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 September 30, 2011

¨ 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 October 14, 2011, Public Service Enterprise Group Incorporated had outstanding 505,904,850 shares of its sole class of Common Stock, without par value.

As of October 14, 2011, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.

PSEG Power LLC and Public Service Electric and Gas Company are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q. Each is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.


		Page
FORWARD-LOOKING STATEMENTS			ii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated		1
	PSEG Power LLC		5
	Public Service Electric and Gas Company		8
	Notes to Condensed Consolidated Financial Statements		12
	Note 1. Organization and Basis of Presentation		12
	Note 2. Recent Accounting Standards		13
	Note 3. Variable Interest Entities (VIEs)		14
	Note 4. Discontinued Operations and Dispositions		14
	Note 5. Financing Receivables		15
	Note 6. Available-for-Sale Securities		18
	Note 7. Pension and Other Postretirement Benefits (OPEB)		22
	Note 8. Commitments and Contingent Liabilities		23
	Note 9. Changes in Capitalization		34
	Note 10. Financial Risk Management Activities		34
	Note 11. Fair Value Measurements		41
	Note 12. Other Income and Deductions		48
	Note 13. Income Taxes		49
	Note 14. Comprehensive Income, Net of Tax		50
	Note 15. Earnings Per Share (EPS)		52
	Note 16. Financial Information by Business Segments		53
	Note 17. Related-Party Transactions		54
	Note 18. Guarantees of Debt		56
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		59
	Overview of 2011 and Future Outlook		59
	Results of Operations		66
	Liquidity and Capital Resources		74
	Capital Requirements		77
	Accounting Matters		77
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		78
Item 4.	Controls and Procedures		79
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		80
Item 1A.	Risk Factors		81
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		81
Item 5.	Other Information		81
Item 6.	Exhibits		89
	Signatures		91

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 “will,” “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 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,

•

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

•

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

•

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

•

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

•

adverse changes in the demand for or price of the capacity and energy that we sell into wholesale electricity markets,

•

increase in competition in energy markets in which we compete,

•

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.

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

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

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

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	For The Three Months Ended September 30,						For The Nine Months Ended September 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	2,620		$	3,114		$	8,443		$	9,048
OPERATING EXPENSES
Energy Costs		1,167			1,261			3,740			4,021
Operation and Maintenance		603			591			1,829			1,862
Depreciation and Amortization		263			260			739			716
Taxes Other Than Income Taxes		31			31			102			101

Total Operating Expenses		2,064			2,143			6,410			6,700

OPERATING INCOME		556			971			2,033			2,348
Income from Equity Method Investments		1			4			8			12
Other Income		45			75			176			165
Other Deductions		(11	)		(9	)		(39	)		(37	)
Other-Than-Temporary Impairments		(8	)		(3	)		(13	)		(9	)
Interest Expense		(117	)		(120	)		(361	)		(356	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		466			918			1,804			2,123
Income Tax (Expense) Benefit		(201	)		(371	)		(757	)		(856	)

INCOME FROM CONTINUING OPERATIONS		265			547			1,047			1,267
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(11) for the three months and $(51) and $(10) for the nine months ended 2011 and 2010, respectively		29			20			96			15

NET INCOME	$	294		$	567		$	1,143		$	1,282

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC		505,909			505,945			505,959			506,001

DILUTED		506,999			506,968			506,963			507,068

EARNINGS PER SHARE
BASIC
INCOME FROM CONTINUING OPERATIONS	$	0.52		$	1.08		$	2.07		$	2.50

NET INCOME	$	0.58		$	1.12		$	2.26		$	2.53

DILUTED
INCOME FROM CONTINUING OPERATIONS	$	0.52		$	1.08		$	2.06		$	2.50

NET INCOME	$	0.58		$	1.12		$	2.25		$	2.53

DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.3425		$	0.3425		$	1.0275		$	1.0275

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	September 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	1,242		$	280
Accounts Receivable, net of allowances of $64 and $68 in 2011 and 2010, respectively		1,164			1,387
Tax Receivable		377			689
Unbilled Revenues		251			400
Fuel		740			666
Materials and Supplies, net		365			359
Prepayments		416			204
Derivative Contracts		113			182
Assets of Discontinued Operations		0			564
Deferred Income Taxes		96			43
Regulatory Assets		86			155
Other		120			122

Total Current Assets		4,970			5,051

PROPERTY, PLANT AND EQUIPMENT		24,618			23,272
Less: Accumulated Depreciation and Amortization		(7,336	)		(6,882	)

Net Property, Plant and Equipment		17,282			16,390

NONCURRENT ASSETS
Regulatory Assets		3,354			3,736
Regulatory Assets of Variable Interest Entities (VIEs)		968			1,128
Long-Term Investments		1,406			1,623
Nuclear Decommissioning Trust (NDT) Funds		1,280			1,363
Other Special Funds		170			160
Goodwill		16			16
Other Intangibles		164			136
Derivative Contracts		75			79
Restricted Cash of VIEs		22			21
Other		204			206

Total Noncurrent Assets		7,659			8,468

TOTAL ASSETS	$	29,911		$	29,909

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	September 30,			December 31,
	2011			2010
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	1,275		$	915
Securitization Debt of VIEs Due Within One Year		214			206
Commercial Paper and Loans		0			64
Accounts Payable		1,144			1,176
Derivative Contracts		94			103
Accrued Interest		131			108
Accrued Taxes		30			49
Clean Energy Program		224			195
Obligation to Return Cash Collateral		107			104
Regulatory Liabilities		161			174
Liabilities of Discontinued Operations		0			72
Other		312			319

Total Current Liabilities		3,692			3,485

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		5,652			5,129
Regulatory Liabilities		235			285
Regulatory Liabilities of VIEs		9			8
Asset Retirement Obligations		482			461
Other Postretirement Benefit (OPEB) Costs		948			967
Accrued Pension Costs		189			788
Clean Energy Program		70			235
Environmental Costs		651			669
Derivative Contracts		31			22
Long-Term Accrued Taxes		234			248
Other		77			152

Total Noncurrent Liabilities		8,578			8,964

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		6,651			6,834
Securitization Debt of VIEs		784			939
Project Level, Non-Recourse Debt		45			46

Total Long-Term Debt		7,480			7,819

STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2011 and 2010—533,556,660 shares		4,818			4,807
Treasury Stock, at cost, 2011—27,651,927 shares; 2010—27,582,437 shares		(601	)		(593	)
Retained Earnings		6,198			5,575
Accumulated Other Comprehensive Loss		(256	)		(156	)

Total Common Stockholders’ Equity		10,159			9,633
Noncontrolling Interest		2			8

Total Stockholders’ Equity		10,161			9,641

Total Capitalization		17,641			17,460

TOTAL LIABILITIES AND CAPITALIZATION	$	29,911		$	29,909

See Notes to Condensed Consolidated Financial Statements.

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For the Nine Months Ended September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,143		$	1,282
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Gain on Disposal of Discontinued Operations		(122	)		0
Depreciation and Amortization		745			730
Amortization of Nuclear Fuel		114			102
Provision for Deferred Income Taxes (Other than Leases) and ITC		629			205
Non-Cash Employee Benefit Plan Costs		138			236
Net (Gain) Loss on Lease Investments		0			(51	)
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes		(16	)		(391	)
Leveraged Lease Reserve, net of tax		170			0
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(14	)		(42	)
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		100			35
Over (Under) Recovery of Societal Benefits Charge (SBC)		(26	)		(55	)
Market Transition Charge Refund		(47	)		98
Cost of Removal		(43	)		(47	)
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(110	)		(73	)
Realized Gains from Rabbi Trusts		(5	)		(31	)
Net Change in Tax Receivable		312			0
Net Change in Certain Current Assets and Liabilities		(44	)		(237	)
Employee Benefit Plan Funding and Related Payments		(486	)		(483	)
Other		(29	)		61

Net Cash Provided By (Used In) Operating Activities		2,409			1,339

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(1,479	)		(1,517	)
Proceeds from Sale of Discontinued Operations		687			0
Proceeds from the Sale of Capital Leases and Investments		0			427
Proceeds from Sales of Available-for-Sale Securities		1,088			886
Investments in Available-for-Sale Securities		(1,110	)		(905	)
Other		(13	)		13

Net Cash Provided By (Used In) Investing Activities		(827	)		(1,096	)

CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans		(64	)		(530	)
Issuance of Long-Term Debt		750			1,608
Redemption of Long-Term Debt		(606	)		(548	)
Repayment of Non-Recourse Debt		(1	)		(3	)
Redemption of Securitization Debt		(147	)		(140	)
Cash Dividends Paid on Common Stock		(520	)		(520	)
Redemption of Preferred Securities		0			(80	)
Other		(32	)		(48	)

Net Cash Provided By (Used In) Financing Activities		(620	)		(261	)

Net Increase (Decrease) in Cash and Cash Equivalents		962			(18	)
Cash and Cash Equivalents at Beginning of Period		280			350

Cash and Cash Equivalents at End of Period	$	1,242		$	332

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	60		$	1,080
Interest Paid, Net of Amounts Capitalized	$	341		$	299

See Notes to Condensed Consolidated Financial Statements.

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	For The Three Months Ended September 30,						For The Nine Months Ended September 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	1,398		$	1,523		$	4,650		$	4,983
OPERATING EXPENSES
Energy Costs		597			620			2,335			2,483
Operation and Maintenance		262			253			810			764
Depreciation and Amortization		56			43			166			130

Total Operating Expenses		915			916			3,311			3,377

OPERATING INCOME		483			607			1,339			1,606
Other Income		37			44			156			126
Other Deductions		(10	)		(9	)		(37	)		(36	)
Other-Than-Temporary Impairments		(8	)		(2	)		(10	)		(8	)
Interest Expense		(42	)		(37	)		(134	)		(119	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		460			603			1,314			1,569
Income Tax (Expense) Benefit		(187	)		(239	)		(539	)		(632	)

INCOME FROM CONTINUING OPERATIONS		273			364			775			937
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(11) for the three months and $(51) and $(10) for the nine months ended 2011 and 2010, respectively		29			20			96			15

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	302		$	384		$	871		$	952

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

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)


	September 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	14		$	11
Accounts Receivable		432			511
Accounts Receivable—Affiliated Companies, net		127			782
Short-Term Loan to Affiliate		1,574			398
Fuel		740			666
Materials and Supplies, net		273			269
Derivative Contracts		95			163
Prepayments		42			80
Assets of Discontinued Operations		0			564

Total Current Assets		3,297			3,444

PROPERTY, PLANT AND EQUIPMENT		9,118			8,643
Less: Accumulated Depreciation and Amortization		(2,552	)		(2,301	)

Net Property, Plant and Equipment		6,566			6,342

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Funds		1,280			1,363
Goodwill		16			16
Other Intangibles		164			130
Other Special Funds		33			32
Derivative Contracts		24			42
Long-Term Accrued Taxes		19			16
Other		85			67

Total Noncurrent Assets		1,621			1,666

TOTAL ASSETS	$	11,484		$	11,452

LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	710		$	650
Accounts Payable		635			643
Derivative Contracts		79			91
Deferred Income Taxes		8			64
Accrued Interest		63			40
Liabilities of Discontinued Operations		0			72
Other		111			91

Total Current Liabilities		1,606			1,651

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		1,211			1,146
Asset Retirement Obligations		255			242
Other Postretirement Benefit (OPEB) Costs		158			151
Derivative Contracts		17			22
Accrued Pension Costs		75			253
Environmental Costs		51			51
Other		34			104

Total Noncurrent Liabilities		1,801			1,969

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT
Total Long-Term Debt		2,640			2,805

MEMBER’S EQUITY
Contributed Capital		2,028			2,028
Basis Adjustment		(986	)		(986	)
Retained Earnings		4,602			4,080
Accumulated Other Comprehensive Loss		(207	)		(95	)

Total Member’s Equity		5,437			5,027

TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,484		$	11,452

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

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For the Nine Months Ended
	September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	871		$	952
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:

Gain on Disposal of Discontinued Operations		(122	)		0
Depreciation and Amortization		173			144
Amortization of Nuclear Fuel		114			102
Provision for Deferred Income Taxes and ITC		74			145
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives		(14	)		(42	)
Non-Cash Employee Benefit Plan Costs		33			53
Net Realized (Gains) Losses and (Income) Expense from NDT Funds		(110	)		(73	)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies		(82	)		(2	)
Margin Deposit		(63	)		(26	)
Accounts Receivable		157			16
Accounts Payable		(103	)		(99	)
Accounts Receivable/Payable-Affiliated Companies, net		650			186
Accrued Interest Payable		23			41
Other Current Assets and Liabilities		48			(42	)
Employee Benefit Plan Funding and Related Payments		(127	)		(131	)
Other		(35	)		32

Net Cash Provided By (Used In) Operating Activities		1,487			1,256

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(530	)		(579	)
Proceeds from Sale of Discontinued Operations		687			0
Proceeds from Sales of Available-for-Sale Securities		1,088			759
Investments in Available-for-Sale Securities		(1,106	)		(778	)
Short-Term Loan—Affiliated Company, net		(1,176	)		(309	)
Other		19			28

Net Cash Provided By (Used In) Investing Activities		(1,018	)		(879	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Recourse Long-Term Debt		500			594
Cash Dividend Paid		(350	)		(550	)
Redemption of Long-Term Debt		(606	)		(248	)
Short-Term Loan—Affiliated Company, net		0			(194	)
Other		(10	)		(17	)

Net Cash Provided By (Used In) Financing Activities		(466	)		(415	)

Net Increase (Decrease) in Cash and Cash Equivalents		3			(38	)
Cash and Cash Equivalents at Beginning of Period		11			64

Cash and Cash Equivalents at End of Period	$	14		$	26

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	110		$	558
Interest Paid, Net of Amounts Capitalized	$	111		$	85

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)


	For the Three Months Ended September 30,						For The Nine Months Ended September 30,
	2011			2010			2011			2010
OPERATING REVENUES	$	1,841		$	2,007		$	5,718		$	5,987
OPERATING EXPENSES
Energy Costs		943			1,115			3,124			3,572
Operation and Maintenance		342			327			1,014			1,084
Depreciation and Amortization		197			209			548			563
Taxes Other Than Income Taxes		31			31			102			101

Total Operating Expenses		1,513			1,682			4,788			5,320

OPERATING INCOME		328			325			930			667
Other Income		7			14			16			22
Other Deductions		(1	)		(1	)		(2	)		(2	)
Other-Than-Temporary Impairments		0			0			(1	)		0
Interest Expense		(77	)		(82	)		(234	)		(239	)

INCOME BEFORE INCOME TAXES		257			256			709			448
Income Tax (Expense) Benefit		(103	)		(101	)		(287	)		(172	)

NET INCOME		154			155			422			276
Preferred Stock Dividends		0			0			0			(1	)

EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	154		$	155		$	422		$	275

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)


	September 30,			December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	242		$	245
Accounts Receivable, net of allowances of $64 in 2011 and $67 in 2010, respectively		720			832
Tax Receivable		21			0
Accounts Receivable—Affiliated Companies, net		304			0
Unbilled Revenues		251			400
Materials and Supplies		91			90
Prepayments		320			117
Regulatory Assets		86			155
Other		35			19

Total Current Assets		2,070			1,858

PROPERTY, PLANT AND EQUIPMENT		14,917			14,068
Less: Accumulated Depreciation and Amortization		(4,500	)		(4,326	)

Net Property, Plant and Equipment		10,417			9,742

NONCURRENT ASSETS
Regulatory Assets		3,354			3,736
Regulatory Assets of VIEs		968			1,128
Long-Term Investments		258			230
Other Special Funds		57			54
Derivative Contracts		0			17
Restricted Cash of VIEs		22			21
Other		89			87

Total Noncurrent Assets		4,748			5,273

TOTAL ASSETS	$	17,235		$	16,873

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)


	September 30,		December 31,
	2011		2010
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	564	$	264
Securitization Debt of VIEs Due Within One Year		214		206
Accounts Payable		396		406
Accounts Payable—Affiliated Companies, net		0		85
Accrued Interest		66		65
Clean Energy Program		224		195
Derivative Contracts		15		12
Deferred Income Taxes		21		19
Obligation to Return Cash Collateral		107		104
Regulatory Liabilities		161		174
Other		190		229

Total Current Liabilities		1,958		1,759

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC		3,690		3,127
Other Postretirement Benefit (OPEB) Costs		743		770
Accrued Pension Costs		18		377
Regulatory Liabilities		235		285
Regulatory Liabilities of VIEs		9		8
Clean Energy Program		70		235
Environmental Costs		600		617
Asset Retirement Obligations		223		216
Derivative Contracts		11		0
Long-Term Accrued Taxes		54		74
Other		21		23

Total Noncurrent Liabilities		5,674		5,732

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt		3,971		4,019
Securitization Debt of VIEs		784		939

Total Long-Term Debt		4,755		4,958

STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2011 and 2010—132,450,344 shares		892		892
Contributed Capital		420		420
Basis Adjustment		986		986
Retained Earnings		2,548		2,126
Accumulated Other Comprehensive Income		2		0

Total Stockholder’s Equity		4,848		4,424

Total Capitalization		9,603		9,382

TOTAL LIABILITIES AND CAPITALIZATION	$	17,235	$	16,873

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

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)


	For The Nine Months Ended September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	422		$	276
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		548			563
Provision for Deferred Income Taxes and ITC		563			41
Non-Cash Employee Benefit Plan Costs		92			162
Cost of Removal		(43	)		(47	)
Market Transition Charge (MTC) Refund		(47	)		98
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs		100			35
Over (Under) Recovery of SBC		(26	)		(55	)
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues		261			117
Materials and Supplies		(1	)		(17	)
Prepayments		(203	)		(126	)
Net Change in Tax Receivable		(21	)		0
Accounts Receivable/Payable-Affiliated Companies, net		(381	)		(318	)
Other Current Assets and Liabilities		(66	)		19
Employee Benefit Plan Funding and Related Payments		(311	)		(305	)
Other		(15	)		(16	)

Net Cash Provided By (Used In) Operating Activities		872			427

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment		(939	)		(871	)
Proceeds from Sales of Available-for-Sale Securities		0			54
Investments in Available-for-Sale Securities		0			(54	)
Solar Loan Investments		(34	)		(11	)
Other		(1	)		(4	)

Net Cash Provided By (Used In) Investing Activities		(974	)		(886	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt		250			1,014
Redemption of Long-Term Debt		0			(300	)
Redemption of Securitization Debt		(147	)		(140	)
Redemption of Preferred Securities		0			(80	)
Common Stock Dividend		0			(150	)
Other		(4	)		(10	)

Net Cash Provided By (Used In) Financing Activities		99			334

Net Increase (Decrease) In Cash and Cash Equivalents		(3	)		(125	)
Cash and Cash Equivalents at Beginning of Period		245			240

Cash and Cash Equivalents at End of Period	$	242		$	115

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(44	)	$	182
Interest Paid, Net of Amounts Capitalized	$	225		$	213

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.

•

PSEG Services Corporation (Services)—which provides management and 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, 2010 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2010.

During 2011, Power sold its two generating facilities located in Texas that were owned and operated by its subsidiary, PSEG Texas. As a result, amounts related to these plants were reclassified as Discontinued Operations in the financial statements. See Note 4. Discontinued Operations and Dispositions for additional information.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 2. Recent Accounting Standards

New Standard Adopted during 2011

Revenue Arrangements with Multiple Deliverables

•

amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist,

•

establishes a selling price hierarchy, such as, “vendor-specific objective evidence,” “third-party evidence” and “estimated selling price” for determining the selling price of a deliverable, and

•

provides guidance for allocating and recognizing revenue based on separate deliverables.

We adopted this standard, prospectively, effective January 1, 2011, for new and significantly modified revenue arrangements. Upon adoption, there was no material impact on our financial statements and we do not anticipate any changes to the pattern or general timing of revenue recognition for our significant units of account in future periods.

New Accounting Standards Issued But Not Yet Adopted

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.

This guidance is effective for interim and annual periods beginning after December 15, 2011. We believe our adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows; however, it will result in expanded disclosures.

Presentation of Comprehensive Income

This accounting standard was issued on 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.

This guidance is effective for fiscal years and interim periods beginning after December 15, 2011. We believe that the adoption of the new guidance on January 1, 2012 will not have an impact on our consolidated financial position, results of operations or cash flows, but will change the presentation of the components of other comprehensive income.

Testing Goodwill for Impairment

This accounting standard was issued to simplify testing for goodwill impairment. The updated guidance allows an entity to first perform a qualitative assessment to determine if it is more likely than not that the fair value of the reporting unit is less than its carrying value. Only if it is concluded that this is the case is it necessary to perform the two-step goodwill impairment test.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Earlier adoption is permitted. We believe that if we adopt the new optional guidance, it will not have a material impact on our consolidated financial position, results of operations or cash flows.

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 September 30, 2011 and December 31, 2010. 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 nine months of 2011 or in 2010. 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 purchase 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 a total purchase price of $335 million, resulting in an after-tax gain of $25 million. The closing of the Odessa sale completed the Texas asset sale process announced by Power in early 2011.

PSEG Texas’ operating results for the three months and nine months ended September 30, 2011 and 2010, which were reclassified to Discontinued Operations, are summarized below:


	Three Months Ended, September 30,				Nine Months Ended, September 30,
	2011		2010		2011		2010
	Millions
Operating Revenues	$	20	$	140	$	112	$	341
Income (Loss ) Before Income Taxes	$	6	$	31	$	26	$	25
Net Income (Loss)	$	4	$	20	$	17	$	15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The carrying amounts of PSEG Texas’ assets and liabilities as of December 31, 2010 are summarized in the following table:


	As of December 31,
	2010
	Millions
Current Assets	$	28
Noncurrent Assets		536

Total Assets of Discontinued Operations	$	564

Current Liabilities	$	28
Noncurrent Liabilities		44

Total Liabilities of Discontinued Operations	$	72

Dispositions

Leveraged Leases

During the first nine months of 2010, Energy Holdings sold its interest in five leveraged leases, including four international leases for which the IRS has indicated its intention to disallow certain tax deductions taken in prior years.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2010		2010
	Millions
Proceeds from Sales	$	204	$	365
Gains on Sales, after-tax	$	15	$	27

Proceeds from the sales of the international leases were used to reduce the tax exposure related to these lease investments. For additional information see Note 8. Commitments and Contingent Liabilities.

Note 5. Financing Receivables

PSE&G

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


Credit Risk Profile Based on Payment Activity	As of		As of
	September 30,		December 31,
Consumer Loans	2011		2010
	Millions
Commercial/Industrial	$	86	$	62
Residential		7		4

	$	93	$	66

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 September 30, 2011 and December 31, 2010, respectively.


	As of September 30,			As of December 31,
	2011			2010
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	763		$	896
Estimated Residual Value of Leased Assets		684			905

		1,447			1,801
Unearned and Deferred Income		(450	)		(546	)

Gross Investments in Leases		997			1,255
Deferred Tax Liabilities		(804	)		(899	)

Net Investment in Leases	$	193		$	356

Note: The above table does not include $264 million of Gross Investment in Leases to subsidiaries of Dynegy Incorporated (Dynegy) as of September 30, 2011 as we have fully reserved our Gross Investment in the Dynegy leases.

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 September 30,		As of December 31,
Counterparties’ Credit Rating (S&P)	2011		2010
	Millions
AAA - AA	$	21	$	21
A		110		112
BBB - BB		316		316
B - B-		300		430
Not Rated		16		17

	$	763	$	896

Note: The above table does not include $121 million of lease receivables as of September 30, 2011 related to subsidiaries of Dynegy as we fully reserved our Gross Investments in the Dynegy leases.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The “B” and “B-” ratings above represent lease receivables underlying coal fired assets in Illinois and Pennsylvania. As of September 30, 2011, the gross investment in the leases of such assets, net of non-recourse debt, was $550 million ($54 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

Rating

Counterparty

Millions

Powerton Station Units 5 and 6

135

64%

1,538

Coal

B-

Edison Mission Energy

Joliet Station Units 7 and 8

64%

1,044

Coal

B-

Edison Mission Energy

Keystone Station Units 1 and 2

112

17%

1,711

Coal

GenOn REMA, LLC

Conemaugh Station Units 1 and 2

112

17%

1,711

Coal

GenOn REMA, LLC

Shawville Station Units 1, 2, 3 and 4

107

100%

603

Coal

GenOn REMA, LLC

Although all payments of equity rent, debt service and other fees are current, no assurances can be given that all payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flow 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.

The credit exposure to the 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, over-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 and similar cash flow restrictions if ratings are not maintained at stated levels. 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 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 of the lease. 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.

Energy Holdings’ collateral related to the lease to two affiliates (the Dynegy lessees) of Dynegy Incorporated (Dynegy), includes a guarantee from Dynegy Holdings LLC (DH), a subsidiary of Dynegy. In early August 2011, Dynegy reorganized the legal entity structure for its generation assets. It transferred substantially all of its coal and natural gas-fired generation assets, other than the Dynegy lessees that lease the Roseton Station Units 1 and 2 and Danskammer Station Units 3 and 4, to new subsidiaries which Dynegy termed as “bankruptcy remote”. This resulted in a lowering of certain credit ratings of Dynegy and DH. Dynegy’s credit is currently rated “CC” by S&P and “Caa3” by Moody’s. On July 22, 2011, subsidiaries of Energy Holdings that hold the lessor interests filed a lawsuit in Delaware Chancery Court to halt the proposed transfer of assets to the new subsidiaries alleging that the proposed transfers would violate DH’s obligations under its Roseton and Danskammer guarantees. The request for a temporary restraining order was denied on July 29, 2011 and on August 5, 2011, the Delaware Supreme Court denied Energy Holdings’ application for certification of an interlocutory appeal and motions to expedite and for injunctive relief. Thereafter on August 8, 2011, Energy Holdings voluntarily dismissed this lawsuit without prejudice.

In September 2011, Dynegy continued its corporate reorganization, transferring DH’s interests in its newly formed coal generation subsidiary directly to the parent company, Dynegy, in exchange for an undertaking. It

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

also launched an exchange offer for a substantial portion of DH’s debt in exchange for Dynegy debt at various discounts. Dynegy has indicated that in the absence of a debt restructuring and/or refinancing, it may not have sufficient resources to pay its indebtedness under the lease. The consummation of these transactions triggered the filing of two separate lawsuits, one by a group of corporate unsecured bondholders of DH and a second on behalf of a majority of the holders of certain debt certificates related to the Dynegy lessee facilities; these lawsuits asserted fraudulent conveyance claims among several other causes of action. In addition to claims asserted against DH, one of the suits included claims against several members of DH’s Board of Directors.

As a result of the above actions, Energy Holdings has evaluated its likely recovery under the lease arrangements for the Roseton and Danskammer facilities leased to subsidiaries of DH, considering the overall value of the underlying assets subject to lease, and has fully reserved its $264 million gross investment. This gross charge is reflected as a reduction to Operating Revenues and resulted in an after-tax charge of approximately $170 million. In the absence of a negotiated resolution of the disputes with Dynegy, Energy Holdings intends to assert claims against DH, its directors and various Dynegy affiliates relative to the reorganization activities which have diminished the value of assets available to satisfy DH’s lease guarantee obligations. In addition, Energy Holdings has a tax indemnity agreement, which is designed to protect it from adverse tax consequences should the lease structure not be maintained. Should there be adverse consequences, Energy Holdings intends to assert its claims under this agreement, notwithstanding any attempt by Dynegy in contravention of current case law to limit such claims in a bankruptcy proceeding of DH. In the event of a bankruptcy filing or the failure of DH to honor its obligations under the lease guarantee, it is possible that the lease certificate holders could foreclose on the underlying facilities in partial satisfaction of their indebtedness. Should this occur, Energy Holdings could be required to pay approximately $100 million to satisfy income tax obligations, an amount for which it would seek reimbursement from DH under the tax indemnity agreement. This potential cash tax obligation is fully reflected in the overall estimate of the aggregate after-tax charge.

Note 6. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Funds

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 funds as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT funds:


	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	537	$	93	$	(55	)	$	575

Debt Securities
Government Obligations		340		16		(1	)		355
Other Debt Securities		273		14		(3	)		284

Total Debt Securities		613		30		(4	)		639
Other Securities		66		0		0			66

Total Available-for-Sale Securities	$	1,216	$	123	$	(59	)	$	1,280

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
	Millions
Equity Securities	$	525	$	213	$	(3	)	$	735

Debt Securities
Government Obligations		301		6		(4	)		303
Other Debt Securities		247		10		(2	)		255

Total Debt Securities		548		16		(6	)		558
Other Securities		70		0		0			70

Total Available-for-Sale Securities	$	1,143	$	229	$	(9	)	$	1,363

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 September 30,		As of December 31,
	2011		2010
	Millions
Accounts Receivable	$	100	$	35
Accounts Payable	$	95	$	60

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


	As of September 30, 2011										As of December 31, 2010
	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)	$	252	$	(55	)	$	0	$	0		$	55	$	(3	)	$	0	$	0

Debt Securities
Government Obligations (B)		72		(1	)		2		0			106		(4	)		1		0
Other Debt Securities (C)		65		(2	)		6		(1	)		65		(1	)		8		(1	)

Total Debt Securities		137		(3	)		8		(1	)		171		(5	)		9		(1	)

Other Securities		1		0			0		0			0		0			0		0

Total Available-for-Sale Securities	$	390	$	(58	)	$	8	$	(1	)	$	226	$	(8	)	$	9	$	(1	)

(A)

Equity Securities—Investments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(B)

Debt Securities (Government)—Unrealized losses on Power’s NDT 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, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2011.

(C)

Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2011.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	Millions						Millions
Proceeds from Sales	$	431		$	302		$	1,088		$	728

Net Realized Gains (Losses)
Gross Realized Gains	$	26		$	26		$	121		$	86
Gross Realized Losses		(10	)		(8	)		(28	)		(31	)

Net Realized Gains	$	16		$	18		$	93		$	55

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 $32 million (after-tax) were recognized in Accumulated Other Comprehensive Income (OCI) on Power’s Condensed Consolidated Balance Sheet as of September 30, 2011. The available-for-sale debt securities held as of September 30, 2011 had the following maturities:


Time Frame	Fair Value
	Millions
Less than 1 Year	$	11
1 - 5 Years		141
6 - 10 Years		172
11 - 15 Years		43
16 - 20 Years		18
Over 20 Years		254

	$	639

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 OCI. In

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

2011, other-than-temporary impairments of $10 million were recognized on securities in the NDT funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost detail of the securities.

Rabbi Trusts

PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in grantor trusts commonly known as “Rabbi Trusts.” In August 2010, PSEG revised the asset structure of the Rabbi Trust and realized gains of $31 million as the investments were transitioned to a new asset allocation and investment manager. The new structure resulted in lower investment management fees.

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


	As of September 30, 2011
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		147		5		0		152

Total PSEG Available-for-Sale Securities	$	163	$	7	$	0	$	170


	As of December 31, 2010
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Estimated Fair Value
	Millions
Equity Securities	$	16	$	2	$	0	$	18
Debt Securities		142		0		0		142

Total PSEG Available-for-Sale Securities	$	158	$	2	$	0	$	160

The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For the nine months ended September 30, 2011, other-than-temporary impairments of $3 million were recognized on the bond portfolio of the Rabbi Trusts.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	Millions				Millions
Proceeds from Sales	$	0	$	158	$	0	$	158

Net Realized Gains (Losses)
Gross Realized Gains	$	0	$	31	$	0	$	31
Gross Realized Losses		0		0		0		0

Net Realized Gains (Losses)	$	0	$	31	$	0	$	31

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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


	As of September 30, 2011		As of December 31, 2010
	Millions
Power	$	33	$	32
PSE&G		57		54
Other		80		74

Total PSEG Available-for-Sale Securities	$	170	$	160

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. In early June 2011, PSEG amended certain provisions of its pension and OPEB plans, including revisions to the benefit formulas for certain participants of PSEG’s qualified and nonqualified pension and OPEB plans. The weighted average discount rate for the pension plans decreased from 5.51% to 5.31% while the discount rate for the OPEB plans decreased from 5.50% to 5.30%. The expected long-term rate of return on plan assets remained at 8.50%. The pension benefit and OPEB obligations, as well as the asset values, were re-measured as of May 31, 2011 (the closest month-end date to the time the revisions were made). As a result, the annual net periodic pension benefit cost for 2011 will decrease by $32 million and the 2011 annual net OPEB cost will decrease by $6 million compared to costs that would have been expensed in 2011 if PSEG did not re-measure. The re-measured pension projected benefit obligations and accumulated OPEB obligation as of May 31, 2011 were $4.3 billion and $1.2 billion, respectively. The year-to-date rate of return on plan assets through the May 31 remeasurement date was 6.70%.

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. The costs for January through May 2011 are calculated under the prior plans’ assumptions. The costs for June 2011 and subsequent months are being calculated under the revised plan provisions. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Pension and OPEB costs for PSEG are detailed as follows:


	Pension Benefits Three Months Ended September 30,						OPEB Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,						OPEB Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	22		$	21		$	3		$	4		$	69		$	65		$	10		$	12
Interest Cost		56			58			15			18			172			173			45			54
Expected Return on Plan Assets		(85	)		(67	)		(5	)		(4	)		(248	)		(200	)		(13	)		(11	)
Amortization of Net
Transition Obligation		0			0			1			6			0			0			4			20
Prior Service Cost (Credit)		(4	)		0			(4	)		4			(6	)		0			(10	)		10
Actuarial Loss		29			31			4			2			89			92			11			6

Net Periodic Benefit Cost		18			43			14			30			76			130			47			91
Effect of Regulatory Asset		0			0			5			5			0			0			15			15

Total Benefit Costs, Including Effect of Regulatory Asset	$	18		$	43		$	19		$	35		$	76		$	130		$	62		$	106

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


	Pension Benefits Three Months Ended September 30,				OPEB Three Months Ended September 30,				Pension Benefits Nine Months Ended September 30,				OPEB Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
	Millions
Power	$	6	$	13	$	3	$	4	$	24	$	40	$	9	$	13
PSE&G		9		24		16		30		41		72		51		90
Other		3		6		0		1		11		18		2		3

Total Benefit Costs	$	18	$	43	$	19	$	35	$	76	$	130	$	62	$	106

During the three months ended March 31, 2011, PSEG contributed its entire planned contributions for the year 2011 of $415 million and $11 million into its pension and postretirement healthcare plans, respectively.

Note 8. Commitments and Contingent Liabilities

Guaranteed Obligations—PSEG and Power

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

The face value of outstanding guarantees, current exposure and margin positions as of September 30, 2011 and December 31, 2010 are shown below:


	As of September 30, 2011			As of December 31, 2010
	Millions
Face Value of Outstanding Guarantees	$	1,758		$	1,936
Exposure under Current Guarantees	$	283		$	330
Letters of Credit Margin Posted	$	135		$	137
Letters of Credit Margin Received	$	53		$	109

Cash Deposited and Received
Counterparty Cash Margin Deposited	$	1		$	0
Counterparty Cash Margin Received		(5	)		(2	)
Net Broker Balance Deposited (Received)		37			(28	)
In the Event Power Were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	765		$	828
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,466		$	2,750
Additional Amounts Posted
Other Letters of Credit	$	99		$	98

Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Receivable.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

In addition, during 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. 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 April 2011, PSEG and Power entered into new 5-year credit agreements resulting in an increase of $650 million in Power’s total credit capacity.

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.

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

The United States Environmental Protection Agency (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 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 $86 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 71 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G’s former MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim.

In 2007, the EPA released a draft “Focused Feasibility Study” that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The 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. A revised focused feasibility study may be released as early as the second quarter of 2012.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 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 is participating in and partially funding 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 next 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

During the third quarter of 2011, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $643 million and $741 million from September 30, 2011 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $643 million on its Condensed Consolidated Balance Sheet as of September 30, 2011. Of this amount, $53 million was recorded in Other Current Liabilities and $590 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $643 million Regulatory Asset with respect to these costs.

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

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

In 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Power’s generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at the Hudson and Mercer facilities designed to meet targeted reductions in emissions of sulfur dioxide (SO₂), nitrogen oxide (NO_x ), particulate matter and mercury. Power completed the construction of all plant modifications by the end of 2010 at a cost of $1.3 billion. Performance testing to validate the agreed-upon emission reductions was completed in the second quarter of 2011 and all performance metrics were met.

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 proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which is expected to be finalized by December 2011. This regulation prescribes reduced levels of mercury and other hazardous air pollutants pursuant to the Clean Air Act. Until the final rule is adopted, the impact cannot be determined; however, if the rule is adopted as proposed, Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rule’s requirements. Some additional controls could be necessary at Power’s Connecticut facilities and some of its other New Jersey facilities, pending engineering evaluation. The impact to Power’s jointly owned coal fired generating facilities in Pennsylvania is under evaluation.

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 expects to achieve 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 has a significant impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW) by April 30, 2015. Power 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)

On July 6, 2011, the EPA issued the CSAPR. CSAPR limits power plant emissions in 27 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. Emission reductions will be governed by this rule beginning on January 1, 2012 for SO₂ and “annual NO_x” and May 1, 2012 for “Ozone season NO_x”. Certain states will be required to make additional SO₂ reductions in 2014.

PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. As 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.

New Jersey Industrial Site Recovery Act (ISRA)

Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability related to these obligations, which was included in Environmental Costs on Power’s and PSEG’s Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

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 impingement and entrainment mortality standards for existing cooling water intake structures with a design flow of more than 2 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. 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 or results of operations. 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 will be issued in substitution for the draft NJPDES permit issued in January 2010. 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.

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 18 MW in 2012. Total expenditures through September 30, 2011 were $94 million and are expected to continue through 2012. The actual increase in nominal capacity is under evaluation.

Power has begun expenditures in pursuit of additional output through an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power’s

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

share of the increased capacity is expected to be approximately 133 MW with an anticipated cost of approximately $400 million. Total expenditures through September 30, 2011 were $28 million and are expected to continue through 2016.

Connecticut

Power was selected by the Connecticut 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 is expected to be in service by June 2012. Power estimates the cost of these generating units to be $140 million to $150 million. Total capitalized expenditures through September 30, 2011 were $99 million, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power. The initial filing is expected to be made in the fourth quarter of 2011. Costs for this project will be recovered subject to regulatory review and approval.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. Construction began in the second quarter of 2011. The projects are expected to be in service by June 2012. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Capacity in the amount of 267 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 and 2014-2015 periods. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through September 30, 2011 were $148 million which are included in Property, Plant and Equipment on Power’s and PSEG’s Condensed Consolidated Balance Sheets.

PSE&G—Solar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&G’s commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units PSE&G estimates the total cost of this project to be $264 million. Approximately 23 MW have been installed as of September 30, 2011. PSE&G’s cumulative investments for these solar units were approximately $164 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 $189 million. Through September 30, 2011, 23 MW representing 15 projects were placed into service with an investment of approximately $116 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 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.

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

Auction Year

2008

2009

2010

2011

36-Month Terms Ending

May 2011

May 2012

May 2013

May 2014

(A)

Load (MW)

2,800

2,900

2,800

$ per kWh

0.11150

0.10372

0.09577

0.09430

(A)	Prices set in the 2011 BGS auction became effective on June 1, 2011 when the 2008 BGS auction agreements expired.

PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. For additional information, see Note 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 and oil to support its fossil generation stations and for supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations and for firm transportation and storage capacity for natural gas.

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

Power’s strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2013 and a portion for 2014 through 2015 at Salem, Hope Creek and Peach Bottom.

As of September 30, 2011, the total minimum purchase requirements included in these commitments were as follows:


Fuel Type	Commitments through 2015 Power’s Share
	Millions
Nuclear Fuel
Uranium	$	493
Enrichment	$	383
Fabrication	$	130
Natural Gas	$	903
Coal/Oil	$	896

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Included in the $896 million commitment for coal is $647 million related to a certain coal contract under which Power can cancel future contractual deliveries at no cost. In 2011, Power has not cancelled any related coal deliveries.

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. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

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

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G’s motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. In June 2011, the plaintiff/petitioner filed a notice of appeal of the BPU action with the Appellate Division. A briefing schedule has been established.

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 discounted liability of $294 million as of September 30, 2011. Of this amount, $224 million was recorded as a current liability and $70 million as a noncurrent liability. 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. It has no impact on current SBC assessments.

Long-Term Capacity Agreement Pilot Program (LCAPP)

In January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of approximately 1,949 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, executed standard offer capacity agreements (SOCA) with each of the three selected generators in compliance with the BPU’s directive, but did so under protest preserving its respective legal rights. The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The LCAPP Act and the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. PSE&G will not make or receive payments under the three contracts unless (1) the plant successfully bids into and clears the capacity auction, and (2) the proposed plant is constructed. In April 2011, the BPU approved the executed contracts. Both PSE&G and Power joined other parties, including the EDCs, and appealed the BPU’s implementation of the LCAPP Act to the Appellate Division. The Division of Rate Counsel filed a motion to dismiss the EDCs’ appeal, which was denied by the Appellate Division.

Leveraged Lease Investments

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

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

In order to reduce the cash tax exposure related to these leases, Energy Holdings pursued opportunities to terminate international leases with lessees that were willing to meet certain economic thresholds. As of December 31, 2010, Energy Holdings had terminated all of these leasing transactions and reduced the related cash tax exposure by $1.1 billion. PSEG has completely eliminated its gross investment in such transactions.

Cash Impact

As of September 30, 2011, an aggregate of approximately $266 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, eliminating its cash exposure completely. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. Penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure will grow at an average rate of $2 million per quarter during 2011. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $20 million to $40 million of tax would be due for tax positions through September 30, 2011.

Unless this matter is resolved with the IRS, PSEG currently anticipates that it may be required to pay between $110 million and $300 million in tax, interest and penalties for the tax years 1997-2000 during 2011 and subsequently commence litigation to recover those amounts. It is possible that an additional payment of between $220 million and $560 million could be required during 2011 for tax years 2001-2003 followed by further litigation to recover those amounts. The amounts that may be required to litigate differ from the potential net cash exposure noted above, as the former amounts include all potential deficiencies for only contested tax years 1997 through 2003. These litigation amounts also include penalties which are not included in the computation of potential net cash exposure as PSEG believes it has strong defenses. These amounts also

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

exclude an offset for taxes paid on lease terminations, which is netted in the potential net cash exposure as PSEG would be entitled to a refund of such amounts under a loss scenario. Any potential claims PSEG would make to recover such amounts would include the deposit noted above.

Earnings Impact

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

Note 9. Changes in Capitalization

The following capital transactions occurred in the first nine months of 2011:

Power

•

issued $250 million of 2.75% Senior Notes due September 2016 in September,

•

issued $250 million of 4.15% Senior Notes due September 2021 in September,

•

paid $606 million of 7.75% Senior Notes at maturity in April, and

•

paid cash dividends of $350 million to PSEG.

PSE&G

•

issued $250 million of 0.85% Medium Term Notes due August 2014 in August, and

•

paid $142 million of Transition Funding’s securitization debt, and

•

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

Energy Holdings

•

paid $1 million of nonrecourse project debt.

PSE&G

In addition, $164 million of tax-exempt bonds of the Pollution Control Financing Authority of Salem County (Authority Bonds), which are serviced and secured by PSE&G’s first mortgage bonds of like tenor, are subject to a mandatory put in November 2011. PSE&G intends to buy the Authority Bonds in on their mandatory put date. The Authority Bonds had an initial term rate of 0.95%.

Also, $100 million of tax-exempt bonds of the New Jersey Economic Development Authority (EDA Bonds), which are serviced and secured by PSE&G’s first mortgage bonds of like tenor, are subject to a mandatory put in December 2011. PSE&G intends to buy the EDA Bonds in on their mandatory put date. The EDA Bonds had an initial term rate of 1.20%.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 and

•

the price of fuel to meet its fuel purchase requirements.

These derivative transactions are designated and effective as cash flow hedges. As of September 30, 2011 and December 31, 2010, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:


	As of September 30, 2011		As of December 31, 2010
	Millions
Fair Value of Cash Flow Hedges	$	79	$	196
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	34	$	114

The expiration date of the longest-dated cash flow hedge at Power is in 2013. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $33 million. There was ineffectiveness of $3 million associated with these hedges as of September 30, 2011.

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 are 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 only enter into transactions that are associated with the output or fuel purchase requirements of its facilities.

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These asset backed 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. The fair value of these contracts as of September 30, 2011 and December 31, 2010 was $19 million and $(4) million, respectively.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. Since 2009, PSEG has entered into eleven interest rate swaps totaling $1.4 billion. These swaps convert $300 million of Power’s $600 million of 6.95% Senior Notes due June 2012, 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 September 30, 2011 and December 31, 2010, the fair value of all the underlying hedges was $66 million and $39 million, respectively.

Cash Flow Hedges

PSEG and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of September 30, 2011, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of September 30, 2011 and December 31, 2010. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(3) million and $(3) million as of September 30, 2011 and December 31, 2010, respectively.

Fair Values of Derivative Instruments

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


	As of September 30, 2011
	Power												PSE&G			PSEG			Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			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	$	76		$	232		$	(213	)	$	95		$	0		$	18		$	113
Noncurrent Assets		7			44			(27	)		24			0			51			75

Total Mark-to-Market Derivative Assets	$	83		$	276		$	(240	)	$	119		$	0		$	69		$	188

Derivative Contracts
Current Liabilities	$	(2	)	$	(281	)	$	204		$	(79	)	$	(15	)	$	0		$	(94	)
Noncurrent Liabilities		(2	)		(41	)		26			(17	)		(11	)		(3	)		(31	)

Total Mark-to-Market Derivative (Liabilities)	$	(4	)	$	(322	)	$	230		$	(96	)	$	(26	)	$	(3	)	$	(125	)

Total Net Mark-to-Market Derivative Assets (Liabilities)	$	79		$	(46	)	$	(10	)	$	23		$	(26	)	$	66		$	63

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


	As of December 31, 2010
	Power												PSE&G			PSEG		Consolidated
	Cash Flow Hedges			Non Hedges			Netting (A)			Total Power			Non Hedges			FairValue 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	$	204		$	403		$	(444	)	$	163		$	0		$	19	$	182
Noncurrent Assets		3			80			(41	)		42			17			20		79

Total Mark-to-Market Derivative Assets	$	207		$	483		$	(485	)	$	205		$	17		$	39	$	261

Derivative Contracts
Current Liabilities	$	(11	)	$	(454	)	$	374		$	(91	)	$	(12	)	$	0	$	(103	)
Noncurrent Liabilities		0			(72	)		50			(22	)		0			0		(22	)

Total Mark-to-Market Derivative (Liabilities)	$	(11	)	$	(526	)	$	424		$	(113	)	$	(12	)	$	0	$	(125	)

Total Net Mark-to-Market Derivative Assets (Liabilities)	$	196		$	(43	)	$	(61	)	$	92		$	5		$	39	$	136

(A)

Represents the netting of fair value balances with the same counterparty and the application of collateral. As of September 30, 2011 and December 31, 2010, net cash collateral received of $10 million and $61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $10 million as of September 30, 2011, cash collateral of $(9) million and $(1) million were netted against current assets and noncurrent assets, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively.

The aggregate fair value of energy-related contracts in a liability position as of September 30, 2011 that contain triggers for additional collateral was $182 million. This potential additional collateral is included in the $765 million 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 September 30, 2011 and 2010:


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 September 30,					Three Months Ended September 30,					Three Months Ended September 30,
	2011		2010			2011		2010			2011		2010
	Millions
PSEG
Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0
Interest Rate Swaps		0		0	Interest Expense		0		0			0		0

Total PSEG	$	21	$	62		$	60	$	60		$	0	$	0

Power

Energy-Related Contracts	$	21	$	62	Operating Revenues	$	60	$	60	Operating Revenues	$	0	$	0
Energy-Related Contracts		0		0	Energy Costs		0		0			0		0

Total Power	$	21	$	62		$	60	$	60		$	0	$	0

The following shows the effect on the Condensed Consolidated Statements of Operations and on AOCI of derivative instruments designated as cash flow hedges for the nine months ended September 30, 2011 and 2010:

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)

Nine Months
Ended
September 30,

2011

2010

2011

2010

2011

2010

Millions

PSEG (A)

Energy-Related Contracts

171

Operating Revenues

152

178

Operating Revenues