Edgar Filing: PUBLIC SERVICE ELECTRIC & GAS CO

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, 2012

¨ 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 x	No ¨
Public Service Electric and Gas Company	Yes x	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 17, 2012, Public Service Enterprise Group Incorporated had outstanding 505,935,372 shares of its sole class of Common Stock, without par value.

As of July 17, 2012, 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		6
	Public Service Electric and Gas Company		11
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation		16
	Note 2. Recent Accounting Standards		17
	Note 3. Variable Interest Entities (VIEs)		18
	Note 4. Discontinued Operations and Dispositions		18
	Note 5. Financing Receivables		19
	Note 6. Available-for-Sale Securities		22
	Note 7. Pension and Other Postretirement Benefits (OPEB)		27
	Note 8. Commitments and Contingent Liabilities		28
	Note 9. Changes in Capitalization		38
	Note 10. Financial Risk Management Activities		39
	Note 11. Fair Value Measurements		46
	Note 12. Other Income and Deductions		55
	Note 13. Income Taxes		56
	Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax		57
	Note 15. Earnings Per Share (EPS) and Dividends		58
	Note 16. Financial Information by Business Segments		59
	Note 17. Related-Party Transactions		60
	Note 18. Guarantees of Debt		62
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		65
	Overview of 2012 and Future Outlook		65
	Results of Operations		69
	Liquidity and Capital Resources		77
	Capital Requirements		80
	Accounting Matters		80
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		81
Item 4.	Controls and Procedures		82

PART II. OTHER INFORMATION			83
Item 1.	Legal Proceedings		83
Item 1A.	Risk Factors		83
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		83
Item 5.	Other Information		83
Item 6.	Exhibits		91
	Signatures		92

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “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 8. 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 the demand for or the price of the capacity and energy that we sell into wholesale electricity markets,

•

adverse changes in energy industry law, policies and regulation, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, transmission planning and cost allocation rules, including rules regarding how transmission is planned and who is permitted to build transmission in the future, 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 our operations,

•

changes in nuclear regulation and/or general developments in the nuclear power industry, including various impacts from any accidents or incidents experienced at our facilities or by others in the industry, 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 or the credit quality of our counterparties, including in our leveraged leases,

•

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

•

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,

•

any inability to achieve, or continue to sustain, our expected levels of operating performance,

•

increase in competition in energy supply markets as well as competition for certain rate-based transmission projects,

•

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

•

challenges associated with recruitment and/or retention of a qualified workforce,

•

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.

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 apply only 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)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
OPERATING REVENUES	$	2,098		$	2,469		$	4,973		$	5,823
OPERATING EXPENSES
Energy Costs		761			1,010			1,940			2,573
Operation and Maintenance		629			575			1,257			1,226
Depreciation and Amortization		255			235			511			476
Taxes Other Than Income Taxes		20			28			49			71

Total Operating Expenses		1,665			1,848			3,757			4,346

OPERATING INCOME		433			621			1,216			1,477
Income from Equity Method Investments		2			4			2			7
Other Income		51			55			95			131
Other Deductions		(19	)		(15	)		(35	)		(28	)
Other-Than-Temporary Impairments		(7	)		(1	)		(12	)		(5	)
Interest Expense		(103	)		(117	)		(204	)		(244	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		357			547			1,062			1,338
Income Tax (Expense) Benefit		(146	)		(227	)		(358	)		(556	)

INCOME FROM CONTINUING OPERATIONS		211			320			704			782
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $0 and $(36) for the three and six months ended 2011		0			3			0			67

NET INCOME	$	211		$	323		$	704		$	849

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC		505,903			505,988			505,956			505,984

DILUTED		506,969			506,761			506,999			506,945

EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS	$	0.42		$	0.63		$	1.39		$	1.55

NET INCOME	$	0.42		$	0.63		$	1.39		$	1.68

DILUTED
INCOME FROM CONTINUING OPERATIONS	$	0.42		$	0.63		$	1.39		$	1.54

NET INCOME	$	0.42		$	0.63		$	1.39		$	1.67

DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.3550		$	0.3425		$	0.7100		$	0.6850

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
NET INCOME	$	211		$	323		$	704		$	849
Other Comprehensive Income (Loss), net of tax
Available-for-Sale Securities, net of tax of $(17), $(9), $21 and $(17) for the three and six months ended 2012 and 2011, respectively		(15	)		(10	)		22			(15	)
Change in Fair Value of Derivative Instruments, net of tax of $(3), $(7), $11 and $(1) for the three and six months ended 2012 and 2011, respectively		(5	)		(10	)		15			(1	)
Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $(2), $(9), $(17) and $(37) for the three and six months ended 2012 and 2011, respectively		(5	)		(15	)		(25	)		(56	)
Pension/OPEB adjustment, net of tax of $6, $26, $11 and $30 for the three and six months ended 2012 and 2011, respectively		8			43			15			49

Other Comprehensive Income (Loss), net of tax		(17	)		8			27			(23	)

COMPREHENSIVE INCOME	$	194		$	331		$	731		$	826

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	June 30,			December 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	765		$	834
Accounts Receivable, net of allowances of $56 in 2012 and 2011		896			967
Tax Receivable		16			16
Unbilled Revenues		255			289
Fuel		562			685
Materials and Supplies, net		403			367
Prepayments		397			308
Derivative Contracts		165			156
Deferred Income Taxes		90			0
Regulatory Assets		359			167
Other		32			122

Total Current Assets		3,940			3,911

PROPERTY, PLANT AND EQUIPMENT		26,045			25,080
Less: Accumulated Depreciation and Amortization		(7,455	)		(7,231	)

Net Property, Plant and Equipment		18,590			17,849

NONCURRENT ASSETS
Regulatory Assets		3,417			3,805
Regulatory Assets of Variable Interest Entities (VIEs)		827			925
Long-Term Investments		1,294			1,303
Nuclear Decommissioning Trust (NDT) Fund		1,417			1,349
Other Special Funds		187			172
Goodwill		16			16
Other Intangibles		52			131
Derivative Contracts		133			106
Restricted Cash of VIEs		19			22
Other		250			232

Total Noncurrent Assets		7,612			8,061

TOTAL ASSETS	$	30,142		$	29,821

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	June 30, 2012			December 31, 2011
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year (includes $50 at fair value in 2011)	$	751		$	417
Securitization Debt of VIEs Due Within One Year		221			216
Commercial Paper and Loans		16			0
Accounts Payable		898			1,184
Derivative Contracts		88			131
Accrued Interest		98			97
Accrued Taxes		88			30
Deferred Income Taxes		0			170
Clean Energy Program		138			214
Obligation to Return Cash Collateral		123			107
Regulatory Liabilities		72			100
Other		323			291

Total Current Liabilities		2,816			2,957

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		5,939			5,458
Regulatory Liabilities		206			228
Regulatory Liabilities of VIEs		10			9
Asset Retirement Obligations		505			489
Other Postretirement Benefit (OPEB) Costs		1,115			1,127
Accrued Pension Costs		624			734
Clean Energy Program		0			39
Environmental Costs		588			643
Derivative Contracts		112			26
Long-Term Accrued Taxes		152			292
Other		93			86

Total Noncurrent Liabilities		9,344			9,131

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		6,676			6,694
Securitization Debt of VIEs		616			723
Project Level, Non-Recourse Debt		44			44

Total Long-Term Debt		7,336			7,461

STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2012 and 2011—533,556,660 shares		4,829			4,823
Treasury Stock, at cost, 2012—27,646,288 shares; 2011—27,611,374 shares		(605	)		(601	)
Retained Earnings		6,730			6,385
Accumulated Other Comprehensive Loss		(310	)		(337	)

Total Common Stockholders’ Equity		10,644			10,270
Noncontrolling Interest		2			2

Total Stockholders’ Equity		10,646			10,272

Total Capitalization		17,982			17,733

TOTAL LIABILITIES AND CAPITALIZATION	$	30,142		$	29,821

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	704		$	849
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations		0			(82	)
Depreciation and Amortization		511			483
Amortization of Nuclear Fuel		84			75
Provision for Deferred Income Taxes (Other than Leases) and ITC		165			(28	)
Non-Cash Employee Benefit Plan Costs		134			101
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes		(98	)		(21	)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(86	)		35
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		8			23
Over (Under) Recovery of Societal Benefits Charge (SBC)		(30	)		(19	)
Market Transition Charge Refund		(23	)		(29	)
Cost of Removal		(44	)		(25	)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund		(26	)		(93	)
Net Change in Tax Receivable		0			593
Net Change in Certain Current Assets and Liabilities		278			(2	)
Employee Benefit Plan Funding and Related Payments		(175	)		(465	)
Other		(24	)		0

Net Cash Provided By (Used In) Operating Activities		1,378			1,395

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(1,280	)		(1,002	)
Proceeds from Sale of Discontinued Operations		0			352
Proceeds from Sales of Available-for-Sale Securities		850			657
Investments in Available-for-Sale Securities		(867	)		(676	)
Other		(42	)		(4	)

Net Cash Provided By (Used In) Investing Activities		(1,339	)		(673	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans		16			234
Issuance of Long-Term Debt		500			0
Redemption of Long-Term Debt		(139	)		(606	)
Repayment of Non-Recourse Debt		0			(1	)
Redemption of Securitization Debt		(101	)		(96	)
Cash Dividends Paid on Common Stock		(359	)		(347	)
Other		(25	)		(27	)

Net Cash Provided By (Used In) Financing Activities		(108	)		(843	)

Net Increase (Decrease) in Cash and Cash Equivalents		(69	)		(121	)
Cash and Cash Equivalents at Beginning of Period		834			280

Cash and Cash Equivalents at End of Period	$	765		$	159

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	114		$	57
Interest Paid, Net of Amounts Capitalized	$	197		$	259
Increase (Decrease) in Accrued Property, Plant and Equipment Expenditures	$	(129	)	$	(118	)

See Notes to Condensed Consolidated Financial Statements.

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
OPERATING REVENUES	$	985		$	1,285		$	2,546		$	3,252
OPERATING EXPENSES
Energy Costs		447			603			1,269			1,738
Operation and Maintenance		284			271			525			548
Depreciation and Amortization		58			56			115			110

Total Operating Expenses		789			930			1,909			2,396

OPERATING INCOME		196			355			637			856
Other Income		37			49			67			119
Other Deductions		(17	)		(14	)		(32	)		(26	)
Other-Than-Temporary Impairments		(7	)		(1	)		(12	)		(3	)
Interest Expense		(32	)		(41	)		(62	)		(92	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		177			348			598			854
Income Tax (Expense) Benefit		(73	)		(143	)		(241	)		(352	)

INCOME FROM CONTINUING OPERATIONS		104			205			357			502
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $0 and $(36) for the three and six months ended 2011		0			3			0			67

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	104		$	208		$	357		$	569

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

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
NET INCOME	$	104		$	208		$	357		$	569
Other Comprehensive Income (Loss), net of tax
Available-for-Sale Securities, net of tax of $(17), $(10), $22 and $(19) for the three and six months ended 2012 and 2011, respectively		(15	)		(10	)		22			(17	)
Change in Fair Value of Derivative Instruments, net of tax of $(3), $(7), $11 and $(1) for the three and six months ended 2012 and 2011, respectively		(5	)		(10	)		15			(1	)
Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $(2), $(9), $(17) and $(37) for the three and six months ended 2012 and 2011, respectively		(5	)		(15	)		(25	)		(56	)
Pension/OPEB adjustment, net of tax of $5, $24, $10 and $28 for the three and six months ended 2012 and 2011, respectively		7			36			14			42

Other Comprehensive Income (Loss), net of tax		(18	)		1			26			(32	)

COMPREHENSIVE INCOME	$	86		$	209		$	383		$	537

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,			December 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	2		$	12
Accounts Receivable		258			267
Accounts Receivable—Affiliated Companies, net		265			381
Short-Term Loan to Affiliate		737			907
Fuel		562			685
Materials and Supplies, net		301			272
Derivative Contracts		146			139
Prepayments		21			24
Other		2			0

Total Current Assets		2,294			2,687

PROPERTY, PLANT AND EQUIPMENT		9,379			9,191
Less: Accumulated Depreciation and Amortization		(2,586	)		(2,460	)

Net Property, Plant and Equipment		6,793			6,731

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund		1,417			1,349
Goodwill		16			16
Other Intangibles		52			131
Other Special Funds		35			33
Derivative Contracts		40			55
Other		102			85

Total Noncurrent Assets		1,662			1,669

TOTAL ASSETS	$	10,749		$	11,087

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,			December 31,
	2012			2011
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	300		$	66
Accounts Payable		343			541
Derivative Contracts		88			124
Deferred Income Taxes		41			53
Accrued Interest		32			32
Other		86			86

Total Current Liabilities		890			902

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		1,442			1,266
Asset Retirement Obligations		270			259
Other Postretirement Benefit (OPEB) Costs		186			180
Derivative Contracts		8			24
Accrued Pension Costs		202			236
Long-Term Accrued Taxes		53			8
Other		85			83

Total Noncurrent Liabilities		2,246			2,056

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT
Total Long-Term Debt		2,386			2,685

MEMBER’S EQUITY
Contributed Capital		2,028			2,028
Basis Adjustment		(986	)		(986	)
Retained Earnings		4,435			4,678
Accumulated Other Comprehensive Loss		(250	)		(276	)

Total Member’s Equity		5,227			5,444

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	10,749		$	11,087

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)


	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	357		$	569
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations		0			(82	)
Depreciation and Amortization		115			116
Amortization of Nuclear Fuel		84			75
Provision for Deferred Income Taxes and ITC		184			(92	)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(86	)		35
Non-Cash Employee Benefit Plan Costs		34			24
Net Realized (Gains) Losses and (Income) Expense from NDT Fund		(26	)		(93	)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies		94			99
Margin Deposit		36			(54	)
Accounts Receivable		40			162
Accounts Payable		(14	)		(141	)
Accounts Receivable/Payable-Affiliated Companies, net		73			649
Other Current Assets and Liabilities		(6	)		10
Employee Benefit Plan Funding and Related Payments		(39	)		(125	)
Other		6			(6	)

Net Cash Provided By (Used In) Operating Activities		852			1,146

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(344	)		(323	)
Proceeds from Sale of Discontinued Operations		0			352
Proceeds from Sales of Available-for-Sale Securities		677			657
Investments in Available-for-Sale Securities		(692	)		(672	)
Short-Term Loan—Affiliated Company, net		170			(211	)
Other		0			16

Net Cash Provided By (Used In) Investing Activities		(189	)		(181	)

CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid		(600	)		(350	)
Redemption of Long-Term Debt		(66	)		(606	)
Other		(7	)		(6	)

Net Cash Provided By (Used In) Financing Activities		(673	)		(962	)

Net Increase (Decrease) in Cash and Cash Equivalents		(10	)		3
Cash and Cash Equivalents at Beginning of Period		12			11

Cash and Cash Equivalents at End of Period	$	2		$	14

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	118		$	69
Interest Paid, Net of Amounts Capitalized	$	57		$	101
Increase (Decrease) in Accrued Property, Plant and Equipment Expenditures	$	(83	)	$	(69	)

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
OPERATING REVENUES	$	1,407		$	1,571		$	3,346		$	3,877
OPERATING EXPENSES
Energy Costs		622			815			1,624			2,181
Operation and Maintenance		350			304			726			672
Depreciation and Amortization		188			172			378			351
Taxes Other Than Income Taxes		20			28			49			71

Total Operating Expenses		1,180			1,319			2,777			3,275

OPERATING INCOME		227			252			569			602
Other Income		12			4			23			9
Other Deductions		(1	)		0			(2	)		(1	)
Other-Than-Temporary Impairments		0			0			0			(1	)
Interest Expense		(74	)		(78	)		(147	)		(157	)

INCOME BEFORE INCOME TAXES		164			178			443			452
Income Tax (Expense) Benefit		(63	)		(73	)		(145	)		(184	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	101		$	105		$	298		$	268

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 COMPREHENSIVE INCOME

Millions

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012			2011
NET INCOME	$	101	$	105	$	298		$	268
Available-for-Sale Securities, net of tax of $0, $0, $(1) and $1 for the three and six months ended 2012 and 2011, respectively		0		0		(1	)		1

COMPREHENSIVE INCOME	$	101	$	105	$	297		$	269

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,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	22		$	143
Accounts Receivable, net of allowances of $56 in 2012 and 2011		630			691
Tax Receivable		16			16
Unbilled Revenues		255			289
Materials and Supplies		102			94
Prepayments		243			117
Regulatory Assets		359			167
Other		20			21

Total Current Assets		1,647			1,538

PROPERTY, PLANT AND EQUIPMENT		16,050			15,306
Less: Accumulated Depreciation and Amortization		(4,618	)		(4,539	)

Net Property, Plant and Equipment		11,432			10,767

NONCURRENT ASSETS
Regulatory Assets		3,417			3,805
Regulatory Assets of VIEs		827			925
Long-Term Investments		313			280
Other Special Funds		61			57
Derivative Contracts		45			4
Restricted Cash of VIEs		19			22
Other		102			89

Total Noncurrent Assets		4,784			5,182

TOTAL ASSETS	$	17,863		$	17,487

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,
	2012		2011
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	450	$	300
Securitization Debt of VIEs Due Within One Year		221		216
Commercial Paper and Loans		16		0
Accounts Payable		428		498
Accounts Payable—Affiliated Companies, net		146		280
Accrued Interest		66		65
Clean Energy Program		138		214
Derivative Contracts		0		7
Deferred Income Taxes		37		32
Obligation to Return Cash Collateral		123		107
Regulatory Liabilities		72		100
Other		210		186

Total Current Liabilities		1,907		2,005

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC		3,837		3,675
Other Postretirement Benefit (OPEB) Costs		881		900
Accrued Pension Costs		283		355
Regulatory Liabilities		206		228
Regulatory Liabilities of VIEs		10		9
Clean Energy Program		0		39
Environmental Costs		537		592
Asset Retirement Obligations		231		226
Derivative Contracts		104		0
Long-Term Accrued Taxes		18		83
Other		43		35

Total Noncurrent Liabilities		6,150		6,142

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		4,246		3,970
Securitization Debt of VIEs		616		723

Total Long-Term Debt		4,862		4,693

STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2012 and 2011—132,450,344 shares		892		892
Contributed Capital		420		420
Basis Adjustment		986		986
Retained Earnings		2,645		2,347
Accumulated Other Comprehensive Income		1		2

Total Stockholder’s Equity		4,944		4,647

Total Capitalization		9,806		9,340

TOTAL LIABILITIES AND CAPITALIZATION	$	17,863	$	17,487

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)


	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	298		$	268
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		378			351
Provision for Deferred Income Taxes and ITC		75			65
Non-Cash Employee Benefit Plan Costs		89			67
Cost of Removal		(44	)		(25	)
Market Transition Charge (MTC) Refund		(23	)		(29	)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		8			23
Over (Under) Recovery of SBC		(30	)		(19	)
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		108			204
Materials and Supplies		(8	)		(2	)
Prepayments		(126	)		(234	)
Accounts Receivable/Payable-Affiliated Companies, net		(94	)		(65	)
Other Current Assets and Liabilities		(11	)		(30	)
Employee Benefit Plan Funding and Related Payments		(121	)		(294	)
Other		(40	)		(1	)

Net Cash Provided By (Used In) Operating Activities		459			279

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(870	)		(674	)
Proceeds from Sale of Available-for-Sale Securities		71			0
Investments in Available-for-Sale Securities		(71	)		0
Solar Loan Investments		(48	)		(23	)
Restricted Funds		3			0

Net Cash Provided By (Used In) Investing Activities		(915	)		(697	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt		16			298
Issuance of Long-Term Debt		500			0
Redemption of Long-Term Debt		(73	)		0
Redemption of Securitization Debt		(101	)		(96	)
Deferred Issuance Costs		(7	)		(3	)

Net Cash Provided By (Used In) Financing Activities		335			199

Net Increase (Decrease) In Cash and Cash Equivalents		(121	)		(219	)
Cash and Cash Equivalents at Beginning of Period		143			245

Cash and Cash Equivalents at End of Period	$	22		$	26

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	4		$	(44	)
Interest Paid, Net of Amounts Capitalized	$	139		$	153
Increase (Decrease) in Accrued Property, Plant and Equipment Expenditures	$	(46	)	$	(49	)

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. PSE&G is also investing in the development of solar generation projects and energy efficiency programs, which are regulated by the BPU.

•

PSEG Energy Holdings L.L.C. (Energy Holdings)—which has invested in leveraged leases and owns and operates primarily domestic projects engaged in the generation of energy 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 has also invested in solar generation projects and is exploring opportunities for other investments in renewable generation and has been awarded a contract to manage the transmission and distribution assets of the Long Island Power Authority (LIPA).

•

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

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, 2011 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

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. All significant intercompany accounts and transactions are eliminated in consolidation, except as discussed in Note 17. Related-Party Transactions. 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, 2011.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 2. Recent Accounting Standards

New Standards Adopted during 2012

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)

This accounting standard was issued to update guidance related to fair value measurements and disclosures as a step towards achieving convergence between GAAP and IFRS. The updated guidance

•

clarifies intent about application of existing fair value measurements and disclosures,

•

changes some requirements for fair value measurements, and

•

requires expanded disclosures.

We adopted this standard prospectively effective January 1, 2012. Upon adoption there was no material impact on our consolidated financial position, results of operations or cash flows; however, it has resulted in expanded disclosures. For additional information, see Note 11. Fair Value Measurements.

Presentation of Comprehensive Income

This accounting standard addresses the presentation of comprehensive income as a step towards achieving convergence between GAAP and IFRS. The updated guidance

•

allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and

•

eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.

In December 2011, the FASB issued an amendment to this standard to indefinitely defer the effective date for some of the specific disclosure requirements that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income by component in both the statement in which net income is presented and the statement in which other comprehensive income is presented. During the deferral period, the existing requirements in GAAP for the presentation of reclassification adjustments must continue to be followed.

We adopted this standard retrospectively effective January 1, 2012. Upon adoption of the new amended guidance, there was no impact on our consolidated financial position, results of operations or cash flows, but there was a change in the presentation of the components of other comprehensive income.

New Accounting Standards Issued But Not Yet Adopted

Disclosures about Offsetting Assets and Liabilities

This accounting standard was issued on balance sheet offsetting disclosures to facilitate comparability between financial statements prepared on the basis of GAAP and IFRS. This standard requires entities:

•

to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on an entity’s financial position, and

•

to present both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset.

The guidance is effective for fiscal years and interim periods beginning on or after January 1, 2013. As this standard requires disclosures only, it will not have any impact on our consolidated financial position, results of operations or cash flows upon adoption.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 3. Variable Interest Entities (VIEs)

Variable Interest Entities for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary 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 a 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. No Transition Funding or Transition Funding II creditor has 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 or 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, 2012 and December 31, 2011. 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 2012 or in 2011. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.

Note 4. Discontinued Operations and Dispositions

Discontinued Operations

Power

In March 2011, Power completed the sale of its 1,000 MW gas-fired Guadalupe generating facility for a total price of $352 million, resulting in an after-tax gain of $54 million.

In July 2011, Power completed the sale of its 1,000 MW gas-fired Odessa generating facility for approximately $335 million, resulting in an after-tax gain of approximately $25 million.

PSEG Texas’ operating results for the three months and six months ended June 30, 2011, which were reclassified to Discontinued Operations, are summarized below:


	Three Months Ended June 30, 2011		Six Months Ended June 30, 2011
	Millions
Operating Revenues	$	29	$	92
Income Before Income Taxes	$	2	$	20
Net Income	$	2	$	13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 5. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with Solar Renewable Energy Certificates (SRECs) generated from the installed solar electric system. The following table reflects the outstanding short and long-term loans by class of customer, none of which are considered “non-performing.”


Credit Risk Profile Based on Payment Activity
	As of		As of
	June 30,		December 31,
Consumer Loans	2012		2011
	Millions
Performing
Commercial/Industrial	$	150	$	106
Residential		13		10

Total Consumer Loans	$	163	$	116

Energy Holdings

Energy Holdings has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings’ investments in the leases are comprised of the total expected lease receivables on its investments over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Condensed Consolidated Balance Sheets. The table below shows Energy Holdings’ gross and net lease investment as of June 30, 2012 and December 31, 2011, respectively.


	As of			As of
	June 30,			December 31,
	2012			2011
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	725		$	763
Estimated Residual Value of Leased Assets		535			553

		1,260			1,316
Unearned and Deferred Income		(427	)		(435	)

Gross Investments in Leases		833			881
Deferred Tax Liabilities		(677	)		(716	)

Net Investments in Leases	$	156		$	165

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The corresponding receivables associated with the lease portfolio are reflected below, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. “Not Rated” counterparties relate to investments in leases of commercial real estate properties.


	Lease Receivables, Net of Non-Recourse Debt
	As of June 30,		As of December 31,
Counterparties’ Credit Rating (S&P)	2012		2011
	Millions
AA	$	21	$	21
A+		73		110
BBB - BB		316		316
B - B-		165		299
CCC		134		0
Not Rated		16		17

Total	$	725	$	763

The “B-” and “CCC” ratings above represent lease receivables related to coal-fired assets in Illinois and Pennsylvania. As of June 30, 2012, the gross investment in the leases of such assets, net of non-recourse debt, was $553 million ($57 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the table below.

Asset

Location

Gross
Investment

%
Owned

Total

Fuel
Type

Counterparties’
S&P Credit
Ratings

Counterparty

Millions

Powerton Station Units 5 and 6

134

64%

1,538

Coal

CCC

Edison Mission Energy

Joliet Station Units 7 and 8

64%

1,044

Coal

CCC

Edison Mission Energy

Keystone Station Units 1 and 2

113

17%

1,711

Coal

B-

GenOn REMA, LLC

Conemaugh Station Units 1 and 2

114

17%

1,711

Coal

B-

GenOn REMA, LLC

Shawville Station Units 1, 2, 3 and 4

108

100%

603

Coal

B-

GenOn REMA, LLC

Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel and electricity, overall financial condition of lease counterparties and the quality and condition of assets under lease. Of our facilities under lease to GenOn REMA, LLC (GenOn REMA), a subsidiary of GenOn Energy Inc (GenOn), PSEG believes Keystone has adequate environmental controls installed. Conemaugh has flue gas desulfurization control. Selective catalytic reduction (SCR) equipment for Nitrogen Oxide and mercury control are scheduled to be installed at Conemaugh in 2014.

GenOn’s plan for the coal-fired units at the Shawville facility is to place them in a “long-term protective layup” by April 2015; however, GenOn has indicated that it will continue paying the required rent and maintaining the facility in accordance with the lease terms. GenOn has further stated that the lessee is

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

evaluating its options under the lease, including termination for obsolescence or continuing to keep the facility in “long-term protective layup.” In the event that the lessee is able to terminate for obsolescence, the lessee would be required, among other things, to pay the contractual termination value structured to recover Energy Holdings’ lease investment as specified in the lease agreement. On July 22, 2012, GenOn announced that it has signed a definitive agreement to merge with NRG Energy, Inc. We are carefully monitoring these developments.

With respect to Edison Mission Energy’s (EME) Midwest Generation leases on the Powerton and Joliet coal units in Illinois, the lessees completed investments in mercury removal (Activated Carbon Injection), low NOx burners and Selective Non-Catalytic Reduction systems and plan to employ a dry sorbent (Trona) system to reduce sulfur. EME and these units remain in litigation with the United States Environmental Protection Agency (EPA) and the State of Illinois regarding certain environmental matters; however EME has announced that the above actions should enable compliance with pending environmental rules. The federal district court has dismissed new source review claims in reference to Powerton and Joliet, but certain opacity claims remain active and under appeal by the EPA and the State of Illinois. The federal district court has stayed proceedings in connection with the opacity claims until the appeal is resolved. In its most recent quarterly report filed on July 31, 2012, EME’s parent, Edison International, reported that it will no longer provide financial support to EME, that Midwest Generation is largely dependent upon EME for its funding, that based upon current projections EME will not be able to meet its debt obligation in June 2013, and that failing a restructuring of its obligations, EME and Midwest Generation may need to file for protection under Chapter 11 of the Bankruptcy Code, which could have an impact on the Powerton and Joliet leases.

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverage ratios are not met. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a temporary market downturn or degradation in operating performance of the leased assets. In the event of a default in any of the lease transactions, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure on the lease by the lenders. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities.

On December 13, 2011, affiliates of Energy Holdings and Dynegy reached a settlement agreement resolving disputes that had arisen between them with regard to Dynegy Holding’s (DH) rejection of the Dynegy leases. The settlement agreement resolves certain disputes regarding the Dynegy leases, including claims under our Tax Indemnity Agreement with DH. The original terms of the settlement agreement included a cash payment of $7.5 million, which was received on January 4, 2012, and the Bankruptcy Court’s allowance of a $110 million claim against DH. On June 1, 2012, an amended and restated settlement agreement entered into by DH, Dynegy and their creditors was approved by the Bankruptcy Court and became effective on June 5, 2012. As part of that settlement, Energy Holdings, DH and the creditors of DH agreed to commence a process to sell the Roseton and Danskammer facilities; the agreement allocates proceeds from the sale of the facilities to pay DH’s creditors, including the lease bondholders, and grants the lease bondholders claims in agreed upon amounts against DH in its bankruptcy proceedings. The settlement agreement also includes an exchange of releases by various settling claimants, including parties to the leases with respect to claims arising out of the leases. Concurrently with the entry into the settlement agreement, DH filed an amended plan of reorganization, which is supported by the various settling claimants, providing that we and other unsecured creditors of DH will be paid our claims partially in cash and partially in stock in a reorganized Dynegy that will emerge at the conclusion of the bankruptcy. On July 3, 2012, the Bankruptcy Court approved DH’s disclosure statement

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

describing its amended plan of reorganization; that disclosure statement is now being used in the formal solicitation of creditor votes on DH’s amended plan. The Bankruptcy Court will receive the results of the balloting by creditors and conduct a hearing on approval of DH’s amended plan on September 5, 2012.

On December 30, 2011, the effective date of the court order authorizing the Dynegy lease rejections, the leases no longer qualified for leveraged lease accounting treatment under GAAP since the lease agreements were effectively terminated. As a result, Energy Holdings wrote off the $264 million gross lease investment against the previously recorded reserve. As the owner of the two plants, Energy Holdings’ lessor entities ceased leveraged lease accounting, and recorded the generation assets and related nonrecourse project debt on their balance sheets at their respective fair values (See Note 11. Fair Value Measurements). DH remains responsible for the operations, including the financial obligations, of these lessor entities. As of the June 5, 2012 effective date of the amended settlement agreement, the lease debt and the related assets were written off.

Note 6. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Fund

Power maintains an external master nuclear decommissioning trust 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 Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund:


	As of June 30, 2012
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	583	$	155	$	(10	)	$	728

Debt Securities
Government Obligations		291		15		0			306
Other Debt Securities		303		17		0			320

Total Debt Securities		594		32		0			626
Other Securities		63		0		0			63

Total NDT Available-for-Sale Securities	$	1,240	$	187	$	(10	)	$	1,417


	As of December 31, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	582	$	126	$	(23	)	$	685

Debt Securities
Government Obligations		343		16		0			359
Other Debt Securities		268		15		(2	)		281

Total Debt Securities		611		31		(2	)		640
Other Securities		24		0		0			24

Total NDT Available-for-Sale Securities	$	1,217	$	157	$	(25	)	$	1,349

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

These amounts do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.


	As of June 30, 2012		As of December 31, 2011
	Millions
Accounts Receivable	$	21	$	27
Accounts Payable	$	16	$	22

The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2012.


	As of June 30, 2012									As of December 31, 2011
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	143	$	(10	)	$	0	$	0	$	183	$	(23	)	$	0	$	0

Debt Securities
Government Obligations (B)		18		0			1		0		20		0			3		0
Other Debt Securities (C)		33		0			7		0		56		(1	)		4		(1	)

Total Debt Securities		51		0			8		0		76		(1	)		7		(1	)

Other Securities		1		0			0		0		0		0			0		0

NDT Available-for-Sale Securities	$	195	$	(10	)	$	8	$	0	$	259	$	(24	)	$	7	$	(1	)

(A)	Equity Securities—Represent investments primarily in common stock within a broad range of industries and sectors. The unrealized losses are distributed over two hundred companies with limited impairment durations.

(B)

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

(C)	Debt Securities (Corporate)—Represent investment grade corporate bonds which are not expected to settle for less than their amortized cost. Power does not intend to sell nor will it be more-likely-than-not required to sell these securities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	Millions
Proceeds from NDT Fund Sales	$	290		$	342		$	635		$	657

Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	26		$	36		$	42		$	95
Gross Realized Losses		(16	)		(11	)		(22	)		(18	)

Net Realized Gains (Losses) on NDT Fund	$	10		$	25		$	20		$	77

Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $88 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on Power’s Condensed Consolidated Balance Sheet as of June 30, 2012. The NDT available-for-sale debt securities held as of June 30, 2012 had the following maturities:


Time Frame	Fair Value
	Millions
Less than one year	$	15
1 - 5 years		138
6 - 10 years		178
11 - 15 years		34
16 - 20 years		11
Over 20 years		250

Total NDT Available-for-Sale Debt Securities	$	626

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 (Loss). In 2012, other-than-temporary impairments of $12 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be 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 Trust

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 a grantor trust commonly known as the “Rabbi Trust.” In March 2012, PSEG restructured the fixed income component of the Rabbi Trust.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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


	As of June 30, 2012
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	13	$	3	$	0	$	16

Debt Securities
Government Obligations		114		2		0		116
Other Debt Securities		43		1		0		44

Total Debt Securities		157		3		0		160
Other Securities		3		0		0		3

Total Rabbi Trust Available-for-Sale Securities	$	173	$	6	$	0	$	179


	As of December 31, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities	$	16	$	3	$	0	$	19
Debt Securities		148		5		0		153

Total Rabbi Trust Available-for-Sale Securities	$	164	$	8	$	0	$	172

As of June 30, 2012, amounts in the above table do not include Accounts Receivable of $1 million and Accounts Payable of $2 million for Rabbi Trust Fund transactions which had not yet settled. These amounts are included on the Condensed Consolidated Balance Sheets.


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	Millions
Proceeds from Rabbi Trust Sales	$	61	$	0	$	215	$	0

Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	1	$	0	$	6	$	0
Gross Realized Losses		0		0		0		0

Net Realized Gains (Losses) on Rabbi Trust	$	1	$	0	$	6	$	0

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Gross realized gains disclosed in the above table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of $4 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of June 30, 2012. The Rabbi Trust available-for-sale debt securities held as of June 30, 2012 had the following maturities:


Time Frame	Fair Value
	Millions
Less than one year	$	0
1 - 5 years		58
6 - 10 years		29
11 - 15 years		16
16 - 20 years		5
Over 20 years		52

Total Rabbi Trust Available-for-Sale Debt Securities	$	160

PSEG 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, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, 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. 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 (Loss). 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.

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

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


	As of June 30, 2012		As of December 31, 2011
	Millions
Power	$	35	$	33
PSE&G		59		57
Other		85		82

Total Rabbi Trust Available-for-Sale Securities	$	179	$	172

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 7. Pension and 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 13. Income Taxes for additional information.

Pension and OPEB costs for PSEG 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,
	2012			2011			2012			2011			2012			2011			2012			2011
	Millions
Components of Net Periodic Benefit Cost:
Service Cost	$	25		$	23		$	4		$	3		$	50		$	47		$	8		$	7
Interest Cost		55			58			16			15			111			116			32			30
Expected Return on Plan Assets		(77	)		(82	)		(5	)		(4	)		(153	)		(163	)		(9	)		(8	)
Amortization of Net
Transition Obligation		0			0			0			1			0			0			1			3
Prior Service Cost (Credit)		(4	)		(2	)		(3	)		(3	)		(9	)		(2	)		(7	)		(6	)
Actuarial Loss		42			30			8			4			84			60			16			7

Net Periodic Benefit Cost	$	41		$	27		$	20		$	16		$	83		$	58		$	41		$	33
Effect of Regulatory Asset		0			0			5			5			0			0			10			10

Total Benefit Costs, Including Effect of Regulatory Asset	$	41		$	27		$	25		$	21		$	83		$	58		$	51		$	43

Pension and OPEB costs for Power, PSE&G and PSEG’s other subsidiaries 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,
	2012		2011		2012		2011		2012		2011		2012		2011
	Millions
Power	$	12	$	8	$	4	$	3	$	25	$	18	$	9	$	6
PSE&G		25		15		20		17		49		32		40		35
Other		4		4		1		1		9		8		2		2

Total Benefit Costs	$	41	$	27	$	25	$	21	$	83	$	58	$	51	$	43

During the three months ended March 31, 2012, PSEG contributed its entire planned contribution for the year 2012 of $124 million and $11 million into its pension and postretirement healthcare plans, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 8. 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 result is unlikely. For this reason, Power believes that 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.

In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The face value of outstanding guarantees, current exposure and margin positions as of June 30, 2012 and December 31, 2011 are shown below:


	As of			As of
	June 30,			December 31,
	2012			2011
	Millions
Face Value of Outstanding Guarantees	$	1,573		$	1,756
Exposure under Current Guarantees	$	271		$	315
Letters of Credit Margin Posted	$	178		$	135
Letters of Credit Margin Received	$	115		$	91
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	29		$	20
Counterparty Cash Margin Received		(4	)		(7	)
Net Broker Balance Deposited (Received)		(69	)		(92	)
In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required	$	705		$	812
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,467		$	3,415
Additional Amounts Posted
Other Letters of Credit	$	55		$	52

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. In accordance with our accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

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 S&P ratings or a three level downgrade from its current Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

In addition, during 2012, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. The CFTC issued a Final Rule regarding the definition of a swap dealer in May 2012 but the CFTC has yet to publish the Final Rule regarding the definition of a swap. In July 2012, the CFTC held a public meeting on the definition of a swap as well as the end-user exemption. Power will carefully monitor these new rules as they are developed to analyze the potential impact on its swap and derivatives transactions, including any potential increase to collateral requirements.

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. See table above.

Environmental Matters

Passaic River

Historic operations of 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

The EPA has determined that an eight-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under CERCLA. The EPA has determined the need 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.

The EPA believes that certain 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. The total cost of the study is now estimated at approximately $105 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently 70 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” (FFS) that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The EPA estimated costs for the proposed remedy 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. The EPA is conducting a revised focused feasibility study which may be released as early as the fourth quarter of 2012.

In June 2008, an agreement was announced between the EPA and Tierra Solutions, Inc. and Maxus Energy Corporation (Tierra/Maxus) for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. That removal work is underway. Tierra/Maxus have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

The EPA has advised that the levels of contaminants at Passaic River mile 10.9 may require a pilot study and will require removal in advance of the completion of the Remedial Investigation and Feasibility Study or the issuance of a revised draft FFS. The CPG members, with the exception of Tierra/Maxus, have agreed to fund the 10.9 pilot study and removal currently estimated at approximately $30 million. PSEG’s share of that effort is approximately three percent.

Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to these matters.

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 both the Passaic River and the balance of the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed hazardous substances to a total of 11 sites or facilities that impacted these water bodies. 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 and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaint in June 2010. A special master for discovery has been appointed by the court and document production has

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

commenced. 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. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.

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 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. PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.

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 River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but it is uncertain at this time whether the PSEG companies will consent to fund the third phase. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.

MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $616 million and $714 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $616 million as of June 30, 2012. Of this amount, $90 million was recorded in Other Current Liabilities and $526 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $616 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In 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.

Hazardous Air Pollutants Regulation

In accordance with a court ruling, the EPA published a Maximum Achievable Control Technology (MACT) regulation in the Federal Register on February 16, 2012. These Mercury Air Toxics Standards (MATS) go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the Clean Air Act. On March 19, 2012, PSEG filed a motion to intervene in support of the EPA’s implementation of MATS. The back-end technology environmental controls recently installed at Power’s Hudson and Mercer coal facilities will meet the rule’s requirements. It will not be necessary to install any material controls at Power’s other New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an estimated cost of approximately $5 million. In December 2011, a decision was reached to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. PSEG’s share of this investment is approximately $147 million.

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.

With newly installed controls at its plants in New Jersey, Power has achieved the required mercury reductions 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.

Nitrogen Oxide (NO_x) Regulation

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 generating units. The rule will have 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 four older New Jersey steam electric generating units (approximately 400 MW) by May 30, 2015. Power is currently evaluating its compliance options and is unable to estimate the possible loss or range of loss related to this matter.

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. In 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.

Cross-State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) that limits power plant emissions in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions would have been governed by this rule beginning on January 1, 2012 for Sulfur Dioxide (SO₂) and “annual NO_x” and May 1, 2012 for “Ozone season NO_x”.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Certain states would have been required to make additional SO₂reductions in 2014. The EPA issued draft technical adjustments to the final CSAPR in October 2011. Technical revisions to the CSAPR were finalized on February 7, 2012. The EPA increased New Jersey’s allocation of annual NO_x and ozone season NO_x allowances beyond what was proposed. The EPA also finalized the increase in New Jersey’s allocation of SO₂ allowances from the October proposal. The additional increases in NO_x allocations are favorable to us, since both Power and New Jersey as a whole were projected to be short on NO_x allowances (both ozone season and annual) under the original allocation scenario.

On December 30, 2011, the United States Court of Appeals for the D.C. Circuit issued a ruling to stay CSAPR pending judicial review. Until a final decision is reached, the court has ordered that the Clean Air Interstate Rule (CAIR) requirements continue temporarily. PSEG has intervened in this litigation along with Calpine and Exelon in support of implementing CSAPR. Oral argument occurred on April 13, 2012. A final decision on the merits is expected in the summer of 2012.

The continuation of CAIR affects our generating stations in Connecticut, New Jersey and New York. The purpose of CAIR is to improve Ozone and Fine Particulate (PM2.5) air quality within states that have not demonstrated achievement of the National Ambient Air Quality Standards (NAAQS). CAIR was implemented through a cap-and-trade program and to date the impact has not been material to us as the allowances allocated to our stations were sufficient. If 2012 operations are similar to those in the past three years, it is expected that the impact to operations from the temporary implementation of CAIR in 2012 will not be significant.

PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. Power has made major capital investments over the past several years to lower the SO₂ and NO_x emissions of its fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania). Power does not foresee the need to make significant additional expenditures to its generation fleet to comply with the regulation. As such, Power believes this rule will not have a material impact to its capital investment program or units’ operations.

Clean Water Act 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 a 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.

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 316(b) rules published in 2004. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules 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.

As a result of several legal challenges to the 2004 316(b) rule by certain northeast states, environmentalists and industry groups, the rule has been suspended and has been returned to the EPA to be consistent with a 2009 United States Supreme Court decision which concluded 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012. In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power’s electric generating stations would be affected. On June 11, 2012, the EPA posted a Notice of Data Availability (NODA) requesting comment on a series of technical issues related to the impingement mortality proposed standards. On June 12, 2012, the EPA posted a second NODA outlining its plans to finalize a “Willingness to Pay” survey it initiated to develop non-use benefits data in support of the April 2011 rule proposal. PSEG and industry trade associations submitted comments on both NODAs in early July. In July 2012, the EPA and environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.

Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition, results of operations or cash flows. 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 would 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 cost estimates have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures. In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies may 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. In December 2010, the NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit was issued by NJDEP on June 1, 2011. The permit was issued as final on December 21, 2011 incorporating the 316(b) requirements as defined in the ACO. In that permit, NJDEP defended its position that closed-cycle cooling was not the best technology available for that facility. Per that permit the facility will cease operations on December 31, 2019. Power 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.

Power has received a preliminary draft of the Delaware River Basin Commission (DRBC) water discharge permit that would revise Mercer Generating Station’s thermal discharge limits and require compliance within five years of approval. Power is reviewing the proposed revisions with NJDEP and DRBC staff. Power cannot at this time determine the final form of the permit that will be presented to the DRBC commissioners for approval and what, if any, impact this permit would have on Mercer’s operations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

New Generation and Development

Nuclear

Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed on schedule in October 2011. Unit 2 upgrades are expected to result in an increase of Power’s share of nominal capacity by approximately 14 MW in 2012. Total expenditures through June 30, 2012 were $127 million.

Power has also approved the expenditure of $419 million for an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to result in an increase in Power’s share of nominal capacity by approximately 130 MW. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Total expenditures through June 30, 2012 were $44 million.

Connecticut

Power was selected by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control, in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project was placed in service in June 2012. Power’s total capitalized expenditures for these generating units, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power, were approximately $149 million (not including the capitalized cost to finance during construction).

PJM Interconnection L.L.C. (PJM)

In June 2012, Power completed construction and placed in service new 267 MW gas fired peaking facilities at its Kearny site. Power’s total capitalized expenditures for these generating units, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power, were approximately $244 million.

PSE&G—Solar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G estimates the total cost of this project to be $262 million. Approximately 30 MW have been installed as of June 30, 2012. PSE&G’s cumulative investments for these solar units were approximately $215 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available.

Another aspect of the Solar 4 All program is the installation of 40 MW of solar systems on land and buildings owned by PSE&G and third parties. PSE&G estimates the total cost of this phase of the program to be $194 million. Through June 30, 2012, 36 MW representing 20 projects had been placed into service with an investment of approximately $173 million.

Energy Holdings—Solar

In January 2012, Energy Holdings acquired a 25 MW solar project currently under construction in Arizona. Completion of this project is expected in 2012. Energy Holdings issued guarantees of up to $71.5 million for payment of obligations related to the construction of the project, of which $23 million was outstanding as of June 30, 2012. These guarantees will terminate upon successful completion of the project. The total investment for the project is expected to be approximately $75 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 with the winners of these BGS auctions following the BPU’s approval of

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 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.

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

Auction Year

2009

2010

2011

2012

36-Month Terms Ending

May 2012

May 2013

May 2014

May 2015

(A)

Load (MW)

2,900

2,800

2,900

$ per kWh

0.10372

0.09577

0.09430

0.08388

(A)	Prices set in the 2012 BGS auction became effective on June 1, 2012 when the 2009 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. 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 17. 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 through 2014 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 strategy is to maintain certain levels of uranium 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 2015 and a portion for 2016 at Salem, Hope Creek and Peach Bottom.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of June 30, 2012, the total minimum purchase requirements included in these commitments were as follows:


Fuel Type	Power’s Share of Commitments through 2016
	Millions
Nuclear Fuel
Uranium	$	465
Enrichment	$	451
Fabrication	$	146
Natural Gas	$	960
Coal/Oil	$	235

Regulatory Proceedings

Electric Discount and Energy Competition Act (Competition Act)

In 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. The Superior Court subsequently granted PSE&G’s motion to dismiss the Complaint, which dismissal was upheld by the Appellate Division.

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 June 2010, the BPU granted PSE&G’s motion to dismiss, and the plaintiff/petitioner subsequently appealed this dismissal to the Appellate Division. In June 2012, the Appellate Division affirmed the BPU’s decision, concluding that the BPU had correctly found that the plaintiff’s claims failed as a matter of law. The petitioner has filed a Notice of Petition for Certification with the New Jersey Supreme Court.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey EDC 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 current liability of $138 million as of June 30, 2012. The liability is reduced as normal payments are made. 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 Societal Benefits Charge (SBC).

The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. The proceeding has no impact on current SBC assessments.

Long-Term Capacity Agreement Pilot Program (LCAPP)

In 2011, New Jersey enacted the LCAPP Act that resulted in the selection of three generators to build a total of approximately 2,000 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the three selected generators, but did so under protest preserving their legal rights. The SOCA provides for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement. The BPU has publicly released these guaranteed capacity prices for two of the three generators. The remaining generator has challenged the release of its guaranteed capacity price in state court. Legal challenges to the BPU’s implementation of the LCAPP Act were filed in New Jersey appellate

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

court and the challenge filed by the EDCs has been remanded back to the BPU for consideration of certain procedural issues. In addition, the LCAPP Act has been challenged on constitutional grounds in federal court, and this case is pending.

In May 2012, two of the three generators cleared the RPM auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300 MW of installed capacity. SOCA payments are for a 15 year term, which are scheduled to commence for one of the generators in the 2015/2016 delivery year and for the other generator in the 2016/2017 delivery year. Under current accounting guidance, the estimated fair value of the SOCAs is recorded as a derivative asset or liability with an offsetting Regulatory Asset or Liability on PSE&G’s Condensed Consolidated Balance Sheets. See Note 11. Fair Value Measurements for additional information.

Leveraged Lease Investments

On January 31, 2012, PSEG entered into a specific matter closing agreement settling the dispute with the IRS over previously challenged leveraged lease transactions. This agreement settles the leasing dispute with finality for all tax periods in which PSEG realized tax deductions from these transactions. On January 31, 2012, PSEG also signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements conclude ten years of audits for PSEG and the leasing issue for all tax years. For PSEG, the impact of these agreements is an increase in financial statement Income Tax Expense of approximately $175 million. In prior periods, PSEG had established financial statement tax liabilities for uncertain tax positions in the amount of $245 million with respect to these tax years. Accordingly, the settlement resulted in a net $70 million decrease in the Income Tax Expense of PSEG.

Cash Impact

For tax years 1997 through 2003, the tax and interest PSEG owes the IRS as a result of this settlement will be reduced by the $320 million PSEG has on deposit with the IRS for this matter. PSEG paid a net deficiency for these years of approximately $4 million during the second quarter 2012. Based upon the closing agreement and the Form 870-AD for tax years 2004 through 2006, PSEG owes the IRS approximately $620 million in tax and interest for tax years from 2004 through 2006. Based on the settlement of the leasing dispute, for tax years 2007 through 2010, the IRS owes PSEG approximately $676 million. It is possible that PSEG would have to pay $620 million over the next year to the IRS and file claims for refunds for $676 million which the IRS would process in the normal course; it could take several years for the IRS to process these claims. In addition to the above, PSEG will claim a tax deduction for the accrued deficiency interest associated with this settlement in 2012, which will give rise to a cash tax savings of approximately $100 million.

Note 9. Changes in Capitalization

The following capital transactions occurred in the first six months of 2012:

Power

•

paid $66 million of 5.00% Pollution Control Revenue Refunding bond at maturity, and

•

paid cash dividends of $600 million to PSEG.

PSE&G

•

refinanced at par $50 million of 5.45% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due February 1, 2032, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds, with $50 million of weekly-reset variable rate demand bonds due April 1, 2046, which are serviced and secured by PSE&G’s First and Refunding Mortgage Bonds,

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

•

redeemed and retired at par $23 million of 5.20% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due March 1, 2025, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor,

•

issued $450 million of 3.95% Secured Medium-Term Notes, Series H due May 2042,

•

paid $96 million of Transition Funding’s securitization debt, and

•

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

Energy Holdings

•

released from $50 million of nonrecourse project debt related to the Dynegy Leases.

Note 10. 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.

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 (MTM) 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 and futures contracts to hedge

•

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

•

the price of fuel to meet its fuel purchase requirements, and

•

certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G.

These derivative transactions are designated and effective as cash flow hedges. During the second quarter of 2012, Power de-designated certain of its commodity derivative transactions that had previously qualified as cash flow hedges as they were deemed to no longer be highly effective as required by the relevant accounting guidance. As a result, subsequent to June 1, 2012, Power recognizes all gains and losses from changes in the fair value of these derivatives immediately in earnings rather than deferring any such amounts in Accumulated Other Comprehensive Income (Loss). The fair values of Power’s de-designated hedges were frozen in Accumulated Other Comprehensive Income (Loss) as the original forecasted transaction is still expected to occur and are reclassified into earnings as the original derivative transactions settle.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of June 30, 2012 and December 31, 2011, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows:


	As of June 30, 2012		As of December 31, 2011
	Millions
Fair Value of Cash Flow Hedges	$	5	$	57
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	23	$	33

The expiration date of the longest-dated cash flow hedge at Power is in 2014. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $19 million. There was no ineffectiveness associated with qualifying hedges as of June 30, 2012.

Trading Derivatives

The primary 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. Historically, Power engaged in trading of electricity and energy-related products where such transactions were not associated with the output or fuel purchase requirements of its facilities. This trading consisted mostly of energy supply contracts where Power secured sales commitments with the intent to supply the energy services from purchases in the market rather than from its owned generation. Such trading activities were marked to market through the income statement and represented less than one percent of gross margin (revenues less energy costs) on an annual basis. Effective July 2011, Power anticipates that it will not enter into any more trading derivative contracts.

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of our expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in fair market value of these contracts are recorded in earnings.

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 by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we have used a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of June 30, 2012, PSEG had eight interest rate swaps outstanding totaling $1.1 billion. These swaps convert Power’s $250 million of 5% Senior Notes due April 2014, Power’s $300 million of 5.5% Senior Notes due December 2015, $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 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. As of June 30, 2012 and December 31, 2011, the fair value of all the underlying hedges was $66 million and $62 million, respectively.

Cash Flow Hedges

PSEG uses 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. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(2) million as of June 30, 2012 and December 31, 2011.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Values of Derivative Instruments

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


	As of June 30, 2012
	Power											PSE&G			PSEG		Consolidated
	Cash Flow Hedges		Non Hedges									Non Hedges			Fair Value Hedges
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	$	5	$	480		$	(339	)	$	146		$	1		$	18	$	165
Noncurrent Assets		0		156			(116	)		40			45			48		133

Total Mark-to-Market Derivative Assets	$	5	$	636		$	(455	)	$	186		$	46		$	66	$	298

Derivative Contracts
Current Liabilities	$	0	$	(370	)	$	282		$	(88	)	$	0		$	0	$	(88	)
Noncurrent Liabilities		0		(108	)		100			(8	)		(104	)		0		(112	)

Total Mark-to-Market Derivative (Liabilities)	$	0	$	(478	)	$	382		$	(96	)	$	(104	)	$	0	$	(200	)

Total Net Mark-to-Market Derivative Assets (Liabilities)	$	5	$	158		$	(73	)	$	90		$	(58	)	$	66	$	98


	As of December 31, 2011
	Power												PSE&G			PSEG			Consolidated
	Cash Flow Hedges			Non Hedges									Non Hedges			Fair Value Hedges
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	$	55		$	532		$	(448	)	$	139		$	0		$	17		$	156
Noncurrent Assets		8			121			(74	)		55			4			47			106

Total Mark-to-Market Derivative Assets	$	63		$	653		$	(522	)	$	194		$	4		$	64		$	262

Derivative Contracts
Current Liabilities	$	(5	)	$	(506	)	$	387		$	(124	)	$	(7	)	$	0		$	(131	)
Noncurrent Liabilities		(1	)		(76	)		53			(24	)		0			(2	)		(26	)

Total Mark-to-Market Derivative (Liabilities)	$	(6	)	$	(582	)	$	440		$	(148	)	$	(7	)	$	(2	)	$	(157	)

Total Net Mark-to-Market Derivative Assets (Liabilities)	$	57		$	71		$	(82	)	$	46		$	(3	)	$	62		$	105

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(A)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. As of June 30, 2012 and December 31, 2011, net cash collateral received of $73 million and $82 million, respectively, was netted against the corresponding net derivative contract positions. Of the $73 million as of June 30, 2012, cash collateral of $(66) million and $(17) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $10 million was netted against current liabilities. Of the $82 million as of December 31, 2011, cash collateral of $(77) million and $(23) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $16 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

Certain of PSEG’s derivative instruments contain provisions that require PSEG to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PSEG’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if PSEG were to be downgraded or lose its investment grade credit rating, it would be required to provide additional collateral. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. PSEG also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was $209 million and $285 million as of June 30, 2012 and December 31, 2011, respectively. As of June 30, 2012 and December 31, 2011, PSEG had the contractual right of offset of $125 million and $149 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If PSEG had been downgraded or lost its investment grade rating, it would have had additional collateral obligations of $84 million and $136 million as of June 30, 2012 and December 31, 2011, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $705 million and $812 million as of June 30, 2012 and December 31, 2011, respectively, discussed in Note 8. Commitments and Contingent Liabilities.

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 three months ended June 30, 2012 and 2011:


Derivatives in 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,
	2012			2011				2012			2011				2012		2011
	Millions
PSEG (A)
Energy-Related Contracts	$	(8	)	$	(16	)	Operating Revenues	$	13		$	26		Operating Revenues	$	1	$	3
Energy-Related Contracts		0			(1	)	Energy Costs		(5	)		(1	)			0		0
Interest Rate Swaps		0			0		Interest Expense		(1	)		(1	)			0		0

Total PSEG	$	(8	)	$	(17	)		$	7		$	24			$	1	$	3

PSEG Power
Energy-Related Contracts	$	(8	)	$	(16	)	Operating Revenues	$	13		$	26		Operating Revenues	$	1	$	3
Energy-Related Contracts		0			(1	)	Energy Costs		(5	)		(1	)			0		0

Total Power	$	(8	)	$	(17	)		$	8		$	25			$	1	$	3

(A)	Includes amounts for PSEG parent.


Derivatives in 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,
	2012			2011				2012			2011				2012		2011
	Millions
PSEG (A)
Energy-Related Contracts	$	30		$	(3	)	Operating Revenues	$	52		$	92		Operating Revenues	$	0	$	1
Energy-Related Contracts		(4	)		1		Energy Costs		(9	)		2				0		0
Interest Rate Swaps		0			0		Interest Expense		(1	)		(1	)			0		0

Total PSEG	$	26		$	(2	)		$	42		$	93			$	0	$	1

PSEG Power
Energy-Related Contracts	$	30		$	(3	)	Operating Revenues	$	52		$	92		Operating Revenues	$	0	$	1
Energy-Related Contracts		(4	)		1		Energy Costs		(9	)		2				0		0

Total Power	$	26		$	(2	)		$	43		$	94			$	0	$	1

(A)	Includes amounts for PSEG parent.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, 2011	$	54		$	31
Gain Recognized in AOCI		34			20
Less: Gain Reclassified into Income		(35	)		(20	)

Balance as of March 31, 2012	$	53		$	31

Loss Recognized in AOCI		(8	)		(5	)
Less: Gain Reclassified into Income		(7	)		(5	)

Balance as of June 30, 2012	$	38		$	21

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, 2012 and 2011:


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,
		Three Months Ended June 30,					Six Months Ended June 30,
		2012		2011			2012			2011
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	40	$	0		$	235		$	(42	)
Energy-Related Contracts	Energy Costs		3		(2	)		(23	)		1

Total PSEG and Power		$	43	$	(2	)	$	212		$	(41	)

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas 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 was to reduce interest expense by $5 million and $7 million for the three month periods and $11 million and $13 million for the six month periods ended June 30, 2012 and 2011, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, 2012 and December 31, 2011:


Type	Notional	Total		PSEG		Power		PSE&G
	Millions
As of June 30, 2012
Natural Gas	Dth		720		0		507		213
Electricity	MWh		160		0		160		0
Capacity	MW days		4		0		0		4
FTRs	MWh		36		0		36		0
Interest Rate Swaps	US Dollars		1,100		1,100		0		0
Coal	Tons		1		0		1		0
As of December 31, 2011
Natural Gas	Dth		612		0		377		235
Electricity	MWh		137		0		137		0
FTRs	MWh		12		0		12		0
Interest Rate Swaps	US Dollars		1,100		1,100		0		0
Coal	Tons		1		0		1		0

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 and PSEG’s financial condition, results of operations or net cash flows.

As of June 30, 2012, 99% of the credit for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

The following table provides information on Power’s credit risk from others, net of cash collateral, as of June 30, 2012. 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 Power’s credit risk by credit rating of the counterparties.


Rating	Current Exposure		Securities held as Collateral		Net Exposure		Number of Counterparties >10%		Net Exposure of Counterparties >10%
	Millions								Millions
Investment Grade—External Rating	$	472	$	88	$	469		2	$	265	(A)
Non-Investment Grade—External Rating		2		0		2		0		0
Investment Grade—No External Rating		9		0		9		0		0
Non-Investment Grade—No External Rating		3		0		3		0		0

Total	$	486	$	88	$	483		2	$	265

(A)	Includes net exposure of $196 million with PSE&G. The remaining net exposure of $69 million is with one nonaffiliated power purchaser which is a regulated investment grade counterparty.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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, 2012, Power had 206 active counterparties.

Note 11. Fair Value Measurements

PSEG, Power and PSE&G adopted accounting standard “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)” effective January 1, 2012. This standard 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. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

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

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. As of June 30, 2012, these consist primarily of electric swaps whose basis is deemed significant to the fair value measurement, long-term electric capacity contracts and long-term gas supply contracts.

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 as of June 30, 2012 and December 31, 2011, 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, 2012
Description	Total			Cash Collateral Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
PSEG							Millions
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	232		$	(83	)	$	0	$	247		$	68
Interest Rate Swaps (B)	$	66		$	0		$	0	$	66		$	0
NDT Fund (C)
Equity Securities	$	728		$	0		$	728	$	0		$	0
Debt Securities—Govt Obligations	$	306		$	0		$	0	$	306		$	0
Debt Securities—Other	$	320		$	0		$	0	$	320		$	0
Other Securities	$	62		$	0		$	0	$	62		$	0
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	16		$	0		$	16	$	0		$	0
Debt Securities—Govt Obligations	$	116		$	0		$	0	$	116		$	0
Debt Securities—Other	$	44		$	0		$	0	$	44		$	0
Other Securities	$	3		$	0		$	0	$	3		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(200	)	$	10		$	0	$	(106	)	$	(104	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	186		$	(83	)	$	0	$	247		$	22
NDT Fund (C)
Equity Securities	$	728		$	0		$	728	$	0		$	0
Debt Securities—Govt Obligations	$	306		$	0		$	0	$	306		$	0
Debt Securities—Other	$	320		$	0		$	0	$	320		$	0
Other Securities	$	62		$	0		$	0	$	62		$	0
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	3		$	0		$	3	$	0		$	0
Debt Securities—Govt Obligations	$	23		$	0		$	0	$	23		$	0
Debt Securities—Other	$	8		$	0		$	0	$	8		$	0
Other Securities	$	1		$	0		$	0	$	1		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(96	)	$	10		$	0	$	(106	)	$	0
PSE&G
Assets:
Derivative Contracts:
Energy Related Contracts (A)	$	46		$	0		$	0	$	0		$	46
Rabbi Trust (C)
Equity Securities—Mutual Funds	$	5		$	0		$	5	$	0		$	0
Debt Securities—Govt Obligations	$	38		$	0		$	0	$	38		$	0
Debt Securities—Other	$	15		$	0		$	0	$	15		$	0
Other Securities	$	1		$	0		$	0	$	1		$	0
Liabilities:
Derivative Contracts:
Energy Related Contracts (A)	$	(104	)	$	0		$	0	$	0		$	(104	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Recurring Fair Value Measurements as of December 31, 2011
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)	$	198		$	(100	)	$	0	$	257		$	41
Interest Rate Swaps (B)	$	64		$	0		$	0	$	64		$	0
NDT Fund: (C)
Equity Securities	$	685		$	0		$	685	$	0		$	0
Debt Securities-Govt Obligations	$	359		$	0		$	0	$	359		$	0
Debt Securities-Other	$	281		$	0		$	0	$	281		$	0
Other Securities	$	24		$	0		$	0	$	24		$	0
Rabbi Trust—Mutual Funds (C)	$	172		$	0		$	19	$	153		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(155	)	$	18		$	0	$	(153	)	$	(20	)
Interest Rate Swaps (B)	$	(2	)	$	0		$	0	$	(2	)	$	0
Non-Recourse Debt (D)	$	(50	)	$	0		$	0	$	0		$	(50	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	194		$	(100	)	$	0	$	257		$	37
NDT Fund: (C)
Equity Securities	$	685		$	0		$	685	$	0		$	0
Debt Securities-Govt Obligations	$	359		$	0		$	0	$	359		$	0
Debt Securities-Other	$	281		$	0		$	0	$	281		$	0
Other Securities	$	24		$	0		$	0	$	24		$	0
Rabbi Trust—Mutual Funds (C)	$	33		$	0		$	4	$	29		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(148	)	$	18		$	0	$	(153	)	$	(13	)
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	4		$	0		$	0	$	0		$	4
Rabbi Trust—Mutual Funds (C)	$	57		$	0		$	6	$	51		$	0
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(7	)	$	0		$	0	$	0		$	(7	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(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 of the bid/ask midpoints 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 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 are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.

(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 fair value measurements table excludes cash of $1 million which is part of the NDT Fund as of June 30, 2012. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund 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). The Rabbi Trust equity index fund is valued based on quoted prices in an active market (Level 1).

Level 2—NDT and Rabbi Trust fixed income securities are limited to investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes, and issuer spreads (primarily Level 2). Short-term investments and certain commingled temporary 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).

(D)	For Non-Recourse Debt, see Fair Value Option below.

(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.

Additional Information Regarding Level 3 Measurements

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by PSEG Energy Resources & Trade LLC (ER&T)’s traders to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group, and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

Disclosed below is detail surrounding our significant Level 3 valuations, of which the most significant positions are electric swaps for Power and long-term electric capacity contracts and long-term natural gas supply contracts for PSE&G. For Power, in general, electric swaps are valued based on at least two pricing inputs, basis and underlying. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as Level 3. The remaining balance of Power’s Level 3 positions consist primarily of certain long-term electric capacity contracts and certain long-term natural gas supply contracts. Long-term electric capacity contracts are measured at fair value using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For Power and PSE&G, long-term gas supply contracts are measured at fair value using both actively traded pricing points as well as unobservable inputs such as gas prices beyond observable periods and long-term basis quotes and accordingly, the fair value measurements are classified in Level 3. For PSE&G, long-term electric capacity contracts are measured at fair value using both observable capacity prices and unobservable inputs consisting of forecasts of future long-term electric capacity prices and include adjustments for contingencies, such as litigation risk and plant construction risk. Accordingly, the fair value measurements are classified as Level 3.

The table below discloses the significant unobservable inputs used in developing the fair value of these Level 3 positions:


	Quantitative Information About Level 3 Fair Value Measurements
Commodity	Level 3 Position	Fair Value at June 30, 2012					Valuation Technique(s)	Significant Unobservable Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Swaps	$	18	$	1		Discounted cash flow	Power Basis	$0 -$10/MWh
Other	Various (A)		4		(1	)

Total Power		$	22	$	0

PSE&G
Gas and Capacity	Forward Contracts (B)	$	46	$	(104	)	Discounted cash flow	Long-Term Gas Basis and Capacity Prices	(B)

Total PSE&G		$	46	$	(104	)

TOTAL PSEG		$	68	$	(104	)

(A)	Includes long-term electric capacity and long-term gas supply positions which are immaterial.

(B)

Includes long-term gas supply and long-term electric capacity positions with various unobservable inputs. Significant unobservable inputs for the gas supply contracts include long-term basis prices in the range of $0 to $2/MMBTU of natural gas. Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of $100 to $400/MW day.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power and PSE&G are sellers, an increase in either the power basis or the load variability or the longer-term basis amounts would decrease the fair value. For long-term electric capacity contracts where Power or PSE&G are buyers, an increase in the capacity price would increase the fair value.

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and six months ended June 30, 2012 follows:

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

for the Three Months Ended June 30, 2012


				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2012			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		Issuances (Settlements) (D)			Transfers In (Out) (E)		Balance as of June 30, 2012
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	61		$	7	$	(90	)	$	0	$	(14	)	$	0	$	(36	)
Non-Recourse Debt	$	(50	)	$	50	$	0		$	0	$	0		$	0	$	0
Power
Net Derivative Assets (Liabilities)	$	29		$	7	$	0		$	0	$	(14	)	$	0	$	22
PSE&G
Net Derivative Assets (Liabilities)	$	32		$	0	$	(90	)	$	0	$	0		$	0	$	(58	)

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

for the Six Months Ended June 30, 2012


				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2012			Included in Income (F)		Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		Issuances (Settlements) (D)			Transfers In (Out) (E)		Balance as of June 30, 2012
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21		$	41	$	(55	)	$	0	$	(43	)	$	0	$	(36	)
Non-Recourse Debt	$	(50	)	$	50	$	0		$	0	$	0		$	0	$	0
Power
Net Derivative Assets (Liabilities)	$	24		$	41	$	0		$	0	$	(43	)	$	0	$	22
PSE&G
Net Derivative Assets (Liabilities)	$	(3	)	$	0	$	(55	)	$	0	$	0		$	0	$	(58	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and six months ended June 30, 2011 follows:

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

for the Three Months Ended June 30, 2011


				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2011			Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)		Purchases, (Sales) (C)		Issuances (Settlements) (D)			Transfers In (Out) (E)		Balance as of June 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	2		$	(9	)	$	6	$	1	$	(3	)	$	0	$	(3	)
Power
Net Derivative Assets (Liabilities)	$	7		$	(9	)	$	0	$	1	$	(3	)	$	0	$	(4	)
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	0		$	6	$	0	$	0		$	0	$	1

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

for the Six Months Ended June 30, 2011


			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2011		Included in Income (F)			Included in Regulatory Assets/ Liabilities (B)			Purchases, (Sales) (C)		Issuances (Settlements) (D)			Transfers In (Out) (E)			Balance as of June 30, 2011
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	47	$	(40	)	$	(4	)	$	19	$	(25	)	$	0		$	(3	)
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
Power
Net Derivative Assets (Liabilities)	$	42	$	(40	)	$	0		$	19	$	(25	)	$	0		$	(4	)
NDT Funds	$	8	$	0		$	0		$	0	$	0		$	(8	)	$	0
PSE&G
Net Derivative Assets (Liabilities)	$	5	$	0		$	(4	)	$	0	$	0		$	0		$	1

(A)

PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $7 million and $(7) million in Operating Income in 2012 and 2011 respectively; $(2) million in OCI and less than $1 million in Income from Discontinued Operations in 2011. Of the $7 million in Operating Income in 2012, $(7) million is unrealized. Of the $(7) million in Operating Income in 2011, $(24) million is unrealized. Energy Holdings’ release from its obligations under the non-recourse debt is included in PSEG’s Operating Income and is offset by the write-off of the related assets.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(C)	Includes none in purchases and sales in 2012. Includes $37 million in purchases and $(36) million in sales for the three months ended June 30, 2011. Includes $55 million in purchases and $(36) in sales for the six months ended June 30, 2011.

(D)

Includes $0 million and $(9) million in issuances and $(14) million and $6 million in settlements for the three months ended June 30, 2012 and 2011, respectively. Includes $0 million and $(20) million in issuances and $(43) million and $(5) million in settlements for the six months ended June 30, 2012 and 2011, respectively.

(E)

There were no transfers among levels during the three months ended June 30, 2012 and 2011 and the six months ended June 30, 2012. During the six months ended June 30, 2011, $8 million of assets in the NDT fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. The transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred), as per PSEG’s policy.

(F)

PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $41 million and $(40) million in Operating Income in 2012 and 2011, respectively; $(3) million in OCI and $3 million in Income from Discontinued Operations in 2011. Of the $41 million in Operating Income in 2012, $(2) million is unrealized. Of the $(40) million in Operating Income in 2011, $(56) million is unrealized. Energy Holdings’ release from its obligations under the non-recourse debt is included in PSEG’s Operating Income and is offset by the write-off of the related assets.

As of June 30, 2012, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $(36) 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.

As of June 30, 2011, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $(3) 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.

Fair Value Option

As of December 31, 2011, the effective date of the Dynegy lease rejections, the leases of the Roseton and Danskammer generation facilities were effectively terminated and no longer qualified for leveraged lease accounting under the guidance for leases. As the owner of the facilities, Energy Holdings was required to recognize the underlying assets and nonrecourse notes payable (Notes Payable) associated with these leases at their respective fair values on the effective date of the rejection. Energy Holdings has elected to record the Notes Payable at fair value each reporting period under the fair value option in accordance with guidance for Financial Instruments. The fair value option permits the irrevocable fair value election for selected eligible financial assets or liabilities. Any changes in the fair value of the Notes Payable will be included in earnings each period. The $550 million of contractual principal outstanding on the Notes Payable is valued at $50 million as of December 31, 2011. Energy Holdings elected this option to eliminate certain complexities in applying the effective interest method of amortization given the uncertain payment streams between the election date and the expected foreclosure date. There were no other debt instruments of this type eligible for the fair value option as of December 31, 2011. The $50 million fair value of these Notes Payable is included on PSEG’s Condensed Consolidated Balance Sheet as of December 31, 2011. The fair values of the Notes Payable include significant internal assumptions based on expected cash flows and the fair values of the underlying collateral. Changes to projected capacity factors, capacity and energy prices, fuel costs and other required cash outflows could significantly impact the fair value of the collateral which would increase or decrease the fair value of the Notes. These Notes Payable are classified as Level 3 in the fair value hierarchy as a result of mainly unobservable inputs. As of the June 5, 2012 effective date of the amended settlement agreement, the Notes Payable and related assets were written off.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of June 30, 2012 and December 31, 2011.


	June 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	44	$	66	$	39	$	62
Power -Recourse Debt (B)		2,686		3,112		2,751		3,158
PSE&G (B)		4,696		5,206		4,270		4,905
Transition Funding (PSE&G) (B)		799		896		895		1,016
Transition Funding II (PSE&G) (B)		38		41		44		47
Energy Holdings:
Project Level, Non-Recourse Debt (C)		45		45		95		95

Total Long-Term Debt	$	8,308	$	9,366	$	8,094	$	9,283

(A)	Fair value represents net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power and the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(B)

The debt fair valuation is based on the present value of each bond’s future cash flows. The discount rates used in the present value analysis are based on an estimate of new issue bond yields across the treasury curve. When a bond has embedded options, an interest rate model is used to reflect the impact of interest rate volatility into the analysis (primarily Level 2 measurements).

(C)

Fair value amounts as of December 31, 2011 include $50 million of non-recourse project debt related to Dynegy which is classified as a Level 3 measurement. See “Fair Value Option” above for more details on Dynegy debt. Non-recourse project debt of $45 million is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 12. Other Income and Deductions


Other Income	Power		PSE&G		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2012
NDT Fund Gains, Interest, Dividend and Other Income	$	36	$	0	$	0	$	36
Solar Loan Interest		0		4		0		4
Other		1		8		2		11

Total Other Income	$	37	$	12	$	2	$	51

Three Months Ended June 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	48	$	0	$	0	$	48
Solar Loan Interest		0		2		0		2
Other		1		2		2		5

Total Other Income	$	49	$	4	$	2	$	55

Six Months Ended June 30, 2012
NDT Fund Gains, Interest, Dividend and Other Income	$	64	$	0	$	0	$	64
Solar Loan Interest		0		8		0		8
Other		3		15		5		23

Total Other Income	$	67	$	23	$	5	$	95

Six Months Ended June 30, 2011
NDT Fund Gains, Interest, Dividend and Other Income	$	117	$	0	$	0	$	117
Solar Loan Interest		0		4		0		4
Other		2		5		3		10

Total Other Income	$	119	$	9	$	3	$	131

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


Other Deductions	Power		PSE&G		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2012
NDT Fund Realized Losses and Expenses	$	17	$	0	$	0	$	17
Other		0		1		1		2

Total Other Deductions	$	17	$	1	$	1	$	19

Three Months Ended June 30, 2011
NDT Fund Realized Losses and Expenses	$	13	$	0	$	0	$	13
Other		1		0		1		2

Total Other Deductions	$	14	$	0	$	1	$	15

Six Months Ended June 30, 2012
NDT Fund Realized Losses and Expenses	$	25	$	0	$	0	$	25
Other		7		2		1		10

Total Other Deductions	$	32	$	2	$	1	$	35

Six Months Ended June 30, 2011
NDT Fund Realized Losses and Expenses	$	22	$	0	$	0	$	22
Other		4		1		1		6

Total Other Deductions	$	26	$	1	$	1	$	28

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

Note 13. Income Taxes

PSEG’s, Power’s and PSE&G’s effective tax rates for the three months and six months ended June 30, 2012 and 2011 were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
PSEG		40.9%		41.5%		33.7%		41.6%
Power		41.2%		41.1%		40.3%		41.2%
PSE&G		38.4%		41.0%		32.7%		40.7%

For the three months ended June 30, 2012, the decrease in PSE&G’s effective tax rate was due primarily to tax benefits from PSE&G’s increased write-offs of uncollectible accounts.

For the six months ended June 30, 2012, the decrease in PSEG’s and PSE&G’s effective tax rate was due primarily to the settlement with the IRS in regard to leveraged leases (See Note 8. Commitments and Contingent Liabilities) and the federal audits for tax years 1997 through 2006 (see below). The decrease in Power’s effective tax rate was due primarily to a reduction in NDT taxes which was partially offset by a reduction in the IRC section 199 deduction for domestic production activities.

The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, enacted December 17, 2010, included a provision making qualified property placed into service after September 8, 2010 and before January 1, 2012, eligible for 100% bonus depreciation for tax purposes. In addition, qualified

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

property placed into service in 2012 will be eligible for 50% bonus depreciation for tax purposes. These provisions have generated cash for PSEG through tax benefits related to the accelerated depreciation in 2011 and will for 2012. These tax benefits would have otherwise been received over an estimated average 20 year period.

PSE&G has accrued $11 million of Investment Tax Credits (ITC) associated with alternative energy projects in the first six months of 2012. Prior to 2012, the law provided an option to claim either a grant or the ITC. For years prior to 2012, the ITC had been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense. As the grant program expired at the end of 2011, ITC for 2012 has been accounted for as an accumulated deferred investment credit on the balance sheet which is amortized as a reduction of tax expense over the life of the related project.

PSEG’s unrecognized tax benefits decreased by approximately $546 million through the first half of 2012, primarily attributable to PSEG. This decrease was primarily due to the settlement with the IRS, in the amount of $387 million, of the leasing issue (See Note 8. Commitments and Contingent Liabilities) and the federal audits for tax years 1997 through 2006 (see below). The remaining unrecognized tax benefit of $159 million represents a decrease of prior period positions. As a result, as of June 30, 2012, there is no material increase or decrease in unrecognized tax benefits that is reasonably possible to occur within the next twelve months. The interest and penalties associated with the decrease in the uncertain tax position was $356 million. The impact on the accumulated deferred income taxes and regulatory asset associated with the unrecognized tax benefit decrease is $228 million. The change in the total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $318 million.

On June 26, 2009, September 15, 2008 and December 17, 2007, PSEG made tax deposits with the IRS in the amounts of $140 million, $80 million and $100 million, respectively, to defray potential interest costs associated with disputed tax assessments associated with certain lease investments (see Note 8. Commitments and Contingent Liabilities). On January 31, 2012, PSEG signed a specific matter closing agreement with the IRS regarding this matter. Based on this agreement, these deposits will be applied against tax and interest due pursuant to the closing agreement. Further, on the same date, PSEG signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements conclude ten years of audits for PSEG and the leasing issue for all tax years. The financial statement impacts of these agreements, net of existing financial statement reserves, is a net decrease in tax expense of approximately $70 million for PSEG, including $30 million and $1 million for PSE&G and Power, respectively.

Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax


	Balance as of December 31, 2011			Other Comprehensive Income (Loss) Six Months Ended June 30, 2012								Balance as of June 30, 2012
	Balance as of December 31, 2011			Power			PSE&G			Other		Balance as of June 30, 2012
	Millions
Derivative Contracts	$	31		$	(10	)	$	0		$	0	$	21
Pension and OPEB Plans		(438	)		14			0			1		(423	)
NDT Funds		66			22			0			0		88
Other		4			0			(1	)		1		4

Accumulated Other Comprehensive Income (Loss)	$	(337	)	$	26		$	(1	)	$	2	$	(310	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Balance as of December 31, 2010			Other Comprehensive Income (Loss) Six Months Ended June 30, 2011							Balance as of June 30, 2011
	Balance as of December 31, 2010			Power			PSE&G		Other		Balance as of June 30, 2011
	Millions
Derivative Contracts	$	111		$	(57	)	$	0	$	0	$	54
Pension and OPEB Plans		(377	)		42			0		7		(328	)
NDT Fund		109			(17	)		0		0		92
Other		1			0			1		1		3

Accumulated Other Comprehensive Income (Loss)	$	(156	)	$	(32	)	$	1	$	8	$	(179	)

Note 15. Earnings Per Share (EPS) and Dividends

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,
	2012				2011				2012				2011
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Continuing Operations	$	211	$	211	$	320	$	320	$	704	$	704	$	782	$	782
Discontinued Operations		0		0		3		3		0		0		67		67

Net Income	$	211	$	211	$	323	$	323	$	704	$	704	$	849	$	849

EPS Denominator (Thousands)
Weighted Average Common Shares Outstanding		505,903		505,903		505,988		505,988		505,956		505,956		505,984		505,984
Effect of Stock Based Compensation Awards		0		1,066		0		773		0		1,043		0		961

Total Shares		505,903		506,969		505,988		506,761		505,956		506,999		505,984		506,945

EPS
Continuing Operations	$	0.42	$	0.42	$	0.63	$	0.63	$	1.39	$	1.39	$	1.55	$	1.54
Discontinued Operations		0.00		0.00		0.00		0.00		0.00		0.00		0.13		0.13

Net Income	$	0.42	$	0.42	$	0.63	$	0.63	$	1.39	$	1.39	$	1.68	$	1.67


	Three Months Ended June 30,				Six Months Ended June 30,
Dividend Payments on Common Stock	2012		2011		2012		2011
Per Share	$	0.3550	$	0.3425	$	0.7100	$	0.6850
in Millions	$	180	$	173	$	359	$	347

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 16. Financial Information by Business Segments


	Power		PSE&G		Energy Holdings		Other (A)			Consolidated
	Millions
Three Months Ended June 30, 2012
Total Operating Revenues	$	985	$	1,407	$	14	$	(308	)	$	2,098
Income (Loss) From Continuing Operations		104		101		2		4			211
Net Income (Loss)		104		101		2		4			211
Segment Earnings (Loss)		104		101		2		4			211
Gross Additions to Long-Lived Assets		107		435		44		7			593
Three Months Ended June 30, 2011
Total Operating Revenues	$	1,285	$	1,571	$	21	$	(408	)	$	2,469
Income (Loss) From Continuing Operations		205		105		5		5			320
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		3		0		0		0			3
Net Income (Loss)		208		105		5		5			323
Segment Earnings (Loss)		208		105		5		5			323
Gross Additions to Long-Lived Assets		168		335		0		2			505
Six Months Ended June 30, 2012
Total Operating Revenues	$	2,546	$	3,346	$	34	$	(953	)	$	4,973
Income (Loss) From Continuing Operations		357		298		42		7			704
Net Income (Loss)		357		298		42		7			704
Segment Earnings (Loss)		357		298		42		7			704
Gross Additions to Long-Lived Assets		344		870		55		11			1,280
Six Months Ended June 30, 2011
Total Operating Revenues	$	3,252	$	3,877	$	41	$	(1,347	)	$	5,823
Income (Loss) From Continuing Operations		502		268		2		10			782
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax		67		0		0		0			67
Net Income (Loss)		569		268		2		10			849
Segment Earnings (Loss)		569		268		2		10			849
Gross Additions to Long-Lived Assets		323		674		1		4			1,002
As of June 30, 2012
Total Assets	$	10,749	$	17,863	$	1,953	$	(423	)	$	30,142
Investments in Equity Method Subsidiaries	$	41	$	0	$	103	$	0		$	144
As of December 31, 2011
Total Assets	$	11,087	$	17,487	$	1,888	$	(641	)	$	29,821
Investments in Equity Method Subsidiaries	$	31	$	0	$	106	$	0		$	137

(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 17. Related-Party Transactions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 17. 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	2012			2011			2012			2011
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)	$	112		$	169		$	563		$	867
Billings to PSE&G through BGS (A)		192			229			381			462

Total Revenue from Affiliates	$	304		$	398		$	944		$	1,329

Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(38	)	$	(35	)	$	(72	)	$	(72	)

Total Expense Billings from Affiliates	$	(38	)	$	(35	)	$	(72	)	$	(72	)


Related Party Transactions	As of June 30, 2012			As of December 31, 2011
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	102		$	247
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)		66			109
Receivable from (Payable to) Services (B)		(24	)		(26	)
Tax Receivable from (Payable to) PSEG (C)		121			58
Receivable from (Payable to) PSEG		0			(7	)

Accounts Receivable—Affiliated Companies, net	$	265		$	381

Short-Term Loan to Affiliate (Demand Note to PSEG) (D)	$	737		$	907

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

Long-Term Accrued Taxes Receivable (Payable) (C)	$	(53	)	$	(8	)

PSE&G

The financial 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	2012			2011			2012			2011
	Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A)	$	(112	)	$	(169	)	$	(563	)	$	(867	)
Billings from Power through BGS (A)		(192	)		(229	)		(381	)		(462	)
Administrative Billings from Services (B)		(57	)		(50	)		(107	)		(101	)

Total Expense Billings from Affiliates	$	(361	)	$	(448	)	$	(1,051	)	$	(1,430	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


Related Party Transactions	As of June 30, 2012			As of December 31, 2011
	Millions
Payable to Power through BGS and BGSS Contracts (A)	$	(102	)	$	(247	)
Payable to Power Related to Gas Supply Hedges for BGSS (A)		(66	)		(109	)
Payable to Power for SREC Liability (F)		(7	)		(7	)
Receivable from (Payable to) Services (B)		(47	)		(56	)
Tax Receivable from (Payable to) PSEG (C)		72			131
Receivable from PSEG		3			8
Receivable from Energy Holdings		1			0

Accounts Payable—Affiliated Companies, net	$	(146	)	$	(280	)

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

Long-Term Accrued Taxes Payable (C)	$	(18	)	$	(83	)

(A)

PSE&G has entered into a requirements contract with Power under which Power provided the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 31, 2012 and continues on a year-to-year basis 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.

(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.

(D)	Power’s short-term loans with PSEG 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 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. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU’s 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court’s ruling. On May 1, 2012, the BPU affirmed its earlier order and ruled that BGS suppliers could recover verified SREC expenditures above $300 per SREC. The BPU further directed the state’s Electric Distribution Companies (EDCs), including PSE&G, to file by July 1, 2012 a proposed rate recovery mechanism and a method for BGS suppliers to demonstrate that any incremental costs were reasonably and prudently incurred. The BPU has not yet acted on the EDCs’ joint proposal, which was filed on June 26, 2012. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of June 30, 2012 and December 31, 2011, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies as of June 30, 2012 and December 31, 2011. Under current guidance, Power was 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, 2012 and December 31, 2011.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 18. 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 its subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and ER&T. The following table presents condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries.


	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Three Months Ended June 30, 2012
Operating Revenues	$	0		$	1,329		$	31		$	(375	)	$	985
Operating Expenses		2			1,135			28			(376	)		789

Operating Income (Loss)		(2	)		194			3			1			196
Equity Earnings (Losses) of Subsidiaries		116			(1	)		0			(115	)		0
Other Income		11			39			0			(13	)		37
Other Deductions		0			(17	)		0			0			(17	)
Other-Than-Temporary Impairments		0			(7	)		0			0			(7	)
Interest Expense		(31	)		(10	)		(4	)		13			(32	)
Income Tax Benefit (Expense)		10			(82	)		0			(1	)		(73	)

Net Income (Loss)	$	104		$	116		$	(1	)	$	(115	)	$	104

Comprehensive Income (Loss)	$	86		$	91		$	(1	)	$	(90	)	$	86

Three Months Ended June 30, 2011
Operating Revenues	$	0		$	1,619		$	27		$	(361	)	$	1,285
Operating Expenses		(1	)		1,263			28			(360	)		930

Operating Income (Loss)		1			356			(1	)		(1	)		355
Equity Earnings (Losses) of Subsidiaries		220			0			0			(220	)		0
Other Income		9			50			0			(10	)		49
Other Deductions		0			(14	)		0			0			(14	)
Other-Than-Temporary Impairments		0			(1	)		0			0			(1	)
Interest Expense		(36	)		(11	)		(4	)		10			(41	)
Income Tax Benefit (Expense)		14			(160	)		2			1			(143	)
Income (Loss) on Discontinued Operations, net of tax		0			0			3			0			3

Net Income (Loss)	$	208		$	220		$	0		$	(220	)	$	208

Comprehensive Income (Loss)	$	209		$	185		$	0		$	(185	)	$	209

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Six Months Ended June 30, 2012
Operating Revenues	$	0		$	3,202		$	57		$	(713	)	$	2,546
Operating Expenses		0			2,568			55			(714	)		1,909

Operating Income (Loss)		0			634			2			1			637
Equity Earnings (Losses) of Subsidiaries		376			(4	)		0			(372	)		0
Other Income		24			70			0			(27	)		67
Other Deductions		(7	)		(25	)		0			0			(32	)
Other-Than-Temporary Impairments		0			(12	)		0			0			(12	)
Interest Expense		(60	)		(20	)		(8	)		26			(62	)
Income Tax Benefit (Expense)		24			(267	)		2			0			(241	)

Net Income (Loss)	$	357		$	376		$	(4	)	$	(372	)	$	357

Comprehensive Income (Loss)	$	383		$	388		$	(4	)	$	(384	)	$	383

Six Months Ended June 30, 2012
Net Cash Provided By (Used In) Operating Activities	$	301		$	902		$	3		$	(354	)	$	852
Net Cash Provided By (Used In) Investing Activities	$	365		$	(601	)	$	(23	)	$	70		$	(189	)
Net Cash Provided By (Used In) Financing Activities	$	(666	)	$	(310	)	$	19		$	284		$	(673	)
Six Months Ended June 30, 2011
Operating Revenues	$	0		$	3,897		$	77		$	(722	)	$	3,252
Operating Expenses		1			3,037			80			(722	)		2,396

Operating Income (Loss)		(1	)		860			(3	)		0			856
Equity Earnings (Losses) of Subsidiaries		602			59			0			(661	)		0
Other Income		19			121			0			(21	)		119
Other Deductions		(3	)		(23	)		0			0			(26	)
Other-Than-Temporary Impairments		(1	)		(2	)		0			0			(3	)
Interest Expense		(82	)		(21	)		(10	)		21			(92	)
Income Tax Benefit (Expense)		35			(392	)		5			0			(352	)
Income (Loss) on Discontinued Operations, net of tax		0			0			67			0			67

Net Income (Loss)	$	569		$	602		$	59		$	(661	)	$	569

Comprehensive Income (Loss)	$	537		$	528		$	59		$	(587	)	$	537

Six Months Ended June 30, 2011
Net Cash Provided By (Used In) Operating Activities	$	367		$	1,400		$	(148	)	$	(473	)	$	1,146
Net Cash Provided By (Used In) Investing Activities	$	589		$	(674	)	$	317		$	(413	)	$	(181	)
Net Cash Provided By (Used In) Financing Activities	$	(956	)	$	(725	)	$	(168	)	$	887		$	(962	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated
	Millions
As of June 30, 2012
Current Assets	$	4,071	$	7,718	$	906	$	(10,401	)	$	2,294
Property, Plant and Equipment, net		71		5,765		957		0			6,793
Investment in Subsidiaries		4,124		740		0		(4,864	)		0
Noncurrent Assets		189		1,534		62		(123	)		1,662

Total Assets	$	8,455	$	15,757	$	1,925	$	(15,388	)	$	10,749

Current Liabilities	$	385	$	9,896	$	1,011	$	(10,402	)	$	890
Noncurrent Liabilities		458		1,737		173		(122	)		2,246
Long-Term Debt		2,386		0		0		0			2,386
Member’s Equity		5,226		4,124		741		(4,864	)		5,227

Total Liabilities and Member’s Equity	$	8,455	$	15,757	$	1,925	$	(15,388	)	$	10,749


As of December 31, 2011
Current Assets	$	4,311	$	7,248	$	951	$	(9,823	)	$	2,687
Property, Plant and Equipment, net		66		5,715		950		0			6,731
Investment in Subsidiaries		4,185		804		0		(4,989	)		0
Noncurrent Assets		179		1,557		51		(118	)		1,669

Total Assets	$	8,741	$	15,324	$	1,952	$	(14,930	)	$	11,087

Current Liabilities	$	172	$	9,549	$	1,003	$	(9,822	)	$	902
Noncurrent Liabilities		440		1,589		145		(118	)		2,056
Long-Term Debt		2,685		0		0		0			2,685
Member’s Equity		5,444		4,186		804		(4,990	)		5,444

Total Liabilities and Member’s Equity	$	8,741	$	15,324	$	1,952	$	(14,930	)	$	11,087

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 United States,

•

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 2011 Annual Report on 10-K (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, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part II Item 1A of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Overview of 2011 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2012 and any changes to the key factors that we expect may 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 discussion should be read in conjunction with such Statements, Notes, the 2011 Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

OVERVIEW OF 2012 AND FUTURE OUTLOOK

During the first half of 2012, our results continued to be adversely impacted by lower prices for electricity and natural gas in the markets we serve. Our pricing also continues to be affected by customer migration away from our BGS supply contracts as these volumes are replaced with lower priced spot market sales. While the average BGS rates have been declining based on recent market prices, customers may still see an incentive to switch to third party suppliers. The result of such a switch may affect the price we receive on our sales, shifting from BGS rates that were established in auctions that had taken place over the past three years, to prices offered by third party suppliers which may be more representative of recent market pricing.

Partially offsetting this lower commodity pricing are higher transmission revenues as a result of our 2012 Annual Formula Rate Update with the Federal Energy Regulatory Commission (FERC), which provides for approximately $94 million in increased annual transmission revenues effective January 1, 2012.

Under the most recent auction in May 2012, for the 2015-2016 period, Power cleared approximately 9,000 MW of its generating capacity at an average price of $167 per MW-day.

Our volumes of gas sales were lower in the first half of 2012, but the decline in gas revenues was significantly mitigated by the favorable impact of a $51 million increase due to recovery of deficiency revenues through the Weather Normalization Charge (WNC). PSE&G’s WNC is a rate mechanism that allows us to increase our rates to compensate for lower revenues we receive from customers as a result of warmer-than-normal winters and to decrease our rates to make up for higher revenues we receive as a result of colder-than-normal winters.

For 2012 and beyond, the key issues we expect our business to confront include:

•

the continuing potential for sustained lower natural gas and electricity prices, both at market hubs and at locations where we operate,

•

uncertainty in the national and regional economic recovery, which impacts customer demand,

•

regulatory and political uncertainty, particularly with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, and

•

challenges to competitive markets, including support for subsidized generation in many states, particularly in New Jersey.

Our future success will depend on our ability to respond to these challenges and take advantage of opportunities presented by these and other regulatory and legislative initiatives. In order to do this, we must:

•

continue to focus on controlling costs while maintaining our safety, reliability and compliance standards,

•

successfully recontract our open supply positions, and

•

execute our capital investment program, including investments for growth that yield contemporaneous and attractive risk adjusted returns.

There have also been certain significant regulatory and legislative developments during the year which may affect our operations in the future as new rules and regulations are adopted. For additional information on these issues, see Item 5. Other Information.

•

On April 12, 2012, the Maryland Public Utility Commission (PUC) issued an order requiring three of the four Maryland utility companies to enter into contracts with CPV Shore, LLC (CPV) to construct a new 661 MW natural gas-fired, combined cycle station in Maryland with an in-service date of June 2015. CPV cleared the May 2012 Reliability Pricing Model (RPM) auction. These developments in Maryland may stimulate construction of subsidized generation and impact energy and capacity prices in PJM. Power has joined other generators in challenging the constitutionality of this order in federal court. In addition, the Maryland electric distribution companies have appealed the PUC’s order in state court. Both proceedings are pending.

New Jersey’s Long-Term Capacity Agreement Pilot Program Act (LCAPP Act), Maryland’s Request for Proposal or similar activity in other states may artificially depress prices in the competitive wholesale market and have the potential to harm competitive markets and adversely impact our generation business, on both a short-term and long-term basis.

•

FERC Final Rule 1000 (Order 1000), issued in July 2011, among other things directs regional planners such as PJM to (i) be more flexible in how they plan for future transmission build (ii) eliminate any Right of First Refusal, which permits incumbent transmission owners, like us, the first opportunity to construct transmission within their respective service territories, subject to certain exceptions, and (iii) allocate costs for transmission projects in a way that roughly matches costs with benefits, while leaving flexibility to the regions to determine precise cost allocation methodologies. In June 2012, PSEG appealed this Order in federal court. Other companies and state commissions have filed appeals as well. PJM is currently conducting a stakeholder process to develop implementing details regarding Order 1000. An expected outcome of this process is the construction of more transmission and the opening up of transmission construction and ownership to third-party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 in the various regions, including within our service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.

•

On March 30, 2012, the FERC issued an order finding that allocation of costs associated with high voltage (500 kV and higher) transmission projects in PJM to all customers in PJM is just and reasonable. This order, which has been challenged on rehearing, therefore preserves the current cost allocation for the Susquehanna-Roseland project. However, the FERC also stated in its order that other cost allocation methodologies could be just and reasonable and this may lead to the adoption of a different cost allocation methodology for transmission in PJM in the future.

•

During 2012, the SEC and the Commodity Futures Trading Commission (CFTC) continued efforts to enact stricter regulation over swaps and derivatives. The CFTC has issued Notices of Proposed Rulemakings on many of the key issues and is in the process of issuing Final Rules on these issues. In May 2012, the CFTC issued a Final Rule regarding the definition of a swap dealer and, in July 2012, the CFTC voted to issue a Final Rule regarding the definition of a swap, but this rule has yet to be published. We are carefully monitoring these new rules as they are issued to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements.

Operational Excellence

Our nuclear and fossil facilities continued their strong operating performance through the first six months of 2012. Our nuclear units have achieved a capacity factor of 92.7% and our combined cycle units have continued to improve their forced outage rates. Overall, generation volumes for the first half of 2012 were 25.8 TWh, approximately 5% lower than in 2011 due primarily to reduced demands due to milder weather in 2012.

In the second quarter of 2012, we received the final approvals for the 10-year contract that we won in December 2011 to manage Long Island Power Authority’s electric transmission and distribution system in Long Island, New York. The contract, which commences January 1, 2014, represents an opportunity to improve returns and is recognition of our history of strong reliability and customer satisfaction.

Financial Strength

Our cash from operations has remained strong. During the first six months of 2012, we made approximately $1.3 billion in capital expenditures, paid dividends of $359 million and made our entire planned pension and other postretirement employee benefit contributions for the year 2012 of $135 million.

In March 2012, Power’s $1.525 billion and PSEG’s $477 million credit facilities that were set to expire in December 2012 were replaced with $1.6 billion and $500 million credit facilities, respectively, expiring in March 2017. As of June 30, 2012, our total credit capacity was $4.3 billion and we had over $750 million of cash on hand.

On January 31, 2012, we entered into a specific matter closing agreement settling our dispute with the IRS over certain lease transactions. This agreement settles the international leveraged lease dispute with finality for all tax periods in which we realized tax deductions from these transactions. Also on January 31, 2012, we signed a settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, we executed a formal settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements conclude 10 years of audits for us and the leasing issue for all tax years.

Disciplined Investment

We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include upgrading critical energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. We also have several projects where we are investing to continue to improve our operational performance. Over the past few years, we have shifted our focus to investing at the utility. Our capital expenditure forecast includes over $6.7 billion in spending over the next three years, over 75% of which is at PSE&G.

•

We are continuing to pursue obtaining the necessary regulatory approvals for the Susquehanna-Roseland transmission project including approval from the National Park Service (NPS), which has resulted in a delay to the project implementation date. In March 2012, the NPS identified a “preferred alternative” for the final form of its Draft Environmental Impact Statement (EIS), under which the project would follow the route of the existing transmission line. This route was the one approved by state regulators including the BPU. The final EIS is expected to be issued in October 2012. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. The cost of construction is up to an estimated $790 million for this project. As of June 30, 2012, total capital expenditures were $217 million.

•

We are continuing the process of obtaining regulatory approvals for the North East Grid project, a 230 kV project running from Roseland to Hudson with an expected in-service date of June 2015 and an estimated cost of construction of $895 million. In June 2012, we obtained the major regulatory approvals for another 230 kV project, the North-Central Reliability project, located in the northern and central portions of New Jersey with an expected in-service date of June 2014 and an estimated cost of construction of up to $390 million. Construction of this project has commenced.

•

We have made additional investments in solar power in New Jersey. Under our solar loan program we have provided a total of $177 million in loans for 721 projects as of June 30, 2012, representing 55 MW to date. Under our Solar 4 All program, we have made total program expenditures of approximately $401 million as of June 30, 2012. Approximately 30 MW of solar panels have been installed on distribution poles and another 36 MW representing 20 projects have been placed into service. Additional projects are in various stages of development. Our total anticipated expenditures to develop all approved 80 MW are approximately $456 million. The BPU has concluded a generic stakeholder proceeding to examine whether utility rate-based solar programs should be modified, expanded or terminated in the future, and has determined that utility rate-based solar programs should be continued under defined scope and size parameters.

On July 23, 2012, the Governor of New Jersey signed legislation that, among other things, requires energy providers, including BGS providers and third party suppliers, to increase the amount of power in their portfolios derived from solar electricity, increasing the demand for Solar Renewable Energy Credits and increasing the potential for additional utility solar generation investment.

On July 31, 2012, PSE&G filed for an extension of its Solar 4 All program. In this filing, PSE&G is seeking BPU approval for up to $690 million to develop 136 MW of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistent with the existing Solar 4 All program, PSE&G proposes to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets.

Also, consistent with the BPU’s generic proceeding on solar, PSE&G filed for an additional extension of our Solar Loan program (Solar Loan III) on July 31, 2012. In the filing, PSE&G is seeking BPU approval to provide financing support for the installation of 97 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, projects are built and loans are closed.

The estimated project costs included in the July 31, 2012 filings for extensions of our Solar 4 All and Solar Loan III programs are not included in our $6.7 billion three-year capital forecast.

•

Our Capital Infrastructure Program (CIP II) provides for approximately $273 million in accelerated capital investments in our electric and gas infrastructure through 2012. As of June 30, 2012, total capital expenditures since inception of this program were $177 million.

•

We made additional expenditures under our Energy Efficiency and Demand Response programs. As of June 30, 2012, total capital expenditures since inception of these projects were $147 million for Energy Efficiency Economic Stimulus (EEE), $2 million for EEE Extension and $43 million for Carbon Abatement and $23 million for Demand Response.

•

We continued various construction activities at Power, including a steam path retrofit and extended power uprate at Peach Bottom and we completed construction of new gas-fired peaking units at Kearny and in Connecticut (see Note 8. Commitments and Contingent Liabilities and Part II. Item 5. Other Information for additional information). This additional capacity at Kearny was bid into and has cleared the RPM capacity auction, and the additional capacity in Connecticut is subject to a contract with a Connecticut utility.

•

We are continuing our efforts to obtain an Early Site Permit for a new nuclear generating station to be located at the current site of Salem and Hope Creek stations. The Nuclear Regulatory Commission (NRC) acceptance review is complete and agency evaluation is underway. There were no petitions filed for permission to intervene. The current NRC schedule would likely result in issuance of the Early Site Permit in 2014.

•

In January 2012, we acquired an additional 25 MW solar project at Energy Holdings, currently under construction in Arizona. Completion of this project is expected in 2012. All of the energy, capacity and environmental attributes generated by the project in the first 20 years are expected to be sold under a long-term power purchase agreement. The total investment for the project will be approximately $75 million.

There is no guarantee that the projects described above or any future initiatives will be achieved since many issues need to be favorably resolved, such as regulatory approvals. Delays in the construction schedules of our projects could impact the timing of expected revenues.

RESULTS OF OPERATIONS

The results for PSEG, PSE&G, Power and Energy Holdings for the three months and six months ended June 30, 2012 and 2011 are presented below:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
Earnings (Losses)	2012		2011		2012		2011
		Millions
Power	$	104	$	205	$	357	$	502
PSE&G		101		105		298		268
Energy Holdings		2		5		42		2
Other (A)		4		5		7		10

PSEG Income from Continuing Operations		211		320		704		782
Income (Loss) from Discontinued Operations (B)		0		3		0		67

PSEG Net Income	$	211	$	323	$	704	$	849

Three Months Ended

Six Months Ended

June 30,

Earnings Per Share (Diluted)

2012

2011

2012

2011

PSEG Income from Continuing Operations

0.42

0.63

1.39

1.54

Income (Loss) from Discontinued Operations (B)

0.00

0.13

PSEG Net Income

0.42

0.63

1.39

1.67

(A)	Other primarily includes parent company interest and financing costs, donations and certain administrative and general expenses.

(B)	See Note 4. Discontinued Operations and Dispositions.

Our results include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity. This includes the net realized gains, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions. This also includes credit-related impairments on certain NDT securities which are included in Other-Than-Temporary Impairments and 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 asset.

Our results also include the after-tax impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with forward delivery dates.

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					Six Months Ended
	June 30,					June 30,
	2012			2011		2012		2011
		Millions, after tax
NDT Fund Income (Expense)	$	4		$	15	$	9	$	42
Non-Trading MTM Gains (Losses)	$	(10	)	$	4	$	42	$	8

In addition to the changes in NDT and MTM, our $109 million and $78 million decreases in Income from Continuing Operations for the three months and six months ended June 30, 2012, respectively, were driven primarily by:

•

lower average pricing and volumes for electricity sold under our BGS contracts,

•

lower realized prices and/or lower sales volumes in the various power pools, and

•

lower gas volumes and demand due to milder winter weather, partially offset by the WNC.

The decrease for the six months ended June 30, 2012 was partially offset by increased earnings from transmission and renewable investments at PSE&G and lower tax expense due to the settlement of 10 years of IRS audits.

PSEG

Our results of operations are primarily 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, charitable contributions and general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 17. 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)
	2012		2011		2012 vs 2011					2012		2011		2012 vs 2011
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	2,098	$	2,469	$	(371	)	(15	)	$	4,973	$	5,823	$	(850	)	(15	)
Energy Costs		761		1,010		(249	)	(25	)		1,940		2,573		(633	)	(25	)
Operation and Maintenance		629		575		54		9			1,257		1,226		31		3
Depreciation and Amortization		255		235		20		9			511		476		35		7
Taxes Other than Income Taxes		20		28		(8	)	(29	)		49		71		(22	)	(31	)
Income from Equity Method Investments		2		4		(2	)	(50	)		2		7		(5	)	(71	)
Other Income and (Deductions)		32		40		(8	)	(20	)		60		103		(43	)	(42	)
Other-Than-Temporary Impairments		7		1		6		N/A			12		5		7		N/A
Interest Expense		103		117		(14	)	(12	)		204		244		(40	)	(16	)
Income Tax Expense		146		227		(81	)	(36	)		358		556		(198	)	(36	)
Income (Loss) from Discontinued Operations		0		3		(3	)	N/A			0		67		(67	)	N/A

Power


	Three Months Ended June 30,				Increase/ (Decrease)			Six Months Ended June 30,				Increase/ (Decrease)
	2012		2011		2012 vs 2011			2012		2011		2012 vs 2011
		Millions
Income from Continuing Operations	$	104	$	205	$	(101	)	$	357	$	502	$	(145	)
Income (Loss) from Discontinued Operations, net of tax		0		3		(3	)		0		67		(67	)
Net Income	$	104	$	208	$	(104	)	$	357	$	569	$	(212	)

For the three months and six months ended June 30, 2012, the primary reasons for the $101 million and $145 million decreases in Income from Continuing Operations were

•

lower average prices realized on generation sold into the PJM and New York power pools,

•

lower average pricing and lower volumes of electricity sold under our BGS contracts, net of lower cost to serve,

•

lower volumes on wholesale load contracts in PJM, lower operating reserve, ancillary and Reliability Must Run (RMR) revenues primarily in PJM and New England,

•

lower average pricing and volumes of gas sold under our BGSS contracts, net of lower cost to serve, as a result of warmer winter weather in 2012,

•

higher operation and maintenance costs in 2012 at our nuclear plants, and

•

lower net realized gains on the NDT Fund.

These decreases were partially offset by

•

lower operation and maintenance costs in 2012 at our fossil plants, and

•

lower interest expense due to the maturity of Senior Notes in December 2011.

The decrease for the three months ended June 30, 2012 was also attributable to unfavorable MTM activity. The decrease for the six months ended June 30, 2012 was partially offset by favorable MTM activity and lower interest expense due to the early redemption of Senior Notes in April 2011.

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)
	2012		2011		2012 vs 2011					2012		2011		2012 vs 2011
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	985	$	1,285	$	(300	)	(23	)	$	2,546	$	3,252	$	(706	)	(22	)
Energy Costs		447		603		(156	)	(26	)		1,269		1,738		(469	)	(27	)
Operation and Maintenance		284		271		13		5			525		548		(23	)	(4	)
Depreciation and Amortization		58		56		2		4			115		110		5		5
Other Income (Deductions)		20		35		(15	)	(43	)		35		93		(58	)	(62	)
Other-Than-Temporary Impairments		7		1		6		N/A			12		3		9		N/A
Interest Expense		32		41		(9	)	(22	)		62		92		(30	)	(33	)
Income Tax Expense		73		143		(70	)	(49	)		241		352		(111	)	(32	)
Income (Loss) from Discontinued Operations		0		3		(3	)	N/A			0		67		(67	)	N/A

Three Months ended June 30, 2012 as compared to 2011

Operating Revenues decreased $300 million due to

Generation Revenues decreased $244 million due primarily to

•

lower net revenues of $113 million due primarily to lower average realized and unrealized prices for our generation sold into the PJM and New York power pools, partially offset by higher prices on generation sales in New England,

•

a decrease of $75 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts primarily as a result of customer migration and re-contracting,

•

a decrease of $42 million due to lower volumes on wholesale load contracts in the PJM and New England regions, and

•

a decrease of $25 million due to lower operating reserve revenue in 2012 resulting from lower demand and lower market prices, lower ancillary revenues and lower RMR revenues in the PJM region.

Gas Supply Revenues decreased $55 million due primarily to

•

a decrease of $51 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2012 due to milder winter weather during the second quarter of 2012, and

•

a net decrease of $4 million due primarily to lower average gas prices on higher sales volumes to third party customers.

Trading Revenues were immaterial in 2012 due to the discontinuation of trading activities in the second quarter of 2011.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $156 million due to

•

Generation costs decreased by $109 million due primarily to $83 million of lower fuel costs, primarily due to lower fossil fuel costs, reflecting the utilization of lower volumes of coal and lower natural gas prices, partially offset by the utilization of higher volumes of natural gas. The decrease was also attributable to $36 million in lower energy purchases in the PJM and New England regions as a result of lower load contract demand in 2012, and $8 million of lower CO₂ emission charges. These decreases were partially offset by an increase of $18 million in congestion costs in 2012 in the PJM region.

•

Gas costs decreased $47 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2012 due to milder winter weather during the second quarter of 2012.

Operation and Maintenance increased $13 million due primarily to higher refueling costs in 2012 for our 100%-owned Hope Creek nuclear facility as compared to our portion of refueling costs in 2011 for our 57%-owned Salem 2 nuclear unit. This increase was partially offset by lower planned fossil outage and maintenance costs in 2012, primarily at our coal-fired Mercer facility and gas-fired Linden and Bergen plants in New Jersey and our coal-fired Keystone plant in Pennsylvania.

Depreciation and Amortization experienced no material change.

Other Income and (Deductions) net decrease of $15 million was due primarily to lower net realized gains on our NDT Fund.

Other-Than-Temporary Impairments increased $6 million due primarily to impairments on the NDT Fund in 2012.

Interest Expense decreased $9 million due primarily to the early redemption of $600 million of 6.95% Senior Notes in December 2011.

Income Tax Expense decreased $70 million in 2012 due primarily to lower pre-tax income.

Income (Loss) from Discontinued Operations

In 2011, we sold our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions. In March 2011, we completed the sale of one plant for proceeds of $352 million at an after-tax gain of $54 million. In July 2011, we completed the sale of the second plant for proceeds of $335 million at an after-tax gain of $25 million. The sale of the second plant was reflected in Power’s Condensed Consolidated Financial Statements for the third quarter of 2011. The results of operations for both plants are included for the second quarter of 2011 in this category. See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions for additional information.

Six Months ended June 30, 2012 as compared to 2011

Operating Revenues decreased $706 million due to

Generation Revenues decreased $429 million due primarily to

•

lower net revenues of $144 million due primarily to lower average realized and unrealized prices for our generation sold into the PJM and New York power pools,

•

a decrease of $137 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts primarily as a result of warmer winter weather in 2012 as well as customer migration,

•

a decrease of $69 million due to lower volumes on wholesale load contracts in the PJM and New England regions, and

•

a decrease of $64 million due to lower operating reserve revenue in 2012 resulting from lower demand and lower average market prices, lower ancillary revenues and lower RMR revenues in the PJM region.

Gas Supply Revenues decreased $310 million due primarily to

•

a net decrease of $272 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2012 due to warmer average temperatures during the first quarter of 2012, and

•

a net decrease of $38 million due primarily to lower average gas prices partially offset by higher sales volumes to third party customers.

Trading Revenues increased $33 million in 2012 due to the discontinuation of trading activities in the second quarter of 2011. As a result, the increase is due primarily to the absence of losses on electric energy supply contracts recognized in 2011.

Operating Expenses

•

Gas costs decreased $272 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2012 due primarily to warmer average temperatures during the first quarter of 2012.

•

Generation costs decreased by $197 million due primarily to $184 million of lower fuel costs, reflecting the utilization of lower volumes of both coal and oil and lower natural gas prices, partially offset by the utilization of higher volumes of nuclear fuel at higher prices in 2012. The decrease was also attributable to $68 million in lower energy purchases in the PJM region as a result of lower load contract demand in 2012, and $13 million of lower CO₂emission charges. These decreases were partially offset by an increase of $68 million in congestion costs.

Operation and Maintenance decreased $23 million due primarily to lower planned outage and maintenance costs in 2012, mainly at our gas-fired Bethlehem facility in New York, Bergen and Linden gas-fired plants and Mercer coal-fired plant in New Jersey, and coal-fired Keystone plant in Pennsylvania. This decrease was partially offset by refueling costs in 2012 for our 100%-owned Hope Creek nuclear facility as compared to our portion of refueling costs in 2011 for our 57%-owned Salem 2 nuclear unit.

Depreciation and Amortization increased $5 million due primarily to higher depreciable asset bases at Fossil and Nuclear, largely resulting from placing a new 267 MW gas-fired peaking unit at Kearny, New Jersey and 130 MW gas-fired peaking capacity at New Haven, Connecticut into service on June 1, 2012 as well as completion of the steam path retrofit upgrade at Peach Bottom Unit 3 in October 2011.

Other Income and (Deductions) net decrease of $58 million was due primarily to lower net realized gains on our NDT Fund.

Other-Than-Temporary Impairments increased $9 million due primarily to impairments on the NDT Fund in 2012.

Interest Expense decreased $30 million due primarily to

•

a decrease of $26 million resulting primarily from the redemption of $606 million of 7.75% Senior Notes in early April 2011 and the early redemption of $600 million of 6.95% Senior Notes in December 2011, and

•

a $4 million decrease due to interest costs that we capitalized in 2012 for projects while under construction, primarily the gas-fired peaking facilities at Kearny, New Jersey and New Haven, Connecticut, both of which we began building in the second quarter of 2011.

Income Tax Expense decreased $111 million in 2012 due primarily to lower pre-tax income.

Income (Loss) from Discontinued Operations

As discussed above, we sold our two Texas plants in March 2011 and July 2011, respectively. The results of operations of both plants, including the after-tax gain of $54 million from the March 2011 sale, are included in this category. See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions for additional information.

PSE&G


	Three Months Ended June 30,				Increase/ (Decrease)			Six Months Ended June 30,				Increase/ (Decrease)
	2012		2011		2012 vs 2011			2012		2011		2012 vs 2011
		Millions
Income from Continuing Operations	$	101	$	105	$	(4	)	$	298	$	268	$	30
Net Income	$	101	$	105	$	(4	)	$	298	$	268	$	30

For the three months ended June 30, 2012, the primary reasons for the $4 million decrease in Income from Continuing Operations were

•

higher Operation and Maintenance costs,

•

partially offset by higher transmission formula rates and

•

higher Weather Normalization Charge (WNC).

For the six months ended June 30, 2012, the primary reasons for the $30 million increase in Income from Continuing Operations were

•

higher WNC,

•

higher transmission formula rates, and

•

tax benefits related to settlement of IRS audits,

•

partially offset by lower gas volumes and demands due to milder winter weather.

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)
	2012		2011		2012 vs 2011					2012		2011		2012 vs 2011
		Millions				Millions		%			Millions				Millions		%
Operating Revenues	$	1,407	$	1,571	$	(164	)	(10	)	$	3,346	$	3,877	$	(531	)	(14	)
Energy Costs		622		815		(193	)	(24	)		1,624		2,181		(557	)	(26	)
Operation and Maintenance		350		304		46		15			726		672		54		8
Depreciation and Amortization		188		172		16		9			378		351		27		8
Taxes Other Than Income Taxes		20		28		(8	)	(29	)		49		71		(22	)	(31	)
Other Income (Deductions)		11		4		7		N/A			21		8		13		N/A
Other-Than Temporary Impairments		0		0		0		0			0		1		(1	)	N/A
Interest Expense		74		78		(4	)	(5	)		147		157		(10	)	(6	)
Income Tax Expense (Benefit)		63		73		(10	)	(14	)		145		184		(39	)	(21	)

Three Months ended June 30, 2012 as compared to 2011

Operating Revenues decreased $164 million due primarily to

Commodity Revenue decreased $193 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.

•

Electric revenues decreased $135 million due primarily to $107 million in lower BGS revenues and $28 million in lower revenues from the sale of Non-Utility Generation (NUG) energy and collections of Non-Utility Generation Charges (NGC) due primarily to lower prices. BGS sales decreased 15% due primarily to customer migration to third party suppliers (TPS); in contrast, delivery sales decreased only 2%.

•

Gas revenues decreased $58 million due to lower BGSS prices of $42 million and lower BGSS volumes of $16 million due to weather.

Other Operating Revenues decreased $1 million due primarily to lower miscellaneous electric operating revenues, partially offset by increased revenues from our appliance repair business.

Delivery Revenues increased $23 million due primarily to an increase in transmission revenues.

•

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

•

Gas distribution revenues increased $6 million due primarily to a higher WNC and higher Capital Infrastructure Program (CIP) revenue, partially offset by lower sales volume and lower Transitional Energy Facilities Assessment (TEFA) revenue due to a lower TEFA rate and lower sales volumes.

•

Electric distribution revenues decreased $3 million due primarily to lower TEFA revenue due to a lower TEFA rate and lower sales volumes, partially offset by higher Solar, Energy Efficiency and Conservation Program (Solar/EE) revenue and higher CIP revenue.

Clause Revenues increased $7 million due primarily to higher Securitization Transition Charge (STC) revenues of $4 million, a higher Margin Adjustment Clause (MAC) of $2 million and higher Societal Benefit Charges (SBC) of $1 million. The changes in STC, MAC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC or STC collections.

Energy Costs decreased $193 million. This is entirely offset by Commodity Revenue.

•

Electric costs decreased $135 million due to $69 million or 10% in lower BGS and NUG volumes due to customer migration to TPS, $62 million of lower BGS prices, and $4 million for decreased deferred cost recovery.

•

Gas costs decreased $58 million due to $42 million or 24% in lower prices and $16 million or 9% in lower sales volumes due primarily to weather.

Operation and Maintenance increased $46 million due primarily to

•

a $14 million increase in costs recognized related to SBC, Solar/EE and CIP,

•

a $9 million increase in transmission related costs,

•

a $6 million increase in payroll costs, and

•

a $5 million increase in pension and other postretirement benefits (OPEB) expenses.

Depreciation and Amortization increased $16 million due primarily to

•

an increase of $10 million for amortization of Regulatory Assets, and

•

an increase of $6 million for additional plant in service.

Taxes Other Than Income Taxes decreased $8 million due to a lower TEFA rate and lower sales volumes for electric and gas.

Other Income and (Deductions) net increase of $7 million was due primarily to a $5 million increase in capitalized allowance for Equity Funds used during construction and a $2 million increase in Solar Loan interest income.

Interest Expense decreased $4 million due primarily to the $101 million redemption of securitization debts, partially offset by the interest associated with the $450 million MTN issued in May 2012. See Note 9. Changes in Capitalization for details.

Income Tax Expense decreased $10 million due primarily to lower pre-tax income.

Six Months ended June 30, 2012 as compared to 2011

Operating Revenues decreased $531 million due primarily to

Commodity Revenue decreased $557 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 $298 million due to lower BGSS volumes of $163 million and lower BGSS prices of $135 million. The average price of gas was 16% lower in 2012 than in 2011.

•

Electric revenues decreased $259 million due primarily to $230 million in lower BGS revenues and $29 million in lower revenues from the sale of NUG energy and collections of NGC due primarily to lower prices. BGS sales decreased 16% due primarily to customer migration to TPS; in contrast, delivery sales decreased only 3%.

Clause Revenues were flat due primarily to higher STC revenues of $6 million and higher MAC of $1 million, offset by lower SBC of $7 million. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC or STC collections.

Delivery Revenues increased $24 million due primarily to an increase in transmission revenues.

•

Transmission revenues were $42 million higher due primarily to net rate increases.

•

Gas distribution revenues decreased $12 million due primarily to lower sales volume, lower TEFA revenue due to a lower TEFA rate and lower Solar/EE revenue, partially offset by higher WNC and higher CIP revenue.

•

Electric distribution revenues decreased $6 million due primarily to lower TEFA revenue due to a lower TEFA rate and lower sales volumes, partially offset by higher Solar/EE revenue and higher CIP revenue.

Other Operating Revenues increased $2 million due primarily to increased revenues from our appliance repair business, partially offset by lower miscellaneous electric operating revenues.

Energy Costs decreased $557 million. This is entirely offset by Commodity Revenue.

•

Gas costs decreased $298 million due to $163 million or 19% in lower sales volumes due primarily to weather and $135 million or 16% in lower prices.

•

Electric costs decreased $259 million due to $135 million or 10% in lower BGS and NUG volumes due to customer migration to TPS, $97 million of lower BGS prices, and $27 million for decreased deferred cost recovery.

Operation and Maintenance increased $54 million due primarily to

•

a $15 million increase in costs recognized related to SBC, Solar/EE and CIP,

•

a $13 million increase in transmission related costs,

•

a $9 million increase in payroll costs, and

•

a $8 million increase in pension and OPEB expenses.

Depreciation and Amortization increased $27 million due primarily to

•

an increase of $16 million for amortization of Regulatory Assets, and

•

an increase of $12 million for additional plant in service.

Taxes Other Than Income Taxes decreased $22 million due to a lower TEFA rate and lower sales volumes for electric and gas.

Other Income and (Deductions) net increase of $13 million was due primarily to a $9 million increase in capitalized allowance for Equity Funds used during construction and a $3 million increase in Solar Loan interest income.

Other-Than-Temporary Impairments experienced no material change.

Interest Expense decreased $10 million due primarily to the $101 million redemption of securitization debts, partially offset by the interest associated with the $450 million Medium-Term Notes issued in May 2012. See Note 9. Changes in Capitalization for details.

Income Tax Expense decreased $39 million due primarily to tax benefits related to settlement of IRS tax audits.

Energy Holdings


	Three Months Ended June 30,				Increase/ (Decrease)			Six Months Ended June 30,				Increase/ (Decrease)
	2012		2011		2012 vs 2011			2012		2011		2012 vs 2011
		Millions
Income from Continuing Operations	$	2	$	5	$	(3	)	$	42	$	2	$	40
Net Income	$	2	$	5	$	(3	)	$	42	$	2	$	40

For the six months ended June 30, 2012, the primary reason for the $40 million increase in Income from Continuing Operations was tax benefits related to the settlement of IRS tax audits.

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, 2012, our operating cash flow decreased $17 million as compared to the same period in 2011. The net change was due primarily to net changes from Power and PSE&G, as discussed below.

Power

Power’s operating cash flow decreased $294 million from $1,146 million to $852 million for the six months ended June 30, 2012, as compared to the same period in 2011, primarily resulting from lower earnings, partially offset by a decrease of $86 million in benefit plan funding.

PSE&G

PSE&G’s operating cash flow increased $180 million from $279 million to $459 million for the six months ended June 30, 2012 as compared to the same period in 2011, due primarily to higher earnings combined with

•

a decrease of $173 million in benefit plan funding, and

•

a decrease of $108 million in net prepayments,

•

partially offset by a decrease of $96 million due to lower collections of customer receivables.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of Power, primarily through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Both commercial paper programs are fully back-stopped by their own separate credit facilities.

The commitments under our credit facilities are provided by a diverse bank group. As of June 30, 2012, no single institution represented more than 8% of the total commitments in our credit facilities.

As of June 30, 2012, our total credit capacity was in excess of our anticipated maximum liquidity requirements through 2012.

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, 2012 were as follows:


	As of June 30, 2012
Company/Facility	Total Facility		Usage			Available Liquidity		Expiration Date		Primary Purpose
		Millions
PSEG
5-year Credit Facility	$	500	$	12	(A)	$	488		Mar 2017	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility		500		0			500		Apr 2016	CP Support/Funding/Letters of Credit

Total PSEG	$	1,000	$	12		$	988

Power
5-year Credit Facility	$	1,600	$	121	(A)	$	1,479		Mar 2017	Funding/Letters of Credit
5-year Credit Facility		1,000		0			1,000		Apr 2016	Funding/Letters of Credit
Bilateral Credit Facility		100		100	(A)		0		Sept 2015	Letters of Credit

Total Power	$	2,700	$	221		$	2,479

PSE&G
5-year Credit Facility	$	600	$	16	(A)	$	584		Apr 2016	CP Support/Funding/Letters of Credit

Total PSE&G	$	600	$	16		$	584

Total	$	4,300	$	249		$	4,051

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

Long-Term Debt Financing

PSE&G has $300 million of 5.13% Medium Term Notes maturing in September 2012. For a discussion of our long-term debt transactions during 2012, see Note 9. Changes in Capitalization.

Common Stock Dividends

For information related to cash dividends on our common stock, see Note 15. Earnings Per Share. On July 17, 2012, The Board of Directors declared a quarterly dividend of $0.3550 per share of common stock for the third quarter of 2012. 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 April 2012, S&P published updated credit opinions that left the ratings and outlooks for Power and PSE&G unchanged. In May 2012, S&P published an updated credit opinion for PSEG that left its ratings and outlook unchanged. In May 2012, Moody’s published updated credit opinions on PSEG, Power and PSE&G. Moody’s upgraded PSE&G’s Mortgage Bond Rating to A1 from A2 and revised the outlook to stable

from positive. PSEG’s and Power’s ratings and outlooks remained unchanged. In July 2012, Fitch published updated credit opinions on PSEG, Power and PSE&G. Fitch upgraded PSE&G’s Mortgage Bond Rating to A+ from A and its stable outlook remained unchanged. PSEG’s and Power’s ratings and outlooks remained unchanged.

Moody’s(A)

S&P(B)

Fitch(C)

PSEG

Outlook

Stable

Positive

Stable

Commercial Paper

Power

Outlook

Stable

Positive

Stable

Senior Notes

Baa1

BBB

BBB+

PSE&G

Outlook

Stable

Positive

Stable

Mortgage Bonds

A–

A+

Commercial Paper

(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

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There have been no material changes to our projected construction and investment amounts through 2014 as disclosed in our Form 10-K for the year ended December 31, 2011.

Power

During the six months ended June 30, 2012, Power made $240 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $104 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 8. Commitments and Contingent Liabilities.

PSE&G

During the six months ended June 30, 2012, PSE&G made $920 million of capital expenditures, including $870 million of investment in plant, primarily for reliability of transmission and distribution systems and $50 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $44 million, which is included in operating cash flows.

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 physical sales and other services, 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.

MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The 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 VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.


Three Months Ended June 30, 2012	MTM VaR (A)
		Millions
95% Confidence Level,
Loss could exceed VaR one day in 20 days
Period End	$	15
Average for the Period	$	13
High	$	19
Low	$	9
99.5% Confidence Level,
Loss could exceed VaR one day in 200 days
Period End	$	24
Average for the Period	$	21
High	$	30
Low	$	13

(A)	As of June 30, 2012 and December 31, 2011, there was no trading VaR since we discontinued trading activities in the second quarter of 2011.

See Note 10. 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 of Public Service Enterprise Group Incorporated, PSEG Power LLC, and Public Service Electric and Gas Company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each of Public Service Enterprise Group Incorporated, PSEG Power LLC, and Public Service Electric and Gas 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 2012 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 2011 Form 10-K and Item 5 of Part II of Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, see Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.

Certain information reported under the 2011 Form 10-K is updated below. References are to the related pages on the Form 10-K as printed and distributed.

ITEM 1A.

RISK FACTORS

The Risk Factor shown below updates a risk factor disclosed in Part I Item 1A on page 35 of our 2011 Annual Reports on Form 10-K.

We are subject to comprehensive and evolving regulation by federal, state and local regulatory agencies that affects, or may affect, our businesses.

We are subject to regulation by federal, state and local authorities. Changes in regulation can cause significant delays in or materially affect business planning and transactions and can materially increase our costs. Regulation affects almost every aspect of our businesses, such as our ability to:

•

Obtain fair and timely rate relief— Our transmission assets are regulated by FERC and costs are recovered through rates set by FERC. Transmission formula rates, and specifically the Return on Equity (ROE) embedded in these formula rates, have recently become the target of certain state utility commissions, consumer advocates and consumer groups seeking to lower customer rates in New England. These agencies and groups have filed complaints at FERC asking the FERC to reduce the base ROE of various New England transmission owners with formula rates. They point to changes in the capital markets as justification for lowering the ROE of these companies. While we are not the subject of any of these complaints, the matter could set a precedent for FERC-regulated transmission owners with formula rates in place, such as PSE&G. Inability to obtain a fair return on our investments or to timely recover material costs not included in rates would have a material adverse effect on our business.

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 awards during the second quarter of 2012:


Three Months Ended June 30, 2012	Total Number of Shares Purchased		Average Price Paid per Share
April 1-April 30		0	$	0
May 1-May 31		58,267	$	31.67
June 1-June 30		25,000	$	31.28

ITEM 5.

OTHER INFORMATION

Certain information reported under the 2011 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2012 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2011 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2012. References are to the related pages on the Form 10-K as printed and distributed.

FEDERAL REGULATION

FERC

Capacity Market Issues—LCAPP

PJM, NYISO, and ISO-NE each have capacity markets that have been approved by FERC.

December 31, 2011 Form 10-K page 19 and March 31, 2012 Form-10-Q page 77. In 2011, the State of New Jersey concluded that new natural gas-fired generation was needed and enacted the Long-Term Capacity Agreement Pilot Program Act (LCAPP Act) to subsidize approximately 2,000 MW of new generation. The LCAPP Act provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey Electric Distribution Companies (EDCs). The SOCA requires that the generator bid in and clear in the PJM RPM base residual auction in each year of the SOCA term in order to receive the subsidized payment. The SOCA requires each New Jersey EDC to provide the generators with guaranteed capacity payments funded by ratepayers. Each of the New Jersey EDCs, including PSE&G, entered into the SOCAs as directed by the State, but did so under protest reserving their rights. Two generators, CPV Shore, LLC (CPV), a subsidiary of Competitive Power Ventures, Inc. and Hess Newark, LLC, a subsidiary of Hess Corporation, cleared the May 2012 RPM auction.

Legal challenges to the BPU’s implementation of the LCAPP Act were filed in New Jersey appellate court and the challenge filed by the EDCs has been remanded back to the BPU for consideration of certain procedural issues. In addition, the LCAPP Act has been challenged on constitutional grounds in federal court, and this case is pending.

Maryland is also taking action to subsidize above-market new generation. In April 2012, the Maryland PUC issued an order requiring the Maryland utility companies to enter into a contract with CPV to build a new 661 MW natural gas-fired, combined cycle station in Maryland with an in-service date of June 2015. In the May 2012 RPM auction, the CPV generator cleared the auction. Power has joined other generators in challenging this order on constitutional grounds in federal court. The Maryland EDCs have also appealed the April 12, 2012 order in state court. Developments in Maryland may stimulate the construction of subsidized generation and impact energy and capacity prices in PJM.

These efforts to artificially depress the wholesale capacity auction were intended to be mitigated by the Minimum Offer Price Rule (MOPR) approved by FERC. The MOPR was intended to restrict new natural gas fired generation from bidding in RPM at less than an established minimum level established by Tariff, or a cost-based bid to the extent that the generator can demonstrate that its costs are lower than the MOPR. Despite challenges by several parties, the MOPR was in place for the May 2012 auction, although we believe it did not operate to protect the market against suppression efforts. As a result, discussions to improve the MOPR are ongoing in PJM. In addition, legal challenges to the FERC’s MOPR order remain pending.

Transmission Regulation—Transmission Policy Development

December 31, 2011 Form 10-K page 20. In July 2011, FERC issued Order 1000 which, among other things (i) directs regional planners, such as PJM, to modify their planning processes to “consider transmission needs driven by public policy requirements established by state or federal laws or regulations” (ii) directs regional planners to remove the “ right of first refusal” (ROFR) from its tariffs and agreements under which incumbent transmission companies have a ROFR to build transmission located within their respective service territories, subject to certain exceptions (iii) requires regional planners to develop regional cost allocation methodologies that take into consideration that costs be “roughly commensurate” with project benefits and (iv) requires regional planners in neighboring regions to have a common interregional cost allocation method for new interregional facilities. We, along with many other parties to the proceeding, sought rehearing of the Final Rule. In May 2012, the FERC issued an order that denied rehearing in this proceeding. In June 2012, PSEG filed a Petition for Review of Order No. 1000 in federal appellate court, in which we plan to challenge the legal basis for the FERC’s actions. Other companies and state commissions have filed appeals as well. PJM is currently conducting a stakeholder process to develop implementing details regarding Order 1000. An expected outcome of this Final Rule is the construction of more transmission through “public policy” planning and the

opening up of transmission construction and ownership to third-party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 in the various regions, including within our service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.

Transmission Regulation—Transmission Expansion

December 31, 2011 Form 10-K page 21 and March 31, 2012 Form 10-Q page 78. We have not received certain environmental approvals that are required for each of the Eastern and Western segments of the Susquehanna-Roseland line, including from the National Park Service (NPS). On March 29, 2012, the NPS identified a “preferred alternative” for its final Environmental Impact Statement (EIS), under which the project would follow the route of the existing transmission line. This route was the one approved by state regulators including the BPU. The final EIS is expected to be issued in October 2012. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. Delays in the construction schedule could impact the timing of expected transmission revenues.

In 2010, certain environmental groups appealed the BPU’s approval of the Susquehanna-Roseland line, although no stay was sought. This appeal remains pending.

In June 2012, the BPU approved our petition to site the North Central Reliability project. We have also obtained NJDEP approval for the project. This project, which will involve upgrading certain circuits and switching stations from 138 kV to 230 kV, is currently estimated to cost $390 million and has an in-service date of June 2014.

Transmission Rate Proceedings

In September 2011, the Massachusetts Attorney General, along with several state utility commissions, consumer advocates and consumer groups from six New England states, filed a complaint at FERC against a group of New England transmission owners seeking to reduce the base return on equity used in calculating these transmission owners’ formula transmission rates. The matter has been set for hearing. While we are not the subject of any of these complaints, this matter could set a precedent for FERC-regulated transmission owners with formula rates in place, such as PSE&G.

Commodity Futures Trading Commission (CFTC)

December 31, 2011 Form 10-K page 22 and March 31, 2012 Form 10-Q page 79. In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), the SEC and the CFTC are in the process of implementing new rules to effectuate stricter regulation over swaps and derivatives including potentially significant reporting and record-keeping requirements and clearing/collateral requirements. Additionally, the Dodd-Frank Act will require many swaps and other derivative transactions to be standardized and traded on exchanges or other Derivative Clearing Organizations. The CFTC has issued Notices of Proposed Rulemaking on many of the key issues, including defining swaps and swap dealers; reporting requirements; and margin requirements, as well as Final Rules. Specifically, in May 2012, the CFTC issued a Final Rule regarding the definition of a swap dealer. In addition, in July 2012, the CFTC voted to issue a Final Rule regarding commercial end users and the definition of a swap, although this rule has yet to be published. We are continuing to analyze the potential impact of these rules, including whether we will fall within the commercial end-user exemption recognized in the Dodd-Frank Act.

STATE REGULATION

Rates

Retail Gas Transportation Rates

December 31, 2011 Form 10-K page 24 and March 31, 2012 Form 10-Q page 80. The BPU commenced a generic proceeding to evaluate the process and standards for all utilities to provide discounts to their gas

delivery customers, culminating in the issuance of an order in 2011. We, along with the other New Jersey gas utilities, filed to implement tariffs with the BPU setting forth their individual processes by which customers can obtain discounts. On May 23, 2012, the BPU approved PSE&G’s tariff filing.

Connecticut Project

Power was selected by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control, in a regulatory process to build 130 MW of gas fired peaking capacity. The project was placed in service in June 2012. The first of the annual filings to recover the capital and operating costs of the project was submitted in December 2011 to PURA. PURA issued a final decision in early June 2012, authorizing Power to recover $14.5 million for the period June 1, 2012 to December 31, 2012. On July 31, 2012, Power filed a petition and testimony seeking approval from PURA of a 2013 annual fixed revenue requirement of $20.7 million, which represents the facility’s fixed operation and maintenance (O&M) costs along with the return of and return on the investment for the calendar year 2013. PURA is expected to issue a final decision before the end of 2012. Variable costs (e.g., fuel, Connecticut’s generation tax, and certain non-fuel O&M expenses) are recovered through a contract for differences.

Rate Adjustment Clauses

Societal Benefits Charge-Universal Service Fund (USF)

December 31, 2011 Form 10-K page 25. The USF is an energy assistance program mandated by the BPU to provide payment assistance to low income customers. The Lifeline program is a separate mandated energy assistance program to provide payment assistance to elderly and disabled customers. On June 22, 2012, New Jersey’s electric and gas utilities, including PSE&G, filed requests to reset the statewide rates for the USF and the Lifeline program. The filed USF rates were set to recover approximately $226 million on a statewide basis. Of this amount, the statewide electric rates are set to recover $169 million with the remaining $57 million recovered through gas rates. The rates for the Lifeline program were set to recover $66 million, $46 million electric and $20 million gas. We are currently in the discovery phase of this proceeding.

Gas Weather Normalization Charge (WNC)

December 31, 2011 Form 10-K page 25. PSE&G’s WNC is a rate mechanism that allows PSE&G to increase its rates to compensate for lower revenues it receives from customers as a result of warmer-than-normal winters and to decrease its rates to make up for higher revenues it receives as a result of colder-than-normal winters. The payments and refunds are subject to certain limitations and rate caps. Unrecovered balances associated with application of the rate cap are deferred until the next recovery period.

The WNC requires PSE&G to calculate, at the end of each October – May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. On June 27, 2012, we filed a petition and testimony with the BPU seeking BPU approval to recover $56.6 million in deficiency revenues through the WNC, of which $40.7 million would be recovered from our customers during the 2012-2013 Winter Period (October 1 – May 31). The remaining estimated $16 million expected to be recovered will be applied to the 2013-2014 Winter Period, pursuant to the WNC tariff provisions approved by the BPU on July 9, 2010, as part of the Stipulation of Settlement of PSE&G’s 2009 Rate Case.

Solar/EE Recovery Charge

December 31, 2011 Form 10-K page 25. On July 2, 2012, we filed a petition with the BPU requesting an increase in the Solar/EE Recovery Charge seeking to recover approximately $61.6 million in electric revenue and $8.5 million in gas revenue on an annual basis. These changes are the result of adjustments in the components of the Solar/EE Recovery Charges including: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic Extension Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All) and Solar Loan II Program.

Recent Rate Adjustments-Remediation Adjustment Charge (RAC)

December 31, 2011 Form 10-K page 26 and March 31, 2012 Form 10-Q page 80. In November 2011, we filed a RAC 19 petition with the BPU requesting a decrease in electric and gas RAC revenues on an annual basis of $8.9 million and $10.1 million, respectively. We are currently in the settlement phase of the proceeding.

Energy Supply

BGSS

December 31, 2011 Form 10-K page 27 and March 31, 2012 Form 10-Q page 80. On June 1, 2012, PSE&G made its annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $70.7 million, excluding sales and use tax, to be effective October 1, 2012. This represents a reduction of approximately 5.2% for a typical residential gas heating customer. This BGSS reduction will be the ninth consecutive reduction since January 2009. A Draft Stipulation has been circulated which would put the lower BGSS rate into effect as filed on October 1, 2012 on a provisional basis.

Energy Policy

Solar Initiatives

December 31, 2011 Form 10-K page 28 and March 31, 2012 Form 10-Q page 80. The BPU has concluded a generic proceeding examining whether existing utility rate-based solar programs, including ours, should be expanded, modified or discontinued once the current programs expire or the authorized level of solar installations has been achieved. On May 23, 2012, the BPU issued an order ruling that the capacity of utility “financing” programs, which includes PSE&G’s Solar Loan Program, may be increased by a total of 180 MW (allocated to all of the electric utilities) over the next three years.

Also, consistent with the BPU’s generic proceeding on solar, PSE&G filed for an additional extension of our Solar Loan program (Solar Loan III) on July 31, 2012. In the filing, PSE&G is seeking BPU approval to provide financing support for the installation of 97.5 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, projects are built and loans are closed.

Solar Pilot Recovery Charge (SPRC)

On July 18, 2012, the BPU approved a Stipulation regarding our March 2010 Solar I filing, effective August 1, 2012. This Order will result in an increase in rates of $2.5 million for our electric customers. On July 2, 2012, we filed a petition with the BPU for an increase in the electric SPRC for the Solar Loan I program. If our filing is approved by the BPU as filed, the result would be an increase in rates to be paid by our electric customers of $17.0 million on an annual basis.

BPU Audits

Management/Affiliate Audit

December 31, 2011 Form 10-K page 29. In 2009, the BPU, in accordance with New Jersey statutes, initiated audits of PSE&G with respect to the effectiveness of its management and its compliance with rules governing PSE&G’s interactions with its affiliated companies. The audits were conducted on a combined basis by a consultant who was retained by the BPU. On May 23, 2012, the BPU issued the consultant’s audit report for

public comment. The audit report makes a number of findings and recommendations, including the finding that no violations of either the state or federal affiliate rules were found. In accordance with the BPU’s procedural schedule, the comment period will end on September 28, 2012. Thereafter, the BPU is expected to issue an order addressing the audit report’s findings and recommendations.

ENVIRONMENTAL MATTERS

Air Pollution Control

Cross-State Air Pollution Rule (CSAPR)

December 31, 2011 Form 10-K page 31 and March 31, 2012 Form 10-Q page 81. On July 6, 2011, the EPA issued the final CSAPR. CSAPR limits power plant emissions of Sulfur Dioxide (SO₂) and annual and ozone season NO_X in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone National Ambient Air Quality Standards. Technical revisions to the CSAPR were finalized on February 7, 2012. The EPA increased New Jersey’s allocation of annual NO_X and ozone season NO_X allowances beyond what was proposed. The EPA also finalized the increase in New Jersey’s allocation of SO₂ allowances from the October proposal. The additional increases in NO_X allocations are favorable to PSEG, since both PSEG and New Jersey as a whole are projected to be very tight on NO_X allowances (both ozone season and annual).

On December 30, 2011, the United States Court of Appeals for the D.C. circuit issued a ruling to stay CSAPR pending judicial review. Until a final decision is reached, the court has ordered that the existing Clean Air Interstate Rule requirements continue temporarily. PSEG has intervened in this litigation, along with Calpine and Exelon, in support of the rule. Oral argument occurred on April 13, 2012. A final decision on the merits is expected in the summer of 2012.

Climate Change

Regional Greenhouse Gas Initiative (RGGI)

December 31, 2011 Form 10-K page 31. In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO₂ emission reductions in the electric power industry. Ten northeastern states, including New Jersey, New York and Connecticut, originally established RGGI to cap and reduce CO₂ emissions in the region. In general, these states adopted state-specific rules to enable the RGGI regulatory mandate in each state.

Applicable rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO₂ emissions. Generators are required to submit an allowance for each ton emitted over a three year period (e.g. 2009, 2010, and 2011). Allowances are available through the auction or through secondary markets and are required to be submitted to states by March 2012 for the first compliance period.

Pricing for the allowances vary based on future allowance market conditions and electric generation market conditions. For the first three-year compliance period, we have acquired sufficient allowances to compensate for CO₂ emissions from affected sources.

In May 2011, the Governor of New Jersey announced his intent to withdraw New Jersey from RGGI beginning in 2012. Therefore, our New Jersey facilities are no longer obligated to acquire CO₂ emission allowances, but our generation facilities in New York and Connecticut remain subject to RGGI.

On June 6, 2012, the Natural Resources Defense Council and Environment New Jersey filed suit against NJDEP claiming that New Jersey’s withdrawal from RGGI did not follow proper legal procedure.

CO₂ Regulation under the Clean Air Act (CAA)

December 31, 2011 Form 10-K page 32. In April 2010, the EPA and the National Highway Transportation Safety Board (NHTSB) jointly issued a final rule to regulate GHG emissions from certain motor vehicles (Motor Vehicle Rule). Under the CAA, the adoption of the Motor Vehicle Rule would have automatically subjected many emission sources, including ours, to CAA permitting for new facilities and major facility

modifications that increase the emission of GHGs, including CO₂. However, guidance issued by the EPA in March 2010 interpreted the CAA to require permitting for GHGs at other facilities, such as ours, only when the Motor Vehicle Rule was scheduled to take effect in January 2011. In May 2010, the EPA finalized a “Tailoring Rule” that would 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.

In November 2010, the EPA published guidance to state and local permitting authorities to undertake BACT determinations for new and modified emission sources. The guidance does not define the specific technology or technologies that should be considered BACT. The guidance does emphasize the use of energy efficiency, and specifically states that the technology of storing CO₂ under the earth, also known as carbon capture and storage, is not yet mature enough to be considered a viable alternative at this stage. On April 13, 2012, the EPA published the proposed New Source Performance Standards (NSPS) for GHGs for new power plants and refineries. New or modified sources must employ BACT which is defined on a case-by-case basis and can be no less stringent than the applicable NSPS. Thus, for new power plants where the proposed NSPS identifies the applicable standard, if adopted as proposed, all permit decisions regarding BACT and application completeness should be made to reflect at least the level of stringency contained in those standards.

CO₂ Litigation

December 31, 2011 Form 10-K page 32. On June 26, 2012, the US Court of Appeals for the DC Circuit upheld the EPA finding that GHGs could reasonably be expected to endanger public health and welfare. However, the Court dismissed the action brought by individuals, local governments and interest groups alleging that various industries, including various energy companies, emitted GHGs, causing global climate change resulting in a variety of damages. Plaintiffs are expected to appeal to the US Supreme Court.

Water Pollution Control

December 31, 2011 Form 10-K page 33 and March 31, 2012 Form 10-Q page 81. Section 316(b) of the FWPCA requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. The impact of regulations under Section 316(b) can be significant, particularly at steam-electric generating stations which do not have closed cycle cooling through the use of cooling towers to recycle water for cooling purposes. The installation of cooling towers at an existing generating station can impose significant engineering challenges and significant costs, which can affect the economic viability of a particular plant. In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012.

In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the BTA (e.g. closed-cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. We reviewed the proposed rule, assessed the potential impact on our generating facilities and used this information to develop our comments to the EPA which were filed in August 2011. On June 11, 2012, the EPA posted a Notice of Data Availability (NODA) requesting comment on a series of technical issues related to the impingement mortality proposed standards. On June 12, 2012, the EPA posted a second NODA outlining its plans to finalize a “Willingness to Pay” survey it initiated to develop non-use benefits data in support of the April 2011 rule proposal. PSEG and industry trade associations submitted comments on both NODAs in early July. In July 2012, the EPA and environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.

If the rule were to be adopted as proposed, the impact on us would be material since the majority of our electric generating stations would be affected. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material. See Note 8. Commitments and Contingent Liabilities for additional information.

Fuel and Waste Disposal

Nuclear Fuel Disposal

December 31, 2011 Form 10-K page 34. 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 U.S. Department of Environmental Protection (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998 but has not yet done so. The Nuclear Waste Policy Act of 1982 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 March 2011, we joined the Nuclear Energy Institute (NEI) and fifteen other nuclear plant operators in a lawsuit seeking suspension of the Nuclear Waste Fee. On June 1, 2012, The U.S. Court of Appeals for the District of Columbia ruled that the DOE failed to justify continued payments by electricity consumers into the Nuclear Waste Fund. The court ordered the DOE to conduct a complete reassessment of this fee within six months. While the court did not order the DOE to suspend the fee payments, the court rejected the DOE’s bases for continuing to collect the fees and therefore the DOE must provide clear justification to continue to collect the Nuclear Waste Fund fee at the present level.

The Nuclear Waste Fee litigation is not expected to have any effect on our September 2009 settlement agreement with DOE applicable to Salem and Hope Creek under which we will be reimbursed for past and future reasonable and allowable costs resulting from the DOE delay in accepting spent nuclear fuel for permanent disposition. A similar settlement agreement was reached related to Peach Bottom in 2004.

Spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in Independent Spent Fuel Storage Installations located at reactors or away from reactor sites. We have on-site storage facilities that are expected to satisfy the storage needs of Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 through the end of their operating licenses.

Coal Combustion Residuals (CCRs)

December 31, 2011 Form 10-K page 34 and March 31, 2012 Form 10-Q page 82. On April 5, 2012, several environmental organizations brought a citizens’ suit against the EPA in federal court arguing that the EPA has a non-discretionary duty to issue the CCR rules by a certain date. On May 15, 2012, the Utility Solid Waste Activities Group Policy Committee filed a Motion to Intervene in order to be in alignment with EPA in defending against the environmental organizations’ action.

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 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

Exhibit 101.INS:

XBRL Instance Document

Exhibit 101.SCH:

XBRL Taxonomy Extension Schema

Exhibit 101.CAL:

XBRL Taxonomy Extension Calculation Linkbase

Exhibit 101.LAB:

XBRL Taxonomy Extension Labels Linkbase

Exhibit 101.PRE:

XBRL Taxonomy Extension Presentation Linkbase

Exhibit 101.DEF:

XBRL Taxonomy Extension Definition Document

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

Exhibit 101.INS:

XBRL Instance Document*

Exhibit 101.SCH:

XBRL Taxonomy Extension Schema*

Exhibit 101.CAL:

XBRL Taxonomy Extension Calculation Linkbase*

Exhibit 101.LAB:

XBRL Taxonomy Extension Labels Linkbase*

Exhibit 101.PRE:

XBRL Taxonomy Extension Presentation Linkbase*

Exhibit 101.DEF:

XBRL Taxonomy Extension Definition Document*

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

Exhibit 101.INS:

XBRL Instance Document*

Exhibit 101.SCH:

XBRL Taxonomy Extension Schema*

Exhibit 101.CAL:

XBRL Taxonomy Extension Calculation Linkbase*

Exhibit 101.LAB:

XBRL Taxonomy Extension Labels Linkbase*

Exhibit 101.PRE:

XBRL Taxonomy Extension Presentation Linkbase*

Exhibit 101.DEF:

XBRL Taxonomy Extension Definition Document*

*	XBRL information is furnished, not filed.

SIGNATURE

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


PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

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

Date: August 2, 2012

SIGNATURE


PSEG POWER LLC
(Registrant)

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

Date: August 2, 2012

SIGNATURE


PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

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

Date: August 2, 2012