any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe andreliable service to our customers, and any inability to obtain sufficient coverage or recover proceeds of insurance onwith respect to such ~~matters,~~events,

acts of terrorism, cybersecurity attacks or intrusions that could adversely impact our businesses,

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

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

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

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

changes in technology, such as distributed generation and ~~microgrids,~~micro grids, and ~~resultant~~greater reliance on these technologies and changes in customer ~~usage patterns,~~behaviors, including energy efficiency, net-metering and demand response.

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

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

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions, except per share data

(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
OPERATING REVENUES $ 2,554
$ 2,402
$ 7,650
$ 7,375

OPERATING EXPENSES
Energy Costs 801
879
2,711
2,819

Operation and Maintenance 713
619
2,069
1,876

Depreciation and Amortization 313
286
886
797

Taxes Other Than Income Taxes 15
24
50
73

Total Operating Expenses 1,842
1,808
5,716
5,565

OPERATING INCOME 712
594
1,934
1,810

Income from Equity Method Investments 4
7
9
9

Other Income 59
121
172
216

Other Deductions (12 ) (26 ) (54 ) (61 )
Other-Than-Temporary Impairments (3 ) (2 ) (7 ) (14 )
Interest Expense (100 ) (106 ) (303 ) (310 )
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 660
588
1,751
1,650

Income Tax Expense (270 ) (241 ) (708 ) (599 )
NET INCOME $ 390
$ 347
$ 1,043
$ 1,051

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC 505,858
505,914
505,900
505,942

DILUTED 507,694
507,111
507,433
507,037

EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS $ 0.77
$ 0.69
$ 2.06
$ 2.08

NET INCOME $ 0.77
$ 0.69
$ 2.06
$ 2.08

DILUTED
INCOME FROM CONTINUING OPERATIONS $ 0.77
$ 0.68
$ 2.06
$ 2.07

NET INCOME $ 0.77
$ 0.68
$ 2.06
$ 2.07

DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.3600
$ 0.3550
$ 1.0800
$ 1.0650




		Three Months Ended
		March 31,
		2014			2013
	OPERATING REVENUES	$	3,223		$	2,786
	OPERATING EXPENSES
	Energy Costs	1,356			1,155
	Operation and Maintenance	856			710
	Depreciation and Amortization	306			290
	Taxes Other Than Income Taxes	—			21
	Total Operating Expenses	2,518			2,176
	OPERATING INCOME	705			610
	Income from Equity Method Investments	4			2
	Other Income	48			61
	Other Deductions	(12		)	(29		)
	Other-Than-Temporary Impairments	(2		)	(2		)
	Interest Expense	(97		)	(102		)
	INCOME BEFORE INCOME TAXES	646			540
	Income Tax Expense	(260		)	(220		)
	NET INCOME	$	386		$	320
	WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
	BASIC	506,077			505,942
	DILUTED	507,831			507,220
	NET INCOME PER SHARE:
	BASIC	$	0.76		$	0.63
`	DILUTED	$	0.76		$	0.63
	DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.37		$	0.36

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
NET INCOME $ 390
$ 347
$ 1,043
$ 1,051

Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(16), $5, $(27) and $(16) for the three and nine months ended 2013 and 2012, respectively 16
(10 ) 27
12

Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $8, $4 and $14 for the three and nine months ended 2013 and 2012, respectively (1 ) (10 ) (5 ) (20 )
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(6), $(5), $(20) and $(16) for the three and nine months ended 2013 and 2012, respectively 9
8
28
23

Other Comprehensive Income (Loss), net of tax 24
(12 ) 50
15

COMPREHENSIVE INCOME $ 414
$ 335
$ 1,093
$ 1,066




	Three Months Ended
	March 31,
	2014		2013
NET INCOME	$	386	$	320
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(3) and $(27) for 2014 and 2013, respectively	2		27
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(2) and $2 for 2014 and 2013, respectively	2		(4		)
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(2) and $(7) for 2014 and 2013, respectively	4		10
Other Comprehensive Income (Loss), net of tax	8		33
COMPREHENSIVE INCOME	$	394	$	353

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

September 30,
2013 December 31,
2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 448
$ 379

Accounts Receivable, net of allowances of $57 and $56 in 2013 and 2012, respectively 1,069
1,069

Tax Receivable 225
227

Unbilled Revenues 211
314

Fuel 599
583

Materials and Supplies, net 450
422

Prepayments 210
283

Derivative Contracts 107
138

Deferred Income Taxes 31
49

Regulatory Assets 348
349

Other 43
56

Total Current Assets 3,741
3,869

PROPERTY, PLANT AND EQUIPMENT 29,206
27,402

Less: Accumulated Depreciation and Amortization (8,127 ) (7,666 )
Net Property, Plant and Equipment 21,079
19,736

NONCURRENT ASSETS
Regulatory Assets 3,519
3,830

Regulatory Assets of Variable Interest Entities (VIEs) 532
713

Long-Term Investments 1,320
1,324

Nuclear Decommissioning Trust (NDT) Fund 1,635
1,540

Other Special Funds 181
191

Goodwill 16
16

Other Intangibles 52
34

Derivative Contracts 184
153

Restricted Cash of VIEs 23
23

Other 328
296

Total Noncurrent Assets 7,790
8,120

TOTAL ASSETS $ 32,610
$ 31,725




	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	655		$	493
Accounts Receivable, net of allowances of $61 and $56 in 2014 and 2013, respectively	1,710			1,203
Tax Receivable	111			109
Unbilled Revenues	261			300
Fuel	271			545
Materials and Supplies, net	475			479
Prepayments	55			89
Derivative Contracts	43			98
Deferred Income Taxes	114			24
Regulatory Assets	125			243
Other	33			31
Total Current Assets	3,853			3,614
PROPERTY, PLANT AND EQUIPMENT	30,152			29,713
Less: Accumulated Depreciation and Amortization	(8,219		)	(8,068		)
Net Property, Plant and Equipment	21,933			21,645
NONCURRENT ASSETS
Regulatory Assets	2,570			2,612
Regulatory Assets of Variable Interest Entities (VIEs)	414			476
Long-Term Investments	1,321			1,313
Nuclear Decommissioning Trust (NDT) Fund	1,734			1,701
Long-Term Receivable of VIE	418			—
Other Special Funds	635			613
Goodwill	16			16
Other Intangibles	48			33
Derivative Contracts	47			163
Restricted Cash of VIEs	24			24
Other	313			312
Total Noncurrent Assets	7,540			7,263
TOTAL ASSETS	$	33,326		$	32,522

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

September 30,
2013 December 31,
2012
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 775
$ 1,026

Securitization Debt of VIEs Due Within One Year 235
226

Commercial Paper and Loans —
263

Accounts Payable 1,024
1,304

Derivative Contracts 36
46

Accrued Interest 114
91

Accrued Taxes 83
17

Deferred Income Taxes 48
72

Clean Energy Program 185
153

Obligation to Return Cash Collateral 118
122

Regulatory Liabilities 171
67

Other 446
390

Total Current Liabilities 3,235
3,777

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC) 6,807
6,542

Regulatory Liabilities 213
209

Regulatory Liabilities of VIEs 11
10

Asset Retirement Obligations 653
627

Other Postretirement Benefit (OPEB) Costs 1,274
1,285

Accrued Pension Costs 710
876

Environmental Costs 431
537

Derivative Contracts 163
122

Long-Term Accrued Taxes 183
164

Other 115
108

Total Noncurrent Liabilities 10,560
10,480

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

CAPITALIZATION
LONG-TERM DEBT

Long-Term Debt 7,134
6,148

Securitization Debt of VIEs 326
496

Project Level, Non-Recourse Debt 16
43

Total Long-Term Debt 7,476
6,687

STOCKHOLDERS’ EQUITY

Common Stock, no par, authorized 1,000,000,000 shares; issued, 2013 and 2012—533,556,660 shares 4,852
4,833

Treasury Stock, at cost, 2013— 27,695,398 shares; 2012— 27,664,188 shares (615 ) (607 )
Retained Earnings 7,439
6,942

Accumulated Other Comprehensive Loss (338 ) (388 )
Total Common Stockholders’ Equity 11,338
10,780

Noncontrolling Interest 1
1

Total Stockholders’ Equity 11,339
10,781

Total Capitalization 18,815
17,468

TOTAL LIABILITIES AND CAPITALIZATION $ 32,610
$ 31,725




	March 31, 2014			December 31, 2013
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	544		$	544
Securitization Debt of VIEs Due Within One Year	242			237
Commercial Paper and Loans	—			60
Accounts Payable	1,116			1,222
Derivative Contracts	75			76
Accrued Interest	112			95
Accrued Taxes	311			37
Clean Energy Program	85			142
Obligation to Return Cash Collateral	134			119
Regulatory Liabilities	159			43
Other	579			488
Total Current Liabilities	3,357			3,063
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	7,148			7,107
Regulatory Liabilities	172			233
Regulatory Liabilities of VIEs	11			11
Asset Retirement Obligations	687			677
Other Postretirement Benefit (OPEB) Costs	1,081			1,095
OPEB Costs of Servco	307			—
Accrued Pension Costs	122			121
Accrued Pension Costs of Servco	109			—
Environmental Costs	400			414
Derivative Contracts	28			31
Long-Term Accrued Taxes	186			180
Other	116			119
Total Noncurrent Liabilities	10,367			9,988
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt	7,586			7,587
Securitization Debt of VIEs	200			259
Project Level, Non-Recourse Debt	16			16
Total Long-Term Debt	7,802			7,862
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2014 and 2013—533,556,660 shares	4,856			4,861
Treasury Stock, at cost, 2014— 27,680,836 shares; 2013— 27,699,398 shares	(626		)	(615		)
Retained Earnings	7,656			7,457
Accumulated Other Comprehensive Loss	(87		)	(95		)
Total Common Stockholders’ Equity	11,799			11,608
Noncontrolling Interest	1			1
Total Stockholders’ Equity	11,800			11,609
Total Capitalization	19,602			19,471
TOTAL LIABILITIES AND CAPITALIZATION	$	33,326		$	32,522

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

Nine Months Ended
September 30,
2013 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 1,043
$ 1,051

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 886
797

Amortization of Nuclear Fuel 145
129

Provision for Deferred Income Taxes (Other than Leases) and ITC 242
221

Non-Cash Employee Benefit Plan Costs 182
203

Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes (7 ) (81 )
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives 3
116

Change in Accrued Storm Costs (87 ) 5

Net Change in Other Regulatory Assets and Liabilities 134
(82 )
Cost of Removal (66 ) (71 )
Net Realized (Gains) Losses and (Income) Expense from NDT Fund (76 ) (107 )
Net Change in Tax Receivable 2
16

Net Change in Certain Current Assets and Liabilities 173
305

Employee Benefit Plan Funding and Related Payments (210 ) (193 )
Other 71
2

Net Cash Provided By (Used In) Operating Activities 2,435
2,311

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (2,102 ) (1,969 )
Proceeds from Sale of Capital Leases and Investments 42
—

Proceeds from Sales of Available-for-Sale Securities 914
1,473

Investments in Available-for-Sale Securities (922 ) (1,497 )
Other (20 ) (58 )
Net Cash Provided By (Used In) Investing Activities (2,088 ) (2,051 )
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans (263 ) —

Issuance of Long-Term Debt 1,500
850

Redemption of Long-Term Debt (750 ) (439 )
Redemption of Securitization Debt (162 ) (154 )
Repayment of Non-Recourse Debt —
(1 )
Cash Dividends Paid on Common Stock (546 ) (538 )
Other (57 ) (32 )
Net Cash Provided By (Used In) Financing Activities (278 ) (314 )
Net Increase (Decrease) in Cash and Cash Equivalents 69
(54 )
Cash and Cash Equivalents at Beginning of Period 379
834

Cash and Cash Equivalents at End of Period $ 448
$ 780

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 222
$ 109

Interest Paid, Net of Amounts Capitalized $ 274
$ 280

Accrued Property, Plant and Equipment Expenditures $ 258
$ 259




	Three Months Ended
	March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	386		$	320
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	306			290
Amortization of Nuclear Fuel	54			50
Provision for Deferred Income Taxes (Other than Leases) and ITC	(39		)	(5		)
Non-Cash Employee Benefit Plan Costs	11			61
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(22		)	(6		)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	224			165
Change in Accrued Storm Costs	(1		)	(46		)
Net Change in Other Regulatory Assets and Liabilities	177			80
Cost of Removal	(25		)	(24		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(23		)	(24		)
Net Change in Certain Current Assets and Liabilities	80			207
Employee Benefit Plan Funding and Related Payments	(32		)	(192		)
Other	20			1
Net Cash Provided By (Used In) Operating Activities	1,116			877
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(609		)	(724		)
Proceeds from Sales of Available-for-Sale Securities	257			258
Investments in Available-for-Sale Securities	(269		)	(271		)
Other	(8		)	4
Net Cash Provided By (Used In) Investing Activities	(629		)	(733		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(60		)	(98		)
Issuance of Long-Term Debt	—			400
Redemption of Long-Term Debt	—			(150		)
Redemption of Securitization Debt	(54		)	(51		)
Cash Dividends Paid on Common Stock	(187		)	(182		)
Other	(24		)	(22		)
Net Cash Provided By (Used In) Financing Activities	(325		)	(103		)
Net Increase (Decrease) in Cash and Cash Equivalents	162			41
Cash and Cash Equivalents at Beginning of Period	493			379
Cash and Cash Equivalents at End of Period	$	655		$	420
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	15		$	3
Interest Paid, Net of Amounts Capitalized	$	79		$	82
Accrued Property, Plant and Equipment Expenditures	$	247		$	265

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
OPERATING REVENUES $ 1,169
$ 1,038
$ 3,806
$ 3,584

OPERATING EXPENSES
Energy Costs 430
456
1,786
1,725

Operation and Maintenance 304
255
866
780

Depreciation and Amortization 66
60
195
175

Total Operating Expenses 800
771
2,847
2,680

OPERATING INCOME 369
267
959
904

Other Income 45
104
127
171

Other Deductions (11 ) (20 ) (49 ) (52 )
Other-Than-Temporary Impairments (3 ) (2 ) (7 ) (14 )
Interest Expense (26 ) (35 ) (85 ) (97 )
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 374
314
945
912

Income Tax Expense (153 ) (133 ) (383 ) (374 )
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 221
$ 181
$ 562
$ 538




	Three Months Ended
	March 31,
	2014			2013
OPERATING REVENUES	$	1,700		$	1,451
OPERATING EXPENSES
Energy Costs	1,044			860
Operation and Maintenance	302			283
Depreciation and Amortization	72			66
Total Operating Expenses	1,418			1,209
OPERATING INCOME	282			242
Income from Equity Method Investments	4			3
Other Income	33			47
Other Deductions	(10		)	(28		)
Other-Than-Temporary Impairments	(2		)	(2		)
Interest Expense	(32		)	(30		)
INCOME BEFORE INCOME TAXES	275			232
Income Tax Expense	(111		)	(91		)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	164		$	141

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

Table of Contents

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
NET INCOME $ 221
$ 181
$ 562
$ 538

Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(18), $6, $(29) and $(16) for the three and nine months ended 2013 and 2012, respectively 17
(11 ) 30
11

Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $8, $4 and $14 for the three and nine months ended 2013 and 2012, respectively (1 ) (11 ) (6 ) (21 )
Pension/OPEB adjustment, net of tax (expense) benefit of $(6), $(4), $(17) and $(14) for the three and nine months ended 2013 and 2012, respectively 8
7
25
21

Other Comprehensive Income (Loss), net of tax 24
(15 ) 49
11

COMPREHENSIVE INCOME $ 245
$ 166
$ 611
$ 549




	Three Months Ended
	March 31,
	2014		2013
NET INCOME	$	164	$	141
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(2) and $(27) for 2014 and 2013, respectively	2		27
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1) and $2 for 2014 and 2013, respectively	1		(4		)
Pension/OPEB adjustment, net of tax (expense) benefit of $(2) and $(5) for 2014 and 2013, respectively	3		9
Other Comprehensive Income (Loss), net of tax	6		32
COMPREHENSIVE INCOME	$	170	$	173

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

Table of Contents

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

September 30,
2013 December 31,
2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 9
$ 7

Accounts Receivable 211
269

Accounts Receivable—Affiliated Companies, net 34
340

Short-Term Loan to Affiliate 417
574

Fuel 599
583

Materials and Supplies, net 329
307

Derivative Contracts 72
118

Prepayments 16
17

Deferred Income Taxes 3
—

Other —
19

Total Current Assets 1,690
2,234

PROPERTY, PLANT AND EQUIPMENT 10,035
9,697

Less: Accumulated Depreciation and Amortization (2,973 ) (2,679 )
Net Property, Plant and Equipment 7,062
7,018

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund 1,635
1,540

Goodwill 16
16

Other Intangibles 52
34

Other Special Funds 38
36

Derivative Contracts 89
49

Other 139
105

Total Noncurrent Assets 1,969
1,780

TOTAL ASSETS $ 10,721
$ 11,032




	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	10		$	6
Accounts Receivable	544			338
Accounts Receivable—Affiliated Companies, net	36			333
Short-Term Loan to Affiliate	942			790
Fuel	271			545
Materials and Supplies, net	347			362
Derivative Contracts	27			57
Prepayments	15			13
Deferred Income Taxes	105			30
Other	2			2
Total Current Assets	2,299			2,476
PROPERTY, PLANT AND EQUIPMENT	10,372			10,278
Less: Accumulated Depreciation and Amortization	(3,037		)	(2,911		)
Net Property, Plant and Equipment	7,335			7,367
NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund	1,734			1,701
Long-Term Investments	123			123
Goodwill	16			16
Other Intangibles	48			33
Other Special Funds	148			139
Derivative Contracts	9			72
Other	76			75
Total Noncurrent Assets	2,154			2,159
TOTAL ASSETS	$	11,788		$	12,002

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

Table of Contents

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

September 30,
2013 December 31,
2012
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ —
$ 300

Accounts Payable 404
498

Derivative Contracts 36
46

Deferred Income Taxes —
16

Accrued Interest 37
26

Other 109
81

Total Current Liabilities 586
967

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC) 1,732
1,575

Asset Retirement Obligations 385
369

Other Postretirement Benefit (OPEB) Costs 230
221

Derivative Contracts 23
15

Accrued Pension Costs 225
272

Long-Term Accrued Taxes 50
50

Other 90
84

Total Noncurrent Liabilities 2,735
2,586

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

LONG-TERM DEBT
Total Long-Term Debt 2,041
2,040

MEMBER’S EQUITY
Contributed Capital 2,028
2,028

Basis Adjustment (986 ) (986 )
Retained Earnings 4,596
4,725

Accumulated Other Comprehensive Loss (279 ) (328 )
Total Member’s Equity 5,359
5,439

TOTAL LIABILITIES AND MEMBER’S EQUITY $ 10,721
$ 11,032




	March 31, 2014			December 31, 2013
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	44		$	44
Accounts Payable	490			516
Derivative Contracts	67			76
Accrued Interest	43			28
Other	137			136
Total Current Liabilities	781			800
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	2,044			2,031
Asset Retirement Obligations	405			400
Other Postretirement Benefit (OPEB) Costs	209			206
Derivative Contracts	28			31
Accrued Pension Costs	35			35
Long-Term Accrued Taxes	49			53
Other	87			91
Total Noncurrent Liabilities	2,857			2,847
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT
Total Long-Term Debt	2,497			2,497
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,482			4,693
Accumulated Other Comprehensive Loss	(57		)	(63		)
Total Member’s Equity	5,653			5,858
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,788		$	12,002

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

Table of Contents

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

Nine Months Ended
September 30,
2013 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 562
$ 538

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 195
175

Amortization of Nuclear Fuel 145
129

Provision for Deferred Income Taxes and ITC 96
189

Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives 3
116

Non-Cash Employee Benefit Plan Costs 50
53

Net Realized (Gains) Losses and (Income) Expense from NDT Fund (76 ) (107 )
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies (38 ) (10 )
Margin Deposit 17
(107 )
Accounts Receivable 69
50

Accounts Payable (63 ) (31 )
Accounts Receivable/Payable-Affiliated Companies, net 306
193

Accrued Interest Payable 11
17

Other Current Assets and Liabilities 20
2

Employee Benefit Plan Funding and Related Payments (45 ) (40 )
Other 32
5

Net Cash Provided By (Used In) Operating Activities 1,284
1,172

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (419 ) (493 )
Proceeds from Sales of Available-for-Sale Securities 849
1,295

Investments in Available-for-Sale Securities (864 ) (1,315 )
Short-Term Loan—Affiliated Company, net 157
17

Other (13 ) (10 )
Net Cash Provided By (Used In) Investing Activities (290 ) (506 )
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid (690 ) (600 )
Redemption of Long-Term Debt (300 ) (66 )
Other (2 ) (7 )
Net Cash Provided By (Used In) Financing Activities (992 ) (673 )
Net Increase (Decrease) in Cash and Cash Equivalents 2
(7 )
Cash and Cash Equivalents at Beginning of Period 7
12

Cash and Cash Equivalents at End of Period $ 9
$ 5

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 107
$ 130

Interest Paid, Net of Amounts Capitalized $ 72
$ 73

Accrued Property, Plant and Equipment Expenditures $ 58
$ 84




	Three Months Ended
	March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	164		$	141
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	72			66
Amortization of Nuclear Fuel	54			50
Provision for Deferred Income Taxes and ITC	(71		)	(33		)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	224			165
Non-Cash Employee Benefit Plan Costs	3			17
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(23		)	(24		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	289			259
Margin Deposit	(261		)	(117		)
Accounts Receivable	(19		)	2
Accounts Payable	(70		)	(68		)
Accounts Receivable/Payable—Affiliated Companies, net	279			121
Accrued Interest Payable	15			15
Other Current Assets and Liabilities	(4		)	24
Employee Benefit Plan Funding and Related Payments	(2		)	(45		)
Other	24			2
Net Cash Provided By (Used In) Operating Activities	674			575
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(126		)	(151		)
Proceeds from Sales of Available-for-Sale Securities	247			244
Investments in Available-for-Sale Securities	(259		)	(256		)
Short-Term Loan—Affiliated Company, net	(152		)	(174		)
Other	(5		)	8
Net Cash Provided By (Used In) Investing Activities	(295		)	(329		)
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid	(375		)	(253		)
Contributed Capital	—			8
Other	—			(2		)
Net Cash Provided By (Used In) Financing Activities	(375		)	(247		)
Net Increase (Decrease) in Cash and Cash Equivalents	4			(1		)
Cash and Cash Equivalents at Beginning of Period	6			7
Cash and Cash Equivalents at End of Period	$	10		$	6
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(93	)	$	2
Interest Paid, Net of Amounts Capitalized	$	16		$	18
Accrued Property, Plant and Equipment Expenditures	$	62		$	41

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
OPERATING REVENUES $ 1,666
$ 1,683
$ 5,084
$ 5,029

OPERATING EXPENSES
Energy Costs 661
756
2,208
2,380

Operation and Maintenance 408
366
1,204
1,092

Depreciation and Amortization 236
216
658
594

Taxes Other Than Income Taxes 15
24
50
73

Total Operating Expenses 1,320
1,362
4,120
4,139

OPERATING INCOME 346
321
964
890

Other Income 13
16
41
39

Other Deductions (1 ) (6 ) (3 ) (8 )
Interest Expense (75 ) (73 ) (223 ) (220 )
INCOME BEFORE INCOME TAXES 283
258
779
701

Income Tax Expense (115 ) (103 ) (311 ) (248 )
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 168
$ 155
$ 468
$ 453




	Three Months Ended
	March 31,
	2014			2013
OPERATING REVENUES	$	2,145		$	1,995
OPERATING EXPENSES
Energy Costs	1,045			967
Operation and Maintenance	462			427
Depreciation and Amortization	227			215
Taxes Other Than Income Taxes	—			21
Total Operating Expenses	1,734			1,630
OPERATING INCOME	411			365
Other Income	14			13
Other Deductions	—			(1		)
Interest Expense	(68		)	(73		)
INCOME BEFORE INCOME TAXES	357			304
Income Tax Expense	(143		)	(125		)
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED	$	214		$	179

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
NET INCOME $ 168
$ 155
$ 468
$ 453

Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $(1), $1 and $0 for the three and nine months ended 2013 and 2012, respectively —
1
(1 ) —

COMPREHENSIVE INCOME $ 168
$ 156
$ 467
$ 453




	Three Months Ended
	March 31,
	2014		2013
NET INCOME	$	214	$	179
COMPREHENSIVE INCOME	$	214	$	179

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

September 30,
2013 December 31,
2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 253
$ 116

Accounts Receivable, net of allowances of $57 and $56 in 2013 and 2012, respectively 839
783

Accounts Receivable-Affiliated Companies, net 94
—

Unbilled Revenues 211
314

Materials and Supplies 118
114

Prepayments 138
29

Regulatory Assets 348
349

Derivative Contracts 19
5

Deferred Income Taxes 31
49

Other 24
24

Total Current Assets 2,075
1,783

PROPERTY, PLANT AND EQUIPMENT 18,503
17,006

Less: Accumulated Depreciation and Amortization (4,916 ) (4,726 )
Net Property, Plant and Equipment 13,587
12,280

NONCURRENT ASSETS
Regulatory Assets 3,519
3,830

Regulatory Assets of VIEs 532
713

Long-Term Investments 356
348

Other Special Funds 41
61

Derivative Contracts 69
62

Restricted Cash of VIEs 23
23

Other 128
123

Total Noncurrent Assets 4,668
5,160

TOTAL ASSETS $ 20,330
$ 19,223




	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	177		$	18
Accounts Receivable, net of allowances of $61 and $56 in 2014 and 2013, respectively	1,135			832
Unbilled Revenues	261			300
Materials and Supplies	126			115
Prepayments	6			24
Regulatory Assets	125			243
Derivative Contracts	—			25
Deferred Income Taxes	6			16
Other	14			12
Total Current Assets	1,850			1,585
PROPERTY, PLANT AND EQUIPMENT	19,424			19,071
Less: Accumulated Depreciation and Amortization	(4,993		)	(4,964		)
Net Property, Plant and Equipment	14,431			14,107
NONCURRENT ASSETS
Regulatory Assets	2,570			2,612
Regulatory Assets of VIEs	414			476
Long-Term Investments	367			361
Other Special Funds	362			354
Derivative Contracts	20			69
Restricted Cash of VIEs	24			24
Other	137			132
Total Noncurrent Assets	3,894			4,028
TOTAL ASSETS	$	20,175		$	19,720

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)

September 30,
2013 December 31,
2012
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 775
$ 725

Securitization Debt of VIEs Due Within One Year 235
226

Commercial Paper and Loans —
263

Accounts Payable 473
630

Accounts Payable—Affiliated Companies, net —
73

Accrued Interest 77
65

Clean Energy Program 185
153

Deferred Income Taxes 55
60

Obligation to Return Cash Collateral 118
122

Regulatory Liabilities 171
67

Other 306
269

Total Current Liabilities 2,395
2,653

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 4,354
4,223

Other Postretirement Benefit (OPEB) Costs 989
1,011

Accrued Pension Costs 360
463

Regulatory Liabilities 213
209

Regulatory Liabilities of VIEs 11
10

Environmental Costs 380
486

Asset Retirement Obligations 260
250

Derivative Contracts 140
107

Long-Term Accrued Taxes 48
32

Other 46
38

Total Noncurrent Liabilities 6,801
6,829

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt 5,066
4,070

Securitization Debt of VIEs 326
496

Total Long-Term Debt 5,392
4,566

STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2013 and 2012—132,450,344 shares 892
892

Contributed Capital 520
420

Basis Adjustment 986
986

Retained Earnings 3,343
2,875

Accumulated Other Comprehensive Income 1
2

Total Stockholder’s Equity 5,742
5,175

Total Capitalization 11,134
9,741

TOTAL LIABILITIES AND CAPITALIZATION $ 20,330
$ 19,223




	March 31, 2014		December 31, 2013
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	500	$	500
Securitization Debt of VIEs Due Within One Year	242		237
Commercial Paper and Loans	—		60
Accounts Payable	490		535
Accounts Payable—Affiliated Companies, net	293		190
Accrued Interest	69		67
Clean Energy Program	85		142
Derivative Contracts	8		—
Deferred Income Taxes	4		30
Obligation to Return Cash Collateral	134		119
Regulatory Liabilities	159		43
Other	410		314
Total Current Liabilities	2,394		2,237
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	4,450		4,406
Other Postretirement Benefit (OPEB) Costs	822		839
Accrued Pension Costs	27		27
Regulatory Liabilities	172		233
Regulatory Liabilities of VIEs	11		11
Environmental Costs	349		363
Asset Retirement Obligations	278		274
Long-Term Accrued Taxes	82		72
Other	48		47
Total Noncurrent Liabilities	6,239		6,272
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt	5,067		5,066
Securitization Debt of VIEs	200		259
Total Long-Term Debt	5,267		5,325
STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2014 and 2013—132,450,344 shares	892		892
Contributed Capital	695		520
Basis Adjustment	986		986
Retained Earnings	3,701		3,487
Accumulated Other Comprehensive Income	1		1
Total Stockholder’s Equity	6,275		5,886
Total Capitalization	11,542		11,211
TOTAL LIABILITIES AND CAPITALIZATION	$	20,175	$	19,720

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions

(Unaudited)

Nine Months Ended
September 30,
2013 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 468
$ 453

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 658
594

Provision for Deferred Income Taxes and ITC 153
131

Non-Cash Employee Benefit Plan Costs 117
134

Cost of Removal (66 ) (71 )
Change in Accrued Storm Costs (87 ) 5

Net Change in Other Regulatory Assets and Liabilities 134
(82 )
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues 48
97

Materials and Supplies (4 ) (11 )
Prepayments (109 ) (28 )
Net Change in Tax Receivable —
16

Accounts Payable 3
(20 )
Accounts Receivable/Payable-Affiliated Companies, net (171 ) (41 )
Other Current Assets and Liabilities 29
22

Employee Benefit Plan Funding and Related Payments (147 ) (137 )
Other 23
(21 )
Net Cash Provided By (Used In) Operating Activities 1,049
1,041

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (1,628 ) (1,369 )
Proceeds from Sales of Available-for-Sale Securities 35
73

Investments in Available-for-Sale Securities (16 ) (73 )
Solar Loan Investments (11 ) (56 )
Restricted Funds —
1

Net Cash Provided By (Used In) Investing Activities (1,620 ) (1,424 )
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt (263 ) —

Issuance of Long-Term Debt 1,500
850

Redemption of Long-Term Debt (450 ) (373 )
Redemption of Securitization Debt (162 ) (154 )
Contributed Capital 100
—

Other (17 ) (12 )
Net Cash Provided By (Used In) Financing Activities 708
311

Net Increase (Decrease) In Cash and Cash Equivalents 137
(72 )
Cash and Cash Equivalents at Beginning of Period 116
143

Cash and Cash Equivalents at End of Period $ 253
$ 71

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 174
$ (30 )
Interest Paid, Net of Amounts Capitalized $ 199
$ 205

Accrued Property, Plant and Equipment Expenditures $ 200
$ 175




	Three Months Ended
	March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	214		$	179
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	227			215
Provision for Deferred Income Taxes and ITC	31			29
Non-Cash Employee Benefit Plan Costs	6			39
Cost of Removal	(25		)	(24		)
Change in Accrued Storm Costs	(1		)	(46		)
Net Change in Other Regulatory Assets and Liabilities	177			80
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	(264		)	(200		)
Materials and Supplies	(11		)	(7		)
Prepayments	18			20
Accounts Payable	14			8
Accounts Receivable/Payable—Affiliated Companies, net	120			64
Other Current Assets and Liabilities	112			104
Employee Benefit Plan Funding and Related Payments	(29		)	(120		)
Other	(10		)	(12		)
Net Cash Provided By (Used In) Operating Activities	579			329
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(481		)	(572		)
Proceeds from Sales of Available-for-Sale Securities	5			6
Investments in Available-for-Sale Securities	(3		)	(6		)
Solar Loan Investments	(2		)	(7		)
Restricted Funds	—			1
Net Cash Provided By (Used In) Investing Activities	(481		)	(578		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	(60		)	(98		)
Issuance of Long-Term Debt	—			400
Redemption of Long-Term Debt	—			(150		)
Redemption of Securitization Debt	(54		)	(51		)
Contributed Capital	175			100
Other	—			(7		)
Net Cash Provided By (Used In) Financing Activities	61			194
Net Increase (Decrease) In Cash and Cash Equivalents	159			(55		)
Cash and Cash Equivalents at Beginning of Period	18			116
Cash and Cash Equivalents at End of Period	$	177		$	61
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(37	)	$	—
Interest Paid, Net of Amounts Capitalized	$	62		$	63
Accrued Property, Plant and Equipment Expenditures	$	185		$	224

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

Table of Contents

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 and energy trading functions through ~~three~~its 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 aan 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 the FERC. PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU.

PSEG's other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings)—, which primarily has investments in ~~leases and solar generation projects through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by the FERC and the states in~~leveraged leases; PSEG Long Island LLC (PSEG LI), which, ~~they operate. A subsidiary of Energy Holdings has been awarded a contract to manage the transmission and distribution assets of~~effective January 1, 2014, operates the Long Island Power ~~Authority~~Authority's (LIPA) ~~starting in 2014.~~

transmission and distribution (T&D) system under a twelve year Amended and Restated Operations Services Agreement (OSA); and PSEG Services Corporation (Services)—, which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, ~~2012~~ ~~and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and~~ ~~June 30,~~ 2013.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All significant intercompany accounts and transactions are eliminated in ~~consolidation, except as discussed in Note 18. Related-Party Transactions.~~consolidation. 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, ~~2012~~2013.

On December 31, 2013, Energy Holdings distributed the outstanding equity of its 50% interest in a partnership that owns and operates a generation facility in Hawaii and its wholly owned interest in PSEG Solar Source LLC to PSEG. PSEG in turn contributed this distribution to Power as an additional equity investment. This transaction was accounted for as a non-cash transfer of equity interest between entities under common control with prior period financial statements for Power retrospectively adjusted to include the earnings related to the transfer. As a result, Power’s Operating Revenues and Net Income for the three months ended March 31, 2013 each increased by $4 million.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 2. Recent Accounting Standards

New Standards Adopted during ~~2013~~

~~Disclosures about Offsetting Assets and Liabilities~~

This accounting standard requires enhanced disclosures regarding assets and liabilities that are either offset in the financial statements, or are subject to an enforceable master netting arrangement or similar agreement. The guidance is applicable to certain financial instruments (e.g. derivatives) and securities borrowing and lending transactions. This standard requires entities:

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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

We adopted this standard retrospectively effective January��1, 2013. As this standard requires disclosures only, it did not have any impact on our consolidated financial position, results of operations or cash flows. For additional information, see Note 11. Financial Risk Management Activities.

~~Reclassification Adjustments out of Accumulated Other Comprehensive Income~~

~~This accounting standard requires entities to disclose the following information about reclassification adjustments related to Accumulated Other Comprehensive Income:~~

~~changes in Accumulated Other Comprehensive Income balances by component, and~~

significant amounts reclassified out of Accumulated Other Comprehensive Income by respective line items of net income (for amounts that are required by GAAP to be reclassified to net income in their entirety in the same reporting period).

We adopted this standard prospectively effective January 1, 2013. As this standard requires disclosures only, it did not have any impact on our consolidated financial position, results of operations or cash flows. For additional information, see Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax.

~~New Accounting Standards Issued But Not Yet Adopted~~2014

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

This accounting standard was issued to address diversity in practice related to the presentation of an unrecognized tax benefit in certain cases. This standard requires entities to present an unrecognized tax benefit or a portion thereof on the Balance Sheet as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward.

However, in cases in which a net operating loss carryforward, a similar tax loss or a tax credit carryforward is not available at the reporting date under the tax law of the jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or the tax law of the jurisdiction does not require an entity to use, and the entity does not intend to use the deferred tax asset for such purpose, the unrecognized tax benefit will be presented on the Balance Sheet as a liability and will not be combined with deferred tax ~~assets.~~assets in cases where that tax benefit cannot or will not, if permissible, be used to settle any additional income taxes that would result from the disallowance of a tax position.

The standard iswas effective for fiscal years and interim periods beginning after December 15, 2013. ~~We are currently analyzing the~~The impact of adopting this standard ~~to our financial statements.~~was immaterial.

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~~Transition Funding and Transition Funding II 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 of these VIEs 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, 2013~~March 31, 2014 and December 31, ~~2012~~2013. 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~~three months of ~~2013~~2014 or in ~~2012~~.2013. PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.

Variable Interest Entity for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA's T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco's economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.

Pursuant to the OSA, Servco's operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI's risk is limited related to the activities of Servco. PSEG LI has no current obligation, nor expectation, to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by ServCo's annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.

PSEG recognized a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and other postretirement benefit (OPEB) liabilities. This receivable is presented separately on the Condensed Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted. See Note 7. Pension and Other Postretirement Benefits for additional information.

For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance Expense, respectively. For transactions in which Servco acts as an

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

~~Note 4. Asset Disposition~~

~~In June 2013, Energy Holdings closed~~agent for LIPA, it records revenues and the related expenses on ~~the sale of its investments in~~ a ~~commercial office complex for proceeds of~~ ~~$41 million~~,net basis, resulting in ~~an after-tax gain~~no impact on PSEG's Condensed Consolidated Statement of ~~$6 million~~.Operations.

Note 5.4. Rate Filings

The following information discusses significant updates regarding orders and pending rate filings. This Note should be read in conjunction with Note 6. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, ~~2012~~2013.

Remediation Adjustment Charge (RAC)—On April 18, 2014, PSE&G filed a petition with the BPU requesting recovery of $66 million related to RAC 21 net manufactured gas plant expenditures through July 31, 2013. This matter is pending.

Weather Normalization Clause (WNC)—In April ~~2013,~~2014, the BPU approved PSE&G's filing with respect to deficiency revenues from the ~~2011-2012~~2012-2013 Winter Period. AsThe BPU’s approval of a ~~result, provisional rates were approved to recover~~ ~~$41 million~~ ~~from customers during the 2012-2013 Winter Period, with a carryover deficiency of~~ ~~$24 million~~final WNC resulted in no change to the ~~2013-2014 Winter Period. In July 2013, PSE&G filed a petition with~~provisional rate previously approved by the BPU ~~seeking approval~~and implemented effective October 1, 2013, which was set to recover $26 million ~~in revenues from its customers during the 2013-2014 Winter Period inclusive of the~~ ~~$24 million~~ ~~carryover deficiency. In September 2013, the BPU approved PSE&G's petition for~~ ~~$26 million~~ ~~of deficiency revenues which will be recovered~~ from customers during the 2013-2014 Winter Period (October 1, 2013 through May ~~31)~~31, 2014).

~~Universal~~Basic Gas Supply Service ~~Fund (USF) Lifeline~~(BGSS)—In ~~June 2013, New Jersey’s electric~~January and ~~gas utilities, including~~February 2014, PSE&G filed ~~requests to reset the statewide rates for the USF and Lifeline program. In September 2013,~~self-implementing one-month BGSS residential customer bill credits with the BPU ~~approved rates set to recover~~for ~~$274 million~~25 cents ~~on a statewide basis. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.~~

~~Transmission Filing—In October 2013, PSE&G filed its 2014 Annual Formula Rate Update with the FERC, which provides for approximately~~ ~~$176 million~~ ~~in increased annual transmission revenues effective January 1, 2014.~~

~~BGSS—In October 2013, PSE&G filed a self-implementing two-month BGSS bill credit with the BPU. This bill credit will be~~ 35 ~~cents~~ per therm for the months of ~~November~~February and ~~December 2013 and is designed to provide~~March 2014. These credits provided approximately $~~115~~93 million in total credits to residential customers, ~~over the two months and reduce~~reducing the BGSS deferred balance. ~~The~~On April 1, 2014, the BGSS rate ~~will revert~~reverted back to the current ~~rate on January 1, 2014.~~rate.

Note 6.5. Financing Receivables

PSE&G

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

Credit Risk Profile Based on Payment Activity
As of As of
Consumer Loans September 30,
2013 December 31,
2012
Millions
Commercial/Industrial $ 183
$ 174

Residential 15
15

Total $ 198
$ 189




Credit Risk Profile Based on Payment Activity
	As of		As of
Consumer Loans	March 31, 2014		December 31, 2013
	Millions
Commercial/Industrial	$	197	$	192
Residential	15		15
Total	$	212	$	207

Energy Holdings

Energy Holdings, through various of its indirect subsidiary companies, 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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table ~~below~~ shows Energy Holdings’ gross and net lease investment as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, respectively.

As of As of
September 30,
2013 December 31,
2012
Millions
Lease Receivables (net of Non-Recourse Debt) $ 701
$ 721

Estimated Residual Value of Leased Assets 529
535

1,230
1,256

Unearned and Deferred Income (405 ) (416 )
Gross Investments in Leases 825
840

Deferred Tax Liabilities (705 ) (723 )
Net Investments in Leases $ 120
$ 117




	As of			As of
	March 31, 2014			December 31, 2013
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	700		$	701
Estimated Residual Value of Leased Assets	529			529
Total Investments in Rental Receivables	1,229			1,230
Unearned and Deferred Income	(401		)	(405		)
Gross Investments in Leases	828			825
Deferred Tax Liabilities	(708		)	(727		)
Net Investment in Leases	$	120		$	98

The corresponding receivables associated with the lease portfolio are reflected ~~below,~~in the following table, 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 represent investments in lease receivables related to coal-fired assets and commercial real estate properties.

Lease Receivables, Net of
Non-Recourse Debt

Counterparties’ Credit Rating (Standard & Poor's (S&P)) As of As of
As of September 30, 2013 September 30, 2013 December 31, 2012
Millions
AA $ 20
$ 21

AA- 56
73

BBB+ - BBB- 316
316

B 165
166

Not Rated 144
145

Total $ 701
$ 721




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating (Standard & Poor's (S&P))	As of		As of
As of March 31, 2014	March 31, 2014		December 31, 2013
	Millions
AA	$	19	$	19
AA-	56		56
BBB+ - BB+	316		316
B	165		166
Not Rated	144		144
Total	$	700	$	701

The “B” rating and the "Not Rated" ~~above~~in the preceding table include lease receivables related to coal-fired assets in Pennsylvania and Illinois, respectively. As of ~~September 30, 2013~~March 31, 2014, the gross investment in the leases of such assets, net of non-recourse debt, was $562 million ($2318 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




Asset	Location	Gross Investment		% Owned		Total	Fuel Type	Counter-parties’ S&P Credit Ratings	Counterparty
		Millions				MW
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	Not Rated	Edison Mission Energy
Joliet Station Units 7 and 8	IL	$	84	64	%	1,044	Coal	Not Rated	Edison Mission Energy
Keystone Station Units 1 and 2	PA	$	117	17	%	1,711	Coal	B	GenOn REMA, LLC
Conemaugh Station Units 1 and 2	PA	$	117	17	%	1,711	Coal	B	GenOn REMA, LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	110	100	%	603	Coal	B	GenOn REMA, LLC

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, the indirect subsidiary companies of Energy Holdings would exercise their rights and attempt to seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital investments and trigger certain material tax obligations. A bankruptcy of a lessee would likely delay any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities to the Internal Revenue Service (IRS).

~~Indirect subsidiary companies of Energy Holdings lease~~ ~~three~~ coal-fired generation facilities in Pennsylvania (Keystone, Conemaugh and Shawville) to GenOn REMA, LLC (GenOn REMA), a subsidiary of GenOn Energy Inc. (GenOn), which was acquired by NRG Energy, Inc. (NRG) in December 2012. With respect to addressing various environmental controls: Keystone has installed a flue gas desulfurization (FGD) system for sulfur dioxide (SO₂~~), selective catalytic reduction (SCR) equipment for nitrogen oxide (NO~~_X) and mercury control; Conemaugh has a FGD system, while SCR and mercury control equipment are scheduled to be installed and operational by the first quarter of 2015; and GenOn has disclosed its plan to place Shawville in a “long-term protective layup” by April 2015. GenOn has stated that it is evaluating whether to continue to pay the required rent and maintain the facility in accordance with the lease terms or terminate the lease for obsolescence in which case the lessee would be required, among other things, to pay the contractual termination value structured to recover Energy Holdings' indirect subsidiaries' lease investment as specified in the lease agreement.

Although all lease payments ~~from the GenOn REMA leases~~ are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and the quality and condition of assets under lease. GenOn REMA, LLC, an indirect subsidiary of NRG Energy, Inc. (NRG), has disclosed its plan to place Shawville in a “long term protective layup” by April 2015. NRG has stated that it is evaluating whether to continue to pay the required rent and maintain the facility in accordance with the lease terms or terminate the lease for obsolescence in which case the lessee would be required, among other things, to pay the contractual termination value structured to recover the lease investment of Energy Holdings’ indirect subsidiaries as specified in the lease agreement.

Nesbitt Asset Recovery, LLC (Nesbitt), (an indirect, wholly owned subsidiary of Energy Holdings), owns approximately 64% of the lease interest in the Powerton and Joliet coal units in ~~Illinois, with the balance held by Associates Capital Investments, L.L.P. (Associates) (an affiliate of Citigroup, and, together with Nesbitt, the "Equity Investors").~~Illinois. These facilities are leased to Midwest Generation (MWG), which was an indirect subsidiary of Edison Mission Energy (EME).

~~MWG has substantially completed investments in mercury removal (Activated Carbon Injection) and NO~~_X ~~emission controls (low NO~~_X ~~burners and Selective Non-Catalytic Reduction systems). On April 4, 2013, MWG obtained approval from the Illinois Pollution Control Board to defer capital investments for up to~~ ~~two~~ additional years to meet upcoming air emission compliance deadlines under Illinois law. Also, on July 8, 2013, the U.S. Court of Appeals affirmed the judgment of the lower court dismissing claims brought by the U.S. Environmental Protection Agency (EPA) and the State of Illinois against EME and MWG for alleged violations of the Clean Air Act.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

On In December ~~17,~~ 2012, EME and MWG filed for relief under Chapter 11 of the U.S. Bankruptcy Code. Immediately prior to that filing, EME, MWG and the Equity Investors, as well as certain affiliated owner lessors, entered into a forbearance agreement with holders of a majority of the lease debt that financed the original sale-leaseback transaction. The forbearance agreement, which was approved by the Bankruptcy Court, expired on April 5, 2013. In June 2013, the parties reached an agreement, which was approved by the Bankruptcy Court, to again extend the deadline for MWG to assume or reject the leases until September 30, 2013, and in September 2013, extended it to December 31, 2013. As part of this agreement, (i) MWG will make partial lease payments of ~~$4 million~~ each month during the extension period starting in July 2013, (ii) MWG will continue to make certain environmental capital expenditures at the units, and (iii) the parties reserve their rights, claims, and defenses with respect to whether the leases are secured financings, rent amounts due under the leases, and the classification of claims under the leases, among other things.

On October ~~18,~~ 2013, NRG, EME, MWG, ~~the Equity Investors~~Nesbitt and other creditor parties involved in the bankruptcy executed a new agreement ~~which was approved by the Bankruptcy Court on October 24, 2013. The new agreement contains the terms and conditions~~ under which NRG would acquire substantially all of EME’s assets, including the Powerton and Joliet leased assets. In March 2014, the Bankruptcy Court approved the transaction. As part of the ~~proposed~~ transaction, (i) the leases for the Powerton and Joliet coal units ~~would be~~were assumed on their existing terms, (ii) all past due rent under the leases ~~would be~~was paid in full, (iii) NRG ~~would assume~~assumed EME’s tax indemnity and guarantee obligations, and (iv) NRG ~~would~~agreed to invest up to ~~$350~~$350 million in the Powerton and Joliet coal units so they ~~could~~can be operated in compliance with ~~all~~ environmental regulations. ~~The proposed~~On April 1, 2014, NRG and EME closed on the transaction ~~also requires approval by~~in accordance with these terms, bringing the FERC and other regulatory bodies, and there can be no assurances that the above transaction will be consummated. The terms of the aforementioned forbearance agreement will remain in effect beyond December 31, 2013 until such time as the NRG acquisitionlease payments current. NRG's credit rating is ~~consummated or terminated.~~BB-.

Note 7.6. Available-for-Sale Securities

Nuclear Decommissioning Trust (NDT) Fund

Power maintains an external master nuclear decommissioning trust to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains a qualified fund and a non-qualified fund. Section 468A of the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 advisers who operate under investment guidelines developed by Power.

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




	As of March 31, 2014
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	619	$	288	$	(3	)	$	904
Debt Securities
Government Obligations	464		3		(7		)	460
Other Debt Securities	306		11		(2		)	315
Total Debt Securities	770		14		(9		)	775
Other Securities	55		—		—			55
Total NDT Available-for-Sale Securities	$	1,444	$	302	$	(12	)	$	1,734

As of September 30, 2013
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 615
$ 234
$ (6 ) $ 843

Debt Securities
Government Obligations 411
5
(6 ) 410

Other Debt Securities 313
11
(4 ) 320

Total Debt Securities 724
16
(10 ) 730

Other Securities 62
—
—
62

Total NDT Available-for-Sale Securities $ 1,401
$ 250
$ (16 ) $ 1,635

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

As of December 31, 2012
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 648
$ 147
$ (6 ) $ 789

Debt Securities
Government Obligations 274
11
—
285

Other Debt Securities 320
22
—
342

Total Debt Securities 594
33
—
627

Other Securities 124
—
—
124

Total NDT Available-for-Sale Securities $ 1,366
$ 180
$ (6 ) $ 1,540




	As of December 31, 2013
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	609	$	290	$	(2	)	$	897
Debt Securities
Government Obligations	438		3		(12		)	429
Other Debt Securities	285		10		(4		)	291
Total Debt Securities	723		13		(16		)	720
Other Securities	84		—		—			84
Total NDT Available-for-Sale Securities	$	1,416	$	303	$	(18	)	$	1,701

These amounts in the preceding tables 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 As of
September 30,
2013 December 31,
2012
Millions
Accounts Receivable $ 43
$ 18

Accounts Payable $ 47
$ 53




	As of		As of
	March 31, 2014		December 31, 2013
	Millions
Accounts Receivable	$	68	$	39
Accounts Payable	$	70	$	36

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

As of September 30, 2013 As of December 31, 2012

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) $ 78
$ (6 ) $ —
$ —
$ 139
$ (6 ) $ —
$ —

Debt Securities
Government Obligations (B) 158
(6 ) —
—
34
—
1
—

Other Debt Securities (C) 131
(4 ) —
—
31
—
6
—

Total Debt Securities 289
(10 ) —
—
65
—
7
—

Other Securities —
—
—
—
—
—
—
—

NDT Available-for-Sale Securities $ 367
$ (16 ) $ —
$ —
$ 204
$ (6 ) $ 7
$ —




	As of March 31, 2014									As of December 31, 2013
	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)	$	56	$	(3	)	$	1	$	—	$	30	$	(2	)	$	2	$	—
Debt Securities
Government Obligations (B)	269		(7		)	4		—		300		(11		)	1		(1		)
Other Debt Securities (C)	91		(2		)	3		—		107		(4		)	3		—
Total Debt Securities	360		(9		)	7		—		407		(15		)	4		(1		)
NDT Available-for-Sale Securities	$	416	$	(12	)	$	8	$	—	$	437	$	(17	)	$	6	$	(1	)


(A)	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of ~~September 30, 2013~~March 31, 2014.


(B)	Debt Securities (Government)—Unrealized losses on Power’s NDT investments in United States Treasury obligations and Federal Agency ~~asset-backed~~mortgage-backed securities were caused by interest rate changes. Since these investments are

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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, 2013~~ 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 March 31, 2014.

(C)

Debt Securities (Corporate)—Power’s investments in corporate bonds are limited to 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, 2013~~March 31, 2014.

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

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
Millions
Proceeds from NDT Fund Sales $ 220
$ 617
$ 837
$ 1,252

Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains 35
94
95
136

Gross Realized Losses (9 ) (19 ) (34 ) (41 )
Net Realized Gains (Losses) on NDT Fund $ 26
$ 75
$ 61
$ 95




	Three Months Ended
	March 31,
	2014			2013
	Millions
Proceeds from NDT Fund Sales	$	245		$	241
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	23			37
Gross Realized Losses	(4		)	(19		)
Net Realized Gains (Losses) on NDT Fund	$	19		$	18

Gross realized gains and gross realized losses disclosed in the ~~above~~preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $~~115~~143 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of ~~September 30, 2013~~March 31, 2014.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The NDT available-for-sale debt securities held as of ~~September 30, 2013~~March 31, 2014 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ 57

1 - 5 years 167

6 - 10 years 186

11 - 15 years 44

16 - 20 years 19

Over 20 years 257

Total NDT Available-for-Sale Debt Securities $ 730




Time Frame	Fair Value
	Millions
Less than one year	$	38
1 - 5 years	216
6 - 10 years	184
11 - 15 years	54
16 - 20 years	29
Over 20 years	254
Total NDT Available-for-Sale Debt Securities	$	775

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

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In ~~2013~~,the three months ended March 31, 2014, other-than-temporary impairments of $72 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Rabbi Trust

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

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




	As of March 31, 2014
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	9	$	—		$	21
Debt Securities
Government Obligations	110		—		(1		)	109
Other Debt Securities	46		1		(1		)	46
Total Debt Securities	156		1		(2		)	155
Other Securities	7		—		—			7
Total Rabbi Trust Available-for-Sale Securities	$	175	$	10	$	(2	)	$	183

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of September 30, 2013
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 14
$ 7
$ —
$ 21

Debt Securities
Government Obligations 110
—
(2 ) 108

Other Debt Securities 45
—
(1 ) 44

Total Debt Securities 155
—
(3 ) 152

Other Securities 2
—
—
2

Total Rabbi Trust Available-for-Sale Securities $ 171
$ 7
$ (3 ) $ 175

~~Securities in the Rabbi Trust in a gross unrealized loss position have been in such position for less than twelve months.~~

As of December 31, 2012
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 13
$ 5
$ —
$ 18

Debt Securities
Government Obligations 114
3
—
117

Other Debt Securities 45
2
—
47

Total Debt Securities 159
5
—
164

Other Securities 3
—
—
3

Total Rabbi Trust Available-for-Sale Securities $ 175
$ 10
$ —
$ 185




	As of December 31, 2013
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	14	$	9	$	—		$	23
Debt Securities
Government Obligations	109		—		(2		)	107
Other Debt Securities	46		1		(1		)	46
Total Debt Securities	155		1		(3		)	153
Other Securities	3		—		—			3
Total Rabbi Trust Available-for-Sale Securities	$	172	$	10	$	(3	)	$	179

These amounts in the preceding tables do not include receivables and payables for Rabbi Trust 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 As of
September 30,
2013 December 31,
2012
Millions
Accounts Receivable $ 3
$ 4

Accounts Payable $ 3
$ 5




	As of		As of
	March 31, 2014		December 31, 2013
	Millions
Accounts Receivable	$	4	$	1
Accounts Payable	$	3	$	2

The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months.




	As of March 31, 2014									As of December 31, 2013
	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)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government Obligations (B)	42		(1		)	2		—		47		(2		)	2		—
Other Debt Securities (C)	13		(1		)	1		—		18		(1		)	1		—
Total Debt Securities	55		(2		)	3		—		65		(3		)	3		—
Rabbi Trust Available-for-Sale Securities	$	55	$	(2	)	$	3	$	—	$	65	$	(3	)	$	3	$	—


(A)	Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors. PSEG does not consider these securities to be other-than-temporarily impaired as of March 31, 2014.

(B)

Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust 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 PSEG does not intend to sell nor

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of March 31, 2014.

(C)

Debt Securities (Corporate)—PSEG’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 PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of March 31, 2014.

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

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
Millions
Proceeds from Rabbi Trust Sales $ 13
$ 6
$ 77
$ 221

Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains $ —
$ —
$ 4
$ 6

Gross Realized Losses —
—
(3 ) —

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




	Three Months Ended
	March 31,
	2014		2013
	Millions
Proceeds from Rabbi Trust Sales	$	12	$	17
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2	$	—
Gross Realized Losses	—		—
Net Realized Gains (Losses) on Rabbi Trust	$	2	$	—

~~Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations.~~ Net unrealized gains of $24 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of ~~September 30, 2013~~March 31, 2014. The Rabbi Trust available-for-sale debt securities held as of ~~September 30, 2013~~March 31, 2014 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ —

1 - 5 years 59

6 - 10 years 29

11 - 15 years 7

16 - 20 years 4

Over 20 years 53

Total Rabbi Trust Available-for-Sale Debt Securities $ 152




Time Frame	Fair Value
	Millions
Less than one year	$	—
1 - 5 years	60
6 - 10 years	27
11 - 15 years	9
16 - 20 years	4
Over 20 years	55
Total Rabbi Trust Available-for-Sale Debt Securities	$	155

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

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

As of As of
September 30,
2013 December 31,
2012
Millions
Power $ 38
$ 36

PSE&G 41
61

Other 96
88

Total Rabbi Trust Available-for-Sale Securities $ 175
$ 185




	As of		As of
	March 31, 2014		December 31, 2013
	Millions
Power	$	43	$	39
PSE&G	39		42
Other	101		98
Total Rabbi Trust Available-for-Sale Securities	$	183	$	179

Note 8.7. Pension and Other Postretirement Benefits (OPEB)

PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis.

Pension and OPEB costs for PSEG, except for Servco, are detailed as follows:

Pension Benefits OPEB Pension Benefits OPEB
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2013 2012 2013 2012 2013 2012 2013 2012
Millions
Components of Net Periodic Benefit Cost
Service Cost $ 29
$ 26
$ 6
$ 5
$ 87
$ 76
$ 16
$ 13

Interest Cost 54
56
15
17
161
167
47
49

Expected Return on Plan Assets (87 ) (76 ) (6 ) (4 ) (261 ) (229 ) (16 ) (13 )
Amortization of Net
Transition Obligation —
—
—
1
—
—
—
2

Prior Service Cost (Credit) (5 ) (5 ) (4 ) (4 ) (14 ) (14 ) (11 ) (11 )
Actuarial Loss 47
41
11
7
141
125
32
23

Net Periodic Benefit Cost $ 38
$ 42
$ 22
$ 22
$ 114
$ 125
$ 68
$ 63

Special Termination Benefits —
1
—
—
—
1
—
—

Effect of Regulatory Asset —
—
—
4
—
—
—
14

Total Benefit Costs, Including Effect of Regulatory Asset $ 38
$ 43
$ 22
$ 26
$ 114
$ 126
$ 68
$ 77




	Pension Benefits						OPEB
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2014			2013			2014			2013
	Millions
Components of Net Periodic Benefit Cost
Service Cost	$	26		$	29		$	5		$	5
Interest Cost	59			54			17			16
Expected Return on Plan Assets	(100		)	(87		)	(7		)	(5		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(5		)	(4		)	(4		)
Actuarial Loss	14			47			6			11
Total Benefit Costs	$	(6	)	$	38		$	17		$	23

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

Pension Benefits OPEB Pension Benefits OPEB
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2013 2012 2013 2012 2013 2012 2013 2012
Millions
Power $ 11
$ 14
$ 6
$ 5
$ 33
$ 39
$ 17
$ 14

PSE&G 23
24
16
21
68
73
49
61

Other 4
5
—
—
13
14
2
2

Total Benefit Costs $ 38
$ 43
$ 22
$ 26
$ 114
$ 126
$ 68
$ 77




	Pension Benefits					OPEB
	Three Months Ended					Three Months Ended
	March 31,					March 31,
	2014			2013		2014		2013
	Millions
Power	$	(2	)	$	11	$	5	$	6
PSE&G	(5		)	23		11		16
Other	1			4		1		1
Total Benefit Costs	$	(6	)	$	38	$	17	$	23

~~During~~PSEG does not anticipate making contributions into its pension plan during 2014. However, during the three months ended March 31, ~~2013,~~2014, PSEG contributed its entire planned ~~contributions~~contribution for the year ~~2013~~2014 of~~$145 million~~ ~~and~~ $14 million into its postretirement healthcare plan.

Servco Pension and OPEB

At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco's employees had worked under NGES' T&D operations services arrangement with LIPA, Servco's plans provide certain of those employees with pension and OPEB vested credit for prior years' services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 3. Variable Interest Entities (VIEs). These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for the three months ended March 31, 2014 were $23 million. As of March 31, 2014, Servco had funded 17% of its projected pension benefit obligation. Servco plans to contribute an additional $44 million to its pension plan trusts during 2014. There were no OPEB-related revenues earned or costs incurred for the three months ended March 31, 2014.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following assumptions were used to determine the benefit obligations of Servco:




	Pension Benefits		Other Benefits
	January 1, 2014
Weighted-Average Assumptions Used to Determine Benefit Obligations as of January 1, 2014
Discount Rate	5.50	%	5.40		%
Rate of Compensation Increase	2.50	%	2.50		%
Assumed Health Care Cost Trend Rates as of January 1, 2014
Administrative Expense			5.00		%
Dental Costs			5.00		%
Pre-65 Medical Costs
Immediate Rate			7.50		%
Ultimate Rate			5.00		%
Year Ultimate Rate Reached			2019
Post-65 Medical Costs
Immediate Rate			7.50		%
Ultimate Rate			5.00		%
Year Ultimate Rate Reached			2019
			Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation			$	62
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation			$	(49	)

Estimated Future Benefit Payments

The following pension benefit and postretirement ~~healthcare plans, respectively.~~benefit payments are expected to be paid to Servco's plan participants:




Year	Pension Benefits		Other Benefits
	Millions
2014	$	—	$	1
2015	—		3
2016	1		4
2017	2		6
2018	3		8
2019-2023	37		65
Total	$	43	$	87

Note 9.8. Commitments and Contingent Liabilities

Guaranteed Obligations

Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

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

obtain credit.

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

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

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

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

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

Power is subject to

counterparty collateral calls related to commodity contracts, and

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

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

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

The face value of Power's outstanding guarantees, current exposure and margin positions as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013 are shown ~~below:~~as follows:

As of As of
September 30,
2013 December 31,
2012
Millions
Face Value of Outstanding Guarantees $ 1,551
$ 1,508

Exposure under Current Guarantees $ 201
$ 226

Letters of Credit Margin Posted $ 121
$ 124

Letters of Credit Margin Received $ 29
$ 69

Cash Deposited and Received
Counterparty Cash Margin Deposited $ 12
$ 15

Counterparty Cash Margin Received $ —
$ (4 )
Net Broker Balance Deposited (Received) $ 8
$ 26

In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that Could be Required $ 588
$ 654

Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral $ 3,537
$ 3,531

Additional Amounts Posted
Other Letters of Credit $ 42
$ 45




	As of			As of
	March 31, 2014			December 31, 2013
	Millions
Face Value of Outstanding Guarantees	$	1,930		$	1,639
Exposure under Current Guarantees	$	236		$	246
Letters of Credit Margin Posted	$	130		$	132
Letters of Credit Margin Received	$	16		$	25
Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(19	)	$	—
Net Broker Balance Deposited (Received)	$	360		$	80
In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required	$	802		$	691
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,525		$	3,522
Additional Amounts Posted:
Other Letters of Credit	$	45		$	45

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note ~~11.~~10. Financial Risk Management Activities for further discussion. In accordance with PSEG's accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S~~&P's,~~&P, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See ~~table above.~~preceding table.

The SEC and the Commodity Futures Trading Commission (CFTC) continue efforts to implement new rules to effect stricter regulation over swaps and derivatives, including imposing reporting and record-keeping requirements. In August 2013, PSEG began reporting its swap transactions to a CFTC-approved swap data repository. ~~We continue~~PSEG continues to monitor developments in this area, as the CFTC considers additional requirements such as a new position limits rule for energy commodity swaps.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power had posted letters of credit to support Power's various other non-energy contractual and environmental obligations. See ~~table above.~~preceding table.

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.~~Complex in violation of various statutes as discussed as follows.

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

The ~~EPA~~U.S. Environmental Protection Agency (EPA) has determined that an ~~eight-mile~~a 17-mile stretch of the Passaic River ~~in the area of~~from Newark to Clifton, New Jersey is a ~~“facility” within the meaning of that term~~“Super Fund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA.

The EPA has determined the need to perform a comprehensive study of the entire 17~~-mile tidal reach~~17-miles of the lower Passaic River.

PSE&G and certain of its predecessors conducted operations at properties in this area ~~on or adjacent to~~of 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,~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.~~

~~The EPA notified the potentially responsible parties~~Seventy-three Potentially Responsible Parties (PRPs) ~~that the cost of its Remedial Investigation and Feasibility Study (RI/FS) is now estimated at approximately~~ ~~$117 million~~. ~~Seventy-three~~ ~~PRPs,~~, including Power and PSE&G, agreed to assume responsibility for ~~the RI/FS~~conducting a Remedial Investigation and Feasibility Study (RI/FS) and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently ~~seventy~~67 members, is presently ~~executing~~conducting the RI/FS. ~~Approximately~~ ~~five~~The approximate seven percent allocation of the RI/FS costs ~~were~~currently attributable to PSE~~&G's~~&G’s former MGP sites and ~~approximately~~approximate one percentattributable ~~percent~~ to ~~Power's~~Power’s generating stations ~~on an interim basis under~~are non-binding as it relates to the ~~CPG's group agreement.~~ultimate sharing of the remediation costs. Power has provided notice to insurers concerning this potential claim. The RI/FS is expected to be completed by the end of 2014 at an estimated cost of approximately $130 million. Of the estimated $130 million, as of December 31, 2013, the CPG Group had spent approximately $113 million, of which PSEG's total share had been approximately $7 million.

~~In 2007,~~On April 11, 2014, the EPA released ~~a draft~~its revised “Focused Feasibility Study” (FFS) ~~that proposed various options to address~~which contemplates the ~~contamination cleanup~~removal of 4.3 million cubic yards of sediment from the bottom of the Passaic River’s lower eight miles under various alternatives ranging in costs from $365 million to $3.25 billion. The EPA's preferred alternative would involve dredging the river bank to bank and installing an engineered cap at an estimated cost of $1.7 billion. The draft FFS is subject to a public comment period, the EPA’s response, a design phase and at least five years for completion of the ~~Passaic River. The EPA estimated costs for the proposed remedy range from~~ ~~$1.3 billion~~ to ~~$3.7 billion~~.work. The work contemplated by the draft FFS is not subject to the cost sharing agreement discussed above. ~~The EPA's revised proposed FFS may be released for public comment before the end of 2013.~~

In June 2008, an agreement was announced between the EPA and Tierra Solutions, Inc. and Maxus Energy Corporation (Tierra/Maxus) for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of ~~$80 million~~.$80 million. Phase I of the removal work has been completed. ~~Phase II is contingent on the approval of an appropriate sediment disposal facility.~~ Tierra/Maxus have reserved their rights to seek contribution for ~~the~~these removal costs from the other PRPs, including Power and PSE&G.

~~The EPA has advised that~~At the ~~levels of contaminants at Passaic River mile 10.9 will require removal in advance of~~EPA's direction, the ~~completion of the RI/FS. The~~ CPG, ~~members,~~ with the exception of ~~Tierra/~~Tierra and Maxus, which are no longer members, ~~have agreed to and are funding~~has commenced the removal ~~currently~~of certain contaminated sediments at Passaic River Mile 10.9 at an estimated ~~at approximately~~ ~~$30~~cost of $25 million~~. PSEG's~~ to $30 million. PSEG’s share of the cost of that effort is approximately three percent.

~~Except for~~

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Based on the EPA estimates above, Power and PSE&G believe that their respective ultimate shares of the costs to clean up the Passaic River ~~mile 10.9 removal, Power and PSE&G~~will be immaterial, but are unable to ~~estimate their portion~~predict the ultimate outcome of ~~the possible loss or range of loss related to the Passaic River matters.~~this matter.

New Jersey Spill Compensation and Control Act (Spill Act)

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit ~~against a PRP (Occidental Chemical Corporation (OCC)) 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~~a certain 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 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 it allegedly discharged into the Passaic River and the Newark Bay Complex. Power and PSE&G ~~filed answers~~are alleged to ~~the complaints in 2010. On March 22, 2013, Power and PSE&G signed an agreement~~have owned, operated or contributed to ~~settle the NJDEP vs. OCC litigation at~~ a ~~nominal cost. That settlement is contingent upon a public comment and NJDEP response period and the issuance~~total of an order approving the settlement by the Court after conducting a fairness hearing. A stay of third-party discovery remains in place and has been extended. Power and PSE&G believe they have good and valid defenses to the allegations contained in the11 sites or facilities that impacted these water bodies. The third party complaints sought statutory contribution and ~~will vigorously assert those defenses should~~contribution under the ~~matter not settle.~~Spill Act to recover past and future removal costs and damages. In December 2013, the Court approved a settlement of the entire third party action. Power and PSE~~&G are unable~~&G's contributions to ~~estimate their portion of~~ the ~~possible loss~~settlement, either individually or ~~range of loss related to this matter.~~in the aggregate, were immaterial.

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~~.$950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior (the Passaic River federal trustees) 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'~~trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. ~~PSEG~~PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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 OCC to discuss participating in the RI/FS that OCC was conducting.~~Area. The notice stated the ~~EPA's~~EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but ~~it is uncertain at this time whether the~~ PSEG ~~companies will consent~~has not consented to fund the third phase. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.

MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between ~~$476~~$432 million and ~~$552~~$509 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of ~~$476~~$432 million as of ~~September 30, 2013~~.March 31, 2014. Of this amount, ~~$107~~$93 million was recorded in Other Current Liabilities and ~~$369~~$339 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a ~~$476~~$432 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly.

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

The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies 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~~$25,000 to ~~$37,500~~$37,500 per day for each violation, depending upon when the alleged violation occurred.

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

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(UNAUDITED)

the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA 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 ruling of the U.S. Court of Appeals of the District of Columbia ~~(Court of Appeals)~~(D.C. Court), the EPA published a Maximum Achievable Control Technology (MACT) regulation inon February 16, 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the D.C. Court ~~of Appeals~~ in support of the EPA's implementation of MATS. ~~Litigation~~Oral arguments were held in December 2013. On April 15, 2014, the D.C. Court denied all petitions for review of ~~these matters remains pending and~~ the ~~impact on the implementation schedule is unknown at this time.~~existing source NESHAP.

Power believes that it will not be necessary to install any ~~additional~~ material controls at its New Jersey facilities. Additional controls ~~may be necessary~~are being installed at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulations, ~~a decision was reached~~the co-owners group, including Power, agreed to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal-fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. Power's share of this investment is ~~estimated to be up to~~ approximately $110 million.

Nitrogen Oxide (NO~~$147 million~~_X). Regulation

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~NOx Regulation~~

In ~~April~~ 2009, the NJDEP finalized revisions to NO_xemission control regulations that impose new NO_xemission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 30, 2015. ~~Retirement~~Retirement notifications for the combustion turbines ~~except for Salem Unit 3,~~ have been ~~filed with the~~submitted to PJM Interconnection ~~LLC~~L.L.C. (PJM). ~~The~~PJM was notified that the Salem Unit 3 combustion turbine (38 ~~MW)~~will no longer be available as a capacity resource and will be ~~transitioning~~transitioned to an emergency ~~generator. Evaluations are ongoing~~generator for ~~the~~site use only. Based upon Power’s recently-completed evaluations of its steam electric generation ~~units.~~

~~Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs)~~units, an immaterial investment will be required to ~~comply with certain~~consistently reduce 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 untilemissions below required limits beginning on May ~~31, 2014.~~1, 2015.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System (NPDES) 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. States with delegated federal authority for this program manage these permits. The ~~NJDEP~~New Jersey Department of Environmental Protection manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

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.~~

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 late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012.~~ In April 2011, the EPA published a proposed rule to establish marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. ~~In July 2012, the~~The EPA ~~and environmental groups agreed~~is currently scheduled to ~~delay the deadline to June 27, 2013 for finalization of the Rule. On June 27, 2013, the EPA and environmental groups agreed to further extend the deadline to November 4, 2013.~~issue a final rule on May 16, 2014.

Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition, results of operations or cash flows. The results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1$1 billion,, of which Power’s share would

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(UNAUDITED)

have been approximately ~~$575 million. These cost estimates have~~$575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

On October 1, 2013, the Delaware Riverkeeper Network and several other environmental groups filed a lawsuit in the Superior Court ofin New Jersey seeking to compel the NJDEP to take action on Power's pending application for permit renewal at Salem either by denying the application or issuing a draft for public ~~comment.~~comments. At the NJDEP's request, the case was transferred to the Appellate Division on December 16, 2013. Power is unable to predict the outcome of this proceeding.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Capital Expenditures~~

~~The construction programs of PSEG and its subsidiaries are currently estimated to include a base level total investment of approximately~~ ~~$6.4 billion~~ ~~for the three years ended 2015. The three-year projected capital expenditures for PSEG, Power and PSE&G are as follows:~~

2013 2014 2015
Millions
Power $ 400
$ 365
$ 305

PSE&G 2,045
1,765
1,305

Other 95
40
30

Total PSEG $ 2,540
$ 2,170
$ 1,640

Power's projected capital expenditures include baseline maintenance (investments to replace major parts and enhance operational performance), investments in response to environmental, regulatory or legal mandates and nuclear expansion. PSE&G's projections include material additions and replacements in its transmission and distribution systems to meet expected growth and manage reliability.

In May 2013, the BPU approved increased spending on renewable energy under PSE&G's Solar Loan and Solar 4 All investment programs (Solar Loan III and Solar 4 All Extension, respectively). PSE&G's projected expenditures through 2015 in the table above have been updated to include ~~$215 million~~ ~~under its Solar Loan III and Solar 4 All Extension programs.~~

~~Power~~

~~During the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013, Power made~~ ~~$243 million~~ ~~of capital expenditures, including interest capitalized during construction (IDC) but excluding~~ ~~$176 million~~ ~~for nuclear fuel, primarily related to various projects at its fossil and nuclear generation stations.~~

~~PSE&G~~

~~During the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013, PSE&G made~~ ~~$1,648 million~~ ~~of capital expenditures, including~~ ~~$1,628 million~~ ~~of investment in plant, primarily for reliability of transmission and distribution systems and~~ ~~$20 million~~ ~~in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of~~ ~~$66 million, which is included in operating cash flows.~~

~~Energy Holdings~~

~~Included in Other for 2013 in the preceding table is a solar project currently under construction in Arizona for which Energy Holdings had issued an outstanding guarantee of~~ ~~$10 million~~ ~~as of~~ ~~September 30, 2013~~.

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 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.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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

Auction Year
2010 2011 2012 2013
36-Month Terms Ending May 2013
May 2014
May 2015
May 2016
(A)
Load (MW) 2,800
2,800
2,900
2,800

$ per kWh 0.09577
0.09430
0.08388
0.09218




		Auction Year
		2011	2012	2013	2014
	36-Month Terms Ending	May 2014	May 2015	May 2016	May 2017	(A)
��	Load (MW)	2,800	2,900	2,800	2,800
	$ per kWh	0.09430	0.08388	0.09218	0.09739


(A)	Prices set in the ~~2013~~2014 BGS auction ~~became~~will become effective on June 1, ~~2013~~2014 when the ~~2010~~2011 BGS auction agreements ~~expired.~~expire.

PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. 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. For additional information, see Note ~~18.~~17. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power has various long-term fuel purchase commitments for coal through ~~2017~~2018 to support its fossil generation stations and for supply of nuclear fuel for the Salem, Hope Creek and Peach Bottom nuclear generating stations and for firm transportation and storage capacity for natural gas.

Power’s fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through ~~2015~~2016 and a significant portion through ~~2017~~2018 at Salem, Hope Creek and Peach Bottom.

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

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(UNAUDITED)

As of ~~September 30, 2013~~March 31, 2014, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type
Power’s Share of
Commitments
through 2017

Millions
Nuclear Fuel
Uranium $ 470

Enrichment $ 386

Fabrication $ 146

Natural Gas $ 880

Coal $ 446




Fuel Type	Power's Share of Commitments through 2018
	Millions
Nuclear Fuel
Uranium	$	505
Enrichment	$	455
Fabrication	$	173
Natural Gas	$	922
Coal	$	404

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Regulatory Proceedings

FERC Compliance

Power has discovered that it incorrectly calculated certain components of its cost-based bids for certain generating units in the PJM energy market, with resulting over-collection of revenues related to its fossil fleet. Power has notified the FERC, PJM and the PJM Independent Market Monitor of this issue. This matter is still under review, and Power is unable to estimate the ultimate impact or predict any resulting penalties or other costs associated with this matter at the current time.

New Jersey Clean Energy Program

In June 2013, the BPU established the funding level for fiscal 2014 applicable to its Renewable Energy and Energy Efficiency programs. The fiscal year 2014 aggregate funding for all EDCs is $345 million with PSE&G's share of the funding at $200 million. PSE&G has a remaining current liability of $~~185~~86 million as of ~~September 30, 2013~~March 31, 2014 for its outstanding share of ~~the~~ fiscal 2014 ~~and remaining fiscal 2013~~ funding. 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 recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

~~Long-Term Capacity Agreement Pilot Program (LCAPP)~~

~~In 2011, New Jersey enacted the LCAPP Act that resulted in the selection of~~ ~~three~~ ~~generators to build a total of approximately~~ ~~2,000~~ MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the selected generators, but did so under protest preserving their legal rights. The SOCA provides for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement. In July 2013, the SOCA contract with New Jersey Power Development LLC, a subsidiary of NRG Energy, Inc., was terminated early as a result of a default by the generator. SOCA contracts are for a 15~~-year term, which are scheduled to commence for~~ ~~one~~ ~~of the generators in the 2015/2016 delivery year and for the other generator in the 2016/2017 delivery year. These contracts are for the aggregate notional amount of approximately~~ ~~1,300~~ MWs of installed capacity. Based upon the expected percentage of state load that PSE&G will be serving during the term of these contracts, the contracts provide that PSE&G would be responsible for the positive difference of the contract price and the annual RPM clearing price for approximately ~~52%~~ or ~~676~~ MW of this amount provided that these generators satisfy their obligations under the SOCA, including the requirement that the specific generation units set forth in the contract achieve commercial operation.

The current estimated fair value of the SOCAs is recorded as a Derivative Asset or Liability with an offsetting Regulatory Asset or Liability on PSE&G’s Condensed Consolidated Balance Sheets. See Note 12. Fair Value Measurements for additional information.

PSE&G has taken several steps to challenge these subsidies, including joining several parties in challenging the LCAPP Act on constitutional grounds in federal court. On October 11, 2013, the U.S. District Court issued a decision finding that the LCAPP Act violated the Supremacy Clause of the U.S. Constitution and declaring the LCAPP Act null and void. On October 25, 2013, a final judgment was issued implementing the federal court's decision in this proceeding and also finding the SOCA contracts void, invalid and unenforceable and denying the request of the defendants to stay the decision pending appeal. The defendants may appeal the decision and may seek a stay from the U.S. Third Circuit Court of Appeals. Additionally, PSE&G joined an appeal in New Jersey state court challenging the BPU’s implementation of the LCAPP Act. The New Jersey State Appellate Court dismissed that appeal, without prejudice, based on the fact that the federal court had found the LCAPP Act unconstitutional and void.

Superstorm Sandy

In late October 2012, Superstorm Sandy caused severe damage to PSE&G's ~~transmission and distribution~~T&D system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds and the resulting storm surge caused damage to switching stations, substations and generating infrastructure. ~~Power's estimate of the total costs required to restore its damaged facilities to their pre-Superstorm Sandy condition is approximately~~ ~~$364~~

Power had incurred $79 million.

~~Power incurred an additional~~ ~~$17~~ and $85 million ~~and~~ ~~$67 million~~ of storm-related expense ~~for the~~ ~~three months~~in 2013 and ~~nine months~~ ~~ended~~ ~~September 30, 2013~~,2012, respectively, primarily for repairs at certain generating stations in Power's fossil fleet. ~~Power had incurred~~ ~~$85 million~~ ~~of costs in 2012.~~ These costs were recognized in ~~Operation and Maintenance~~O&M Expense, offset by $25 million and $19 million of insurance recoveries in 2013 and 2012, respectively.

Power incurred an additional $9 million for the three months ended March 31, 2014, primarily for repairs at certain generating stations in Power's fossil fleet.

PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. As previously reported, PSEG is seeking recovery from its insurers for the property damage resulting from Superstorm Sandy, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. In June 2013, PSEG, Power and PSE&G filed suit in New Jersey state court against its insurance carriers seeking an interpretation that the insurance policies cover their losses resulting from damage caused by Superstorm Sandy's storm surge. In that lawsuit, PSEG stated that its estimate of the total costs related to damaged facilities was approximately $25426 million. Of these costs, $364 million and $1962 million related to Power and PSE&G, respectively. In August 2013, the insurance carriers filed an answer in which they denied most of ~~insurance recoveries~~the allegations made in the ~~second quarter~~Complaint. Discovery is ongoing. In April 2014, PSEG notified the insurance carriers of ~~2013~~a revised estimate of $579 million for total costs related to damaged facilities, of which $484 million and $95 million related to Power and PSE&G, respectively. We cannot predict the ~~fourth quarter~~outcome of ~~2012, respectively.~~this proceeding.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

~~Leveraged Lease Investments~~

In January 2012, PSEG entered into a specific matter closing agreement with the IRS settling all matters related to cross border lease transactions. This agreement settled the leasing dispute with finality for all tax periods in which PSEG realized tax deductions from these transactions. In January 2012, PSEG also signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. In March 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These agreements concluded the audits for these years for PSEG and the leasing issue for all tax years. For PSEG, the impact of these agreements was an increase in financial statement Income Tax Expense of approximately ~~$175 million~~ ~~in the first quarter of 2012. In prior periods, PSEG had established financial statement tax liabilities for uncertain tax positions in the amount of~~ ~~$246 million~~ ~~with respect to these tax years. Accordingly, the settlement resulted in a net~~ ~~$71 million~~ ~~decrease in the first quarter of 2012 in the Income Tax Expense of PSEG.~~

~~Cash Impact~~

~~For tax years 1997 through 2003, the tax and interest PSEG owes the IRS as a result of this settlement will be reduced by the~~ ~~$320 million~~ ~~PSEG has on deposit with the IRS for this matter. PSEG paid a net deficiency for these years of approximately~~ ~~$4 million~~ ~~during the second quarter of 2012. Based upon the closing agreement and the Form 870-AD for tax years 2004 through 2006, PSEG owes the IRS approximately~~ ~~$620 million~~ ~~in tax and interest. Based on the settlement of the leasing dispute, for tax years 2007 through 2010, the IRS owes PSEG approximately~~ ~~$676 million~~.PSEG has filed amended returns for tax years 2007-2010 reflecting the impact of the settlement. These returns have been audited by the IRS and accepted as filed. As required by statute, the IRS presented the refund claim to the Joint Committee on Taxation for approval. In October 2012, PSEG was notified that the Joint Committee took no exception to the refund claim. In April 2013, PSEG received confirmation from the IRS which shows that overpayments from the 2008 through 2010 tax years have been applied to satisfy the liabilities due with respect to tax years 2004 through 2007. Accordingly, no further cash payments will be required with respect to the contested leasing transactions. In addition to the above, PSEG claimed a tax deduction for the accrued deficiency interest associated with this settlement in 2012, which gives rise to a cash tax savings of approximately ~~$100 million~~.

Note ~~10.~~9. Changes in Capitalization

The following capital transactions occurred in the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014:

Power

paid cash dividends of $~~690~~375 million to ~~PSEG, and~~

~~paid~~ ~~$300 million~~ of ~~2.50%~~ ~~Senior Notes at maturity.~~PSEG.

PSE&G

~~issued~~ ~~$350 million~~ of ~~2.30%~~ ~~Secured Medium-Term Notes, Series I due~~ ~~September 2018~~,

~~issued~~ ~~$250 million~~ of ~~3.75%~~ ~~Secured Medium-Term Notes, Series I due~~ ~~March 2024~~,

paid $~~300 million~~ of ~~5.375%~~ ~~Secured Medium-Term Notes at maturity,~~

~~issued~~ ~~$500 million~~ of ~~2.375%~~ ~~Secured Medium-Term Notes, Series I due~~ ~~May 2023~~,

~~paid~~ ~~$150 million~~ of ~~5.00%~~ ~~Secured Medium-Term Notes at maturity,~~

~~issued~~ ~~$400 million~~ of ~~3.80%~~ ~~Secured Medium-Term Notes, Series H due~~ ~~January 2043~~,

~~received a~~ ~~$100 million~~ ~~capital contribution from PSEG,~~

~~paid~~ ~~$156~~54 million of Transition Funding's securitization debt, and

~~paid $~~received a 6$175 million ~~of Transition Funding II's securitization debt.~~capital contribution from PSEG.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Note ~~11.~~10. Financial Risk Management Activities

The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions.

Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Commodity Prices

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

Cash Flow Hedges

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

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

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

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

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

As of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity were as follows:

As of As of
September 30,
2013 December 31,
2012
Millions
Fair Value of Cash Flow Hedges $ 1
$ 3

Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ 3
$ 9




	As of		As of
	March 31, 2014		December 31, 2013
	Millions
Fair Value of Cash Flow Hedges	$	—	$	(4	)
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)	$	1	$	(1	)

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The expiration date of the longest-dated cash flow hedge at Power is in December 2014. Power’s remaining $31 million of after-tax unrealized gains on these derivatives is expected to be reclassified to earnings during the next 12 months. There was no ineffectiveness associated with qualifying hedges as of ~~September 30, 2013~~March 31, 2014.

~~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 it serves. Historically, Power engaged in trading of electricity and energy-related products where such transactions were not associated with the output or fuel purchase requirements of its facilities. This trading consisted mostly of energy supply contracts where Power secured sales commitments with the intent to supply the energy services from purchases in the market rather than from its owned generation. Such trading activities were marked to market through the income statement and represented less than ~~one percent~~ ~~of gross margin (revenues~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~less energy costs) on an annual basis. Effective July 2011, Power discontinued trading activities and anticipates that it will not enter into any more trading derivative contracts.~~

Other Derivatives

Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of its expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in ~~the~~ fair market value of these contracts are recorded in earnings. PSE&G is a party to certain long-term natural gas sales contracts to optimize its pipeline capacity utilization. ~~In addition, as further described in Note 9. Commitments and Contingent Liabilities, PSE&G was directed to execute long-term SOCAs with certain generators to support the LCAPP Act.~~ These natural gas contracts qualify as derivatives and are marked to fair market value with the offset recorded to Regulatory Assets and Liabilities.

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, they have used a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of ~~September 30, 2013~~March 31, 2014, PSEG had seven interest rate swaps outstanding totaling $850 million. These swaps convert 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 forecasted interest payments of the debt. As of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, the fair value of all the underlying hedges was $4234 million and $5738 million, respectively.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(1) million ~~and~~ ~~$(2) million~~as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013~~, respectively.~~.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. ~~See Note 2. Recent Accounting Standards.~~ In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with our accounting policy, these positions have been offset in the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables.

3736

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of September 30, 2013
Power (A) PSE&G(A) PSEG (A) Consolidated

Cash Flow
Hedges

Non
Hedges

Non
Hedges

Fair Value
Hedges

Balance Sheet Location
Energy-
Related
Contracts

Energy-
Related
Contracts

Netting
(B)

Total
Power

Energy-
Related
Contracts

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 1
$ 228
$ (157 ) $ 72
$ 19
$ 16
$ 107

Noncurrent Assets —
164
(75 ) 89
69
26
184

Total Mark-to-Market Derivative Assets $ 1
$ 392
$ (232 ) $ 161
$ 88
$ 42
$ 291

Derivative Contracts
Current Liabilities $ —
$ (193 ) $ 157
$ (36 ) $ —
$ —
$ (36 )
Noncurrent Liabilities —
(96 ) 73
(23 ) (140 ) —
(163 )
Total Mark-to-Market Derivative (Liabilities) $ —
$ (289 ) $ 230
$ (59 ) $ (140 ) $ —
$ (199 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 1
$ 103
$ (2 ) $ 102
$ (52 ) $ 42
$ 92




	As of March 31, 2014
	Power (A)											PSE&G(A)			PSEG (A)		Consolidated
	Cash Flow Hedges		Non Hedges									Non Hedges			Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts		Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	—	$	606		$	(579	)	$	27		$	—		$	16	$	43
Noncurrent Assets	—		137			(128		)	9			20			18		47
Total Mark-to-Market Derivative Assets	$	—	$	743		$	(707	)	$	36		$	20		$	34	$	90
Derivative Contracts
Current Liabilities	$	—	$	(793	)	$	726		$	(67	)	$	(8	)	$	—	$	(75	)
Noncurrent Liabilities	—		(125		)	97			(28		)	—			—		(28		)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(918	)	$	823		$	(95	)	$	(8	)	$	—	$	(103	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	—	$	(175	)	$	116		$	(59	)	$	12		$	34	$	(13	)

As of December 31, 2012
Power (A) PSE&G (A) PSEG (A) Consolidated

Cash Flow
Hedges

Non
Hedges

Non
Hedges

Fair Value
Hedges

Balance Sheet Location
Energy-
Related
Contracts

Energy-
Related
Contracts

Netting
(B)

Total
Power

Energy-
Related
Contracts

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 3
$ 332
$ (217 ) $ 118
$ 5
$ 15
$ 138

Noncurrent Assets —
75
(26 ) 49
62
42
153

Total Mark-to-Market Derivative Assets $ 3
$ 407
$ (243 ) $ 167
$ 67
$ 57
$ 291

Derivative Contracts
Current Liabilities $ —
$ (265 ) $ 219
$ (46 ) $ —
$ —
$ (46 )
Noncurrent Liabilities —
(41 ) 26
(15 ) (107 ) —
(122 )
Total Mark-to-Market Derivative (Liabilities) $ —
$ (306 ) $ 245
$ (61 ) $ (107 ) $ —
$ (168 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 3
$ 101
$ 2
$ 106
$ (40 ) $ 57
$ 123




	As of December 31, 2013
	Power (A)												PSE&G (A)		PSEG (A)		Consolidated
	Cash Flow Hedges			Non Hedges									Non Hedges		Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts			Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	—		$	323		$	(266	)	$	57		$	25	$	16	$	98
Noncurrent Assets	—			155			(83		)	72			69		22		163
Total Mark-to-Market Derivative Assets	$	—		$	478		$	(349	)	$	129		$	94	$	38	$	261
Derivative Contracts
Current Liabilities	$	(4	)	$	(343	)	$	271		$	(76	)	$	—	$	—	$	(76	)
Noncurrent Liabilities	—			(111		)	80			(31		)	—		—		(31		)
Total Mark-to-Market Derivative (Liabilities)	$	(4	)	$	(454	)	$	351		$	(107	)	$	—	$	—	$	(107	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	(4	)	$	24		$	2		$	22		$	94	$	38	$	154

(A)

Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013. PSE&G does not have any derivative contracts subject to master netting or similar agreements.


(B)	Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the

3837

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

~~the~~ right of offset exists, has been offset in the statement of financial position. As of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, net cash collateral (received) paid of $~~(2)~~116 million and $2 million, respectively, were netted against the corresponding net derivative contract positions. Of the $~~(2)~~116 million as of ~~September 30, 2013~~March 31, 2014, $~~(1)~~(33) million of cash collateral was netted against ~~current assets,~~ ~~$(2) million~~ ~~was netted against~~ noncurrent assets and $1147 million ~~was~~and $2 million were netted against current ~~liabilities.~~liabilities and noncurrent liabilities, respectively. Of the $2$2 million as of December 31, ~~2012~~2013, cash collateral of ~~$(3)~~$(3) million and $5 million were netted against ~~current~~noncurrent assets and current liabilities, respectively.

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

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on NYMEX and ICE that are fully collateralized) was $~~75 million~~ ~~and~~ ~~$98~~91 million as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013~~, respectively.~~. As of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, Power had the contractual right of offset of $4239 million ~~and~~ ~~$61 million, respectively,~~ related to derivative instruments that are assets with the same counterparty under agreements and net of margin posted. If Power had been downgraded or lost its investment grade rating, it would have had additional collateral obligations of $~~33 million~~ ~~and~~ ~~$37~~52 million as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013~~, respectively,~~ related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $~~588~~802 million and $~~654~~691 million as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013, respectively, discussed in Note 9.8. Commitments and Contingent Liabilities.

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, 2013~~March 31, 2014 and ~~2012~~2013:

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 Three Months Ended Three Months Ended
September 30, September 30, September 30,
2013 2012 2013 2012 2013 2012
Millions
PSEG
Energy-Related Contracts $ 1
$ (3 ) Operating Revenues $ 3
$ 15
Operating Revenues $ (1 ) $ (1 )
Total PSEG $ 1
$ (3 ) $ 3
$ 15
$ (1 ) $ (1 )
Power
Energy-Related Contracts $ 1
$ (3 ) Operating Revenues $ 3
$ 15
Operating Revenues $ (1 ) $ (1 )
Total Power $ 1
$ (3 ) $ 3
$ 15
$ (1 ) $ (1 )




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						Three Months Ended						Three Months Ended
	March 31,						March 31,						March 31,
	2014			2013			2014			2013			2014		2013
	Millions
PSEG
Energy-Related Contracts	$	(8	)	$	—	Operating Revenues	$	(12	)	$	6	Operating Revenues	$	—	$	—
Total PSEG	$	(8	)	$	—		$	(12	)	$	6		$	—	$	—
Power
Energy-Related Contracts	$	(8	)	$	—	Operating Revenues	$	(12	)	$	6	Operating Revenues	$	—	$	—
Total Power	$	(8	)	$	—		$	(12	)	$	6		$	—	$	—

3938

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

~~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, 2013~~ ~~and~~ ~~2012~~:

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 Nine Months Ended Nine Months Ended
September 30, September 30, September 30,
2013 2012 2013 2012 2013 2012
Millions
PSEG (A)
Energy-Related Contracts $ 1
$ 27
Operating Revenues $ 11
$ 67
Operating Revenues $ (1 ) $ (1 )
Energy-Related Contracts —
(4 ) Energy Costs —
(9 ) —
—

Interest Rate Swaps —
—
Interest Expense (1 ) (1 ) —
—

Total PSEG $ 1
$ 23
$ 10
$ 57
$ (1 ) $ (1 )
Power
Energy-Related Contracts $ 1
$ 27
Operating Revenues $ 11
$ 67
Operating Revenues $ (1 ) $ (1 )
Energy-Related Contracts —
(4 ) Energy Costs —
(9 ) —
—

Total Power $ 1
$ 23
$ 11
$ 58
$ (1 ) $ (1 )

~~(A) Includes amounts for PSEG parent.~~

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

Accumulated Other Comprehensive Income Pre-Tax After-Tax
Millions
Balance as of December 31, 2012 $ 12
$ 7

Less: Gain Reclassified into Income (7 ) (4 )
Balance as of June 30, 2013 $ 5
$ 3

Gain Recognized in AOCI $ 1
1

Less: Gain Reclassified into Income (3 ) (2 )
Balance as of September 30, 2013 $ 3
$ 2




Accumulated Other Comprehensive Income	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2012	$	12		$	7
Loss Recognized in AOCI	(4		)	(2		)
Gain Reclassified into Income	(12		)	(7		)
Balance as of December 31, 2013	$	(4	)	$	(2	)
Loss Recognized in AOCI	(8		)	(5		)
Loss Reclassified into Income	12			7
Balance as of March 31, 2014	$	—		$	—

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months ~~and~~ ~~nine months~~ended ~~September 30, 2013~~March 31, 2014 and ~~2012~~2013:

Derivatives Not Designated as Hedges
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives

Pre-Tax Gain (Loss)
Recognized in Income
on Derivatives

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
Millions
PSEG and Power
Energy-Related Contracts Operating Revenues $ 14
$ (90 ) $ (32 ) $ 145

Energy-Related Contracts Energy Costs 10
6
63
(17 )
Total PSEG and Power $ 24
$ (84 ) $ 31
$ 128




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives		Pre-Tax Gain (Loss) Recognized in Income on Derivatives
			Three Months Ended
			March 31,
			2014			2013
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues		$	(794	)	$	(209	)
Energy-Related Contracts	Energy Costs		113			58
Total PSEG and Power			$	(681	)	$	(151	)

Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of these contracts are marked to market. The tables above do not include contracts for which Power has elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $45 million ~~and~~ ~~$6 million~~for each of the three month periods ~~and~~ended ~~$14 million~~March 31, 2014 and ~~$17 million~~ ~~for the~~ ~~nine~~ ~~month periods ended~~ ~~September 30,~~ 2013 ~~and~~ ~~2012, respectively.~~.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following reflects the gross volume, on an absolute value basis, of derivatives as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013:

Type Notional Total PSEG Power PSE&G
Millions
As of September 30, 2013
Natural Gas Dth 537
—
377
160

Electricity MWh 247
—
247
—

Capacity MW days 4
—
—
4

FTRs MWh 22
—
22
—

Interest Rate Swaps U.S. Dollars 850
850
—
—

As of December 31, 2012
Natural Gas Dth 596
—
404
192

Electricity MWh 208
—
208
—

Capacity MW days 4
—
—
4

FTRs MWh 19
—
19
—

Interest Rate Swaps U.S. Dollars 850
850
—
—

Coal Tons 1
—
1
—




Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of March 31, 2014
Natural Gas	Dth	622	—	485	137
Electricity	MWh	304	—	304	—
Financial Transmission Rights (FTRs)	MWh	10	—	10	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—
As of December 31, 2013
Natural Gas	Dth	614	—	466	148
Electricity	MWh	243	—	243	—
FTRs	MWh	16	—	16	—
Interest Rate Swaps	U.S. Dollars	850	850	—	—

Credit Risk

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of ~~September 30, 2013~~March 31, 2014, ~~95%~~97% of the credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

The following table provides information on Power’s credit risk from others, net of cash collateral, as of ~~September 30, 2013~~March 31, 2014. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.

Rating
Current
Exposure

Securities
Held as
Collateral

Net
Exposure

Number of
Counterparties
>10%

Net Exposure of
Counterparties
>10%

Millions Millions
Investment Grade—External Rating $ 180
$ 17
$ 180
1
$ 90
(A)
Non-Investment Grade—External Rating 2
—
2
—
—

Investment Grade—No External Rating 7
—
7
—
—

Non-Investment Grade—No External Rating 8
—
8
—
—

Total $ 197
$ 17
$ 197
1
$ 90




Rating	Current Exposure		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade—External Rating	$	201	$	33	$	199	1	$	164	(A)
Non-Investment Grade—External Rating	—		—		—		—	—
Investment Grade—No External Rating	2		—		2		—	—
Non-Investment Grade—No External Rating	5		—		5		—	—
Total	$	208	$	33	$	206	1	$	164


(A)	Represents net exposure with PSE&G.

The net exposure listed ~~above,~~in the preceding table, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would be no exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of ~~September 30, 2013~~March 31, 2014, Power had ~~142~~158 active counterparties.

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~12.~~11. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

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

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

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of ~~September 30, 2013~~,March 31, 2014, these ~~consist~~consisted primarily of electric swaps whose basis is deemed significant to the fair value measurement, ~~long-term~~certain electric load ~~contracts,~~deals and long-term gas supply ~~contracts and long-term capacity~~ contracts.

The following tables present information about PSEG’s, Power’s and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~,2013, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.

4241

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Recurring Fair Value Measurements as of September 30, 2013
Description Total
Cash
Collateral
Netting (D)

Quoted Market Prices for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs
(Level 3)

Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A) $ 249
$ (3 ) $ —
$ 156
$ 96

Interest Rate Swaps (B) $ 42
$ —
$ —
$ 42
$ —

NDT Fund (C)
Equity Securities $ 843
$ —
$ 842
$ 1
$ —

Debt Securities—Govt Obligations $ 410
$ —
$ —
$ 410
$ —

Debt Securities—Other $ 320
$ —
$ —
$ 320
$ —

Other Securities $ 62
$ —
$ —
$ 62
$ —

Rabbi Trust (C)
Equity Securities—Mutual Funds $ 21
$ —
$ 21
$ —
$ —

Debt Securities—Govt Obligations $ 108
$ —
$ —
$ 108
$ —

Debt Securities—Other $ 44
$ —
$ —
$ 44
$ —

Other Securities $ 2
$ —
$ —
$ 2
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (A) $ (199 ) $ 1
$ —
$ (58 ) $ (142 )
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A) $ 161
$ (3 ) $ —
$ 156

$ 8

NDT Fund (C)
Equity Securities $ 843
$ —
$ 842
$ 1
$ —

Debt Securities—Govt Obligations $ 410
$ —
$ —
$ 410
$ —

Debt Securities—Other $ 320
$ —
$ —
$ 320
$ —

Other Securities $ 62
$ —
$ —
$ 62
$ —

Rabbi Trust (C)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—Govt Obligations $ 23
$ —
$ —
$ 23
$ —

Debt Securities—Other $ 10
$ —
$ —
$ 10
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (A) $ (59 ) $ 1
$ —
$ (58 ) $ (2 )
PSE&G
Assets:
Derivative Contracts:
Energy-Related Contracts (A) $ 88
$ —
$ —
$ —
$ 88

Rabbi Trust (C)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—Govt Obligations $ 26
$ —
$ —
$ 26
$ —

Debt Securities—Other $ 10
$ —
$ —
$ 10
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (A) $ (140 ) $ —
$ —
$ —
$ (140 )




	Recurring Fair Value Measurements as of March 31, 2014
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	566		$	—		$	566	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	56		$	(707	)	$	—	$	740		$	23
Interest Rate Swaps (C)	$	34		$	—		$	—	$	34		$	—
NDT Fund (D)
Equity Securities	$	904		$	—		$	898	$	6		$	—
Debt Securities—Govt Obligations	$	460		$	—		$	—	$	460		$	—
Debt Securities—Other	$	315		$	—		$	—	$	315		$	—
Other Securities	$	55		$	—		$	55	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	21		$	—		$	21	$	—		$	—
Debt Securities—Govt Obligations	$	109		$	—		$	—	$	109		$	—
Debt Securities—Other	$	46		$	—		$	—	$	46		$	—
Other Securities	$	7		$	—		$	—	$	7		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(103	)	$	823		$	—	$	(904	)	$	(22	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	36		$	(707	)	$	—	$	740		$	3
NDT Fund (D)
Equity Securities	$	904		$	—		$	898	$	6		$	—
Debt Securities—Govt Obligations	$	460		$	—		$	—	$	460		$	—
Debt Securities—Other	$	315		$	—		$	—	$	315		$	—
Other Securities	$	55		$	—		$	55	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	23		$	—		$	—	$	23		$	—
Debt Securities—Other	$	11		$	—		$	—	$	11		$	—
Other Securities	$	4		$	—		$	—	$	4		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(95	)	$	823		$	—	$	(904	)	$	(14	)
PSE&G
Assets:
Cash Equivalents (A)	$	132		$	—		$	132	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	20		$	—		$	—	$	—		$	20
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	3		$	—		$	3	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	10		$	—		$	—	$	10		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(8	)	$	—		$	—	$	—		$	(8	)

4342

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Recurring Fair Value Measurements as of December 31, 2012
Description Total
Cash
Collateral
Netting (D)

Quoted Market Prices for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs
(Level 3)

Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A) $ 234
$ (3 ) $ —
$ 157
$ 80

Interest Rate Swaps (B) $ 57
$ —
$ —
$ 57
$ —

NDT Fund (C)
Equity Securities $ 789
$ —
$ 789
$ —
$ —

Debt Securities—Govt Obligations $ 285
$ —
$ —
$ 285
$ —

Debt Securities—Other $ 342
$ —
$ —
$ 342
$ —

Other Securities $ 124
$ —
$ —
$ 124
$ —

Rabbi Trust (C)
Equity Securities—Mutual Funds $ 18
$ —
$ 18
$ —
$ —

Debt Securities—Govt Obligations $ 117
$ —
$ —
$ 117
$ —

Debt Securities—Other $ 47
$ —
$ —
$ 47
$ —

Other Securities $ 3
$ —
$ —
$ 3
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (A) $ (168 ) $ 5
$ —
$ (62 ) $ (111 )
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A) $ 167
$ (3 ) $ —
$ 157
$ 13

NDT Fund (C)
Equity Securities $ 789
$ —
$ 789
$ —
$ —

Debt Securities—Govt Obligations $ 285
$ —
$ —
$ 285
$ —

Debt Securities—Other $ 342
$ —
$ —
$ 342
$ —

Other Securities $ 124
$ —
$ —
$ 124
$ —

Rabbi Trust (C)
Equity Securities—Mutual Funds $ 3
$ —
$ 3
$ —
$ —

Debt Securities—Govt Obligations $ 23
$ —
$ —
$ 23
$ —

Debt Securities—Other $ 9
$ —
$ —
$ 9
$ —

Other Securities $ 1
$ —
$ —
$ 1
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (A) $ (61 ) $ 5
$ —
$ (62 ) $ (4 )
PSE&G
Assets:
Derivative Contracts:
Energy Related Contracts (A) $ 67
$ —
$ —
$ —
$ 67

Rabbi Trust (C)
Equity Securities—Mutual Funds $ 6
$ —
$ 6
$ —
$ —

Debt Securities—Govt Obligations $ 39
$ —
$ —
$ 39
$ —

Debt Securities—Other $ 15
$ —
$ —
$ 15
$ —

Other Securities $ 1
$ —
$ —
$ 1
$ —

Liabilities:
Derivative Contracts:
Energy Related Contracts (A) $ (107 ) $ —
$ —
$ —
$ (107 )




	Recurring Fair Value Measurements as of December 31, 2013
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	439		$	—		$	439	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	223		$	(349	)	$	—	$	474		$	98
Interest Rate Swaps (C)	$	38		$	—		$	—	$	38		$	—
NDT Fund (D)
Equity Securities	$	897		$	—		$	892	$	5		$	—
Debt Securities—Govt Obligations	$	429		$	—		$	—	$	429		$	—
Debt Securities—Other	$	291		$	—		$	—	$	291		$	—
Other Securities	$	84		$	—		$	57	$	27		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	23		$	—		$	23	$	—		$	—
Debt Securities—Govt Obligations	$	107		$	—		$	—	$	107		$	—
Debt Securities—Other	$	46		$	—		$	—	$	46		$	—
Other Securities	$	3		$	—		$	—	$	3		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(107	)	$	351		$	—	$	(448	)	$	(10	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	129		$	(349	)	$	—	$	474		$	4
NDT Fund (D)
Equity Securities	$	897		$	—		$	892	$	5		$	—
Debt Securities—Govt Obligations	$	429		$	—		$	—	$	429		$	—
Debt Securities—Other	$	291		$	—		$	—	$	291		$	—
Other Securities	$	84		$	—		$	57	$	27		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	23		$	—		$	—	$	23		$	—
Debt Securities—Other	$	10		$	—		$	—	$	10		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(107	)	$	351		$	—	$	(448	)	$	(10	)
PSE&G
Assets:
Derivative Contracts:
Energy Related Contracts (B)	$	94		$	—		$	—	$	—		$	94
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	25		$	—		$	—	$	25		$	—
Debt Securities—Other	$	11		$	—		$	—	$	11		$	—
Other Securities	$	1		$	—		$	—	$	1		$	—


(A)	Represents money market mutual funds.

(B)

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis ~~adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.~~

4443

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(UNAUDITED)

adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.


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

~~(C)~~(D)

The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask ~~price (primarily Level 1).~~price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active ~~market (Level 1).~~market.

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

~~(D)~~(E)

~~Cash~~Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral ~~netting represents~~received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheet. As of March 31, 2014, net cash collateral ~~amounts~~(received) paid of $116 million, was netted against the corresponding net derivative contract positions. Of the $116 million as of March 31, 2014, $(33) million of cash collateral was netted against assets, and ~~liabilities~~$149 million was netted against liabilities. As of December 31, 2013, net cash collateral (received) paid of $2 million, was netted against the corresponding net derivative contract positions. Of the $2 million as ~~permitted under the accounting guidance for Offsetting~~ of ~~Amounts Related to Certain Contracts.~~December 31, 2013, $(3) million of cash collateral was netted against assets, and $5 million was netted against liabilities.

Additional Information Regarding Level 3 Measurements

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group, and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and ~~nonperformance~~non-performance risk were not material to the financial statements.

For Power, in general, electric swaps are measured at fair value based on at least two pricing inputs, the underlying price of electricity at a liquid reference point and the basis difference between electricity prices at the liquid reference point and electricity prices at the respective delivery locations. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as Level 3. The fair value of certain of Power's electric load

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. For Power, long-term electric capacity contracts are measured using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For Power and PSE&G, natural gas supply contracts are measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. For PSE&G, long-term electric capacity contracts are measured at fair value using both observable capacity auction prices and unobservable future long-term capacity prices. The measurement of these contracts include adjustments for contingencies, such as the potential outcome of litigation specifically related to the contract and the risk related to the construction of the specified capacity facilities.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Accordingly, the fair value measurements are classified as Level 3.~~ The following tables provide details surrounding significant Level 3 valuations as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013.

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position September 30, 2013 Technique(s) Input Range
Assets (Liabilities)
Millions
Power
                Electricity              Electric Swaps $ 7
$ —
Discounted Cash Flow Power Basis $0 to $10/MWh
                 Electricity Electric Load Contracts —
(2 ) Discounted Cash Flow Historic Load Variability -5% to +10%
Other Various (A) 1
—

Total Power $ 8
$ (2 )
PSE&G
Gas and Capacity    Forward Contracts (B) $ 88
$ (140 ) Discounted Cash Flow Long-Term Capacity Prices and Transportation Costs (B)
Total PSE&G $ 88
$ (140 )
TOTAL PSEG $ 96
$ (142 )




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	March 31, 2014					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Swaps	$	—	$	(5	)	Discounted Cash Flow	Power Basis	-$3 to +$10/MWh
Electricity	Electric Load Contracts	1		(9		)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Other	Various (A)	2		—
Total Power		$	3	$	(14	)
PSE&G
Gas	Forward Contracts	$	20	$	(8	)	Discounted Cash Flow	Transportation Costs	$0.70 to $1/dekatherm
Total PSE&G		$	20	$	(8	)
TOTAL PSEG		$	23	$	(22	)

Quantitative Information About Level 3 Fair Value Measurements
Commodity Level 3 Position Fair Value as of December 31, 2012
Valuation
Technique(s)

Significant
Unobservable Input
Range
Assets (Liabilities)
Millions
Power
                Electricity                Electric Swaps $ 7
$ (1 ) Discounted Cash Flow Power Basis                     $0 to $10/MWh
                 Electricity Electric Load Contracts 1
(2 ) Discounted Cash Flow Historic Load Variability -5% to +10%
Other Various (A) 5
(1 )
Total Power $ 13
$ (4 )
PSE&G
Gas and Capacity                      Forward Contracts (C) $ 67
$ (107 ) Discounted Cash Flow Long-Term Gas Basis and Capacity Prices (C)
Total PSE&G $ 67
$ (107 )
TOTAL PSEG $ 80
$ (111 )




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2013					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Swaps	$	3	$	(1	)	Discounted Cash Flow	Power Basis	$0 to $10/MWh
Electricity	Electric Load Contracts	—		(8		)	Discounted Cash Flow	Historic Load Variability	-5% to +10%
Other	Various (B)	1		(1		)
Total Power		$	4	$	(10	)
PSE&G
Gas	Forward Contracts	$	94	$	—		Discounted Cash Flow	Transportation Costs	$0.70 to $1/dekatherm
Total PSE&G		$	94	$	—
TOTAL PSEG		$	98	$	(10	)


(A)	Includes gas supply positions ~~which are immaterial as of~~ ~~September 30, 2013~~and~~December 31, 2012. Also includes~~ long-term electric capacity positions which are immaterial as of March 31, 2014.


(B)	Includes gas supply positions which were immaterial as of December 31, ~~2012~~2013.

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(UNAUDITED)


~~(B)~~	~~Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of~~ ~~$100~~ to ~~$400/MW day. Unobservable inputs for gas supply contracts include the weighted average cost of transporting gas in the range of~~ ~~$0.70~~ to $1 ~~per dekatherm.~~


~~(C)~~	Includes long-term electric capacity and long-term gas supply positions with various unobservable inputs. Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of ~~$100~~ to ~~$400/MW day. Significant unobservable inputs for the gas supply contracts include long-term basis prices in the range of~~ $0 to $4~~/MMBTU of natural gas.~~

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

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months ended March 31, 2014 and ~~nine months~~ ~~ended~~ ~~September 30,~~ 2013, ~~and~~ ~~2012~~, respectively, follows:

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

for the Three Months Ended ~~September 30, 2013~~March 31, 2014

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of
July 1, 2013
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
(D)
Balance as of September 30, 2013
Millions
PSEG
Net Derivative Assets (Liabilities) $ (35 ) $ 1
$ (11 ) $ —
$ (1 ) $ —
$ (46 )
Power
Net Derivative Assets (Liabilities) $ 6
$ 1
$ —
$ —
$ (1 ) $ —
$ 6

PSE&G
Net Derivative Assets (Liabilities) $ (41 ) $ —
$ (11 ) $ —
$ —
$ —
$ (52 )




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2014			Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)		Transfers In/Out (D)		Balance as of March 31, 2014
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	88		$	(64	)	$	(82	)	$	—	$	59	$	—	$	1
Power
Net Derivative Assets (Liabilities)	$	(6	)	$	(64	)	$	—		$	—	$	59	$	—	$	(11	)
PSE&G
Net Derivative Assets (Liabilities)	$	94		$	—		$	(82	)	$	—	$	—	$	—	$	12

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2013

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of
January 1, 2013
Included in
Income (E)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
(D)
Balance as of September 30, 2013
Millions
PSEG
Net Derivative Assets (Liabilities) $ (31 ) $ (16 ) $ (12 ) $ —
$ 9
$ 4
$ (46 )
Power
Net Derivative Assets (Liabilities) $ 9
$ (16 ) $ —
$ —
$ 9
$ 4
$ 6

PSE&G
Net Derivative Assets (Liabilities) $ (40 ) $ —
$ (12 ) $ —
$ —
$ —
$ (52 )

~~Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the~~ ~~Three Months EndedSeptember 30, 2012~~

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of
July 1, 2012
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
(D)
Balance as of September 30, 2012
Millions
PSEG
Net Derivative Assets (Liabilities) $ (36 ) $ (1 ) $ 25
$ —
$ (9 ) $ —
$ (21 )
Non-Recourse Debt $ —
$ —
$ —
$ —
$ —
$ —
$ —

Power
Net Derivative Assets (Liabilities) $ 22
$ (1 ) $ —
$ —
$ (9 ) $ —
$ 12

PSE&G
Net Derivative Assets (Liabilities) $ (58 ) $ —
$ 25
$ —
$ —
$ —
$ (33 )

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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

~~for the~~ ~~Nine Months EndedSeptember 30, 2012~~

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of
January 1, 2012
Included in
Income (E)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
(D)
Balance as of September 30, 2012
Millions
PSEG
Net Derivative Assets (Liabilities) $ 21
$ 40
$ (30 ) $ —
$ (52 ) $ —
$ (21 )
Non-Recourse Debt $ (50 ) $ 50
$ —
$ —
$ —
$ —
$ —

Power
Net Derivative Assets (Liabilities) $ 24
$ 40
$ —
$ —
$ (52 ) $ —
$ 12

PSE&G
Net Derivative Assets (Liabilities) $ (3 ) $ —
$ (30 ) $ —
$ —
$ —
$ (33 )




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2013			Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)		Transfers In/Out (D)			Balance as of March 31, 2013
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(31	)	$	(34	)	$	—	$	—	$	10	$	(2	)	$	(57	)
Power
Net Derivative Assets (Liabilities)	$	9		$	(34	)	$	—	$	—	$	10	$	(2	)	$	(17	)
PSE&G
Net Derivative Assets (Liabilities)	$	(40	)	$	—		$	—	$	—	$	—	$	—		$	(40	)

(A)

PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1$(64) million and ~~$(1)~~$(34) million in Operating Income in ~~2013~~2014 and ~~2012~~,2013, respectively. ~~The $1~~Of the $(64) million in Operating Income in ~~2013~~2014, $(5) million is unrealized. Of the ~~$(1)~~$(34) million in Operating Income in ~~2012~~, ~~$(10)~~2013, $(24) million is unrealized. ~~Energy Holdings' release from its obligation under the non-recourse debt is included in PSEG's Operating Income for~~ ~~2012~~ ~~and is offset by the write-off of the related assets.~~


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


(C)	Represents ~~$(1)~~$59 million and ~~$(9)~~$10 million in settlements for the three months ended ~~September 30, 2013~~March 31, 2014 and ~~2012. Includes~~ ~~$9 million~~ ~~and~~ ~~$(52) million~~ ~~in settlements for the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013~~ ~~and~~ ~~2012, respectively.~~2013.

(D)

~~During~~There were no transfers among levels during the ~~nine~~three months ended ~~September 30,~~March 31, 2014. During the three months ended March 31, 2013,, $4 $2 million of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred), as per PSEG's policy. ~~There were no transfers among levels during the~~ ~~three months~~ ~~ended~~ ~~September 30, 2013~~ ~~and~~ ~~2012~~ ~~and the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2012~~.

~~(E)~~

~~PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include~~ ~~$(16) million~~ ~~and~~ ~~$40 million~~ ~~in Operating Income in~~ ~~2013~~ ~~and~~ ~~2012, respectively. Of the~~ ~~$(16) million~~ ~~in Operating Income in~~ ~~2013~~, ~~$(7) million~~ ~~is unrealized. Of the~~ ~~$40 million~~ ~~in Operating Income in~~ ~~2012~~, ~~$(12) million~~ ~~is unrealized. Energy Holdings' release from its obligation under the non-recourse debt is included in PSEG's Operating Income for~~ ~~2012~~ ~~and is offset by the write-off of the related assets.~~

As of ~~September 30, 2013~~March 31, 2014, PSEG carried $~~1.9~~2.5 billion of net assets that are measured at fair value on a recurring basis, of which $461 million of net ~~liabilities~~assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of ~~September 30, 2012~~March 31, 2013, PSEG carried $1.8 billion of net assets that are measured at fair value on a recurring basis, of which $2157 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

4947

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of ~~September 30, 2013~~March 31, 2014 and December 31, ~~2012~~2013.

September 30, 2013 December 31, 2012

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Millions
Long-Term Debt:
PSEG (Parent) (A) $ 27
$ 42
$ 38
$ 57

Power -Recourse Debt (B) 2,041
2,355
2,340
2,818

PSE&G (B) 5,841
6,058
4,795
5,606

Transition Funding (PSE&G) (B) 534
578
690
765

Transition Funding II (PSE&G) (B) 27
28
32
34

Energy Holdings:
Project Level, Non-Recourse Debt (C) 16
16
44
44

Total Long-Term Debt $ 8,486
$ 9,077
$ 7,939
$ 9,324




	As of				As of
	March 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	22	$	34	$	24	$	38
Power -Recourse Debt (B)	2,541		2,889		2,541		2,846
PSE&G (B)	5,567		5,885		5,566		5,629
Transition Funding (PSE&G) (B)	422		450		476		511
Transition Funding II (PSE&G) (B)	20		21		20		21
Energy Holdings:
Project Level, Non-Recourse Debt (C)	16		16		16		16
Total Long-Term Debt	$	8,588	$	9,295	$	8,643	$	9,061


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


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


(C)	Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Note ~~13.~~12. Other Income and Deductions

Other Income Power PSE&G Other (A) Consolidated
Millions
Three Months Ended September 30, 2013
NDT Fund Gains, Interest, Dividend and Other Income $ 45
$ —
$ —
$ 45

Allowance of Funds Used During Construction —
5
—
5

Solar Loan Interest —
7
—
7

Other —
1
1
2

Total Other Income $ 45
$ 13
$ 1
$ 59

Three Months Ended September 30, 2012
NDT Fund Gains, Interest, Dividend and Other Income $ 103
$ —
$ —
$ 103

Allowance of Funds Used During Construction —
6
—
6

Solar Loan Interest —
5
—
5

Other 1
5
1
7

Total Other Income $ 104
$ 16
$ 1
$ 121

Nine Months Ended September 30, 2013
NDT Fund Gains, Interest, Dividend and Other Income $ 125
$ —
$ —
$ 125

Allowance of Funds Used During Construction —
17
—
17

Solar Loan Interest —
18
—
18

Other 2
6
4
12

Total Other Income $ 127
$ 41
$ 4
$ 172

Nine Months Ended September 30, 2012
NDT Fund Gains, Interest, Dividend and Other Income $ 167
$ —
$ —
$ 167

Allowance of Funds Used During Construction —
17
—
17

Solar Loan Interest —
13
—
13

Other 4
9
6
19

Total Other Income $ 171
$ 39
$ 6
$ 216




Other Income	Power		PSE&G		Other (A)		Consolidated
	Millions
Three Months Ended March 31, 2014
NDT Fund Gains, Interest, Dividend and Other Income	$	32	$	—	$	—	$	32
Allowance of Funds Used During Construction	—		6		—		6
Solar Loan Interest	—		6		—		6
Other	1		2		1		4
Total Other Income	$	33	$	14	$	1	$	48
Three Months Ended March 31, 2013
NDT Fund Gains, Interest, Dividend and Other Income	$	47	$	—	$	—	$	47
Allowance of Funds Used During Construction	—		6		—		6
Solar Loan Interest	—		6		—		6
Other	—		1		1		2
Total Other Income	$	47	$	13	$	1	$	61

5148

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Other Deductions Power PSE&G Other (A) Consolidated
Millions
Three Months Ended September 30, 2013
  NDT Fund Realized Losses and Expenses $ 11
$ —
$ —
$ 11

  Other —
1
—
1

    Total Other Deductions $ 11
$ 1
$ —
$ 12

Three Months Ended September 30, 2012
  NDT Fund Realized Losses and Expenses $ 20
$ —
$ —
$ 20

  Other —
6
—
6

    Total Other Deductions $ 20
$ 6
$ —
$ 26

Nine Months Ended September 30, 2013
  NDT Fund Realized Losses and Expenses $ 40
$ —
$ —
$ 40

  Other 9
3
2
14

  Total Other Deductions $ 49
$ 3
$ 2
$ 54

Nine Months Ended September 30, 2012
  NDT Fund Realized Losses and Expenses $ 45
$ —
$ —
$ 45

  Other 7
8
1
16

  Total Other Deductions $ 52
$ 8
$ 1
$ 61




Other Deductions	Power		PSE&G		Other (A)		Consolidated
	Millions
Three Months Ended March 31, 2014
NDT Fund Realized Losses and Expenses	$	6	$	—	$	—	$	6
Other	4		—		2		6
Total Other Deductions	$	10	$	—	$	2	$	12
Three Months Ended March 31, 2013
NDT Fund Realized Losses and Expenses	$	20	$	—	$	—	$	20
Other	8		1		—		9
Total Other Deductions	$	28	$	1	$	—	$	29


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

Note ~~14.~~13. Income Taxes

PSEG’s, Power’s and PSE&G’s effective tax rates for the three months ended March 31, 2014 and ~~nine months~~ ~~ended~~ ~~September 30,~~ 2013 ~~and~~ ~~2012~~ were as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
PSEG 41.0 % 41.0 % 40.5 % 36.3 %
Power 41.0 % 42.4 % 40.6 % 41.0 %
PSE&G 40.6 % 39.9 % 40.0 % 35.4 %




	Three Months Ended
	March 31,
	2014		2013
PSEG	40.2	%	40.7	%
Power	40.4	%	39.8	%
PSE&G	40.1	%	41.1	%

~~For~~There were no material changes in the effective tax rates of PSEG, Power and PSE&G for the three months ended ~~September 30, 2013~~March 31, 2014, as compared to the same period in the prior ~~year, the decrease in Power's effective tax rate was due primarily to higher NDT income in 2012.~~

~~For the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013~~, PSEG's and PSE&G's effective tax rates were higher than last year's effective tax rates due primarily to a settlement in 2012 with the IRS in regard to leveraged leases and the federal tax audit for tax years 1997 through 2006.year.

In September 2013, the U.S. Department of the Treasury and the IRS released final regulations that provide guidance on applying Section 263(a) of the Internal Revenue Code to amounts paid to acquire, produce, or improve tangible property, as well as rules for materials and supplies. ~~Implementation of these final~~These regulations became effective in ~~September 2013 had no~~2014 and their implementation did not have any material impact on PSEG’s and its subsidiaries’ results of operations, financial condition or cash flows.

The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 included a provision making qualified property placed into service after September 8, 2010 and before January 1, 2012, eligible for 100% bonus depreciation for tax purposes. In addition, qualified property placed into service in 2012 was eligible for 50% bonus depreciation for tax purposes. On January 2, 2013, the President signed into law the American Taxpayer Relief Act of 2012 that further ~~extends~~extended the 50% bonus depreciation for qualified property placed into service before January 1, 2014. In addition, long production property placed into service in 2014 is eligible for 50% bonus depreciation for tax purposes. These provisions have generated cash for

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

PSEG through tax benefits related to the accelerated depreciation. These tax benefits otherwise would have ~~otherwise~~ been received over an estimated average 20 year period.

~~In June 2009, September 2008 and December 2007, PSEG made tax deposits with the IRS in the amounts of~~ ~~$140 million~~, ~~$80 million~~ ~~and~~ ~~$100 million~~, respectively, to defray potential interest costs associated with disputed tax assessments associated with certain lease investments. On January 31, 2012, PSEG signed a specific matter closing agreement with the IRS regarding this matter. Based on this agreement, these deposits were applied against tax and interest due pursuant to the closing agreement. Further, on the same date, PSEG signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. In March 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These agreements concluded the audits for these years for PSEG and the leasing issue for all tax years. The financial statement impacts of these agreements, net of existing financial statement reserves, was a net decrease in tax expense in the first quarter of 2012 of ~~$71 million~~ ~~for PSEG, including~~ ~~$30 million~~ ~~and~~ ~~$1 million~~ ~~for PSE&G and Power, respectively.~~

~~Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax~~

Other Comprehensive Income (Loss)
PSEG Three Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss) Derivative Contracts Pension and OPEB Plans Available-for -Sale Securities Total
Millions
Balance as of June 30, 2013 $ 3
$ (466 ) $ 101
$ (362 )
Other Comprehensive Income before Reclassifications 1
—
27
28

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (2 ) 9
(11 ) (4 )
Net Current Period Other Comprehensive Income (Loss) (1 ) 9
16
24

Balance as of September 30, 2013 $ 2
$ (457 ) $ 117
$ (338 )

Other Comprehensive Income (Loss)
Power Three Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss) Derivative Contracts Pension and OPEB Plans Available-for -Sale Securities Total
Millions
Balance as of June 30, 2013 $ 4
$ (405 ) $ 98
$ (303 )
Other Comprehensive Income before Reclassifications 1
—
28
29

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (2 ) 8
(11 ) (5 )
Net Current Period Other Comprehensive Income (Loss) (1 ) 8
17
24

Balance as of September 30, 2013 $ 3
$ (397 ) $ 115
$ (279 )

Other Comprehensive Income (Loss)
PSEG Nine Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss) Derivative Contracts Pension and OPEB Plans Available-for -Sale Securities Total
Millions
Balance as of December 31, 2012 $ 7
$ (485 ) $ 90
$ (388 )
Other Comprehensive Income before Reclassifications 1
—
53
54

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (6 ) 28
(26 ) (4 )
Net Current Period Other Comprehensive Income (Loss) (5 ) 28
27
50

Balance as of September 30, 2013 $ 2
$ (457 ) $ 117
$ (338 )

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Other Comprehensive Income (Loss)
Power Nine Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss) Derivative Contracts Pension and OPEB Plans Available-for -Sale Securities Total
Millions
Balance as of December 31, 2012 $ 9
$ (422 ) $ 85
$ (328 )
Other Comprehensive Income before Reclassifications 1
—
56
57

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (7 ) 25
(26 ) (8 )
Net Current Period Other Comprehensive Income (Loss) (6 ) 25
30
49

Balance as of September 30, 2013 $ 3
$ (397 ) $ 115
$ (279 )

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
PSEG Three Months Ended Nine Months Ended
September 30, 2013 September 30, 2013
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Energy Related Contracts Operating Revenues $ 3
$ (1 ) $ 2
$ 11
$ (4 ) $ 7

Interest Rate Swaps Interest Expense —
—
—
(1 ) —
$ (1 )
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit Operation and Maintenance Expense 3
(1 ) 2
8
(3 ) 5

Amortization of Actuarial Loss Operation and Maintenance Expense (18 ) 7
(11 ) (56 ) 23
(33 )
Available-for-Sale Securities
Realized Gains Other Income 35
(18 ) 17
99
(51 ) 48

Realized Losses Other Deductions (9 ) 4
(5 ) (37 ) 18
(19 )
Other-Than-Temporary Impairments Other-Than-Temporary Impairments (3 ) 2
(1 ) (7 ) 4
(3 )
Total $ 11
$ (7 ) $ 4
$ 17
$ (13 ) $ 4

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Power Three Months Ended Nine Months Ended
September 30, 2013 September 30, 2013

Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Energy Related Contracts Operating Revenues $ 3
$ (1 ) $ 2
$ 11
$ (4 ) $ 7

Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit Operation and Maintenance Expense 3
(1 ) 2
7
(3 ) 4

Amortization of Actuarial Loss Operation and Maintenance Expense (17 ) 7
(10 ) (49 ) 20
(29 )
Available-for-Sale Securities
Realized Gains Other Income 35
(18 ) 17
95
(49 ) 46

Realized Losses Other Deductions (9 ) 4
(5 ) (34 ) 17
(17 )
Other-Than-Temporary Impairments Other-Than-Temporary Impairments (3 ) 2
(1 ) (7 ) 4
(3 )
Total $ 12
$ (7 ) $ 5
$ 23
$ (15 ) $ 8

Balance as of December 31, 2011 Other Comprehensive Income (Loss)
Nine Months Ended
September 30, 2012 Balance as of September 30, 2012
Power PSE&G Other
Millions
Derivative Contracts $ 31
$ (21 ) $ —
$ 1
$ 11

Pension and OPEB Plans (438 ) 21
—
2
(415 )
Available-for-Sale Securities 70
11
—
1
82

Accumulated Other Comprehensive Income (Loss) $ (337 ) $ 11
$ —
$ 4
$ (322 )

5549

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~16.~~14. Accumulated Other Comprehensive Income (Loss), Net of Tax




	Other Comprehensive Income (Loss)
PSEG	Three Months Ended March 31, 2014
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2013	(2		)	$	(238	)	$	145		$	(95	)
Other Comprehensive Income before Reclassifications	(5		)	—			11			6
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	7			4			(9		)	2
Net Current Period Other Comprehensive Income (Loss)	2			4			2			8
Balance as of March 31, 2014	$	—		$	(234	)	$	147		$	(87	)




	Other Comprehensive Income (Loss)
Power	Three Months Ended March 31, 2014
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2013	$	(1	)	$	(204	)	$	142		$	(63	)
Other Comprehensive Income before Reclassifications	(6		)	—			10			4
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	7			3			(8		)	2
Net Current Period Other Comprehensive Income (Loss)	1			3			2			6
Balance as of March 31, 2014	$	—		$	(201	)	$	144		$	(57	)




	Other Comprehensive Income (Loss)
PSEG	Three Months Ended March 31, 2013
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities		Total
	Millions
Balance as of December 31, 2012	$	7		$	(485	)	$	90	$	(388	)
Other Comprehensive Income before Reclassifications	—			—			27		27
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(4		)	10			—		6
Net Current Period Other Comprehensive Income (Loss)	(4		)	10			27		33
Balance as of March 31, 2013	$	3		$	(475	)	$	117	$	(355	)




	Other Comprehensive Income (Loss)
Power	Three Months Ended March 31, 2013
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities		Total
	Millions
Balance as of December 31, 2012	$	9		$	(422	)	$	85	$	(328	)
Other Comprehensive Income before Reclassifications	—			—			27		27
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(4		)	9			—		5
Net Current Period Other Comprehensive Income (Loss)	(4		)	9			27		32
Balance as of March 31, 2013	$	5		$	(413	)	$	112	$	(296	)

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
PSEG		Three Months Ended									Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	March 31, 2014									March 31, 2013
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	(12	)	$	5		$	(7	)	$	6		$	(2	)	$	4
Total Cash Flow Hedges		(12		)	5			(7		)	6			(2		)	4
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Operation and Maintenance (O&M) Expense	2			(1		)	1			4			(2		)	2
Amortization of Actuarial Loss	O&M Expense	(8		)	3			(5		)	(21		)	9			(12		)
Total Pension and OPEB Plans		(6		)	2			(4		)	(17		)	7			(10		)
Available-for-Sale Securities
Realized Gains	Other Income	25			(13		)	12			2			(1		)	1
Realized Losses	Other Deductions	(4		)	2			(2		)	—			—			—
Other-Than-Temporary Impairments (OTTI)	Other-Than-Temporary Impairments (OTTI)	(2		)	1			(1		)	(2		)	1			(1		)
Total Available-for-Sale Securities		19			(10		)	9			—			—			—
Total		$	1		$	(3	)	$	(2	)	$	(11	)	$	5		$	(6	)




		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Power		Three Months Ended									Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	March 31, 2014									March 31, 2013
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	(12	)	$	5		$	(7	)	$	6		$	(2	)	$	4
Total Cash Flow Hedges		(12		)	5			(7		)	6			(2		)	4
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	2			(1		)	1			2			(1		)	1
Amortization of Actuarial Loss	O&M Expense	(6		)	2			(4		)	(16		)	6			(10		)
Total Pension and OPEB Plans		(4		)	1			(3		)	(14		)	5			(9		)
Available-for-Sale Securities
Realized Gains	Other Income	23			(12		)	11			2			(1		)	1
Realized Losses	Other Deductions	(4		)	2			(2		)	—			—			—
OTTI	OTTI	(2		)	1			(1		)	(2		)	1			(1		)
Total Available-for-Sale Securities		17			(9		)	8			—			—			—
Total		$	1		$	(3	)	$	(2	)	$	(8	)	$	3		$	(5	)

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 15. Earnings Per Share (EPS) and Dividends

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

Three Months Ended September 30, Nine Months Ended September 30,
2013 2012 2013 2012
Basic Diluted Basic Diluted Basic Diluted Basic Diluted

EPS Numerator (Millions)

Net Income $ 390
$ 390
$ 347
$ 347
$ 1,043
$ 1,043
$ 1,051
$ 1,051

EPS Denominator (Thousands)

Weighted Average Common Shares Outstanding 505,858
505,858
505,914
505,914
505,900
505,900
505,942
505,942

Effect of Stock Based Compensation Awards —
1,836
—
1,197
—
1,533
—
1,095

Total Shares 505,858
507,694
505,914
507,111
505,900
507,433
505,942
507,037

EPS
Net Income $ 0.77
$ 0.77
$ 0.69
$ 0.68
$ 2.06
$ 2.06
$ 2.08
$ 2.07




	Three Months Ended March 31,
	2014				2013
	Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Net Income	$	386	$	386	$	320	$	320
EPS Denominator (Thousands)
Weighted Average Common Shares Outstanding	506,077		506,077		505,942		505,942
Effect of Stock Based Compensation Awards	—		1,754		—		1,278
Total Shares	506,077		507,831		505,942		507,220

EPS
Net Income	$	0.76	$	0.76	$	0.63	$	0.63

Three Months Ended Nine Months Ended
September 30, September 30,
Dividend Payments on Common Stock 2013 2012 2013 2012
Per Share $ 0.3600
$ 0.3550
$ 1.0800
$ 1.0650

in Millions $ 182
$ 180
$ 546
$ 538




	Three Months Ended
	March 31,
Dividend Payments on Common Stock	2014		2013
Per Share	$	0.37	$	0.36
In Millions	$	187	$	182

5652

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~17.~~16. Financial Information by Business Segments

Power PSE&G
Energy
Holdings
Other (A) Consolidated
Millions
Three Months Ended September 30, 2013
Total Operating Revenues $ 1,169
$ 1,666
$ 8
$ (289 ) $ 2,554

Income (Loss) From Continuing Operations 221
168
(3 ) 4
390

Net Income (Loss) 221
168
(3 ) 4
390

Segment Earnings (Loss) 221
168
(3 ) 4
390

Gross Additions to Long-Lived Assets 197
480
13
6
696

Three Months Ended September 30, 2012
Total Operating Revenues $ 1,038
$ 1,683
$ 15
$ (334 ) $ 2,402

Income (Loss) From Continuing Operations 181
155
7
4
347

Net Income (Loss) 181
155
7
4
347

Segment Earnings (Loss) 181
155
7
4
347

Gross Additions to Long-Lived Assets 149
499
30
11
689

Nine Months Ended September 30, 2013
Total Operating Revenues $ 3,806
$ 5,084
$ 42
$ (1,282 ) $ 7,650

Income (Loss) From Continuing Operations 562
468
1
12
1,043

Net Income (Loss) 562
468
1
12
1,043

Segment Earnings (Loss) 562
468
1
12
1,043

Gross Additions to Long-Lived Assets 419
1,628
40
15
2,102

Nine Months Ended September 30, 2012
Total Operating Revenues $ 3,584
$ 5,029
$ 49
$ (1,287 ) $ 7,375

Income (Loss) From Continuing Operations 538
453
49
11
1,051

Net Income (Loss) 538
453
49
11
1,051

Segment Earnings (Loss) 538
453
49
11
1,051

Gross Additions to Long-Lived Assets 493
1,369
85
22
1,969

As of September 30, 2013
Total Assets $ 10,721
$ 20,330
$ 1,448
$ 111
$ 32,610

Investments in Equity Method Subsidiaries $ 40
$ —
$ 100
$ —
$ 140

As of December 31, 2012
Total Assets $ 11,032
$ 19,223
$ 1,454
$ 16
$ 31,725

Investments in Equity Method Subsidiaries $ 40
$ —
$ 94
$ —
$ 134




	Power		PSE&G		Other (A)		Eliminations (B)			Consolidated
	Millions
Three Months Ended March 31, 2014
Total Operating Revenues	$	1,700	$	2,145	$	105	$	(727	)	$	3,223
Net Income (Loss)	164		214		8		—			$	386
Gross Additions to Long-Lived Assets	126		481		2		—			$	609
Three Months Ended March 31, 2013
Total Operating Revenues	$	1,451	$	1,995	$	12	$	(672	)	$	2,786
Net Income (Loss)	141		179		—		—			320
Gross Additions to Long-Lived Assets	151		572		1		—			724
As of March 31, 2014
Total Assets	$	11,788	$	20,175	$	4,511	$	(3,148	)	$	33,326
Investments in Equity Method Subsidiaries	$	123	$	—	$	3	$	—		$	126
As of December 31, 2013
Total Assets	$	12,002	$	19,720	$	4,025	$	(3,225	)	$	32,522
Investments in Equity Method Subsidiaries	$	123	$	—	$	3	$	—		$	126


(A)	Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other ~~activities include~~also includes amounts applicable to PSEG ~~(as parent company), Services~~(parent corporation) and ~~intercompany~~Services.

(B)

Intercompany eliminations, primarily ~~relating~~related to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are ~~priced in accordance with applicable regulations, including affiliate pricing rules,~~at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note ~~18.~~17. Related-Party Transactions.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Note ~~18.~~17. Related-Party Transactions

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

Power

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

Three Months Ended Nine Months Ended
September 30, September 30,
Related-Party Transactions 2013 2012 2013 2012
Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A) $ 48
$ 67
$ 654
$ 630

Billings to PSE&G through BGS (A) 236
258
621
639

Total Revenue from Affiliates $ 284
$ 325
$ 1,275
$ 1,269

Expense Billings from Affiliates:
Administrative Billings from Services (B) $ (43 ) $ (38 ) $ (131 ) $ (110 )
Total Expense Billings from Affiliates $ (43 ) $ (38 ) $ (131 ) $ (110 )




	Three Months Ended
	March 31,
Related-Party Transactions	2014			2013
	Millions
Revenue from Affiliates:
Billings to PSE&G through BGS and BGSS Contracts (A)	$	731		$	671
Expense Billings from Affiliates:
Administrative Billings from Services (B)	$	(42	)	$	(45	)
Total Expense Billings from Affiliates	$	(42	)	$	(45	)

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of As of
Related-Party Transactions September 30, 2013 December 31, 2012
Millions
Receivables from PSE&G through BGS and BGSS Contracts (A) $ 87
$ 238

Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A) 28
27

Receivable from (Payable to) Services (B) (26 ) (31 )
Tax Receivable from (Payable to) PSEG (C) (54 ) 111

Receivable from (Payable to) PSEG (1 ) (5 )
Accounts Receivable (Payable)—Affiliated Companies, net $ 34
$ 340

Short-Term Loan to Affiliate (Demand Note to PSEG) (D)
$ 417
$ 574

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

Long-Term Accrued Taxes Receivable (Payable) (C)
$ (50 ) $ (50 )




	As of			As of
Related-Party Transactions	March 31, 2014			December 31, 2013
	Millions
Receivables from PSE&G through BGS and BGSS Contracts (A)	$	234		$	267
Receivable from (Payable to) Services (B)	(26		)	(31		)
Receivable from (Payable to) PSEG (C)	(172		)	97
Accounts Receivable (Payable)—Affiliated Companies, net	$	36		$	333
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)	$	942		$	790
Working Capital Advances to Services (E)	$	17		$	17
Long-Term Accrued Taxes Receivable (Payable)	$	(49	)	$	(53	)

PSE&G

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

Three Months Ended Nine Months Ended
September 30, September 30,
Related-Party Transactions 2013 2012 2013 2012
Millions
Expense Billings from Affiliates:
Billings from Power through BGSS (A) $ (48 ) $ (67 ) $ (654 ) $ (630 )
Billings from Power through BGS (A) (236 ) (258 ) (621 ) (639 )
Administrative Billings from Services (B) (61 ) (58 ) (184 ) (165 )
Total Expense Billings from Affiliates $ (345 ) $ (383 ) $ (1,459 ) $ (1,434 )




	Three Months Ended
	March 31,
Related-Party Transactions	2014			2013
	Millions
Expense Billings from Affiliates:
Billings from Power through BGS and BGSS (A)	$	(731	)	$	(671	)
Administrative Billings from Services (B)	(60		)	(61		)
Total Expense Billings from Affiliates	$	(791	)	$	(732	)

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

As of As of
Related-Party Transactions September 30, 2013 December 31, 2012
Millions
Payable to Power through BGS and BGSS Contracts (A) $ (87 ) $ (238 )
Payable to Power Related to Gas Supply Hedges for BGSS (A) (28 ) (27 )
Payable to Power for SREC Liability (F) —
(7 )
Receivable from (Payable to) Services (B) (58 ) (65 )
Tax Receivable from (Payable to) PSEG (C) 263
256

Receivable from (Payable to) PSEG 3
6

Receivable from Energy Holdings 1
2

Accounts Receivable (Payable)—Affiliated Companies, net $ 94
$ (73 )

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

Long-Term Accrued Taxes Receivable (Payable) (C)
$ (48 ) $ (32 )




	As of			As of
Related-Party Transactions	March 31, 2014			December 31, 2013
	Millions
Payable to Power through BGS and BGSS Contracts (A)	$	(234	)	$	(267	)
Receivable from (Payable to) Services (B)	(53		)	(73		)
Receivable from (Payable to) PSEG (C)	(6		)	150
Accounts Receivable (Payable)—Affiliated Companies, net	$	(293	)	$	(190	)
Working Capital Advances to Services (E)	$	33		$	33
Long-Term Accrued Taxes Receivable (Payable)	$	(82	)	$	(72	)


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


(B)	Services provides and bills administrative services to Power and PSE&G at cost. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.

(C)

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


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


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

~~(F)~~

~~Pursuant to a 2008 BPU Order, certain BGS suppliers, including Power, would be reimbursed for the cost they incurred above~~ ~~$300~~ per Solar Renewable Energy Certificate (SREC) or per Solar Alternative Compliance Payment (SACP) during the period June 1, 2008 through May 31, 2010 and such excess cost would be passed onto ratepayers. In accordance with a Stipulation of Settlement approved by the BPU in a December 2012 Order describing the mechanism for BGS suppliers to recover these costs, PSE&G, as a New Jersey EDC, estimated and accrued a total liability for the excess SREC cost expected to be recovered from ratepayers of $~~17 million, including approximately~~ ~~$7 million~~ ~~for Power’s share which was included in PSE&G’s Accounts Receivable (Payable)-Affiliated Companies, as of~~ ~~December 31, 2012~~. Under current accounting guidance, Power was unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet until the BPU issued an Order approving such payments. As a result, PSE&G’s liability to Power was not eliminated in consolidation and was included in Other Current Liabilities on PSEG’s Condensed Consolidated Balance Sheet as of ~~December 31, 2012. In May 2013, the BPU issued an Order approving the BGS payments for these SRECs. This Order was not appealed and went into effect in July 2013. As a result, Power recorded its~~ ~~$9 million~~ ~~then outstanding receivable from PSE&G. In August 2013, PSE&G reimbursed Power and its other BGS suppliers for the excess SREC costs.~~

5954

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~19.~~18. Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following table presents condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries.

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
Three Months Ended September 30, 2013
Operating Revenues $ —
$ 1,511
$ 66
$ (408 ) $ 1,169

Operating Expenses 2
1,145
62
(409 ) 800

Operating Income (Loss) (2 ) 366
4
1
369

Equity Earnings (Losses) of Subsidiaries 226
(1 ) —
(225 ) —

Other Income 8
47
—
(10 ) 45

Other Deductions 1
(11 ) —
(1 ) (11 )
Other-Than-Temporary Impairments —
(3 ) —
—
(3 )
Interest Expense (19 ) (13 ) (4 ) 10
(26 )
Income Tax Benefit (Expense) 7
(160 ) —
—
(153 )
Net Income (Loss) $ 221
$ 225
$ —
$ (225 ) $ 221

Comprehensive Income (Loss) $ 245
$ 242
$ —
$ (242 ) $ 245

Three Months Ended September 30, 2012
Operating Revenues $ —
$ 1,358
$ 36
$ (356 ) $ 1,038

Operating Expenses (1 ) 1,095
32
(355 ) 771

Operating Income (Loss) 1
263
4
(1 ) 267

Equity Earnings (Losses) of Subsidiaries 191
—
—
(191 ) —

Other Income 11
106
—
(13 ) 104

Other Deductions —
(20 ) —
—
(20 )
Other-Than-Temporary Impairments —
(2 ) —
—
(2 )
Interest Expense (29 ) (15 ) (5 ) 14
(35 )
Income Tax Benefit (Expense) 7
(142 ) 1
1
(133 )
Net Income (Loss) $ 181
$ 190
$ —
$ (190 ) $ 181

Comprehensive Income (Loss) $ 166
$ 168
$ —
$ (168 ) $ 166




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Consolidated
	Millions
Three Months Ended March 31, 2014
Operating Revenues	$	—		$	2,077		$	40		$	(417	)	$	1,700
Operating Expenses	4			1,797			34			(417		)	1,418
Operating Income (Loss)	(4		)	280			6			—			282
Equity Earnings (Losses) of Subsidiaries	177			—			4			(177		)	4
Other Income	8			33			—			(8		)	33
Other Deductions	(4		)	(6		)	—			—			(10		)
Other-Than-Temporary Impairments	—			(2		)	—			—			(2		)
Interest Expense	(28		)	(7		)	(5		)	8			(32		)
Income Tax Benefit (Expense)	15			(125		)	(1		)	—			(111		)
Net Income (Loss)	$	164		$	173		$	4		$	(177	)	$	164
Comprehensive Income (Loss)	$	170		$	176		$	4		$	(180	)	$	170
Three Months Ended March 31, 2014
Net Cash Provided By (Used In) Operating Activities	$	291		$	603		$	1		$	(221	)	$	674
Net Cash Provided By (Used In) Investing Activities	$	87		$	(315	)	$	—		$	(67	)	$	(295	)
Net Cash Provided By (Used In) Financing Activities	$	(375	)	$	(287	)	$	(1	)	$	288		$	(375	)
Three Months Ended March 31, 2013
Operating Revenues	$	—		$	1,803		$	37		$	(389	)	$	1,451
Operating Expenses	2			1,562			33			(388		)	1,209
Operating Income (Loss)	(2		)	241			4			(1		)	242
Equity Earnings (Losses) of Subsidiaries	153			—			3			(153		)	3
Other Income	9			48			—			(10		)	47
Other Deductions	(8		)	(20		)	—			—			(28		)
Other-Than-Temporary Impairments	—			(2		)	—			—			(2		)
Interest Expense	(27		)	(10		)	(4		)	11			(30		)
Income Tax Benefit (Expense)	16			(108		)	1			—			(91		)
Net Income (Loss)	$	141		$	149		$	4		$	(153	)	$	141
Comprehensive Income (Loss)	$	173		$	172		$	4		$	(176	)	$	173
Three Months Ended March 31, 2013
Net Cash Provided By (Used In) Operating Activities	$	189		$	574		$	1		$	(189	)	$	575
Net Cash Provided By (Used In) Investing Activities	$	56		$	(353	)	$	(8	)	$	(24	)	$	(329	)
Net Cash Provided By (Used In) Financing Activities	$	(245	)	$	(221	)	$	7		$	212		$	(247	)

6055

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
Nine Months Ended September 30, 2013
Operating Revenues $ —
$ 4,849
$ 133
$ (1,176 ) $ 3,806

Operating Expenses 6
3,894
123
(1,176 ) 2,847

Operating Income (Loss) (6 ) 955
10
—
959

Equity Earnings (Losses) of Subsidiaries 588
(3 ) —
(585 ) —

Other Income 27
130
—
(30 ) 127

Other Deductions (9 ) (40 ) —
—
(49 )

Other-Than-Temporary
   Impairments
—
(7 ) —
—
(7 )
Interest Expense (72 ) (29 ) (14 ) 30
(85 )
Income Tax Benefit (Expense) 34
(419 ) 2
—
(383 )
Net Income (Loss) $ 562
$ 587
$ (2 ) $ (585 ) $ 562

Comprehensive Income (Loss) $ 611
$ 612
$ (2 ) $ (610 ) $ 611

Nine Months Ended September 30, 2013

Net Cash Provided By (Used In)
   Operating Activities
$ 425
$ 1,360
$ 5
$ (506 ) $ 1,284

Net Cash Provided By (Used In)
   Investing Activities
$ 569
$ (869 ) $ (1 ) $ 11
$ (290 )

Net Cash Provided By (Used In)
   Financing Activities
$ (990 ) $ (492 ) $ (4 ) $ 494
$ (992 )
Nine Months Ended September 30, 2012
Operating Revenues $ —
$ 4,560
$ 93
$ (1,069 ) $ 3,584

Operating Expenses (1 ) 3,663
87
(1,069 ) 2,680

Operating Income (Loss) 1
897
6
—
904

Equity Earnings (Losses) of Subsidiaries 567
(4 ) —
(563 ) —

Other Income 35
176
—
(40 ) 171

Other Deductions (7 ) (45 ) —
—
(52 )

Other-Than-Temporary
   Impairments
—
(14 ) —
—
(14 )
Interest Expense (89 ) (35 ) (13 ) 40
(97 )
Income Tax Benefit (Expense) 31
(409 ) 3
1
(374 )
Net Income (Loss) $ 538
$ 566
$ (4 ) $ (562 ) $ 538

Comprehensive Income (Loss) $ 549
$ 556
$ (4 ) $ (552 ) $ 549

Nine Months Ended September 30, 2012

Net Cash Provided By (Used In)
   Operating Activities
$ 409
$ 1,259
$ (3 ) $ (493 ) $ 1,172

Net Cash Provided By (Used In)
   Investing Activities
$ 257
$ (897 ) $ (24 ) $ 158
$ (506 )

Net Cash Provided By (Used In)
   Financing Activities
$ (666 ) $ (368 ) $ 26
$ 335
$ (673 )




	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Consolidated
	Millions
As of March 31, 2014
Current Assets	$	4,109	$	9,145	$	951	$	(11,906	)	$	2,299
Property, Plant and Equipment, net	81		6,082		1,172		—			7,335
Investment in Subsidiaries	4,570		727		—		(5,297		)	—
Noncurrent Assets	301		1,832		138		(117		)	2,154
Total Assets	$	9,061	$	17,786	$	2,261	$	(17,320	)	$	11,788
Current Liabilities	$	603	$	11,103	$	980	$	(11,905	)	$	781
Noncurrent Liabilities	308		2,323		344		(118		)	2,857
Long-Term Debt	2,497		—		—		—			2,497
Member’s Equity	5,653		4,360		937		(5,297		)	5,653
Total Liabilities and Member’s Equity	$	9,061	$	17,786	$	2,261	$	(17,320	)	$	11,788
As of December 31, 2013
Current Assets	$	4,160	$	8,916	$	944	$	(11,544	)	$	2,476
Property, Plant and Equipment, net	81		6,108		1,178		—			7,367
Investment in Subsidiaries	4,645		729		—		(5,374		)	—
Noncurrent Assets	222		1,847		138		(48		)	2,159
Total Assets	$	9,108	$	17,600	$	2,260	$	(16,966	)	$	12,002
Current Liabilities	$	444	$	10,919	$	982	$	(11,545	)	$	800
Noncurrent Liabilities	309		2,247		338		(47		)	2,847
Long-Term Debt	2,497		—		—		—			2,497
Member’s Equity	5,858		4,434		940		(5,374		)	5,858
Total Liabilities and Member’s Equity	$	9,108	$	17,600	$	2,260	$	(16,966	)	$	12,002

6156

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
As of September 30, 2013
Current Assets $ 4,065
$ 8,609
$ 957
$ (11,941 ) $ 1,690

Property, Plant and Equipment, net 81
6,059
922
—
7,062

Investment in Subsidiaries 4,331
730
—
(5,061 ) —

Noncurrent Assets 197
1,842
56
(126 ) 1,969

Total Assets $ 8,674
$ 17,240
$ 1,935
$ (17,128 ) $ 10,721

Current Liabilities $ 752
$ 10,778
$ 997
$ (11,941 ) $ 586

Noncurrent Liabilities 522
2,130
208
(125 ) 2,735

Long-Term Debt 2,041
—
—
—
2,041

Member’s Equity 5,359
4,332
730
(5,062 ) 5,359

Total Liabilities and Member’s Equity $ 8,674
$ 17,240
$ 1,935
$ (17,128 ) $ 10,721

As of December 31, 2012
Current Assets $ 3,922
$ 8,084
$ 940
$ (10,712 ) $ 2,234

Property, Plant and Equipment, net 80
5,988
950
—
7,018

Investment in Subsidiaries 4,317
733
—
(5,050 ) —

Noncurrent Assets 201
1,660
60
(141 ) 1,780

Total Assets $ 8,520
$ 16,465
$ 1,950
$ (15,903 ) $ 11,032

Current Liabilities $ 482
$ 10,187
$ 1,010
$ (10,712 ) $ 967

Noncurrent Liabilities 559
1,960
207
(140 ) 2,586

Long-Term Debt 2,040
—
—
—
2,040

Member’s Equity 5,439
4,318
733
(5,051 ) 5,439

Total Liabilities and Member’s Equity $ 8,520
$ 16,465
$ 1,950
$ (15,903 ) $ 11,032

Table of Contents


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

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

~~PSEG’s~~PSEG's business consists of ~~three~~two reportable segments, our principal direct wholly owned subsidiaries, which are:

Power, our wholesale energy supply company that integrates its nuclear, fossil and renewable generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid-Atlantic United States, and

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

~~Energy Holdings,~~ ~~which principally owns energy-related leveraged leases and solar generation projects. A subsidiary of~~PSEG's other direct wholly owned subsidiaries are: PSEG Energy Holdings ~~has been awarded a contract to manage~~L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments; PSEG Long Island LLC (PSEG LI), which effective January 1, 2014, operates the Long Island Power Authority's (LIPA) transmission and distribution ~~assets of LIPA beginning on January 1, 2014.~~

(T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and these operating subsidiaries with certain management, administrative and general services at cost.

Our business discussion in Part I, Item 1. Business of our ~~2012~~2013 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part I, Item 1A1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Overview of ~~2012~~2013 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during ~~2013~~2014 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes ~~the 2012 Form 10-K~~ and the ~~Quarterly Reports on~~2013 Form ~~10-Q for the quarters ended June 30, 2013 and March 31, 2013.~~10-K.

OVERVIEW OF ~~2013~~2014 AND FUTURE OUTLOOK

Our business plan is designed to ~~maintain earnings stability while achieving~~achieve growth in ~~recognition of~~response to market, regulatory and economic ~~trends.~~trends while managing the risks associated with fluctuating commodity prices and changes in customer demand. We continue toour focus on operational excellence, ~~to provide the foundation for our~~ financial strength and disciplined investment. These guiding principles have provided the base from which ~~enables~~we have been able to execute our strategic initiatives, including:

Growing our utility operations through continued investment in T&D infrastructure projects with a consequential rebalancing of our business mix and greater diversification of regulatory oversight, and

Maintaining a reliable generation fleet with the flexibility to utilize a diverse mix of fuels to allow us to ~~invest~~respond to market volatility and capitalize on market opportunities as they arise in ~~a disciplined way.~~the locations in which we operate.

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Financial Results

The results for PSEG, PSE&G ~~Power~~ and ~~Energy Holdings~~Power for the three months ~~and~~ ~~nine months~~ended ~~September 30, 2013~~March 31, 2014 and ~~2012~~2013 are presented ~~below:~~as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
Earnings (Losses) 2013 2012 2013 2012
Millions
Power $ 221
$ 181
$ 562
$ 538

PSE&G 168
155
468
453

Energy Holdings (3 ) 7
1
49

Other (A) 4
4
12
11

PSEG Net Income $ 390
$ 347
$ 1,043
$ 1,051

Earnings Per Share (Diluted)
PSEG Net Income $ 0.77
$ 0.68
$ 2.06
$ 2.07




	Three Months Ended
	March 31,
Earnings (Losses)	2014		2013
	Millions
Power (A)	$	164	$	141
PSE&G	214		179
Other (B)	8		—
PSEG Net Income	$	386	$	320

PSEG Net Income Per Share (Diluted)	$	0.76	$	0.63


(A)	Power's results in 2014 and 2013 include after-tax expenses of $9 million and $28 million, respectively, for Operations and Maintenance (O&M) costs due to severe damage caused by Superstorm Sandy. See Note 8. Commitments and Contingent Liabilities.


(B)	Other primarily includes parent company interest and financing activity and certain administrative and general expenses.

Power’s results above include the realized gains, losses and earnings on the Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity and the impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with forward delivery dates.

The variances in our Net Income include the changes related to NDT and MTM shown in the ~~chart below:~~following table:

Three Months Ended Nine Months Ended
September 30, September 30,
2013 2012 2013 2012
Millions, after tax
NDT Fund Income (Expense) (A) $ 12
$ 40
$ 29
$ 49

Non-Trading MTM Gains (Losses) $ 3
$ (76 ) $ (22 ) $ (34 )




	Three Months Ended
	March 31,
	2014			2013
	Millions, after tax
NDT Fund Income (Expense) (A)	$	9		$	9
Non-Trading MTM Gains (Losses)	$	(132	)	$	(105	)

(A)

NDT Fund Income (Expense) includes the net realized gains, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and ~~Deductions. This also includes~~Deductions, and impairments on certain NDT securities ~~which are included in~~recorded as Other-Than-Temporary ~~Impairments and the interest~~Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO)~~, which~~ is recorded in ~~Operation and Maintenance~~O&M Expense, ~~and~~as well as the depreciation related to the ARO asset.

Our ~~$43~~$66 million increase in Net Income for the three months ended ~~September 30, 2013~~March 31, 2014 includes the MTM and NDT activity ~~above~~presented in the preceding table and was also impacted by:

higher ~~revenues due to increased investments in transmission projects, and~~

~~higher capacity revenues, and~~

~~higher Operation and Maintenance Costs due~~energy volumes sold primarily to planned maintenance costs at our gas-fired Bethlehem Energy Center (BEC) in New York and costs related to damage caused by Superstorm Sandy at our fossil plants, partly offset by cost control measures.

~~Our $8 million decrease in Net Income for the nine months ended September 30, 2013 was driven primarily by:~~

~~lower volumes of electricity sold under our basic generation service (BGS) contracts at lower average prices,~~

~~lower volumes of wholesale load contracts~~ in the PJM and NENew England (NE) regions

at higher ~~generation costs due to higher fuel costs,~~

~~higher Operation and Maintenance Costs in 2013, including costs related to damage caused by Superstorm Sandy, partially offset by cost control measures,~~

~~higher Income Tax Expense at PSE&G and Energy Holdings due to the absence of tax benefits related to the settlement of the 1997-2006 Internal Revenue Service (IRS) audits in 2012, and~~

~~net~~average realized ~~gains in September 2012 resulting from restructuring our NDT Fund.~~

~~These decreases were largely offset by~~

~~higher capacity pricing in the PJM region resulting from higher auction~~ prices as well as higher ~~generation sold~~capacity revenues primarily in ~~the~~ PJM ~~region,~~resulting from higher average prices,

higher sales volumes under the basic gas supply service (BGSS) contract due to colder average ~~gas prices on sales to third party customers,~~temperatures, and

higher revenues due to increased investments in transmission ~~projects,~~projects.

~~Under~~These increases were partially offset by

higher generation costs due to higher fuel costs and higher gas costs related to the ~~PJM capacity auction conducted in May 2013, Power cleared 8,637 MW of its generating capacity~~BGSS contract, and

higher O&M costs due to a planned outage at ~~an average price of $166 per MW-day for the 2016-2017 delivery period. While this year's auction resulted in~~our Linden fossil station partly offset by lower clearing prices for the PJM Regional Transmission Organization (RTO), Power benefited from higher prices than the rest of the RTO, as the majority of its generation fleet is situated in the relatively constrained Eastern part of PJM.pension and other postretirement benefit (OPEB) costs and cost control measures.

Power’s results also benefited from access to ~~low cost~~reasonably-priced natural gas ~~from the Marcellus region~~supplies through its existing firm pipeline transportation ~~and storage contracts.~~during the cold weather experienced in the first quarter of 2014. Power manages these contracts ~~primarily~~ for the benefit of PSE&G’s customers through the ~~basic~~BGSS arrangement. The contracts are sized to ensure delivery of a reliable gas supply ~~service (BGSS) arrangement. During times of low customer demand for gas,~~to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power can use ~~the remaining transportation that is available~~it to supply ~~the Marcellus~~ gas to its generating units in New ~~Jersey.~~Jersey and to make third party sales.

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At PSE&G, our regulated utility, we continued to invest capital in ~~transmission and distribution~~T&D infrastructure projects aimed at maintaining the reliability of our service to our customers. PSE&G’s results for ~~2013~~the first quarter of 2014 reflect the favorable impacts from these investments. WeIn December 2013, we filed ~~our~~a Modified 2014 Annual Formula Rate Update with the ~~FERC in October of this year,~~Federal Energy Regulatory Commission (FERC) which ~~would provide~~provides for approximately ~~$176~~$171 million in increased annual transmission revenues effective January 1, 2014. Over the past few years, these types of investments have altered the business mix of PSEG’s overall results of operations to reflect a higher percentage contribution by PSE&G.

Regulatory, Legislative and Other Developments

In developing and implementing our strategy of operational excellence, financial strength and disciplined investment, we monitor significant regulatory and legislative developments. Competitive wholesale power market design is of particular importance to our results and we continue to advocate for policies and rules that promote competitive electricity markets. This includes opposing efforts by states to subsidize generation ~~and~~while supporting rule changes which we believe are necessary to avoid artificial price suppression and other distortions in the energy and capacity markets. ~~For a more detailed discussion of the status of these efforts, refer to Part II. Item 5. Other Information—Federal Regulation—Capacity Market Issues—LCAPP.~~

We continue to advocate for the development and implementation of fair and reasonable rules by the U.S. Environmental Protection Agency (EPA). and state environmental regulators. In particular, the EPA's 316(b) rule on cooling water intake could adversely impact future nuclear and fossil operations and costs. Clean Air Act (CAA) regulations governing hazardous air pollutants under the EPA's Maximum Achievable Control Technology (MACT) rules are also of significance; however, we believe our generation business remains well-positioned for such air pollution control regulations if and when they are implemented. ~~These matters are discussed in Part II. Item 5. Other Information—Environmental Matters—Climate Change—CO~~₂~~Regulation under the CAA.~~

~~As discussed in further detail under Part II. Item 5. Other Information—Federal Regulation—Transmission Regulation— Transmission Policy Developments, the~~The FERC's rules under Order 1000 altered the right of first refusal previously held by incumbent utilities to build all transmission within their respective service territories. We are challenging the FERC's determination in court as we do not believe that the FERC sufficiently justified its decision to alter this right embedded in the FERC-approved contracts and tariffs. At the same time, the FERC's action presents opportunities for us to construct transmission outside of our service territory.

In the fourth quarter of 2012, we were severely impacted by Superstorm Sandy, which resulted in the highest level of customer outages in our history. ~~We sustained significant damage~~For more detailed information, refer to ~~some of our generation, transmission~~Item 1—Note 8. Commitments and ~~distribution facilities. The~~Contingent Liabilities—Superstorm Sandy. In February 2013, we filed a petition with the New Jersey Board of Public Utilities (BPU) issued an order allowing us to defer actually incurred prudent, incremental storm restoration costs not otherwise recoverable through base rates or insurance. In February 2013, the BPU initiated a generic proceeding to evaluate the prudency of extraordinary storm-related costs incurred by all of the regulated utilities as a result of the natural disasters experienced in New Jersey in 2011 and 2012. In June 2013, we made a compliance filing with the BPU providing the details of our storm restoration costs for Superstorm Sandy as well as other major storms and seeking to demonstrate that we responded to these extreme weather events in a timely, diligent and thorough manner and that the costs incurred were prudent. We requested that the BPU issue an Order approving the compliance filing and specifically finding that the storm costs incurred were reasonable and prudent, and should be recovered from ratepayers.

Power also incurred significant storm-related expenses, primarily for repairs at certain of its coal and gas-fired generating stations in the first nine months of 2013 (See Note 9. Commitments and Contingent Liabilities). We are seeking recovery from our insurers for the property damage, above our self-insured retentions; however, no assurances can be given relative to the timing or amount of any such recovery. In June 2013, we filed suit against the insurance carriers seeking legal interpretation of certain terms in the insurance policies regarding losses resulting from damage caused by Superstorm Sandy's storm surge. For a more detailed discussion concerning this proceeding, refer to Part II. Item 1. Legal Proceedings—Superstorm Sandy.

~~On February 20, 2013, we filed a petition with the BPU~~ describing our Energy Strong program, consisting of $3.9 billion of proposed improvements we recommend making to our gas and electric distribution systems over a ten-year period to ~~harden and~~ improve resiliency. In the petition, we sought approval for $2.6 billion of the $3.9 billion of investments over an initial ~~five year~~five-year period, plus associated expenses, and to receive contemporaneous recovery of and on such investments. On May 1, 2014, we reached a $1.22 billion settlement on our Energy Strong proposal. The settlement provides for cost recovery at a 9.75% rate of return on equity on the first $1.0 billion of the investment, plus associated allowance for funds used during construction (AFUDC), through an accelerated recovery mechanism. We ~~cannot predict~~will seek recovery of the ~~outcome~~remaining $220 million of ~~this pending proceeding, including whether~~investment in PSE&G's next base rate case, to be filed no later than November 1, 2017. The stipulation, signed by the ~~program~~staff of the BPU, the New Jersey Division of Rate Counsel and AARP, is now being reviewed by the other parties and participants in the case and will be ~~approved or~~submitted to the ~~terms under which it would be approved.~~BPU for review and approval. We anticipate seeking BPU approval to complete our investment under the program at a later date. In addition, we anticipate investing an additional $1.5 billion in our transmission system for the same reason. As proposed, we believe that the rate impacts of the Energy Strong program will be significantly muted as a result of scheduled reductions to customer bills that will be taking place over the next few years and assuming continued low gas prices. ~~See Part II~~For more detailed information, refer to Item 5. Other Information—~~State Regulation—~~Energy Strong ~~Program for additional details.~~Program.

~~We continue to take all necessary steps in connection with the expected~~On January 1, 2014, ~~commencement of our management~~we commenced operation of the ~~Long Island Power Authority (LIPA) transmission and distribution (T&D) system. Legislation enacted in New York in July 2013 authorized an expanded role for us in the management of LIPA's~~LIPA T&D ~~system. A revised~~system under a twelve-year contract with opportunity to extend for an additional eight years. Also, beginning in 2015, Power will provide fuel procurement and power management services to LIPA ~~was approved by the LIPA Board in October 2013, but implementation of the new contract remains subject to a number of factors,~~

including LIPA’s receipt of a Private Letter Ruling from the IRS on the continued tax-exempt status of certain LIPA debt securities and LIPA’s approval of the proposed 2014 and 2015 operating and capital pass-through budgets. See Part II. Item 5. Other Information—Business Operations and Strategy—Energy Holdings—Products and Services for additional details.under separate agreements.

Operational Excellence

We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of market opportunities presented ~~in the first nine months of~~during the year as we remain diligent in managing costs. In the first ~~nine~~three months of ~~2013,~~2014, our

~~outstanding~~total nuclear fleet achieved an average capacity factor of 100%,

solid performance, a diverse fuel mix and dispatch flexibility allowed us to increase generation as compared to the comparable 2013 period by 3% to meet ~~loads,~~demand, while balancing fuel availability and price volatility, and

construction of transmission and solar projects proceeded on schedule and within budget.

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Financial Strength

Our financial strength is predicated on a solid balance sheet, positive cash flow and reasonable risk-adjusted returns on increased investment. Our financial positionremained strong during the first ~~nine~~three months ~~of 2013~~2014 as we:

had cash on hand of ~~$448~~$655 million as of ~~September 30, 2013,~~March 31, 2014,

extended the expiration ~~date~~dates of ~~approximately half of our~~PSEG's $500 million and Power's $1.6 billion five-year credit facilities from 2017 to 2019, and maintained substantial liquidity and solid investment grade credit ratings, ~~as evidenced by the recent credit rating upgrades by Standard & Poor's (S&P) of PSEG, Power and PSE&G as disclosed below in Liquidity and Capital Resources—Credit Ratings,~~

~~completed pension and other postretirement benefit funding for 2013,~~

~~issued bonds at PSE&G to refinance its maturing debt at historically low rates and fund its capital program,~~

~~repaid Power's maturing debt with cash on hand,~~ and

increased our indicated annual dividend for 2014 to ~~$1.44.~~$1.48 per share.

We expect to be able to fund our ~~proposed~~transmission projects required under PJM's reliability program, our Energy Strong program and other projects with internally generated cash and external debt financing.

Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first ~~nine months~~quarter of ~~2013 we~~2014 we:

made additional investments in transmission infrastructure projects,

continued to execute our existing BPU-approved utility programs,

~~obtained approval from the BPU~~initiated installation of equipment to increase output and improve efficiency at our ~~spending up to $247 million and $199 million under our Solar 4 All Extension and Solar Loan III investment programs, respectively,~~existing combined cycle gas turbine generation facilities, and

~~continued construction~~commenced operation of a 19newly constructed 4 MW solar project in ~~Arizona.~~

~~Delays in the construction schedules of our projects could impact their costs as well as the timing of expected revenues.~~California.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a difficult economy and cost-constrained environment, to capitalize on or otherwise address appropriately regulatory and legislative developments and to respond to the issues and challenges described below. In order to do this, we must continue to:

focus on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,

successfully re-contract our open supply positions,

execute our capital investment program, including our Energy Strong program and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,

advocate for measures to ensure the implementation by PJM and the FERC of market design rules that continue to protect competition and achieve appropriate Reliability Pricing Model (RPM) and ~~BGS~~basic generation service (BGS) pricing, ~~and~~

engage multiple stakeholders, including regulators, government officials, customers and ~~investors.~~investors, and

successfully operate the LIPA T&D system.

For the remainder of ~~2013~~2014 and beyond, the key issues and challenges we expect our business to confront ~~include~~include:

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

uncertainty in the slowly improving national and regional economic recovery, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer demand,

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

the aftermath of Hurricane Irene and Superstorm Sandy, including addressing the BPU's review of performance and communications, ~~as well as cost recovery~~ and ~~opportunities for investment in system strengthening, including our proposed Energy Strong program,~~

~~financially-stressed power plant leveraged lease investments,~~

delays and other obstacles that might arise in connection with the construction of our ~~transmission and distribution~~T&D projects, including in connection with permitting and regulatory ~~approvals, and~~approvals.

~~the successful transition to our management of the LIPA T&D system.~~

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RESULTS OF OPERATIONS

PSEG

Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, Power and PSE&G, ~~and Energy Holdings,~~ excluding charges related to intercompany transactions, which are eliminated in consolidation. ~~We also include certain financing costs, charitable contributions and general and administrative costs at the parent company.~~ For additional information on intercompany transactions, see Note ~~18.~~17. Related-Party Transactions. ~~For an explanation~~




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	2014		2013		2014 vs. 2013
	Millions				Millions			%
Operating Revenues	$	3,223	$	2,786	$	437		16
Energy Costs	1,356		1,155		201			17
Operation and Maintenance	856		710		146			21
Depreciation and Amortization	306		290		16			6
Taxes Other than Income Taxes	—		21		(21		)	(100	)
Income from Equity Method Investments	4		2		2			100
Other Income and (Deductions)	36		32		4			13
Other-Than-Temporary Impairments	2		2		—			—
Interest Expense	97		102		(5		)	(5	)
Income Tax Expense	260		220		40			18

The 2014 amounts in the preceding table for Operating Revenues and Operation and Maintenance (O&M) Costs each include $89 million for Long Island Electric Utility Servco, LLC, a wholly owned subsidiary of PSEG LI. These amounts represent the ~~variances, see~~O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Note 3. Variable Interest Entities for further explanation. The following discussions for Power and PSE&G ~~and Energy Holdings that follow the table below:~~

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2013 2012 2013 vs. 2012 2013 2012 2013 vs. 2012
Millions Millions % Millions Millions %
Operating Revenues $ 2,554
$ 2,402
$ 152
6
$ 7,650
$ 7,375
$ 275
4

Energy Costs 801
879
(78 ) (9 ) 2,711
2,819
(108 ) (4 )
Operation and Maintenance 713
619
94
15
2,069
1,876
193
10

Depreciation and Amortization 313
286
27
9
886
797
89
11

Taxes Other than Income Taxes 15
24
(9 ) (38 ) 50
73
(23 ) (32 )
Income from Equity Method Investments 4
7
(3 ) (43 ) 9
9
—
N/A

Other Income and (Deductions) 47
95
(48 ) (51 ) 118
155
(37 ) (24 )
Other-Than-Temporary Impairments 3
2
1
50
7
14
(7 ) (50 )
Interest Expense 100
106
(6 ) (6 ) 303
310
(7 ) (2 )
Income Tax Expense 270
241
29
12
708
599
109
18

provide a detailed explanation of their respective variances.

Power

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2013 2012 2013 vs. 2012 2013 2012 2013 vs. 2012
Millions
Net Income $ 221
$ 181
$ 40
$ 562
$ 538
$ 24




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	2014		2013		2014 vs. 2013
	Millions				Millions		%
Operating Revenues	$	1,700	$	1,451	$	249	17
Energy Costs	1,044		860		184		21
Operation and Maintenance	302		283		19		7
Depreciation and Amortization	72		66		6		9
Income from Equity Method Investments	4		3		1		33
Other Income (Deductions)	23		19		4		21
Other-Than-Temporary Impairments	2		2		—		—
Interest Expense	32		30		2		7
Income Tax Expense	111		91		20		22

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~~For the~~ Three Months Ended~~three months~~March 31, 2014 ~~ended~~ ~~September 30,~~as Compared to 2013

~~, the primary reasons for the~~ ~~$40 million~~Operating Revenues ~~increase~~increased$249 million due to changes in ~~Net Income were:~~generation, gas supply and other operating revenues.

~~significant~~Generation Revenuesincreased$151 million due primarily to

higher net revenues of $111 million due primarily to higher energy volumes sold in the PJM and NE regions at higher average realized prices, partially offset by lower generation sold in the New York region and higher MTM losses in ~~2012~~2014 resulting from an increase in prices on forward positions, and

~~higher capacity revenues in 2013.~~

~~These increases were partially offset by~~

~~higher Operation and Maintenance Costs,~~a net increase of $65 million due primarily ~~to planned maintenance costs at our BEC plant and costs related to damage caused by Superstorm Sandy at our fossil plants, and~~

~~$59 million of net realized gains in September 2012 resulting from restructuring our NDT Fund.~~

~~For the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013, the primary reasons for the~~ ~~$24 millionincrease~~ ~~in Net Income were:~~

~~higher capacity pricing in the PJM region resulting from higher auction prices as well as higher generation sold primarily in the PJM region, and~~

~~higher average gas prices on sales to third party customers.~~

~~These increases were largely offset by~~

~~lower volumes of electricity sold under our BGS contracts at lower average prices,~~

~~lower volumes of wholesale load contracts in the PJM and NE regions,~~

~~higher generation costs due to higher fuel costs,~~

~~higher Operation and Maintenance Costs in 2013, including costs related to damage caused by Superstorm Sandy at our fossil plants, and~~

~~$59 million of net realized gains in September 2012 resulting from restructuring our NDT Fund.~~

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

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2013 2012 2013 vs. 2012 2013 2012 2013 vs. 2012
Millions Millions % Millions Millions %
Operating Revenues $ 1,169
$ 1,038
$ 131
13
$ 3,806
$ 3,584
$ 222
6

Energy Costs 430
456
(26 ) (6 ) 1,786
1,725
61
4

Operation and Maintenance 304
255
49
19
866
780
86
11

Depreciation and Amortization 66
60
6
10
195
175
20
11

Other Income (Deductions) 34
84
(50 ) (60 ) 78
119
(41 ) (34 )
Other-Than-Temporary Impairments 3
2
1
50
7
14
(7 ) (50 )
Interest Expense 26
35
(9 ) (26 ) 85
97
(12 ) (12 )
Income Tax Expense 153
133
20
15
383
374
9
2

~~Three Months EndedSeptember 30, 2013~~ ~~as Compared to~~ ~~2012~~

~~Operating Revenuesincreased$131 million~~ ~~due to changes in generation and gas supply revenues.~~

~~Generation Revenuesincreased$133 million~~ ~~due primarily to~~

an increase of $147 million largely due to a $137 million increase primarily attributable to significant MTM losses in 2012 in the PJM region resulting from increases in prices on forward positions, and

~~an increase of $78 million due~~ to higher capacity revenues resulting from higher average auction prices ~~and an increase~~partially offset by a decrease in operating reserve revenues in ~~the~~ PJM, ~~region,~~

partially offset by a decrease of ~~$74~~$15 million due primarily to lower volumes of electricity sold under our BGS contracts as a result of serving fewer tranches than in 2013 and lower average pricing, and

a net decrease of ~~$18 million due primarily to lower volumes in the NE region as well as lower average prices in the PJM and NE regions on wholesale load contracts.~~

~~Gas Supply Revenuesdecreased$2 million~~ ~~due primarily to~~

~~a net decrease of $5 million in sales under the BGSS contract, primarily due to lower average gas prices partly offset by higher sales volumes,~~

~~partially offset by a net increase of $3 million partially due to higher sales volumes to third party customers.~~

~~Operating Expenses~~

~~Energy Costs~~ represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs ~~decreased$26 million~~ ~~due to~~

~~Generation costsdecreased$20 million~~ due primarily to $28 million of lower fuel costs, reflecting utilization of lower volumes of coal and natural gas at lower average prices, partially offset by higher nuclear fuel prices. This decrease was partially offset by a net increase of $8 million due to energy purchases at higher average prices partly offset by the recovery of excess solar renewable energy credit (SREC) cost in PJM.

~~Gas costsdecreased$6 million~~ ~~due primarily to lower average prices under the BGSS contract and on sales to third party customers offset in part by higher sales volumes in 2013.~~

~~Operation and Maintenanceincreased$49 million~~ ~~due primarily to planned maintenance costs at our BEC plant and costs incurred from Superstorm Sandy in 2013 at our New Jersey fossil plants.~~

~~Depreciation and Amortizationincreased$6 million~~ ~~due primarily to a higher depreciable fossil asset base and completion of a steam path retrofit upgrade at our co-owned nuclear Peach Bottom Unit 2 in October 2012.~~

~~Other Income and (Deductions)~~ ~~decreased$50 million~~ ~~due primarily to net realized gains of $59 million resulting from restructuring our NDT Fund in September 2012, partially offset by lower NDT Fund realized losses in 2013.~~

~~Other-Than-Temporary Impairmentsincreased$1 million~~ ~~due to higher impairments on the NDT Fund in 2013.~~

~~Interest Expensedecreased$9 million~~ due primarily to a decrease from lower outstanding debt in 2013 resulting from certain debt redeemed prior to maturity in December 2012, as well as the maturity of Senior Notes in April 2013, and lower interest expense due to interest costs we capitalized for projects under construction.

~~Income Tax Expenseincreased$20 million~~ ~~in 2013 due primarily to higher pre-tax income.~~

~~Nine Months EndedSeptember 30, 2013~~ ~~as Compared to~~ ~~2012~~

~~Operating Revenuesincreased$222 million~~ ~~due to changes in generation and gas supply revenues.~~

~~Generation Revenuesincreased$130 million~~ ~~due primarily to~~

~~an increase of $275 million due to higher capacity revenues resulting from higher average auction prices and an increase in operating reserve revenues in PJM, and~~

~~higher revenues of $91 million due primarily to higher generation sold in the PJM and NE regions partly offset by lower average prices in PJM,~~

~~partially offset by a decrease of $144 million due primarily to lower volumes of electricity sold under our BGS contracts and lower average pricing, and~~

~~a net decrease of $92~~$11 million due to lower volumes on wholesale load contracts in the PJM and NE regions.

Gas Supply Revenues increased $9294 million due primarily to

a net increase of ~~$60~~$79 million in sales under the BGSS contract, substantially comprised of higher sales volumes due to colder average temperatures during the ~~2013~~2014 winter heating season, ~~partially offset by lower average gas prices,~~ and

~~a net~~an increase of ~~$32~~$15 million due ~~primarily~~ to higher ~~average gas prices, partially offset by lower~~ sales volumes to third party ~~customers.~~customers with higher average sales prices.

Other Operating Revenues increased $4 million due to transition fees related to fuel management and power supply management contracts with LIPA.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $61184 million due to

Generation costs increased $18141 million due primarily to ~~$83~~$247 million of higher fuel costs, reflecting higher average realized natural gas prices, ~~higher~~high nuclear fuel costs, ~~and~~ the utilization of higher volumes of natural gas, coal and oil ~~partially~~and the unfavorable MTM impact from lower average unrealized natural gas prices on forward positions and $14 million in higher energy purchases, primarily in the PJM and NE regions as result of higher prices. These higher fuel costs and energy purchases were largely offset by ~~lower average coal prices. The increase was partially offset by $21~~$120 million of lower ~~energy purchases, recovery of excess SREC costs and a decrease of $44 million in~~ congestion costs in ~~PJM.~~the PJM region.

Gas costs increased $43 million, principally related to obligations under the BGSS contract, reflecting higher sales volumes in ~~2013~~2014 due to colder average temperatures during the ~~2013~~2014 winter heating season, partially offset by lower average gas inventory costs.

Operation and Maintenance increased $8619 million due primarily to ~~$63 million in costs incurred from Superstorm Sandy in 2013 at our fossil plants, and $48 million of~~

higher planned outage ~~and maintenance~~fossil costs ~~in 2013, mainly~~of $54 million, primarily at ~~BEC,~~ our ~~Bergen gas-fired~~Linden plant in New Jersey, and ~~Conemaugh coal-fired plant in Pennsylvania. This was~~

higher outside service costs of $5 million,

partially offset by lower storm costs of $19 million,

a decrease in pension and OPEB costs of $14 million, and

lower nuclear outage costs of $10 million largely due to the ~~recognition~~timing of ~~a $25 million insurance recovery related to Superstorm Sandy.~~planned outage costs at our Salem facility.

Depreciation and Amortization increased $206 million due primarily to a higher depreciable fossil and nuclear asset base at Fossil, including placing into service the new gas-fired peaking units at Kearny, New Jersey and New Haven, Connecticut in June 2012 and completion of the steam path retrofit upgrade at our co-owned Peach Bottom Unit 2 in October 2012.base.

Income from Equity Method Investments experienced no material change.

Other Income and (Deductions) ~~decreased~~experienced no material change.

Interest Expenseincreased $412 million due primarily to the ~~factors disclosed~~issuance of $500 million of Senior Notes in ~~the above analysis for the three months ended September 30,~~November 2013, ~~versus 2012.~~

~~Other-Than-Temporary Impairmentsdecreased$7 million~~ ~~due to lower impairments on the NDT Fund in 2013.~~

~~Interest Expensedecreased$12 million~~ ~~due primarily to a decrease from lower outstanding debt in 2013 resulting from certain debt redeemed prior to maturity in December 2012, as well as~~partially offset by the maturity of $300 million of Senior Notes in April ~~2013, partially offset by higher interest costs in 2013 since interest capitalization ceased for our Kearny and New Haven gas-fired peaking projects on their June 2012 in-service date.~~2013.

Income Tax Expense increased $920 million in ~~2013~~2014 due primarily to higher pre-tax income.

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PSE&G

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2013 2012 2013 vs. 2012 2013 2012 2013 vs. 2012
Millions
Net Income $ 168
$ 155
$ 13
$ 468
$ 453
$ 15

~~For the~~ ~~three months~~ ~~ended~~ ~~September 30, 2013, the primary reason for the~~ ~~$13 millionincrease~~ ~~in Net Income was higher transmission revenues due to increased investments in transmission projects.~~

~~For the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013, the primary reasons for the~~ ~~$15 millionincrease~~ ~~in Net Income were~~

~~higher transmission revenues due to increased investments in transmission projects,~~

~~partially offset by higher Income Tax Expense due to the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in 2012.~~




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	2014		2013		2014 vs. 2013
	Millions				Millions			%
Operating Revenues	$	2,145	$	1,995	$	150		8
Energy Costs	1,045		967		78			8
Operation and Maintenance	462		427		35			8
Depreciation and Amortization	227		215		12			6
Taxes Other Than Income Taxes	—		21		(21		)	(100	)
Other Income (Deductions)	14		12		2			17
Interest Expense	68		73		(5		)	(7	)
Income Tax Expense	143		125		18			14

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

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2013 2012 2013 vs. 2012 2013 2012 2013 vs. 2012
Millions Millions % Millions Millions %
Operating Revenues $ 1,666
$ 1,683
$ (17 ) (1 ) $ 5,084
$ 5,029
$ 55
1

Energy Costs 661
756
(95 ) (13 ) 2,208
2,380
(172 ) (7 )
Operation and Maintenance 408
366
42
11
1,204
1,092
112
10

Depreciation and Amortization 236
216
20
9
658
594
64
11

Taxes Other Than Income Taxes 15
24
(9 ) (38 ) 50
73
(23 ) (32 )
Other Income (Deductions) 12
10
2
20
38
31
7
23

Interest Expense 75
73
2
3
223
220
3
1

Income Tax Expense 115
103
12
12
311
248
63
25

Three Months Ended ~~September 30, 2013~~March 31, 2014 as Compared to ~~2012~~2013

Operating Revenues ~~decreased~~increased $17150 million due to changes in delivery, clause, commodity and other operating revenues.

~~Commodity Revenue~~Delivery Revenues ~~decreased~~increased $9554 million due primarily to an increase in transmission revenues.

Transmission revenues were $39 millionhigher due to net rate increases resulting primarily from increased capital investments.

Electric distribution revenues increased$9 million due primarily to higher revenue from Green Program Recovery Charges (GPRC) of $16 million and higher sales volumes of $4 million, partially offset by lower Transitional Energy Facilities Assessment (TEFA) revenue of $11 million due to elimination of the TEFA rate effective January 1, 2014.

Gas distribution revenues increased$6 million due primarily to $51 million from higher sales volumes, partially offset by lower Weather Normalization Clause (WNC) revenue of $36 million due to colder than normal weather and lower TEFA revenue of $10 million due to elimination of TEFA rate effective January 1, 2014.

Commodity Revenueincreased$78 million due to higher Electric and Gas revenues. This is entirely offset ~~as savings in~~with increased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

Electric revenues ~~decreased~~increased $9249 million due primarily to $4052 million in ~~lower~~higher BGS revenues ~~and~~, partially offset by $523 million in lower revenues from ~~a reduced volume~~collection of ~~sales of Non-Utility Generation (NUG) energy and lower~~ Non-Utility Generation Charges (NGC) and sales of Non-Utility generation (NUG) energy due to lower ~~tariff rates.~~volume, partially offset by higher prices. BGS sales ~~decreased~~increased 6%10% due primarily to weather, partially offset by customer migration to third party suppliers (TPS) ~~and weather.~~.

Gas revenues ~~decreased~~increased $329 million due primarily tohigher BGSS volumes of $90 million, partially offset by lower BGSS prices of $561 million~~, partially offset by~~ ~~higher~~ ~~BGSS volumes of~~ ~~$2 million~~ ~~primarily due to weather.~~ The average price of natural gas was 7%12% lower in ~~2013 than in 2012.~~

~~Delivery Revenuesincreased$52 million~~ ~~due primarily to an increase in transmission revenues.~~

~~Transmission revenues were~~ ~~$46 millionhigher~~ ~~due to net rate increases resulting primarily from increased capital investments.~~

~~Electric distribution revenues~~ ~~increased$7 million~~ ~~due primarily to an increase in Capital Infrastructure Program (CIP) related revenues of~~ ~~$14 million~~ ~~and~~ ~~higher~~ ~~Green Program Recovery Charges (GPRC) of~~ ~~$17 million, partially offset by~~ ~~lower sales volumes~~ of ~~$16 million, and~~ ~~lower~~ ~~Transitional Energy Facilities Assessment (TEFA) revenue of~~ ~~$8 million~~ ~~due to a~~ ~~lower TEFA rate~~.

~~Gas distribution revenues~~ ~~decreased$1 million~~ ~~due primarily to~~ ~~lower~~ ~~Weather Normalization Clause (WNC) revenue of~~ ~~$6 million~~ ~~due to more normal weather compared to the prior period, partially offset by~~ ~~$3 million~~ ~~from~~ ~~higher sales volumes~~ ~~and~~ ~~$2 million~~ ~~from CIP related revenues.~~2014.

Clause Revenues increased $2216 million due primarily to higher ~~Securitization Transition Charge (STC) revenues of~~ ~~$10 million~~, ~~higher~~ ~~Solar Pilot Recovery Charge (SPRC) revenue of~~ ~~$5 million~~ ~~and~~ ~~higher~~ ~~Margin Adjustment Clause (MAC) revenue of~~ ~~$7 million~~. The changes in STC, SPRC and MAC amounts were entirely offset by the amortization of Regulatory Assets and related costs in Operation and Maintenance (O&M), Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SPRC or MAC collections.

~~Other Operating Revenuesincreased$4 million~~ ~~due primarily to~~ ~~increased~~ ~~revenues from our miscellaneous electric operating revenues.~~

~~Energy Costsdecreased$95 million. This is entirely offset by Commodity Revenue.~~

~~Electric costs~~ ~~decreased$92 million~~ or ~~14%~~ ~~due to~~ ~~$73 million~~ in ~~lower~~ ~~BGS and NUG volumes,~~ ~~$10 million~~ of ~~lower~~ ~~BGS and NUG prices and~~ ~~$9 million~~ ~~for~~ ~~decreased~~ ~~deferred cost recovery. BGS and NUG volumes decreased~~ ~~11%~~ ~~due primarily to customer migration to TPS and weather.~~

~~Gas costs~~ ~~decreased$3 million~~ or 4% ~~due to~~ ~~$5 million~~ or 7% in ~~lower~~ ~~prices, partially offset by~~ ~~$2 million~~ or 3% in ~~higher~~ ~~sales volumes due primarily to weather.~~

~~Operation and Maintenanceincreased$42 million, of which the most significant components were~~

a ~~$37 millionincrease~~ ~~in costs related primarily to~~ Societal Benefit Charges (SBC)~~, CIP and GPRC. Due to the nature of~~. The change in the SBC ~~CIP and GPRC clause mechanisms, these are entirely offset in revenues, and~~

a ~~$3 millionincrease~~ ~~in appliance service costs.~~

~~Depreciation and Amortizationincreased$20 million~~ ~~due primarily to~~

an ~~$11 millionincrease~~ ~~in amortization of Regulatory Assets, and~~

an ~~$8 millionincrease~~ ~~in depreciation of additional plant in service.~~

~~Taxes Other Than Income Taxesdecreased$9 million~~ ~~due to a~~ ~~lower TEFA rate~~ ~~for electric and gas, partially offset by~~ ~~higher sales volumes~~ ~~for gas.~~

~~Other Income and (Deductions)~~ ~~net~~ ~~increase~~ of ~~$2 million~~amount was ~~due primarily to~~ ~~an increase~~ ~~in Solar Loan interest income.~~

~~Interest Expenseincreased~~ ~~due primarily to higher average long-term debt partially offset by lower average securitization debt.~~

~~Income Tax Expenseincreased$12 million~~ ~~due primarily to higher pre-tax income.~~

~~Nine Months EndedSeptember 30, 2013~~ ~~as Compared to~~ ~~2012~~

~~Operating Revenuesincreased$55 million~~ ~~due to changes in delivery, clause, commodity and other operating revenues.~~

~~Delivery Revenuesincreased$143 million~~ ~~due primarily to~~ ~~an increase~~ ~~in transmission revenues.~~

~~Transmission revenues were~~ ~~$131 millionhigher~~ ~~due to net rate~~ ~~increases~~ ~~resulting primarily from increased capital investments.~~

~~Gas distribution revenues~~ ~~increased$10 million~~ ~~due primarily to~~ ~~$58 million~~ ~~from~~ ~~higher sales volumes~~ ~~and an increase of~~ ~~$16 million~~ ~~in CIP related revenues, partially offset by~~ ~~lower~~ ~~WNC revenue of~~ ~~$61 million~~ ~~due to more normal weather compared to the prior period.~~

~~Electric distribution revenues~~ ~~increased$2 million~~ ~~due primarily to an increase in CIP related revenues of~~ ~~$14 million~~ ~~and~~ ~~higher~~ ~~GPRC of~~ ~~$21 million, partially offset by~~ ~~lower~~ ~~TEFA revenue of~~ ~~$18 million~~ ~~due to a~~ ~~lower TEFA rate~~ ~~and~~ ~~lower sales volumes~~ of ~~$15 million~~.

~~Clause Revenuesincreased$74 million~~ ~~due primarily to~~ ~~higher~~ ~~STC revenues of~~ ~~$35 million~~, ~~higher~~ ~~SBC of~~ ~~$29 million~~, ~~higher~~ ~~SPRC revenue of~~ ~~$8 million~~ ~~and~~ ~~higher~~ ~~MAC revenue of~~ ~~$2 million. The changes in STC, SBC, SPRC and MAC amounts were~~ entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on ~~STC,~~ SBC ~~SPRC or MAC~~ collections.

Other Operating Revenues increased $102 million due ~~primarily~~ to ~~increased~~ ~~revenues from our appliance repair business and~~higher miscellaneous electric operating revenues.

~~Commodity Revenuedecreased$172 million~~ ~~due to lower Electric revenues, partially offset by higher Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.~~Operating Expenses

~~Electric revenues~~ ~~decreased$267 million~~ ~~due primarily to~~ ~~$164 million~~ in ~~lower BGS revenues~~ ~~and~~ ~~$103 million~~ in ~~lower revenues~~ ~~from a lower volume of sales of NUG energy and lower NGC due to lower tariff rates. BGS sales~~ ~~decreased~~6% ~~due primarily to customer migration to TPS.~~

~~Gas revenues~~ ~~increased$95 million~~ ~~due primarily to~~ ~~higher~~ ~~BGSS volumes.~~

Energy Costs ~~decreased~~increased $~~172~~78 million. This is entirely offset by Commodity Revenue.

Electric costs ~~decreased~~increased $~~267~~49 million or ~~15%~~11% due to $~~177~~52 million of increased deferred cost recovery and $8 million of higher BGS and NUG prices, partially offset by $11 million in lower BGS and NUG ~~volumes,~~ ~~$54 million~~ of ~~lower~~ ~~BGS and NUG prices, and~~ ~~$36 million~~ ~~for~~ ~~decreased~~ ~~deferred cost recovery.~~volumes. BGS and NUG volumes decreased ~~10%~~2% due primarily to customer migration to TPS.

Gas costs increased $9529 million or ~~15%~~5% due ~~primarily~~ to $90 million or 17% in higher sales ~~volumes.~~volumes, partially offset by $61 million or 12% in lower prices.

Table of Contents

Operation and Maintenance increased $~~112~~35 million, of which the most significant components were

ana $8734 million increase in costs ~~recognized~~ related primarily to ~~SBC, CIP~~GPRC and ~~GPRC.~~SBC. Due to the nature of the ~~SBC, CIP~~GPRC and ~~GPRC~~SBC clause mechanisms, these are entirely offset in revenues, and

a $13 millionincrease in winter storm-related costs and extreme weather conditions,

partially offset by an $18 million decrease in pension and OPEB expenses.

Depreciation and Amortizationincreased$12 million due primarily to

an $8 million increase in ~~costs relating to repairs from Superstorm Sandy and a colder winter,~~depreciation of additional plant in service, and

a $~~9 millionincrease~~ ~~in appliance service costs.~~

~~Depreciation and Amortizationincreased$64 million~~ ~~due primarily to~~

a ~~$41~~3 million increase in amortization of Regulatory ~~Assets, and~~

a ~~$21 millionincrease~~ ~~in depreciation of additional plant in service.~~Assets.

Taxes Other Than Income Taxes decreased $2321 million due to a ~~lower~~elimination of the TEFA rate ~~for electric and gas, partially offset by~~ ~~higher sales volumes~~ ~~for gas.~~ effective January 1, 2014.

Other Income and (Deductions) ~~net~~ ~~increase~~ of ~~$7 million~~ ~~was due primarily to~~ ~~an increase~~ ~~in Solar Loan interest income.~~experienced no material change.

Interest Expense ~~increased~~decreased $5 million due primarily to ~~higher average long-term debt partially offset by~~a lower average securitization ~~debt.~~debt balance.

Income Tax Expense increased $6318 million due primarily to ~~the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in 2012 and~~ higher pre-tax income.

~~Energy Holdings~~

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2013 2012 2013 vs. 2012 2013 2012 2013 vs. 2012
Millions
Net Income $ (3 ) $ 7
$ (10 ) $ 1
$ 49
$ (48 )

~~For the~~ ~~three months~~ ~~ended~~ ~~September 30, 2013, the primary reasons for the~~ ~~$10 million~~ ~~decrease in Net Income were the impairment of real estate assets and legal expenses related to the LIPA contract expansion in 2013 and a gain on an asset sale in 2012.~~

~~For the~~ ~~nine months~~ ~~ended~~ ~~September 30, 2013, the primary reason for the~~ ~~$48 million~~ ~~decrease in Net Income was the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in the prior year.~~

LIQUIDITY AND CAPITAL RESOURCES

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

Operating Cash Flows

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

For the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014, our operating cash flow increased $~~124~~239 million as compared to the same period in ~~2012~~.2013. The net change was due primarily to net changes from Power and PSE&G, as discussed below.

Power

Power’s operating cash flow increased $~~112~~99 million from $~~1,172~~575 million to $~~1,284~~674 million for the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014, as compared to the same period in ~~2012~~,2013, primarily resulting from higher earnings, a net tax refund and a $43 million decrease in employee benefit plan funding, partially offset by an increase of $~~124~~144 million related to margin deposits.

PSE&G

PSE&G’s operating cash flow increased $8250 million from $~~1,041~~329 million to $~~1,049~~579 million for the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014, as compared to the same period in ~~2012~~2013, due primarily to higher earnings, ~~and~~ an increase ~~from a net change~~ in regulatory ~~deferrals~~liabilities from over-collections primarily related to BGSS gas costs and ~~the collection of~~ Gas Weather Normalization Charges, ~~offset by higher payments for storm related costs. The increases were partially offset by higher~~a $91 million decrease in employee benefit plan funding and a net tax ~~payments.~~refund.

Short-Term Liquidity

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

The commitments under our $4.3 billion credit facilities are provided by a diverse bank group. In March 2013, Power, PSEG and PSE&G amended their respective 5-year credit agreements scheduled to end in 2016, extending the expiration dates from April 2016 to March 2018. Of the total commitments of $2.1 billion under these agreements, $2.0 billion has been extended until 2018. The commitments for the $100 million balance will terminate in 2016. As of ~~September 30, 2013~~March 31, 2014, our total available credit capacity was ~~$4.3 billion~~.$4.1 billion.

As of ~~September 30, 2013~~March 31, 2014, no single institution represented more than 8% of the total commitments in our credit facilities.

As of ~~September 30, 2013~~March 31, 2014, our total credit capacity was in excess of our anticipated maximum liquidity requirements.

Each of our credit facilities is restricted as to availability and use to the specific companies as listed ~~below;~~in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. In April 2014, PSEG and Power amended their 2012 credit agreements ending in 2017, extending the expiration date from March 2017 to April 2019. PSEG's $500 million and Power's $1.6 billion facility amendments, resulting in total commitments of $2.1 billion, will mature in 2019.

Table of Contents

Our total credit facilities and available liquidity as of ~~September 30, 2013~~March 31, 2014 were as follows:

As of September 30, 2013
Company/Facility
Total
Facility
Usage
Available
Liquidity

Expiration
Date
Primary Purpose
Millions
PSEG
  5-year Credit Facility $ 500
$ 5
(D) $ 495
Mar 2017 Commercial Paper (CP) Support/Funding/Letters of Credit
  5-year Credit Facility (A) 500
—
   500
Mar 2018 CP Support/Funding/Letters of Credit
Total PSEG $ 1,000
$ 5
   $ 995

Power
  5-year Credit Facility $ 1,600
$ 58
(D) $ 1,542
Mar 2017 Funding/Letters of Credit
  5-year Credit Facility (B) 1,000
—
   1,000
Mar 2018 Funding/Letters of Credit
  Bilateral Credit Facility 100
100
(D) —
Sept 2015 Letters of Credit
Total Power $ 2,700
$ 158
   $ 2,542

PSE&G
5-year Credit Facility (C) $ 600
$ 13
(D) $ 587
Mar 2018 CP Support/Funding/Letters of Credit
Total PSE&G $ 600
$ 13
   $ 587

Total $ 4,300
$ 176
   $ 4,124




	As of March 31, 2014
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility (A)	$	500	$	8	$	492	Mar 2017	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (B)	500		—		500		Mar 2018	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	8	$	992
Power
5-year Credit Facility (A)	$	1,600	$	67	$	1,533	Mar 2017	Funding/Letters of Credit
5-year Credit Facility (C)	1,000		—		1,000		Mar 2018	Funding/Letters of Credit
Bilateral Credit Facility	100		100		—		Sept 2015	Letters of Credit
Total Power	$	2,700	$	167	$	2,533
PSE&G
5-year Credit Facility (D)	$	600	$	13	$	587	Mar 2018	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	13	$	587
Total	$	4,300	$	188	$	4,112


(A)	In April 2014, the expiration dates of these facilities were extended to April 2019.


(B)	In April 2016, this facility will be reduced by $23 million.


~~(B)~~(C)	In April 2016, this facility will be reduced by $48 million.


~~(C)~~(D)	In April 2016, this facility will be reduced by $29 million.


~~(D)~~	~~Includes amounts related to letters of credit outstanding.~~

Long-Term Debt Financing

PSE&G has ~~$275~~$250 million of ~~6.33%~~ ~~Medium-Term~~5.00%, Series D, Medium Term Notes and $250 million of 0.85%, Series G, Medium Term Notes both maturing in August 2014.

Power has a $44 million pollution control facilities loan servicing and securing a Pennsylvania Economic Development Financing Authority (PEDFA) bond due November ~~2013~~. 2042. The bond is backed by a three-year letter of credit that expires in November 2014. The PEDFA bond has been reclassified as debt due within the year.

For a discussion of our long-term debt transactions during ~~2013,~~2014, see Note ~~10.~~9. Changes in Capitalization.

Common Stock Dividends

On ~~July 16, 2013,~~February 18, 2014, our Board of Directors approved a $0.37 per share common stock dividend for the first quarter of 2014. On April 15, 2014, our Board of Directors declared a quarterly dividend of ~~$0.36~~$0.37 per share of common stock for the ~~third~~second quarter of ~~2013.~~2014. This reflects an indicated annual dividend rate of $1.48 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Note ~~16.~~15. Earnings Per Share (EPS) and Dividends.

Credit Ratings

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

In January 2014, Moody's upgraded PSE&G's Mortgage Bond Rating from A1 to Aa3 and its commercial paper rating from P2 to P1. PSE&G's outlook is stable. In April ~~2013,~~2014, S&P ~~upgraded~~revised the outlooks to

Table of Contents

positive from stable for the corporate credit and senior unsecured long-term ratings onof PSEG, PSE&G and Power. S&P also affirmed the senior unsecured rating of BBB+ at Power and ~~PSE&G to BBB+ from BBB and PSE&G's Mortgage Bond~~senior secured rating toof A ~~from A-. PSEG's, Power's and~~at PSE~~&G's outlooks were changed to stable from positive. In May 2013, Moody's published updated credit opinions on PSEG, Power and PSE~~&G. ~~PSEG's, Power's and PSE&G's ratings and outlooks remained unchanged. In July 2013, Fitch published updated research on PSEG, Power and PSE&G which kept their ratings and outlooks unchanged.~~




	Moody’s (A)	S&P (B)	Fitch (C)
PSEG
Outlook	Stable	Stable	Stable
Commercial Paper	P2	A2	F2
Power
Outlook	Stable	~~Stable~~Positive	Stable
Senior Notes	Baa1	BBB+	BBB+
PSE&G
Outlook	Stable	Stable	Stable
Mortgage Bonds	A1Aa3	A	A+
Commercial Paper	P2P1	A2	F2


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


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


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

CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. ~~In the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, PSE&G reported an increase in its projected base level capital expenditures of~~ ~~$215 million~~ through 2015, as compared to the amounts disclosed in our Form 10-K for the year ended December 31, 2012. This increase primarily reflects our projected additional spending during the period under our Solar Loan III and Solar 4 All Extension programs whichThere were ~~approved by the BPU in May 2013. There have been~~ no ~~additional~~ material changes to our projected capital expenditures at Power ~~PSE&G~~ and ~~Energy Holdings~~Services as compared to amounts disclosed in our 2013 Form 10-K. PSE&G has increased its total projected capital expenditures through 2016 by $295 million, including $145 million for additional transmission reliability enhancements in 2015 and $50 million and $100 million in 2015 and 2016, respectively, related to additional distribution expenditures for reliability enhancements and facility replacement.

On May 1, 2014, we reached a settlement with the BPU Staff on our Energy Strong proposal, agreeing that PSE&G would spend $1.22 billion to protect and strengthen PSE&G's electric and gas systems against severe weather conditions over primarily a three-year period with some projects extending over five years. This amount is not included in the projected capital expenditures disclosed in our 2013 Form 10-K ~~for~~or in the ~~year ended~~ ~~December 31, 2012~~.increases reported above. See ~~Note 9. Commitments and Contingent Liabilities~~Item 5. Other Information—Energy Strong Program for additional information.

Power

During the three months ended March 31, 2014, Power made capital expenditures of $100 million, excluding $26 million for nuclear fuel, primarily related to various projects at is fossil and nuclear generation stations.

PSE&G

During the three months ended March 31, 2014, PSE&G made $483 million of capital expenditures, including $481 million of investment in plant, primarily for transmission and distribution system reliability and $2 million in solar loan investments. This does not include expenditure for cost of removal, net of salvage, of $25 million, which is included in operating cash flows.

ACCOUNTING MATTERS

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

Table of Contents


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Contracts

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

Value-at-Risk (VaR) Models

VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities.

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

During January 2014, extreme weather conditions drove increases in price volatility associated with energy commodities. This led to an increase in VaR during the month of January. VaR subsequently decreased during the months of February and March.

MTM VaR
Three Months Ended September 30, 2013 Year Ended December 31, 2012
Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End $ 9
$ 18

Average for the Period $ 14
$ 16

High $ 19
$ 29

Low $ 9
$ 7

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 15
$ 28

Average for the Period $ 22
$ 25

High $ 30
$ 46

Low $ 14
$ 11




	MTM VaR
	Three Months Ended March 31, 2014		Year Ended December 31, 2013
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	17	$	12
Average for the Period	$	52	$	15
High	$	195	$	29
Low	$	14	$	8
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	26	$	18
Average for the Period	$	82	$	23
High	$	306	$	46
Low	$	22	$	13

See Note ~~11.~~10. Financial Risk Management Activities for a discussion of credit risk.

Table of Contents


ITEM 4.	CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Controls

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the ~~third~~first quarter of ~~2013~~2014 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

7868

Table of Contents

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. Certain information reported under Item 3 of Part I of the 2012 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013 are updated below. For additional information regarding material legal proceedings, including updates to information reported in Item 33. of Part I of the ~~2012~~2013 Annual Report on Form 10-K, ~~and under Item 1 of Part II of the Quarterly Report on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013,~~ see Note 9.8. Commitments and Contingent Liabilities and Item 5. Other Information.

~~Superstorm Sandy~~

~~June 30, 2013 Form 10-Q page 81.~~ PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. PSEG is seeking recovery from its insurers for the property damage, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. PSEG has recorded proceeds of $50 million from its insurance carriers as advance payments, $25 million of which was recognized in the second quarter of 2013 and $25 million was recognized in the fourth quarter of 2012. PSEG does not believe that it has a basis for estimating additional probable insurance recoveries at this time. In June 2013, PSEG, Power and PSE&G filed suit in New Jersey state court against the insurance carriers seeking legal interpretation of certain terms in the insurance policies regarding losses resulting from damage caused by Superstorm Sandy's storm surge. The dispute concerns whether certain sub-limits in the policies apply to damage to property caused by Superstorm Sandy's storm surge. In that Complaint, PSEG stated that its estimate of the total costs required to restore damaged facilities to their pre-Superstorm Sandy condition was approximately $426 million. Of these costs, $364 million and $62 million related to Power and PSE&G, respectively. In August 2013, the insurance carriers filed an answer in which they denied most of the allegations made in the Complaint. Discovery is proceeding.


ITEM 1A.	RISK FACTORS

There are no additional Risk Factors to be added to those disclosed in Part I Item 1A of our ~~2012~~2013 Annual Report on Form 10-K.


ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the ~~third~~first quarter of ~~2013~~2014:

Three Months Ended September 30, 2013
Total Number
of Shares
Purchased

Average
Price Paid
per Share

July 1 - July 31 —
$ —

August 1 - August 31 22,500
$ 33.70

September 1 -September 30 —
$ —




Three Months Ended March 31, 2014	Total Number of Shares Purchased	Average Price Paid per Share
January 1 - January 31	—	$	—
February 1 - February 28	427,711	$	36.82
March 1 - March 31	341,606	$	36.65


ITEM 5.	OTHER INFORMATION

Certain information reported in the ~~2012~~2013 Annual Report on Form 10-K ~~and Quarterly Reports on Form 10-Q for the Quarters Ended March 31, 2013 and June 30, 2013 are~~is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the ~~2012~~2013 Annual Report on Form ~~10-K and the Quarterly Reports on Form 10-Q for the Quarters Ended March 31, 2013 and June 30, 2013.~~10-K. References are to the related pages on the ~~Forms~~Form 10-K ~~and 10-Q~~ as printed and distributed.

Federal Regulation

FERC



Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza, P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com	22-2625848
001-34232	PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza—T25 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com	22-3663480
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza, P.O. Box 570 Newark, New Jersey 07101-0570 973 430-7000 http://www.pseg.com	22-1212800



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

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

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



		Page
FORWARD-LOOKING STATEMENTS		ii

PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated	1
	PSEG Power LLC	6
	Public Service Electric and Gas Company	11
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation	16
	Note 2. Recent Accounting Standards	1617
	Note 3. Variable Interest Entities (VIEs)	17
	Note 4. ~~Asset Disposition~~	18
	~~Note 5.~~ Rate Filings	18
	Note 6.5. Financing Receivables	18
	Note 7.6. Available-for-Sale Securities	2120
	Note 8.7. Pension and Other Postretirement Benefits (OPEB)	26
	Note 9.8. Commitments and Contingent Liabilities	2728
	Note ~~10.~~9. Changes in Capitalization	35
	Note ~~11.~~10. Financial Risk Management Activities	3635
	Note 11. Fair Value Measurements	41
	Note 12. ~~Fair Value Measurements~~Other Income and Deductions	4248
	Note 13. ~~Other~~ Income ~~and Deductions~~Taxes	5149
	Note 14. ~~Income Taxes~~	52
	~~Note 15.~~ Accumulated Other Comprehensive Income (Loss), Net of Tax	5350
	Note ~~16.~~15. Earnings Per Share (EPS) and Dividends	5652
	Note 16. Financial Information by Business Segments	53
	Note 17. ~~Financial Information by Business Segments~~Related-Party Transactions	5753
	Note 18. ~~Related-Party Transactions~~	58
	~~Note 19.~~ Guarantees of Debt	6055
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6357
	Overview of ~~2013~~2014 and Future Outlook	6357
	Results of Operations	6861
	Liquidity and Capital Resources	7464
	Capital Requirements	7766
	Accounting Matters	7766
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	7767
Item 4.	Controls and Procedures	7868

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	7969
Item 1A.	Risk Factors	7969
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	7969
Item 5.	Other Information	7969
Item 6.	Exhibits	8474
	Signatures	8575




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
OPERATING REVENUES	$	2,554		$	2,402		$	7,650		$	7,375
OPERATING EXPENSES
Energy Costs	801			879			2,711			2,819
Operation and Maintenance	713			619			2,069			1,876
Depreciation and Amortization	313			286			886			797
Taxes Other Than Income Taxes	15			24			50			73
Total Operating Expenses	1,842			1,808			5,716			5,565
OPERATING INCOME	712			594			1,934			1,810
Income from Equity Method Investments	4			7			9			9
Other Income	59			121			172			216
Other Deductions	(12		)	(26		)	(54		)	(61		)
Other-Than-Temporary Impairments	(3		)	(2		)	(7		)	(14		)
Interest Expense	(100		)	(106		)	(303		)	(310		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	660			588			1,751			1,650
Income Tax Expense	(270		)	(241		)	(708		)	(599		)
NET INCOME	$	390		$	347		$	1,043		$	1,051
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC	505,858			505,914			505,900			505,942
DILUTED	507,694			507,111			507,433			507,037
EARNINGS PER SHARE:
BASIC
INCOME FROM CONTINUING OPERATIONS	$	0.77		$	0.69		$	2.06		$	2.08
NET INCOME	$	0.77		$	0.69		$	2.06		$	2.08
DILUTED
INCOME FROM CONTINUING OPERATIONS	$	0.77		$	0.68		$	2.06		$	2.07
NET INCOME	$	0.77		$	0.68		$	2.06		$	2.07
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.3600		$	0.3550		$	1.0800		$	1.0650




	September 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	448		$	379
Accounts Receivable, net of allowances of $57 and $56 in 2013 and 2012, respectively	1,069			1,069
Tax Receivable	225			227
Unbilled Revenues	211			314
Fuel	599			583
Materials and Supplies, net	450			422
Prepayments	210			283
Derivative Contracts	107			138
Deferred Income Taxes	31			49
Regulatory Assets	348			349
Other	43			56
Total Current Assets	3,741			3,869
PROPERTY, PLANT AND EQUIPMENT	29,206			27,402
Less: Accumulated Depreciation and Amortization	(8,127		)	(7,666		)
Net Property, Plant and Equipment	21,079			19,736
NONCURRENT ASSETS
Regulatory Assets	3,519			3,830
Regulatory Assets of Variable Interest Entities (VIEs)	532			713
Long-Term Investments	1,320			1,324
Nuclear Decommissioning Trust (NDT) Fund	1,635			1,540
Other Special Funds	181			191
Goodwill	16			16
Other Intangibles	52			34
Derivative Contracts	184			153
Restricted Cash of VIEs	23			23
Other	328			296
Total Noncurrent Assets	7,790			8,120
TOTAL ASSETS	$	32,610		$	31,725




	As of September 30, 2013
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	615	$	234	$	(6	)	$	843
Debt Securities
Government Obligations	411		5		(6		)	410
Other Debt Securities	313		11		(4		)	320
Total Debt Securities	724		16		(10		)	730
Other Securities	62		—		—			62
Total NDT Available-for-Sale Securities	$	1,401	$	250	$	(16	)	$	1,635




	As of December 31, 2012
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	648	$	147	$	(6	)	$	789
Debt Securities
Government Obligations	274		11		—			285
Other Debt Securities	320		22		—			342
Total Debt Securities	594		33		—			627
Other Securities	124		—		—			124
Total NDT Available-for-Sale Securities	$	1,366	$	180	$	(6	)	$	1,540




	Auction Year
	2010	2011	2012	2013
36-Month Terms Ending	May 2013	May 2014	May 2015	May 2016	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per kWh	0.09577	0.09430	0.08388	0.09218




Fuel Type	Power’s Share of Commitments through 2017
	Millions
Nuclear Fuel
Uranium	$	470
Enrichment	$	386
Fabrication	$	146
Natural Gas	$	880
Coal	$	446




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2013		2012			2013			2012
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	14	$	(90	)	$	(32	)	$	145
Energy-Related Contracts	Energy Costs	10		6			63			(17		)
Total PSEG and Power		$	24	$	(84	)	$	31		$	128




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2013			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2013
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(35	)	$	1	$	(11	)	$	—	$	(1	)	$	—	$	(46	)
Power
Net Derivative Assets (Liabilities)	$	6		$	1	$	—		$	—	$	(1	)	$	—	$	6
PSE&G
Net Derivative Assets (Liabilities)	$	(41	)	$	—	$	(11	)	$	—	$	—		$	—	$	(52	)




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2012			Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2012
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	(36	)	$	(1	)	$	25	$	—	$	(9	)	$	—	$	(21	)
Non-Recourse Debt	$	—		$	—		$	—	$	—	$	—		$	—	$	—
Power
Net Derivative Assets (Liabilities)	$	22		$	(1	)	$	—	$	—	$	(9	)	$	—	$	12
PSE&G
Net Derivative Assets (Liabilities)	$	(58	)	$	—		$	25	$	—	$	—		$	—	$	(33	)




				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2012			Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2012
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21		$	40	$	(30	)	$	—	$	(52	)	$	—	$	(21	)
Non-Recourse Debt	$	(50	)	$	50	$	—		$	—	$	—		$	—	$	—
Power
Net Derivative Assets (Liabilities)	$	24		$	40	$	—		$	—	$	(52	)	$	—	$	12
PSE&G
Net Derivative Assets (Liabilities)	$	(3	)	$	—	$	(30	)	$	—	$	—		$	—	$	(33	)




	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	27	$	42	$	38	$	57
Power -Recourse Debt (B)	2,041		2,355		2,340		2,818
PSE&G (B)	5,841		6,058		4,795		5,606
Transition Funding (PSE&G) (B)	534		578		690		765
Transition Funding II (PSE&G) (B)	27		28		32		34
Energy Holdings:
Project Level, Non-Recourse Debt (C)	16		16		44		44
Total Long-Term Debt	$	8,486	$	9,077	$	7,939	$	9,324




	Other Comprehensive Income (Loss)
PSEG	Three Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss)	Derivative Contracts			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of June 30, 2013	$	3		$	(466	)	$	101		$	(362	)
Other Comprehensive Income before Reclassifications	1			—			27			28
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(2		)	9			(11		)	(4		)
Net Current Period Other Comprehensive Income (Loss)	(1		)	9			16			24
Balance as of September 30, 2013	$	2		$	(457	)	$	117		$	(338	)




	Other Comprehensive Income (Loss)
PSEG	Nine Months Ended September 30, 2013
Accumulated Other Comprehensive Income (Loss)	Derivative Contracts			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2012	$	7		$	(485	)	$	90		$	(388	)
Other Comprehensive Income before Reclassifications	1			—			53			54
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(6		)	28			(26		)	(4		)
Net Current Period Other Comprehensive Income (Loss)	(5		)	28			27			50
Balance as of September 30, 2013	$	2		$	(457	)	$	117		$	(338	)




	Balance as of December 31, 2011			Other Comprehensive Income (Loss) Nine Months Ended September 30, 2012							Balance as of September 30, 2012
	Balance as of December 31, 2011			Power			PSE&G		Other		Balance as of September 30, 2012
	Millions
Derivative Contracts	$	31		$	(21	)	$	—	$	1	$	11
Pension and OPEB Plans	(438		)	21			—		2		(415		)
Available-for-Sale Securities	70			11			—		1		82
Accumulated Other Comprehensive Income (Loss)	$	(337	)	$	11		$	—	$	4	$	(322	)




	Three Months Ended September 30,								Nine Months Ended September 30,
	2013				2012				2013				2012
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Net Income	$	390	$	390	$	347	$	347	$	1,043	$	1,043	$	1,051	$	1,051
EPS Denominator (Thousands)
Weighted Average Common Shares Outstanding	505,858		505,858		505,914		505,914		505,900		505,900		505,942		505,942
Effect of Stock Based Compensation Awards	—		1,836		—		1,197		—		1,533		—		1,095
Total Shares	505,858		507,694		505,914		507,111		505,900		507,433		505,942		507,037

EPS
Net Income	$	0.77	$	0.77	$	0.69	$	0.68	$	2.06	$	2.06	$	2.08	$	2.07




	Power		PSE&G		Energy Holdings			Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2013
Total Operating Revenues	$	1,169	$	1,666	$	8		$	(289	)	$	2,554
Income (Loss) From Continuing Operations	221		168		(3		)	4			390
Net Income (Loss)	221		168		(3		)	4			390
Segment Earnings (Loss)	221		168		(3		)	4			390
Gross Additions to Long-Lived Assets	197		480		13			6			696
Three Months Ended September 30, 2012
Total Operating Revenues	$	1,038	$	1,683	$	15		$	(334	)	$	2,402
Income (Loss) From Continuing Operations	181		155		7			4			347
Net Income (Loss)	181		155		7			4			347
Segment Earnings (Loss)	181		155		7			4			347
Gross Additions to Long-Lived Assets	149		499		30			11			689
Nine Months Ended September 30, 2013
Total Operating Revenues	$	3,806	$	5,084	$	42		$	(1,282	)	$	7,650
Income (Loss) From Continuing Operations	562		468		1			12			1,043
Net Income (Loss)	562		468		1			12			1,043
Segment Earnings (Loss)	562		468		1			12			1,043
Gross Additions to Long-Lived Assets	419		1,628		40			15			2,102
Nine Months Ended September 30, 2012
Total Operating Revenues	$	3,584	$	5,029	$	49		$	(1,287	)	$	7,375
Income (Loss) From Continuing Operations	538		453		49			11			1,051
Net Income (Loss)	538		453		49			11			1,051
Segment Earnings (Loss)	538		453		49			11			1,051
Gross Additions to Long-Lived Assets	493		1,369		85			22			1,969
As of September 30, 2013
Total Assets	$	10,721	$	20,330	$	1,448		$	111		$	32,610
Investments in Equity Method Subsidiaries	$	40	$	—	$	100		$	—		$	140
As of December 31, 2012
Total Assets	$	11,032	$	19,223	$	1,454		$	16		$	31,725
Investments in Equity Method Subsidiaries	$	40	$	—	$	94		$	—		$	134




	MTM VaR
	Three Months Ended September 30, 2013		Year Ended December 31, 2012
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	9	$	18
Average for the Period	$	14	$	16
High	$	19	$	29
Low	$	9	$	7
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	15	$	28
Average for the Period	$	22	$	25
High	$	30	$	46
Low	$	14	$	11



a. PSEG:
Exhibit 10:		Stock Plan for Outside Directors, as amended April 15, 2014
Exhibit 12:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:		Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:		Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

b. Power:
Exhibit 12.1:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.2:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:		Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:		Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

c. PSE&G:
Exhibit 10:		Stock Plan for Outside Directors, as amended April 15, 2014
Exhibit 12.2:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.3:		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.4:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5:		Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.4:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.5:		Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document



PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

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