, Power and PSE&G, see Note 7. Commitments and Contingent Liabilities and Item 5. Other Information, Federal Regulation.

ITEM 1A.

RISK FACTORS

There are no additional Risk Factors to be added to those disclosed in Part I Item 1A of our 2009 Annual Reports on Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation award grants during the second quarter of 2010:


Three Months Ended June 30, 2010	Total Number of Shares Purchased	Average Price Paid per Share
April 1-April 30	41,950	$	30.86
May 1-May 31	20,000	$	32.44
June 1-June 30	0		N/A

ITEM 5.

OTHER INFORMATION

Certain information reported under the 2009 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2010 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2009 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2010. References are to the related pages on the Form 10-K or 10-Q as printed and distributed.

FEDERAL REGULATION

Greenhouse Gas—CO₂

March 31, 2010 Form 10-Q, Page 69. In April 2010, the EPA and the National Highway Transportation Safety Board (NHTSB) jointly issued a final rule to regulate greenhouse gas (GHG) emissions from certain motor vehicles (Motor Vehicle Rule). Under the Clean Air Act, the adoption of the Motor Vehicle Rule would have automatically subjected many emission sources, including ours, to Clean Air Act permitting for major facility modifications that increase the emission of GHGs, including CO₂ . However, guidance issued by the EPA in March 2010 interpreted the Clean Air Act to require permitting for GHGs at other facilities, such as ours, only when the Motor Vehicle Rule takes effect in January 2011. On May 13, 2010, the EPA finalized a “Tailoring Rule” that will phase in, beginning in 2011, the application of this permitting requirement to facilities such as ours. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, the owner of the facility would need to evaluate and perhaps install best available control technology (BACT) for GHG emissions. The types of BACT to be considered have not yet been defined by the EPA. The outcome of the EPA rulemaking, including any determination of what the EPA will consider as BACT for GHG, can not be predicted.

Clean Air Transport Rule (CATR)

On July 6, 2010, the EPA pre-released the expected proposed CATR to limit emissions in 32 states that contribute to the ability of downwind states to attain and/or maintain the 1997 and 2006 PM2.5 nonattainment areas and the 1997 ozone National Ambient Air Quality Standards (NAAQS). The rule is proposed to be implemented through 32 federal implementation plans (FIPs). Beginning in 2012, emissions reductions would be governed by this rule, rather than the Clean Air Interstate Rule (CAIR). By 2014, the EPA estimates that this rule, along with other concurrent state and EPA actions, would reduce power plant SO₂ emissions by 71% and NO_X emissions by 52% as compared to 2005 levels. The EPA has acknowledged that further reductions may be necessary to meet several eastern states’ NAAQS. In addition to the states covered by CAIR, the CATR includes Kansas, Nebraska, Oklahoma and the District of Columbia. Minnesota is proposed to be included as well. The outcome of the EPA’s rulemaking can not be predicted.

Coal Combustion Residuals (CCRs)

In June 2010, the EPA formally published a proposed rule in the Federal Register offering three main options for the management of CCRs under the Resource Conservation and Recovery Act. One of these options regulates CCRs as a hazardous waste and the other two options are variations of a non-hazardous designation. All options communicate the EPA’s intent of ceasing wet ash transfer and instituting engineering controls on ash ponds and landfills to limit impact on human health and the environment. We currently have a program to beneficially reuse coal ash as presently allowed by Federal and state regulations. The outcome of the EPA rulemaking can not be predicted.

FERC

Transmission Expansion

2009 Form 10-K, Page 19, and March 31, 2010 Form 10-Q, Page 70. In December 2008, PJM approved a 500 kV transmission project, originating in Branchburg and ending in Hudson County, New Jersey. This project is still in the design phase and will require the receipt of numerous regulatory approvals prior to construction. In October 2009, we filed a petition with FERC seeking incentive rates for the planned project. In December 2009, FERC granted our request for incentive rate treatment. We will receive a Return on Equity (ROE) adder of 125 basis points above our base ROE, recovery of 100% of Construction Work in Progress in rate base and authorization to recover 100% of all prudently-incurred development and construction costs if the project is abandoned or cancelled, in whole or in part, for reasons beyond our control. The estimated cost of the project is approximately $1.1 billion. PJM has specified a June 2013 in-service date for this project, though PJM has publicly indicated that the in-service date may be delayed and that alternatives to the project are being considered. Development activities for the project are currently on hold pending further guidance from PJM.

STATE REGULATION

Rates

Electric and Gas Base Rate Case

2009 Form 10-K, page 21, and March 31, 2010 Form 10-Q, Page 70. In May 2009, we filed briefs in our base rate case supporting an increase in electric and gas distribution base rates. We filed an update in March 2010 requesting an increase of $140 million and $64 million for electric and gas, respectively.

The BPU adopted the stipulation at its June 7, 2010 Agenda Meeting. The BPU accepted and approved the electric portion of the settlement including the electric revenue requirement, the capital structure, re-setting the electric component of the Capital Infrastructure Charge, as well as accepting the modifications to the electric tariff. The new electric rates were put into effect on June 7, 2010. The settlement included a $73.5 million increase in annual electric revenues and an allowed ROE of 10.3%. On June 18, 2010, the BPU approved the gas revenue requirement and rate design set forth in the stipulation, resulting in a $26.5 million increase effective July 9, 2010. The BPU also approved PSE&G’s gas weather normalization clause.

Retail Gas Transportation Rates

There are certain proceedings ongoing. See Note 7. Commitments and Contingent Liabilities for more detail.

Consolidated Tax Adjustments

There are certain proceedings ongoing. See Note 7. Commitments and Contingent Liabilities for more detail.

SBC/NGC

2009 Form 10-K, Page 22, and March 31, 2010 Form 10-Q, Page 70. In February 2009, we filed a petition requesting a decrease in our electric SBC/NGC rates of $18.9 million and an increase in gas SBC rates of $3.7 million. In July 2009, a revision was filed requesting an increase in SBC/NGC rates of $104 million and $15 million for electric and gas, respectively. The electric increase was due to increased non-utility generation (NUG) contract costs. The ALJ issued an initial decision in April 2010 that recommended a revenue increase of $119 million and a disallowance of approximately $254,000 in the NGC and approximately $540,000 in the electric SBC. Although PSE&G filed Exceptions to the recommendation the BPU issued a written order on June 23, 2010, adopting the ALJ’s initial decision. PSE&G is reviewing the BPU order to determine appropriate future actions.

RAC 17

2009 Form 10-K, Page 22. We filed an executed settlement agreement with the ALJ which provides for the recovery of $23.9 million for the twelve months ended July 2009. This settlement agreement has been submitted to the BPU for approval.

Energy Supply

BGSS

2009 From 10-K Page 23. On July 9, 2010, PSE&G self-implemented a reduction in the BGSS rate. The reduction targets an approximate $90 million decrease in the BGSS deferred balance on an annual basis. The reduction in the BGSS-RSG Commodity Charge for a typical gas residential heating customer would be a decrease of approximately 5%.

In May 2010, PSE&G filed a letter with the BPU requesting an extension of time for the annual June 1^st BGSS filing. In July 2010, PSE&G made its annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $123 million, excluding sales and use tax, to be effective October 1, 2010. This represented a reduction of approximately 6.8% for a typical residential gas heating customer.

Energy Policy

Susquehanna-Roseland BPU Petition

2009 Form 10-K, Page 25, and March 31, 2010 Form 10-Q, Page 70. In January 2009, we filed a Petition with the BPU seeking authorization to construct the New Jersey portion of the Susquehanna-Roseland line. The New Jersey portion of the line spans approximately 45 miles and crosses through 16 municipalities. The Petition sought a finding from the BPU that municipal land use and zoning ordinances do not apply to this line. On February 11, 2010, the BPU granted approval to PSE&G to construct the New Jersey portion of this project. On April 21, 2010, the BPU issued a written order memorializing the action taken on February 11, which will enable PSE&G to commence condemnation proceedings if necessary to acquire certain property rights. Certain interveners have appealed the BPU Order. Regarding environmental approvals, in June 2009, the New Jersey Highlands Council provided a favorable applicability determination with respect to the portion of the project crossing the Highlands region and the New Jersey Department of Environmental Protection (NJDEP) approved this determination on January 15, 2010. We have not obtained from the NJDEP certain environmental approvals that are required for each of the Eastern and Western segments of the line. We

believe it unlikely that we will obtain until late 2012, at the earliest, all of the state environmental approvals that are required for completion of either portion of the line. The Western portion of the line requires certain permits from the National Park Service, whose review is not expected to be completed until late 2012. Consequently, at this time, we do not expect the Eastern portion of the line to be in service before June 2014, and do not expect the Western portion to be in service before June 2015. Further delays are possible for both portions. We are reviewing the schedule for pre-construction activities and construction in light of these developments. Delays in the construction schedule could impact the timing of expected transmission revenues. We cannot predict what action, if any, PJM might take with respect to a delay to its scheduled in-service date for the new line.

Federal Transmission Policy Developments

In June 2010, the FERC issued a Notice of Proposed Rulemaking proposing to modify current transmission planning and cost allocation processes. Specifically, FERC has proposed that transmission planning take into account “public policy” requirements established by state or federal laws or regulations, such as state Renewable Portfolio Requirements. FERC has also questioned whether it is appropriate for transmission planning to utilize a “bright line” test to identify needed transmission projects or whether “flexible criteria” should be used. These proposed changes would likely result in more transmission being planned. FERC has proposed to eliminate provisions in FERC-approved tariffs or agreements that permit a transmission owner within whose franchised service territory a transmission project is being constructed to exercise a “right of first refusal” to construct the project. There are also two pending FERC litigated proceedings addressing and challenging this “right of first refusal.” Adverse decisions in these proceedings could result in third parties constructing within PSE&G’s service territory in the future.

ENVIRONMENTAL MATTERS

Piles Creek and South Branch Creek Natural Resource Damage Assessment

On April 29, 2010, we were one of several companies that received a letter from the National Oceanic and Atmospheric Administration (NOAA) inviting us to participate in a Natural Resource Damage Assessment for Piles Creek and South Branch Creek which are located in Union County, New Jersey. NOAA requested that the companies consider entering into a Cooperative Assessment Agreement for the sampling and analysis plan for the study area. We determined that participation at this time was not warranted but will continue to monitor and evaluate whether to participate in the assessment in the future. The costs, if any, of participating in this study and any potential remediation, if necessary, are not yet reasonably estimable.

Fuel and Waste Disposal

2009 Form 10-K, Page 28, and March 31, 2010 Form 10-Q, Page 71. The Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund. Under the contracts, the US Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The Nuclear Waste Policy Act requires the DOE to perform an annual review of the Nuclear Waste Fee to determine whether that fee is set appropriately to fund the national nuclear waste disposal program. In October 2009 the DOE stated that the current fee of 1/10 cent per kWh was adequate to recover program costs. In April 2010, we joined the Nuclear Energy Institute and fifteen other nuclear plant operators in petitioning the United States Court of Appeals for the District of Columbia District to review the DOE decision to continue to collect the Nuclear Waste Fee at the current rate. The Nuclear Waste Fee litigation is not expected to have any effect on Power’s September 2009 settlement agreement with DOE applicable to Salem and Hope Creek under which Power will be reimbursed for past and future reasonable and allowable costs resulting from the DOE delay in accepting spent nuclear fuel for permanent disposition.

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 (1934 Act)

Exhibit 31.1:

Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act

Exhibit 32:

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

Exhibit 32.1:

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

b. Power:

Exhibit 12.1:

Computation of Ratios of Earnings to Fixed Charges

Exhibit 31.2:

Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act

Exhibit 31.3:

Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act

Exhibit 32.2:

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

Exhibit 32.3:

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

c. PSE&G:

Exhibit 12.2:

Computation of Ratios of Earnings to Fixed Charges

Exhibit 12.3:

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

Exhibit 31.4:

Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act

Exhibit 31.5:

Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act

Exhibit 32.4:

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

Exhibit 32.5:

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

SIGNATURE

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


PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:		/S/ DEREK M. DIRISIO
		Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: July 30, 2010

SIGNATURE


PSEG Power LLC
(Registrant)

By:		/S/ DEREK M. DIRISIO
		Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: July 30, 2010

SIGNATURE


PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:		/S/ DEREK M. DIRISIO
		Derek M. DiRisio Vice President and Controller (Principal Accounting Officer)

Date: July 30, 2010