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