Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549 
FORM 10-Q
(Mark One)
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED September 30, 2012March 31, 2013
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM          TO

Commission
File Number
  
Registrants, State of Incorporation,
Address, and Telephone Number
  
I.R.S. Employer
Identification No.
001-09120  
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(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
 
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes ý No ¨
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Public Service Enterprise Group Incorporated
Large accelerated filer x
Accelerated filer 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
Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý
As of OctoberApril 16, 2012,2013, Public Service Enterprise Group Incorporated had outstanding 505,917,472505,968,562 shares of its sole class of Common Stock, without par value.
As of OctoberApril 16, 2012,2013, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.
PSEG Power LLC and Public Service Electric and Gas Company are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q. Each is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.


Table of Contents



 
  
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
16
 
Note 3. Variable Interest Entities (VIEs)
17
 
Note 4. Discontinued Operations and DispositionsRate Filings
1817
 
Note 5. Financing Receivables
18
 
Note 6. Available-for-Sale Securities
2120
 
Note 7. Pension and Other Postretirement Benefits (OPEB)
2625
 
Note 8. Commitments and Contingent Liabilities
2726
 
Note 9. Changes in Capitalization
3634
 
Note 10. Financial Risk Management Activities
3634
 
Note 11. Fair Value Measurements
4241
 
Note 12. Other Income and Deductions
5049
 
Note 13. Income Taxes
5149
 
Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax
5250
 
Note 15. Earnings Per Share (EPS) and Dividends
5352
 
Note 16. Financial Information by Business Segments
5453
 
Note 17. Related-Party Transactions
5554
 
Note 18. Guarantees of Debt
58
Note. 19 Subsequent Event
6156
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
6258
 
Overview of 20122013 and Future Outlook
6258
 
Results of Operations
6661
 
Liquidity and Capital Resources
7466
 
Capital Requirements
7568
 
Accounting Matters
7668
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
7768
Item 4.
Controls and Procedures
7869
  
PART II. OTHER INFORMATION
7970
Item 1.
Legal Proceedings
7970
Item 1A.
Risk Factors
7970
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
7970
Item 5.
Other Information
7970
Item 6.
Exhibits
8474
 
Signatures
8575


i
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FORWARD-LOOKING STATEMENTS
Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial Statements—Note 8. Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to:
adverse changes in the demand for or the price of the capacity and energy that we sell into wholesale electricity markets,
adverse changes in energy industry law, policies and regulation, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, transmission planning and cost allocation rules, including rules regarding how transmission is planned and who is permitted to build transmission in the future, and reliability standards,
any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators,
changes in federal and state environmental regulations that could increase our costs or limit our operations,
changes in nuclear regulation and/or general developments in the nuclear power industry, including various impacts from any accidents or incidents experienced at our facilities or by others in the industry, that could limit operations of our nuclear generating units,
actions or activities at one of our nuclear units located on a multi-unit site that might adversely affect our ability to continue to operate that unit or other units located at the same site,
any inability to balance our energy obligations, available supply and trading risks,
any deterioration in our credit quality or the credit quality of our counterparties, including in our leveraged leases,
availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs,
changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units,
delays in receipt of necessary permits and approvals for our construction and development activities,
delays or unforeseen cost escalations in our construction and development activities,
any inability to achieve, or continue to sustain, our expected levels of operating performance,
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 sufficiently obtain coverage or recover proceeds of insurance on such matters,
increase in competition in energy supply markets as well as competition for certain rate-based transmission projects,
any inability to realize anticipated tax benefits or retain tax credits,
challenges associated with recruitment and/or retention of a qualified workforce,
adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in funding requirements, and
changes in technology and customer usage patterns.
All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change, unless otherwise required by applicable securities laws.
The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.


ii
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
(Unaudited)
 
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2012 2011 2012 2011 
 OPERATING REVENUES$2,402
 $2,620
 $7,375
 $8,443
 
 OPERATING EXPENSES        
 Energy Costs879
 1,167
 2,819
 3,740
 
 Operation and Maintenance619
 603
 1,876
 1,829
 
 Depreciation and Amortization286
 263
 797
 739
 
 Taxes Other Than Income Taxes24
 31
 73
 102
 
 Total Operating Expenses1,808
 2,064
 5,565
 6,410
 
 OPERATING INCOME594
 556

1,810

2,033
 
 Income from Equity Method Investments7
 1
 9
 8
 
 Other Income121
 45
 216
 176
 
 Other Deductions(26) (11) (61) (39) 
 Other-Than-Temporary Impairments(2) (8) (14) (13) 
 Interest Expense(106) (117) (310) (361) 
 INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES588
 466
 1,650
 1,804
 
 Income Tax (Expense) Benefit(241) (201) (599) (757) 
 INCOME FROM CONTINUING OPERATIONS347
 265
 1,051
 1,047
 
 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(51) for the three and nine months ended 2011—
 29
 —
 96
 
 NET INCOME$347
 $294
 $1,051
 $1,143
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):        
 BASIC505,914
 505,909
 505,942
 505,959
 
 DILUTED507,111
 506,999
 507,037
 506,963
 
 EARNINGS PER SHARE:        
 BASIC        
 INCOME FROM CONTINUING OPERATIONS$0.69
 $0.52
 $2.08
 $2.07
 
 NET INCOME$0.69
 $0.58
 $2.08
 $2.26
 
 DILUTED        
 INCOME FROM CONTINUING OPERATIONS$0.68
 $0.52
 $2.07
 $2.06
 
 NET INCOME$0.68
 $0.58
 $2.07
 $2.25
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.3550
 $0.3425
 $1.0650
 $1.0275
 
          
      
  Three Months Ended 
  March 31, 
  2013 2012 
 OPERATING REVENUES$2,786
 $2,875
 
 OPERATING EXPENSES    
 Energy Costs1,155
 1,179
 
 Operation and Maintenance710
 628
 
 Depreciation and Amortization290
 256
 
 Taxes Other Than Income Taxes21
 29
 
 Total Operating Expenses2,176
 2,092
 
 OPERATING INCOME610
 783
 
 Income from Equity Method Investments2
 —
 
 Other Income61
 44
 
 Other Deductions(29) (16) 
 Other-Than-Temporary Impairments(2) (5) 
 Interest Expense(102) (101) 
 INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES540
 705
 
 Income Tax (Expense) Benefit(220) (212) 
 NET INCOME$320
 $493
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):    
 BASIC505,942
 506,010
 
 DILUTED507,220
 507,029
 
 EARNINGS PER SHARE:    
 BASIC    
 INCOME FROM CONTINUING OPERATIONS$0.63
 $0.97
 
 NET INCOME$0.63
 $0.97
 
 DILUTED    
 INCOME FROM CONTINUING OPERATIONS$0.63
 $0.97
 
 NET INCOME$0.63
 $0.97
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.3600
 $0.3550
 
      
.

See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
(Unaudited)
 
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2012 2011 2012 2011 
 NET INCOME$347
 $294
 $1,051
 $1,143
 
 Other Comprehensive Income (Loss), net of tax        
 Available-for-Sale Securities, net of tax (expense) benefit of $5, $59, $(16) and $76 for the three and nine months ended 2012 and 2011, respectively(10) (58) 12
 (73) 
 Change in Fair Value of Derivative Instruments, net of tax (expense) benefit of $1, $(9), $(10) and $(8) for the three and nine months ended 2012 and 2011, respectively(2) 12
 13
 11
 
 Reclassification Adjustments for Net Amounts included in Net Income, net of tax (expense) benefit of $7, $25, $24 and $62 for the three and nine months ended 2012 and 2011, respectively(8) (35) (33) (91) 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(4), $(16) and $(34) for the three and nine months ended 2012 and 2011, respectively8
 4
 23
 53
 
 Other Comprehensive Income (Loss), net of tax(12) (77) 15
 (100) 
 COMPREHENSIVE INCOME$335
 $217
 $1,066
 $1,043
 
          
      
  Three Months Ended 
  March 31, 
  2013 2012 
 NET INCOME$320
 $493
 
 Other Comprehensive Income (Loss), net of tax    
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(27) and $(38) for 2013 and 2012, respectively27
 37
 
 Change in Fair Value of Derivative Instruments, net of tax (expense) benefit of $0 and $(14) for 2013 and 2012, respectively—
 20
 
 Reclassification Adjustments for Net Amounts included in Net Income, net of tax (expense) benefit of $2 and $15 for 2013 and 2012, respectively(4) (20) 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(7) and $(5) for 2013 and 2012, respectively10
 7
 
 Other Comprehensive Income (Loss), net of tax33
 44
 
 COMPREHENSIVE INCOME$353
 $537
 
      

See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  September 30,
2012		 December 31,
2011		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$780
 $834
 
 Accounts Receivable, net of allowances of $52 and $56 in 2012 and 2011, respectively1,044
 967
 
 Tax Receivable—
 16
 
 Unbilled Revenues215
 289
 
 Fuel657
 685
 
 Materials and Supplies, net416
 367
 
 Prepayments274
 308
 
 Derivative Contracts123
 156
 
 Deferred Income Taxes148
 —
 
 Regulatory Assets280
 167
 
 Other41
 122
 
 Total Current Assets3,978
 3,911
 
 PROPERTY, PLANT AND EQUIPMENT26,731
 25,080
 
 Less: Accumulated Depreciation and Amortization(7,628) (7,231) 
 Net Property, Plant and Equipment19,103
 17,849
 
 NONCURRENT ASSETS    
 Regulatory Assets3,336
 3,805
 
 Regulatory Assets of Variable Interest Entities (VIEs)760
 925
 
 Long-Term Investments1,314
 1,303
 
 Nuclear Decommissioning Trust (NDT) Fund1,501
 1,349
 
 Other Special Funds192
 172
 
 Goodwill16
 16
 
 Other Intangibles57
 131
 
 Derivative Contracts144
 106
 
 Restricted Cash of VIEs21
 22
 
 Other284
 232
 
 Total Noncurrent Assets7,625
 8,061
 
 TOTAL ASSETS$30,706
 $29,821
 
      
      
  March 31,
2013		 December 31,
2012		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$420
 $379
 
 Accounts Receivable, net of allowances of $64 and $56 in 2013 and 2012, respectively1,457
 1,069
 
 Tax Receivable226
 227
 
 Unbilled Revenues265
 314
 
 Fuel318
 583
 
 Materials and Supplies, net436
 422
 
 Prepayments87
 283
 
 Derivative Contracts77
 138
 
 Deferred Income Taxes38
 49
 
 Regulatory Assets282
 349
 
 Other50
 56
 
 Total Current Assets3,656
 3,869
 
 PROPERTY, PLANT AND EQUIPMENT27,932
 27,402
 
      Less: Accumulated Depreciation and Amortization(7,807) (7,666) 
 Net Property, Plant and Equipment20,125
 19,736
 
 NONCURRENT ASSETS    
 Regulatory Assets3,643
 3,830
 
 Regulatory Assets of Variable Interest Entities (VIEs)658
 713
 
 Long-Term Investments1,320
 1,324
 
 Nuclear Decommissioning Trust (NDT) Fund1,602
 1,540
 
 Other Special Funds202
 191
 
 Goodwill16
 16
 
 Other Intangibles37
 34
 
 Derivative Contracts102
 153
 
 Restricted Cash of VIEs22
 23
 
 Other329
 296
 
 Total Noncurrent Assets7,931

8,120
 
 TOTAL ASSETS$31,712

$31,725
 
      

See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  September 30,
2012		 December 31,
2011		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year (includes $50 at fair value in 2011)$751
 $417
 
 Securitization Debt of VIEs Due Within One Year224
 216
 
 Accounts Payable1,012
 1,184
 
 Derivative Contracts51
 131
 
 Accrued Interest119
 97
 
 Accrued Taxes216
 30
 
 Deferred Income Taxes—
 170
 
 Clean Energy Program89
 214
 
 Obligation to Return Cash Collateral122
 107
 
 Regulatory Liabilities94
 100
 
 Other361
 291
 
 Total Current Liabilities3,039
 2,957
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)6,058
 5,458
 
 Regulatory Liabilities248
 228
 
 Regulatory Liabilities of VIEs10
 9
 
 Asset Retirement Obligations513
 489
 
 Other Postretirement Benefit (OPEB) Costs1,116
 1,127
 
 Accrued Pension Costs629
 734
 
 Clean Energy Program—
 39
 
 Environmental Costs565
 643
 
 Derivative Contracts112
 26
 
 Long-Term Accrued Taxes166
 292
 
 Other108
 86
 
 Total Noncurrent Liabilities9,525
 9,131
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)    
 CAPITALIZATION    
 LONG-TERM DEBT    
 Long-Term Debt6,729
 6,694
 
 Securitization Debt of VIEs561
 723
 
 Project Level, Non-Recourse Debt44
 44
 
 Total Long-Term Debt7,334
 7,461
 
 STOCKHOLDERS’ EQUITY    
 Common Stock, no par, authorized 1,000,000,000 shares; issued, 2012 and 2011—533,556,660 shares4,836
 4,823
 
 Treasury Stock, at cost, 2012—27,664,188 shares; 2011—27,611,374 shares(606) (601) 
 Retained Earnings6,898
 6,385
 
 Accumulated Other Comprehensive Loss(322) (337) 
 Total Common Stockholders’ Equity10,806
 10,270
 
 Noncontrolling Interest2
 2
 
 Total Stockholders’ Equity10,808
 10,272
 
 Total Capitalization18,142
 17,733
 
 TOTAL LIABILITIES AND CAPITALIZATION$30,706
 $29,821
 
      
      
  March 31,
2013		 December 31,
2012		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$876
 $1,026
 
 Securitization Debt of VIEs Due Within One Year229
 226
 
 Commercial Paper and Loans165
 263
 
 Accounts Payable1,078
 1,304
 
 Derivative Contracts27
 46
 
 Accrued Interest114
 91
 
 Accrued Taxes92
 17
 
 Deferred Income Taxes10
 72
 
 Clean Energy Program92
 153
 
 Obligation to Return Cash Collateral125
 122
 
 Regulatory Liabilities120
 67
 
 Other478
 390
 
 Total Current Liabilities3,406
 3,777
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)6,604
 6,542
 
 Regulatory Liabilities245
 209
 
 Regulatory Liabilities of VIEs10
 10
 
 Asset Retirement Obligations636
 627
 
 Other Postretirement Benefit (OPEB) Costs1,270
 1,285
 
 Accrued Pension Costs724
 876
 
 Environmental Costs464
 537
 
 Derivative Contracts123
 122
 
 Long-Term Accrued Taxes160
 164
 
 Other114
 108
 
 Total Noncurrent Liabilities10,350
 10,480
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)    
 CAPITALIZATION    
 LONG-TERM DEBT
   
 Long-Term Debt6,542
 6,148
 
 Securitization Debt of VIEs442
 496
 
 Project Level, Non-Recourse Debt25
 43
 
 Total Long-Term Debt7,009
 6,687
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000,000,000 shares; issued, 2013 and 2012—533,556,660 shares4,833
 4,833
 
 Treasury Stock, at cost, 2013—27,692,398 shares; 2012—27,664,188 shares(612) (607) 
 Retained Earnings7,080
 6,942
 
 Accumulated Other Comprehensive Loss(355) (388) 
 Total Common Stockholders’ Equity10,946
 10,780
 
 Noncontrolling Interest1
 1
 
 Total Stockholders’ Equity10,947
 10,781
 
 Total Capitalization17,956
 17,468
 
 TOTAL LIABILITIES AND CAPITALIZATION$31,712
 $31,725
 
      

See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
 
      
  Nine Months Ended 
  September 30, 
  2012 2011 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$1,051
 $1,143
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Gain on Disposal of Discontinued Operations—
 (122) 
 Depreciation and Amortization797
 745
 
 Amortization of Nuclear Fuel129
 114
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC221
 629
 
 Non-Cash Employee Benefit Plan Costs203
 138
 
 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes(81) (16) 
 Leveraged Lease Reserve, net of tax—
 170
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives116
 (14) 
 Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs46
 100
 
 Over (Under) Recovery of Societal Benefits Charge (SBC)(51) (26) 
 Market Transition Charge Refund(23) (47) 
 Cost of Removal(71) (43) 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(107) (110) 
 Net Change in Tax Receivable16
 312
 
 Net Change in Certain Current Assets and Liabilities305
 (44) 
 Employee Benefit Plan Funding and Related Payments(193) (486) 
 Other(47) (34) 
 Net Cash Provided By (Used In) Operating Activities2,311
 2,409
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(1,969) (1,479) 
 Proceeds from Sale of Discontinued Operations—
 687
 
 Proceeds from Sales of Available-for-Sale Securities1,473
 1,088
 
 Investments in Available-for-Sale Securities(1,497) (1,110) 
 Other(58) (13) 
 Net Cash Provided By (Used In) Investing Activities(2,051) (827) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans—
 (64) 
 Issuance of Long-Term Debt850
 750
 
 Redemption of Long-Term Debt(439) (606) 
 Repayment of Non-Recourse Debt(1) (1) 
 Redemption of Securitization Debt(154) (147) 
 Cash Dividends Paid on Common Stock(538) (520) 
 Other(32) (32) 
 Net Cash Provided By (Used In) Financing Activities(314) (620) 
 Net Increase (Decrease) in Cash and Cash Equivalents(54) 962
 
 Cash and Cash Equivalents at Beginning of Period834
 280
 
 Cash and Cash Equivalents at End of Period$780
 $1,242
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$109
 $60
 
 Interest Paid, Net of Amounts Capitalized$280
 $341
 
 Accrued Property, Plant and Equipment Expenditures$259
 $211
 
      
      
  Three Months Ended 
  March 31, 
  2013 2012 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$320
 $493
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization290
 256
 
 Amortization of Nuclear Fuel50
 43
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC(5) 12
 
 Non-Cash Employee Benefit Plan Costs61
 68
 
 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes(6) 140
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives165
 —
 
 Deferred Storm Costs(46) 4
 
 Net Change in Regulatory Assets and Liabilities80
 (26) 
 Cost of Removal(24) (20) 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(24) (15) 
 Net Change in Certain Current Assets and Liabilities207
 279
 
 Employee Benefit Plan Funding and Related Payments(192) (154) 
 Other1
 8
 
 Net Cash Provided By (Used In) Operating Activities877
 1,088
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(724) (687) 
 Proceeds from Sales of Available-for-Sale Securities258
 499
 
 Investments in Available-for-Sale Securities(271) (511) 
 Other4
 (7) 
 Net Cash Provided By (Used In) Investing Activities(733) (706) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans(98) 29
 
 Issuance of Long-Term Debt400
 —
 
 Redemption of Long-Term Debt, including Securitization Debt(201) (115) 
 Cash Dividends Paid on Common Stock(182) (179) 
 Other(22) (20) 
 Net Cash Provided By (Used In) Financing Activities(103) (285) 
 Net Increase (Decrease) in Cash and Cash Equivalents41
 97
 
 Cash and Cash Equivalents at Beginning of Period379
 834
 
 Cash and Cash Equivalents at End of Period$420
 $931
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$3
 $3
 
 Interest Paid, Net of Amounts Capitalized$82
 $84
 
 Accrued Property, Plant and Equipment Expenditures$265
 $202
 
      

See Notes to Condensed Consolidated Financial Statements.

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PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
(Unaudited)
 
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2012 2011 2012 2011 
 OPERATING REVENUES$1,038
 $1,398
 $3,584
 $4,650
 
 OPERATING EXPENSES        
 Energy Costs456
 597
 1,725
 2,335
 
 Operation and Maintenance255
 262
 780
 810
 
 Depreciation and Amortization60
 56
 175
 166
 
 Total Operating Expenses771
 915
 2,680
 3,311
 
 OPERATING INCOME267
 483
 904
 1,339
 
 Other Income104
 37
 171
 156
 
 Other Deductions(20) (10) (52) (37) 
 Other-Than-Temporary Impairments(2) (8) (14) (10) 
 Interest Expense(35) (42) (97) (134) 
 INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES314
 460
 912
 1,314
 
 Income Tax (Expense) Benefit(133) (187) (374) (539) 
 INCOME FROM CONTINUING OPERATIONS181
 273
 538
 775
 
 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(51) for the three and nine months ended 2011—
 29
 —
 96
 
 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED$181
 $302
 $538
 $871
 
          
      
  Three Months Ended 
  March 31, 
  2013 2012 
 OPERATING REVENUES$1,447
 $1,561
 
 OPERATING EXPENSES    
 Energy Costs860
 822
 
 Operation and Maintenance282
 241
 
 Depreciation and Amortization64
 57
 
 Total Operating Expenses1,206
 1,120
 
 OPERATING INCOME241
 441
 
 Other Income47
 30
 
 Other Deductions(28) (15) 
 Other-Than-Temporary Impairments(2) (5) 
 Interest Expense(30) (30) 
 INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES228
 421
 
 Income Tax (Expense) Benefit(91) (168) 
 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED$137
 $253
 
  

   

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


6
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PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
(Unaudited)

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 
2012 2011 2012 2011 
 NET INCOME$181
 $302
 $538
 $871
 
 Other Comprehensive Income (Loss), net of tax        
 Available-for-Sale Securities, net of tax (expense) benefit of $6, $58, $(16) and $77 for the three and nine months ended 2012 and 2011, respectively(11) (60) 11
 (77) 
 Change in Fair Value of Derivative Instruments, net of tax (expense) benefit of $1, $(9), $(10) and $(8) for the three and nine months ended 2012 and 2011, respectively(2) 12
 13
 11
 
 Reclassification Adjustments for Net Amounts included in Net Income, net of tax (expense) benefit of $7, $25, $24 and $62 for the three and nine months ended 2012 and 2011, respectively(9) (35) (34) (91) 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(4), $(3), $(14) and $(31) for the three and nine months ended 2012 and 2011, respectively7
 3
 21
 45
 
 Other Comprehensive Income (Loss), net of tax(15) (80) 11
 (112) 
 COMPREHENSIVE INCOME$166
 $222
 $549
 $759
 
          
      
  Three Months Ended 
  March 31, 
 
2013 2012 
 NET INCOME$137
 $253
 
 Other Comprehensive Income (Loss), net of tax    
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(27) and ($39) for 2013 and 2012, respectively27
 37
 
 Change in Fair Value of Derivative Instruments, net of tax (expense) benefit of $0 and $(14) for 2013 and 2012, respectively—
 20
 
 Reclassification Adjustments for Net Amounts included in Net Income, net of tax (expense) benefit of $2 and $15 for 2013, and 2012, respectively(4) (20) 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(5) and $(5) for 2013 and 2012, respectively9
 7
 
 Other Comprehensive Income (Loss), net of tax32
 44
 
 COMPREHENSIVE INCOME$169
 $297
 
      

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


7
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PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  September 30,
2012		 December 31,
2011		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$5
 $12
 
 Accounts Receivable295
 267
 
 Accounts Receivable—Affiliated Companies, net100
 381
 
 Short-Term Loan to Affiliate890
 907
 
 Fuel657
 685
 
 Materials and Supplies, net310
 272
 
 Derivative Contracts102
 139
 
 Prepayments22
 24
 
 Total Current Assets2,381
 2,687
 
 PROPERTY, PLANT AND EQUIPMENT9,564
 9,191
 
 Less: Accumulated Depreciation and Amortization(2,692) (2,460) 
 Net Property, Plant and Equipment6,872
 6,731
 
 NONCURRENT ASSETS    
 Nuclear Decommissioning Trust (NDT) Fund1,501
 1,349
 
 Goodwill16
 16
 
 Other Intangibles57
 131
 
 Other Special Funds36
 33
 
 Derivative Contracts22
 55
 
 Other109
 85
 
 Total Noncurrent Assets1,741
 1,669
 
 TOTAL ASSETS$10,994
 $11,087
 
      
      
  March 31,
2013		 December 31,
2012		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$6
 $7
 
 Accounts Receivable405
 269
 
 Accounts Receivable—Affiliated Companies, net170
 340
 
 Short-Term Loan to Affiliate748
 574
 
 Fuel318
 583
 
 Materials and Supplies, net313
 307
 
 Derivative Contracts52
 118
 
 Prepayments11
 17
 
 Deferred Income Taxes28
 —
 
 Other1
 19
 
 Total Current Assets2,052
 2,234
 
 PROPERTY, PLANT AND EQUIPMENT9,786
 9,697
 
 Less: Accumulated Depreciation and Amortization(2,793) (2,679) 
 Net Property, Plant and Equipment6,993
 7,018
 
 NONCURRENT ASSETS    
 Nuclear Decommissioning Trust (NDT) Fund1,602
 1,540
 
 Goodwill16
 16
 
 Other Intangibles38
 34
 
 Other Special Funds38
 36
 
 Derivative Contracts6
 49
 
 Other120
 105
 
 Total Noncurrent Assets1,820
 1,780
 
 TOTAL ASSETS$10,865
 $11,032
 
      

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


8
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PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2012		 December 31,
2011		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$300
 $66
 
 Accounts Payable433
 541
 
 Derivative Contracts51
 124
 
 Deferred Income Taxes4
 53
 
 Accrued Interest49
 32
 
 Other90
 86
 
 Total Current Liabilities927
 902
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)1,463
 1,266
 
 Asset Retirement Obligations275
 259
 
 Other Postretirement Benefit (OPEB) Costs189
 180
 
 Derivative Contracts6
 24
 
 Accrued Pension Costs205
 236
 
 Long-Term Accrued Taxes66
 8
 
 Other84
 83
 
 Total Noncurrent Liabilities2,288
 2,056
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)    
 LONG-TERM DEBT    
 Total Long-Term Debt2,386
 2,685
 
 MEMBER’S EQUITY    
 Contributed Capital2,028
 2,028
 
 Basis Adjustment(986) (986) 
 Retained Earnings4,616
 4,678
 
 Accumulated Other Comprehensive Loss(265) (276) 
 Total Member’s Equity5,393
 5,444
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$10,994
 $11,087
 
      
      
  March 31,
2013		 December 31,
2012		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$300
 $300
 
 Accounts Payable408
 498
 
 Derivative Contracts27
 46
 
 Deferred Income Taxes—
 16
 
 Accrued Interest41
 26
 
 Other96
 81
 
 Total Current Liabilities872
 967
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)1,628
 1,575
 
 Asset Retirement Obligations374
 369
 
 Other Postretirement Benefit (OPEB) Costs224
 221
 
 Derivative Contracts14
 15
 
 Accrued Pension Costs230
 272
 
 Long-Term Accrued Taxes38
 50
 
 Other87
 84
 
 Total Noncurrent Liabilities2,595
 2,586
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)    
 LONG-TERM DEBT    
 Total Long-Term Debt2,040
 2,040
 
 MEMBER’S EQUITY    
 Contributed Capital2,028
 2,028
 
 Basis Adjustment(986) (986) 
 Retained Earnings4,612
 4,725
 
 Accumulated Other Comprehensive Loss(296) (328) 
 Total Member’s Equity5,358
 5,439
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$10,865
 $11,032
 
      

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


9
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PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
 
      
  Nine Months Ended 
  September 30, 
  2012 2011 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$538
 $871
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Gain on Disposal of Discontinued Operations—
 (122) 
 Depreciation and Amortization175
 173
 
 Amortization of Nuclear Fuel129
 114
 
 Provision for Deferred Income Taxes and ITC189
 74
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives116
 (14) 
 Non-Cash Employee Benefit Plan Costs53
 33
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(107) (110) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies(10) (82) 
 Margin Deposit(107) (63) 
 Accounts Receivable50
 157
 
 Accounts Payable(31) (103) 
 Accounts Receivable/Payable-Affiliated Companies, net193
 650
 
 Accrued Interest Payable17
 23
 
 Other Current Assets and Liabilities2
 48
 
 Employee Benefit Plan Funding and Related Payments(40) (127) 
 Other5
 (35) 
 Net Cash Provided By (Used In) Operating Activities1,172
 1,487
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(493) (530) 
 Proceeds from Sale of Discontinued Operations—
 687
 
 Proceeds from Sales of Available-for-Sale Securities1,295
 1,088
 
 Investments in Available-for-Sale Securities(1,315) (1,106) 
 Short-Term Loan—Affiliated Company, net17
 (1,176) 
 Other(10) 19
 
 Net Cash Provided By (Used In) Investing Activities(506) (1,018) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Issuance of Recourse Long-Term Debt—
 500
 
 Cash Dividend Paid(600) (350) 
 Redemption of Long-Term Debt(66) (606) 
 Other(7) (10) 
 Net Cash Provided By (Used In) Financing Activities(673) (466) 
 Net Increase (Decrease) in Cash and Cash Equivalents(7) 3
 
 Cash and Cash Equivalents at Beginning of Period12
 11
 
 Cash and Cash Equivalents at End of Period$5
 $14
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$130
 $110
 
 Interest Paid, Net of Amounts Capitalized$73
 $111
 
 Accrued Property, Plant and Equipment Expenditures$84
 $86
 
      
      
  Three Months Ended 
  March 31, 
  2013 2012 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$137
 $253
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization64
 57
 
 Amortization of Nuclear Fuel50
 43
 
 Provision for Deferred Income Taxes and ITC(33) 101
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives165
 —
 
 Non-Cash Employee Benefit Plan Costs17
 18
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(24) (15) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies259
 188
 
 Margin Deposit(117) (34)
 Accounts Receivable3
 47
 
 Accounts Payable(67) (11) 
 Accounts Receivable/Payable-Affiliated Companies, net121
 145
 
 Accrued Interest Payable15
 17
 
 Other Current Assets and Liabilities22
 (39) 
 Employee Benefit Plan Funding and Related Payments(45) (38) 
 Other5
 (1) 
 Net Cash Provided By (Used In) Operating Activities572
 731
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(143) (237) 
 Proceeds from Sales of Available-for-Sale Securities244
 375
 
 Investments in Available-for-Sale Securities(256) (385) 
 Short-Term Loan—Affiliated Company, net(174) (128) 
 Other8
 10
 
 Net Cash Provided By (Used In) Investing Activities(321) (365) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Cash Dividend Paid(250) (300) 
 Redemption of Long-Term Debt—
 (66) 
 Other(2) (7) 
 Net Cash Provided By (Used In) Financing Activities(252) (373) 
 Net Increase (Decrease) in Cash and Cash Equivalents(1) (7) 
 Cash and Cash Equivalents at Beginning of Period7
 12
 
 Cash and Cash Equivalents at End of Period$6
 $5
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$2
 $(2) 
 Interest Paid, Net of Amounts Capitalized$18
 $15
 
 Accrued Property, Plant and Equipment Expenditures$41
 $59
 
      

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


10
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
(Unaudited)

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2012 2011 2012 2011 
 OPERATING REVENUES$1,683
 $1,841
 $5,029
 $5,718
 
 OPERATING EXPENSES        
 Energy Costs756
 943
 2,380
 3,124
 
 Operation and Maintenance366
 342
 1,092
 1,014
 
 Depreciation and Amortization216
 197
 594
 548
 
 Taxes Other Than Income Taxes24
 31
 73
 102
 
 Total Operating Expenses1,362
 1,513
 4,139
 4,788
 
 OPERATING INCOME321
 328
 890
 930
 
 Other Income16
 7
 39
 16
 
 Other Deductions(6) (1) (8) (2) 
 Other-Than-Temporary Impairments—
 —
 —
 (1) 
 Interest Expense(73) (77) (220) (234) 
 INCOME BEFORE INCOME TAXES258
 257
 701
 709
 
 Income Tax (Expense) Benefit(103) (103) (248) (287) 
 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED$155
 $154
 $453
 $422
 
          
      
  Three Months Ended 
  March 31, 
  2013 2012 
 OPERATING REVENUES$1,995
 $1,939
 
 OPERATING EXPENSES    
 Energy Costs967
 1,002
 
 Operation and Maintenance427
 376
 
 Depreciation and Amortization215
 190
 
 Taxes Other Than Income Taxes21
 29
 
 Total Operating Expenses1,630
 1,597
 
 OPERATING INCOME365
 342
 
 Other Income13
 11
 
 Other Deductions(1) (1) 
 Interest Expense(73) (73) 
 INCOME BEFORE INCOME TAXES304
 279
 
 Income Tax (Expense) Benefit(125) (82) 
 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED$179
 $197
 
      

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


11
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
(Unaudited)

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2012 2011 2012 2011 
 NET INCOME$155
 $154
 $453
 $422
 
 Available-for-Sale Securities, net of tax (expense) benefit of $(1), $(0), $(0) and $(1) for the three and nine months ended 2012 and 2011, respectively1
 1
 —
 2
 
 COMPREHENSIVE INCOME$156
 $155
 $453
 $424
 
          
      
  Three Months Ended 
  March 31, 
  2013 2012 
 NET INCOME$179
 $197
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 and $1 for 2013 and 2012, respectively—
 (1) 
 COMPREHENSIVE INCOME$179
 $196
 
      

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


12
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2012		 December 31,
2011		 
 ASSETS    
 CURRENT ASSETS    
 Cash and Cash Equivalents$71
 $143
 
 Accounts Receivable, net of allowances of $52 and $56 in 2012 and 2011, respectively729
 691
 
 Tax Receivable—
 16
 
 Unbilled Revenues215
 289
 
 Materials and Supplies105
 94
 
 Prepayments145
 117
 
 Regulatory Assets280
 167
 
 Derivative Contracts3
 —
 
 Other30
 21
 
 Total Current Assets1,578
 1,538
 
 PROPERTY, PLANT AND EQUIPMENT16,509
 15,306
 
 Less: Accumulated Depreciation and Amortization(4,674) (4,539) 
 Net Property, Plant and Equipment11,835
 10,767
 
 NONCURRENT ASSETS    
 Regulatory Assets3,336
 3,805
 
 Regulatory Assets of VIEs760
 925
 
 Long-Term Investments334
 280
 
 Other Special Funds63
 57
 
 Derivative Contracts70
 4
 
 Restricted Cash of VIEs21
 22
 
 Other118
 89
 
 Total Noncurrent Assets4,702
 5,182
 
 TOTAL ASSETS$18,115
 $17,487
 
      
      
  March 31,
2013		 December 31,
2012		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$61
 $116
 
 Accounts Receivable, net of allowances of $64 and $56 in 2013 and 2012, respectively1,032
 783
 
 Unbilled Revenues265
 314
 
 Materials and Supplies121
 114
 
 Prepayments9
 29
 
 Regulatory Assets282
 349
 
 Derivative Contracts10
 5
 
 Deferred Income Taxes38
 49
 
 Other15
 24
 
 Total Current Assets1,833
 1,783
 
 PROPERTY, PLANT AND EQUIPMENT17,494
 17,006
 
 Less: Accumulated Depreciation and Amortization(4,780) (4,726) 
 Net Property, Plant and Equipment12,714
 12,280
 
 NONCURRENT ASSETS    
 Regulatory Assets3,643
 3,830
 
 Regulatory Assets of VIEs658
 713
 
 Long-Term Investments361
 348
 
 Other Special Funds61
 61
 
 Derivative Contracts59
 62
 
 Restricted Cash of VIEs22
 23
 
 Other137
 123
 
 Total Noncurrent Assets4,941
 5,160
 
 TOTAL ASSETS$19,488
 $19,223
 
      

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


13
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2012		 December 31,
2011		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$450
 $300
 
 Securitization Debt of VIEs Due Within One Year224
 216
 
 Accounts Payable449
 498
 
 Accounts Payable—Affiliated Companies, net155
 280
 
 Accrued Interest71
 65
 
 Clean Energy Program89
 214
 
 Derivative Contracts—
 7
 
 Deferred Income Taxes16
 32
 
 Obligation to Return Cash Collateral122
 107
 
 Regulatory Liabilities94
 100
 
 Other243
 186
 
 Total Current Liabilities1,913
 2,005
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC3,916
 3,675
 
 Other Postretirement Benefit (OPEB) Costs879
 900
 
 Accrued Pension Costs285
 355
 
 Regulatory Liabilities248
 228
 
 Regulatory Liabilities of VIEs10
 9
 
 Clean Energy Program—
 39
 
 Environmental Costs514
 592
 
 Asset Retirement Obligations233
 226
 
 Derivative Contracts106
 —
 
 Long-Term Accrued Taxes19
 83
 
 Other37
 35
 
 Total Noncurrent Liabilities6,247
 6,142
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)    
 CAPITALIZATION    
 LONG-TERM DEBT    
 Long-Term Debt4,294
 3,970
 
 Securitization Debt of VIEs561
 723
 
 Total Long-Term Debt4,855
 4,693
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150,000,000 shares authorized; issued and outstanding, 2012 and 2011—132,450,344 shares892
 892
 
 Contributed Capital420
 420
 
 Basis Adjustment986
 986
 
 Retained Earnings2,800
 2,347
 
 Accumulated Other Comprehensive Income2
 2
 
 Total Stockholder’s Equity5,100
 4,647
 
 Total Capitalization9,955
 9,340
 
 TOTAL LIABILITIES AND CAPITALIZATION$18,115
 $17,487
 
      
      
  March 31,
2013		 December 31,
2012		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$575
 $725
 
 Securitization Debt of VIEs Due Within One Year229
 226
 
 Commercial Paper and Loans165
 263
 
 Accounts Payable539
 630
 
 Accounts Payable—Affiliated Companies, net89
 73
 
 Accrued Interest73
 65
 
 Clean Energy Program92
 153
 
 Deferred Income Taxes43
 60
 
 Obligation to Return Cash Collateral125
 122
 
 Regulatory Liabilities120
 67
 
 Other351
 269
 
 Total Current Liabilities2,401
 2,653
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC4,249
 4,223
 
 Other Postretirement Benefit (OPEB) Costs992
 1,011
 
 Accrued Pension Costs369
 463
 
 Regulatory Liabilities245
 209
 
 Regulatory Liabilities of VIEs10
 10
 
 Environmental Costs413
 486
 
 Asset Retirement Obligations254
 250
 
 Derivative Contracts109
 107
 
 Long-Term Accrued Taxes39
 32
 
 Other44
 38
 
 Total Noncurrent Liabilities6,724
 6,829
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)    
 CAPITALIZATION    
 LONG-TERM DEBT    
 Long-Term Debt4,467
 4,070
 
 Securitization Debt of VIEs442
 496
 
 Total Long-Term Debt4,909
 4,566
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150,000,000 shares authorized; issued and outstanding, 2013 and 2012—132,450,344 shares892
 892
 
 Contributed Capital520
 420
 
 Basis Adjustment986
 986
 
 Retained Earnings3,054
 2,875
 
 Accumulated Other Comprehensive Income2
 2
 
 Total Stockholder’s Equity5,454
 5,175
 
 Total Capitalization10,363
 9,741
 
 TOTAL LIABILITIES AND CAPITALIZATION$19,488
 $19,223
 
      

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


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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)

      
  Nine Months Ended 
  September 30, 
  2012 2011 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$453
 $422
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization594
 548
 
 Provision for Deferred Income Taxes and ITC131
 563
 
 Non-Cash Employee Benefit Plan Costs134
 92
 
 Cost of Removal(71) (43) 
 Market Transition Charge (MTC) Refund(23) (47) 
 Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs46
 100
 
 Over (Under) Recovery of SBC(51) (26) 
 Net Changes in Certain Current Assets and Liabilities:    
 Accounts Receivable and Unbilled Revenues97
 261
 
 Materials and Supplies(11) (1) 
 Prepayments(28) (203) 
 Net Change in Tax Receivable16
 (21) 
 Accounts Receivable/Payable-Affiliated Companies, net(41) (381) 
 Other Current Assets and Liabilities2
 (66) 
 Employee Benefit Plan Funding and Related Payments(137) (311) 
 Other(70) (15) 
 Net Cash Provided By (Used In) Operating Activities1,041
 872
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(1,369) (939) 
 Proceeds from Sale of Available-for-Sale Securities73
 —
 
 Investments in Available-for-Sale Securities(73) —
 
 Solar Loan Investments(56) (34) 
 Restricted Funds1
 (1) 
 Net Cash Provided By (Used In) Investing Activities(1,424) (974) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Issuance of Long-Term Debt850
 250
 
 Redemption of Long-Term Debt(373) —
 
 Redemption of Securitization Debt(154) (147) 
 Deferred Issuance Costs(12) (4) 
 Net Cash Provided By (Used In) Financing Activities311
 99
 
 Net Increase (Decrease) In Cash and Cash Equivalents(72) (3) 
 Cash and Cash Equivalents at Beginning of Period143
 245
 
 Cash and Cash Equivalents at End of Period$71
 $242
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(30) $(44) 
 Interest Paid, Net of Amounts Capitalized$205
 $225
 
 Accrued Property, Plant and Equipment Expenditures$175
 $125
 
      
      
  Three Months Ended 
  March 31, 
  2013 2012 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$179
 $197
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization215
 190
 
 Provision for Deferred Income Taxes and ITC29
 8
 
 Non-Cash Employee Benefit Plan Costs39
 44
 
 Cost of Removal(24) (20) 
 Deferred Storm Costs(46) 4
 
 Net Change in Regulatory Assets and Liabilities80
 (26) 
 Net Change in Certain Current Assets and Liabilities:    
 Accounts Receivable and Unbilled Revenues(200) (14) 
 Materials and Supplies(7) (3) 
 Prepayments20
 52
 
 Accounts Receivable/Payable-Affiliated Companies, net64
 (8) 
 Other Current Assets and Liabilities112
 51
 
 Employee Benefit Plan Funding and Related Payments(120) (103) 
 Other(12) (6) 
 Net Cash Provided By (Used In) Operating Activities329
 366
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(572) (435) 
 Proceeds from Sale of Available-for-Sale Securities6
 51
 
 Investments in Available-for-Sale Securities(6) (51) 
 Solar Loan Investments(7) (19) 
 Restricted Funds1
 —
 
 Net Cash Provided By (Used In) Investing Activities(578) (454) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt(98) 29
 
 Issuance of Long-Term Debt400
 —
 
 Redemption of Long-Term Debt(150) —
 
 Redemption of Securitization Debt(51) (49) 
 Contributed Capital100
 —
 
 Other(7) —
 
 Net Cash Provided By (Used In) Financing Activities194
 (20) 
 Net Increase (Decrease) In Cash and Cash Equivalents(55) (108) 
 Cash and Cash Equivalents at Beginning of Period116
 143
 
 Cash and Cash Equivalents at End of Period$61
 $35
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$—
 $(22) 
 Interest Paid, Net of Amounts Capitalized$63
 $69
 
 Accrued Property, Plant and Equipment Expenditures$224
 $143
 
      

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

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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 AtlanticMid-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 and marketing and risk management functions through three principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the states in which they operate.
PSE&G—which is an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the FERC. PSE&G is also investinginvests in the development of solar generation projects and has implemented energy efficiency and demand response programs, which are regulated by the BPU.
PSEG Energy Holdings L.L.C. (Energy Holdings)—which primarily has investedinvestments in leveraged leases and owns and operates domesticsolar generation projects engaged in the generation of energy through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by the FERC and the states in which they operate. Energy Holdings has also invested in solar generation projects and is exploring opportunities for other investments in renewable generation and has been awarded a contract to manage the transmission and distribution assets of the Long Island Power Authority (LIPA) starting in 2014.
PSEG Services Corporation (Services)—which provides management, administrative and general services to PSEG and its subsidiaries at cost.
Basis of Presentation
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 20112012 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012..
The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All significant intercompany accounts and transactions are eliminated in consolidation, except as discussed in Note 17. Related-Party Transactions. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 20112012.


Note 2. Recent Accounting Standards
New Standards Adopted during 2012
Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)
This accounting standard was issued to update guidance related to fair value measurements and disclosures as a step towards achieving convergence between GAAP and IFRS. The updated guidance
clarifies intent about application of existing fair value measurements and disclosures,
changes some requirements for fair value measurements, and
requires expanded disclosures.
We adopted this standard prospectively effective January 1, 2012. Upon adoption there was no material impact on our

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


consolidated financial position, results of operations or cash flows; however, it has resulted in expanded disclosures. For additional information, see Note 11. Fair Value Measurements.
Presentation of Comprehensive Income
This accounting standard addresses the presentation of comprehensive income as a step towards achieving convergence between GAAP and IFRS. The updated guidance
allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and
eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.
In December 2011, the FASB issued an amendment to this standard to indefinitely defer the effective date for some of the specific disclosure requirements that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income by component in both the statement in which net income is presented and the statement in which other comprehensive income is presented. During the deferral period, the existing requirements in GAAP for the presentation of reclassification adjustments must continue to be followed.
We adopted this standard retrospectively effective January 1, 2012. Upon adoption of the new amended guidance, there was no impact on our consolidated financial position, results of operations or cash flows, but there was a change in the presentation of the components of other comprehensive income.
New Accounting Standards Issued But Not Yet Adopted2013
Disclosures about Offsetting Assets and Liabilities
This accounting standard was issued concerning balance sheet offsettingrequires enhanced disclosures to facilitate comparability betweenregarding assets and liabilities that are either offset in the financial statements, prepared on the basis of GAAPor are subject to an enforceable master netting arrangement or similar agreement. The guidance is applicable to certain financial instruments (e.g. derivatives) and IFRS.securities borrowing and lending transactions. This standard requires entitiesentities:
to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on an entity’sentity's financial position, and

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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 that are offset.liabilities.
The guidance isWe adopted this standard retrospectively effective for fiscal years and interim periods beginning on or after January 1, 2013. As this standard requires disclosures only, it willdid not have any impact on our consolidated financial position, results of operations or cash flows upon adoption.flows. For additional information, see Note 10. Financial Risk Management Activities.
Reclassification Adjustments out of Accumulated Other Comprehensive Income (AOCI)
This accounting standard requires entities to disclose the following information about reclassification adjustments related to AOCI:
changes in AOCI balances by component; and
significant amounts reclassified out of AOCI 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 14. Accumulated Other Comprehensive Income (Loss), Net of Tax.


Note 3. Variable Interest Entities (VIEs)
Variable Interest Entities for which PSE&G is the Primary Beneficiary
PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which is pledged as collateral to a trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.
The assets and liabilities of these VIEs are presented separately on the face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the Transition Funding and Transition Funding II assets are restricted and can only be used to settle their respective obligations. No Transition Funding or Transition Funding II creditor has any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding or Transition Funding II, respectively.
PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of September 30, 2012March 31, 2013 and December 31, 20112012. 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 ninethree months of 20122013 or in 2011.2012. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.


Note 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.
Weather Normalization Clause (WNC)—On April 29, 2013, the BPU approved PSE&G's filing with respect to deficiency revenues from the 2011-2012 Winter Period. As a result, provisional rates were approved which are recovering $41 million from customers during the 2012-2013 Winter Period, with a carryover deficiency of $24 million to the 2013-2014 Winter Period.
Remediation Adjustment Charge (RAC)—In April 2013, PSE&G filed a RAC 20 petition with the BPU requesting a decrease in electric and gas RAC revenues on an annual basis of $12 million and $7 million, respectively.




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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)



Note 4. Discontinued Operations and Dispositions
Discontinued Operations
Power
In March 2011, Power completed the sale of its 1,000 MW gas-fired Guadalupe generating facility for a total price of $352 million, resulting in an after-tax gain of $54 million.
In July 2011, Power completed the sale of its 1,000 MW gas-fired Odessa generating facility for approximately $335 million, resulting in an after-tax gain of approximately $25 million.
PSEG Texas’ operating results for the three months and nine months ended September 30, 2011, which were reclassified to Discontinued Operations, are summarized below:

      
  Three Months Ended Nine Months Ended 
  September 30,
2011		 September 30,
2011		 
  Millions 
 Operating Revenues$20
 $112
 
 Income Before Income Taxes$6
 $26
 
 Net Income$4
 $17
 
      

Note 5. Financing Receivables
PSE&G
PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with Solar Renewable Energy Certificates (SRECs) generated from the installed solar electric system. The following table reflects the outstanding short and long-term loans by class of customer, none of which are considered “non-performing.”

      
 Credit Risk Profile Based on Payment Activity 
  As of As of 
 Consumer LoansSeptember 30,
2012		 December 31,
2011		 
  Millions 
 Commercial/Industrial$159
 $106
 
 Residential14
 10
 
 Total$173
 $116
 
      
      
 Credit Risk Profile Based on Payment Activity 
  As of As of 
 Consumer LoansMarch 31,
2013		 December 31,
2012		 
  Millions 
 Commercial/Industrial$185
 $174
 
 Residential16
 15
 
 Total$201
 $189
 
      

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 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 table below shows Energy Holdings’ gross and net lease investment as of September 30, 2012March 31, 2013 and December 31, 20112012, respectively.
      
  As of As of 
  September 30,
2012		 December 31,
2011		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$724
 $763
 
 Estimated Residual Value of Leased Assets535
 553
 
  1,259
 1,316
 
 Unearned and Deferred Income(423) (435) 
 Gross Investments in Leases836
 881
 
 Deferred Tax Liabilities(696) (716) 
 Net Investments in Leases$140
 $165
 
      

      
  As of As of 
  March 31,
2013		 December 31,
2012		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$705
 $721
 
 Estimated Residual Value of Leased Assets529
 535
 
  1,234
 1,256
 
 Unearned and Deferred Income(412) (416) 
 Gross Investments in Leases822
 840
 
 Deferred Tax Liabilities(704) (723) 
 Net Investments in Leases$118
 $117
 
      
The corresponding receivables associated with the lease portfolio are reflected below, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. “Not Rated”"Not Rated" counterparties relate to investments in leases of commercial real estate properties.


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


      
  
Lease Receivables, Net of
Non-Recourse Debt
 
  As of As of 
 Counterparties’ Credit Rating (S&P) as of September 30, 2012September 30,
2012		 December 31,
2011		 
  Millions 
 AA$21
 $21
 
 A+73
 110
 
 BBB+ - BBB-316
 316
 
 B-165
 299
 
 CCC133
 —
 
 Not Rated16
 17
 
 Total$724
 $763
 
      

      
  
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating (Standard & Poor's (S&P))As of As of 
 As of March 31, 2013March 31, 2013 December 31, 2012
 
  Millions 
 AA$20
 $21
 
 AA-58
 73
 
 BBB+ - BBB-316
 316
 
 B166
 166
 
 D134
 134
 
 Not Rated11
 11
 
 Total$705
 $721
 
      
The “B-”“B” and “CCC”"D" ratings above represent lease receivables related to coal-fired assets in Pennsylvania and Illinois, and Pennsylvania.respectively. As of September 30, 2012March 31, 2013, the gross investment in the leases of such assets, net of non-recourse debt, was $555560 million ($4030 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the table below.

                
 AssetLocation 
Gross
Investment
 
%
Owned
 Total 
Fuel
Type
 
Counter-parties’
S&P Credit
Ratings
 Counterparty 
    Millions   MW       
 Powerton Station Units 5 and 6IL $134
 64% 1,538
 Coal D(A)Edison Mission Energy 
 Joliet Station Units 7 and 8IL $84
 64% 1,044
 Coal D(A)Edison Mission Energy 
 Keystone Station Units 1 and 2PA $116
 17% 1,711
 Coal B GenOn REMA, LLC 
 Conemaugh Station Units 1 and 2PA $116
 17% 1,711
 Coal B GenOn REMA, LLC 
 Shawville Station Units 1, 2, 3 and 4PA $110
 100% 603
 Coal B GenOn REMA, LLC 
                
(A) On April 9, 2013, S&P withdrew its credit rating.
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, 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 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.
Of facilities under lease by indirect subsidiary companies of Energy Holdings to GenOn REMA, LLC (GenOn REMA), a subsidiary of GenOn Energy Inc. (GenOn), which was acquired by NRG Energy, Inc. in December 2012, Keystone has installed flue gas desulfurization control for sulfur dioxide (SO2), selective catalytic reduction (SCR) equipment for nitrogen oxide (NOx) and mercury control to meet current environmental requirements. Conemaugh has flue gas desulfurization control, while SCR and mercury control are scheduled to be installed and operational in the first quarter of 2015. GenOn has disclosed its plan for the coal-fired units at the Shawville facility to place them in a “long-term protective layup” by April 2015 while continuing to pay the required rent and maintaining the facility in accordance with the lease terms or terminating the lease for

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


                
 AssetLocation 
Gross
Investment
 
%
Owned
 Total 
Fuel
Type
 
Counterparties’
S&P Credit
Ratings
 Counterparty 
    Millions   MW       
 Powerton Station Units 5 and 6IL $134
 64% 1,538
 Coal CCC Edison Mission Energy 
 Joliet Station Units 7 and 8IL $84
 64% 1,044
 Coal CCC Edison Mission Energy 
 Keystone Station Units 1 and 2PA $114
 17% 1,711
 Coal B-   GenOn REMA, LLC 
 Conemaugh Station Units 1 and 2PA $114
 17% 1,711
 Coal B-   GenOn REMA, LLC 
 Shawville Station Units 1, 2, 3 and 4PA $109
 100% 603
 Coal B-   GenOn REMA, LLC 
                

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 and electricity, overall financial condition of lease counterparties and the quality and condition of assets under lease.
Of facilities under lease by indirect subsidiary companies of Energy Holdings to GenOn REMA, LLC (GenOn REMA), a subsidiary of GenOn Energy Inc (GenOn), Energy Holdings believes Keystone has adequate environmental controls installed. Conemaugh has flue gas desulfurization control. Selective catalytic reduction (SCR) equipment for nitrogen oxide (NOx) and mercury control are scheduled to be installed and operational at Conemaugh in the first quarter of 2015. GenOn’s plan for the coal-fired units at the Shawville facility is to place them in a “long-term protective layup” by April 2015; however, GenOn has indicated that it will continue paying the required rent and maintaining the facility in accordance with the lease terms. GenOn has further stated that the lessee is evaluating its options under the lease, including termination for obsolescence or continuing to keep the facility in “long-term protective layup.” In the event that the lessee is able to terminate for obsolescence, the lessee would be required, among other things, to pay the contractual termination value structured to recover Energy Holdings' indirect subsidiaries' lease investment as specified in the lease agreement. On July 22, 2012, GenOn announced that it has signed a definitive agreement to merge with NRG Energy, Inc. Energy Holdings is carefully monitoring these developments.
With respect to EdisonEnergy Mission Energy’sEnergy's (EME) Midwest Generation (MWG) leases on the Powerton and Joliet coal units in Illinois, the lesseeslessee, MWG, substantially completed investments in mercury removal (Activated Carbon Injection), low and NOx emission controls (low NOx burners and Selective Non-Catalytic Reduction systemssystems), and planplans to employ a dry sorbentinvest in SO2 emission controls (Dry Sorbent Injection (Trona) systemsystems). On April 4, 2013, MWG obtained approval from the Illinois Pollution Control Board to reduce sulfur.defer capital investments for up to two additional years to meet upcoming air emission compliance deadlines under Illinois law. Also, as previously disclosed, EME and these unitsMWG remain in litigation with the United StatesU.S. Environmental Protection Agency (EPA) and the State of Illinois regarding certain environmental matters; however,air emissions. EME has announced that the above actions should enable compliancedoes not anticipate a material change in this current approach in order to comply with pendingexisting federal and Illinois environmental rules. The federal district court has dismissed new source review claims in reference to Powerton and Joliet, but certain opacity claims remain active and under appeal by the EPA and the State of Illinois. The federal district court has stayed proceedings in connection with the opacity claims until the appeal is resolved. In its most recent quarterly report filed on July 31,
On December 17, 2012, EME’s parent, Edison International, reported that it will no longer provide financial support to EME; that Midwest Generation is largely dependent upon EME for its funding; and that, based upon current projections, EME will not be able to meet its debt obligation in June 2013. In addition, Edison International also reported that, if EME and Midwest Generation failed to restructure their obligations, EME and Midwest Generation may need to fileMWG filed for protectionrelief under Chapter 11 of the U.S. Bankruptcy Code,Code. Immediately prior to that filing, EME, MWG, Nesbitt Asset Recovery, LLC (Nesbitt) (an indirect, wholly owned subsidiary of Energy Holdings), and Associates Capital Investments, L.L.P. (Associates) (an affiliate of Citigroup, and, together with Nesbitt, the "Owner Participants"), as well as certain affiliated owner lessors and owner participants, 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 could havewas approved by the bankruptcy court, expired on April 5, 2013. In the absence of a forbearance agreement, the lease indenture trustee has the ability to accelerate or exercise other remedies with respect to the nonrecourse debt and, in June 2013, initiate foreclosure proceedings on the leased assets. Nesbitt is actively involved in the bankruptcy proceedings and is evaluating its options. In April 2013, MWG obtained an impactunopposed extension from the bankruptcy court to defer the deadline upon which it must assume or reject those leases, from April to July 2013, thereby providing it additional time to evaluate its position, including a potential restructuring. MWG did not make its scheduled $48 million rent payments on January 2, 2013 (which related to the prior six month period) on the Powerton and Joliet leases.
The credit exposure A partial $5 million payment for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. The leasing transactions include letters of credit, affiliate guarantees, or covenants that restrict the flow of dividendsperiod from the lessee to its parent. These covenants are designed to maintain cash reserves in the transaction entity for the benefitdate of the non-recourse lenders andpetition filing through January 2, 2013 was received in mid-February, pursuant to the lessor/equity participants in the event of a temporary market downturn or degradation in operating performance of the leased assets. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings could step into the lease directly to protect its investments. In the event of a default in any of the lease transactions, Energy Holdings' indirect subsidiary companies would exercise their rights and attempt to seek recovery of their investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee would likely delay any efforts on the part of the lessors to assert their rights upon default. Failure to recover adequate value could ultimately lead to a foreclosure on the lease by the lenders. If foreclosures were to

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(UNAUDITED)


occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities.
On December 13, 2011, indirect subsidiary companies of Energy Holdings and Dynegy reached a settlement agreement resolving disputes that had arisen between them with regard to Dynegy Holding’s (DH) rejection of the Dynegy leases. The settlement agreement resolved certain disputes regarding Energy Holdings' Dynegy leases, including claims under Tax Indemnity Agreements that indirect subsidiaries of Energy Holdings have with DH. The original terms of the settlement agreement includedforbearance agreement. The difference is a cash payment to Energy Holdings of $7.5 million, which was received on January 4, 2012, and an allowedlessor pre-petition bankruptcy claim, in Bankruptcy Court of $110 million against DH. On December 30, 2011,while rent for the effective date of the court order authorizing the Dynegy lease rejections, the leases no longer qualified for leveraged lease accounting treatment under GAAP. As a result, Energy Holdings wrote off the $264 million gross lease investment against the previously recorded reserve. The Energy Holdings' indirect subsidiary companies that are owners/lessors of the two plants ceased leveraged lease accounting and recorded the generation assets and related nonrecourse project debt on their balance sheets at their respective fair values (See Note 11. Fair Value Measurements).
On June 1, 2012, an amended and restated settlement agreement entered into by DH, Dynegy and their creditors (including indirect subsidiary companies of Energy Holdings) was approved by the Bankruptcy Court and became effective on June 5, 2012. As part of that settlement, the indirect subsidiary companies of Energy Holdings, DH and the creditors of DH agreed to commence a process to sell the Roseton and Danskammer facilities; the agreement allocates proceeds from the saleutilization of the facilities to pay DH’s creditors, including the lease bondholders, and grants the lease bondholders claims in agreed upon amounts against DH in its bankruptcy proceedings. The settlement agreement also includes an exchange of releases by various settling claimants, including parties to the leases with respect to claims arising outMWG during pendency of the leases. Concurrently with the entry into the settlement agreement, DH filedbankruptcy will likely be treated as an amended plan of reorganization, which was supported by the various settling claimants, providing that Energy Holdings and other unsecured creditors of DH would be paid claims partiallyadministrative expense in cash and partially in stock in a reorganized Dynegy that would emerge at the conclusion of the bankruptcy. On September 5, 2012, the Bankruptcy Court approved Dynegy’s plan of reorganization. On October 1, 2012, Dynegy emerged from bankruptcy and distributed cash and stock settlements to the claimants. The total recovery of Energy Holdings' indirect subsidiary companies from the Dynegy leases, including proceeds from the liquidation of Dynegy common stock, the aforementioned cash payment received in January 2012 and the recovery of professional fees of $5.2 million received in June 2012, was approximately $63 million, of which the remaining $49.9 million was recorded in Operating Revenues in the fourth quarter 2012.

Note 6. Available-for-Sale Securities
Nuclear Decommissioning Trust (NDT) Fund
Power maintains an external master nuclear decommissioning trust to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third-party investment advisers who operate under investment guidelines developed by Power.In September 2012, Power restructured a portion of its NDT Fund and realized gains of $59 million.  The investments were transitioned to new investment managers to remove under-performing managers. 













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(UNAUDITED)



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:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


          
  As of March 31, 2013 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$628
 $205
 $(4) $829
 
 Debt Securities        
 Government Obligations370
 9
 (1) 378
 
 Other Debt Securities309
 19
 (1) 327
 
 Total Debt Securities679
 28
 (2) 705
 
 Other Securities68
 —
 —
 68
 
 Total NDT Available-for-Sale Securities$1,375
 $233
 $(6) $1,602
 
          
          
  As of September 30, 2012 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$626
 $128
 $(5) $749
 
 Debt Securities        
 Government Obligations274
 14
 —
 288
 
 Other Debt Securities311
 22
 —
 333
 
 Total Debt Securities585
 36
 —
 621
 
 Other Securities131
 —
 —
 131
 
 Total NDT Available-for-Sale Securities$1,342
 $164
 $(5) $1,501
 
          

          
  As of December 31, 2011 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$582
 $126
 $(23) $685
 
 Debt Securities        
 Government Obligations343
 16
 —
 359
 
 Other Debt Securities268
 15
 (2) 281
 
 Total Debt Securities611
 31
 (2) 640
 
 Other Securities24
 —
 —
 24
 
 Total NDT Available-for-Sale Securities$1,217
 $157
 $(25) $1,349
 
          

          
  As of December 31, 2012 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$648
 $147
 $(6) $789
 
 Debt Securities        
 Government Obligations274
 11
 —
 285
 
 Other Debt Securities320
 22
 —
 342
 
 Total Debt Securities594
 33
 —
 627
 
 Other Securities124
 —
 —
 124
 
 Total NDT Available-for-Sale Securities$1,366
 $180
 $(6) $1,540
 
          
These amounts do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.

      
  As of As of 
  September 30,
2012		 December 31,
2011		 
  Millions 
 Accounts Receivable$61
 $27
 
 Accounts Payable$80
 $22
 
      





      
  As of As of 
  March 31,
2013		 December 31,
2012		 
  Millions 
 Accounts Receivable$51
 $18
 
 Accounts Payable$70
 $53
 
      


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

                  
  As of September 30, 2012 As of December 31, 2011 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Equity Securities (A)$215
 $(5) $—
 $—
 $183
 $(23) $—
 $—
 
 Debt Securities                
 Government Obligations (B)11
 —
 2
 —
 20
 —
 3
 —
 
 Other Debt Securities (C)7
 —
 3
 —
 56
 (1) 4
 (1) 
 Total Debt Securities18
 —
 5
 —
 76
 (1) 7
 (1) 
 Other Securities6
 —
 —
 —
 —
 —
 —
 —
 
 NDT Available-for-Sale Securities$239
 $(5) $5
 $—
 $259
 $(24) $7
 $(1) 
                  

                  
  As of March 31, 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)$67
 $(4) $—
 $—
 $139
 $(6) $—
 $—
 
 Debt Securities                
 Government Obligations (B)92
 (1) 1
 —
 34
 —
 1
 —
 
 Other Debt Securities (C)53
 (1) 1
 —
 31
 —
 6
 —
 
 Total Debt Securities145
 (2) 2
 —
 65
 —
 7
 —
 
 Other Securities—
 —
 —
 —
 —
 —
 —
 —
 
 NDT Available-for-Sale Securities$212
 $(6) $2
 $—
 $204
 $(6) $7
 $—
 
                  
(A)
Equity Securities—Represent investmentsInvestments in marketable equity securities within the NDT Fund are primarily in common stockstocks within a broad range of industries and sectors. The unrealized losses are distributed over two hundred companiesa broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of March 31, 2013.
(B)
Debt Securities (Government)—Unrealized losses on Power’s NDT investments in United States Treasury obligations and Federal Agency mortgage-backedasset-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.basis, since Power does not intend to sell nor will it be more-likely-than-not required to sellsell. Power does not consider these securities.securities to be other-than-temporarily impaired as of March 31, 2013.
(C)
Debt Securities (Corporate)—RepresentPower’s investments in corporate bonds are limited to investment grade corporate bonds which aresecurities. It is not expected tothat 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 securities.debt securities to be other-than-temporarily impaired as of March 31, 2013.
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, 
  2012 2011 2012 2011 
  Millions 
 Proceeds from NDT Fund Sales$617
 $431
 $1,252
 $1,088
 
 Net Realized Gains (Losses) on NDT Fund:        
 Gross Realized Gains$94
 $26
 $136
 $121
 
 Gross Realized Losses(19) (10) (41) (28) 
 Net Realized Gains (Losses) on NDT Fund$75
 $16
 $95
 $93
 
          

      
  Three Months Ended 
  March 31, 
  2013 2012 
  Millions 
 Proceeds from NDT Fund Sales$241
 $345
 
 Net Realized Gains (Losses) on NDT Fund:    
 Gross Realized Gains$37
 $16
 
 Gross Realized Losses(19) (6) 
 Net Realized Gains (Losses) on NDT Fund$18
 $10
 
      
Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $77111 million (after-tax) were recognized ina component of Accumulated Other Comprehensive Loss on Power’s Condensed Consolidated Balance Sheet as of September 30, 2012March 31, 2013.



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(UNAUDITED)


The NDT available-for-sale debt securities held as of September 30, 2012March 31, 2013 had the following maturities:

    
 Time FrameFair Value 
  Millions 
 Less than one year$21
 
 1 - 5 years129
 
 6 - 10 years173
 
 11 - 15 years38
 
 16 - 20 years9
 
 Over 20 years251
 
 Total NDT Available-for-Sale Debt Securities$621
 
    

    
 Time FrameFair Value 
  Millions 
 Less than one year$65
 
 1 - 5 years144
 
 6 - 10 years183
 
 11 - 15 years47
 
 16 - 20 years11
 
 Over 20 years255
 
 Total NDT Available-for-Sale Debt Securities$705
 
    
The cost of these securities was determined on the basis of specific identification.
Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2012,2013, other-than-temporary impairments of $142 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
Rabbi Trust
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as the “Rabbi Trust.” In March 2012, PSEG restructured the fixed income component of the Rabbi Trust.
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 September 30, 2012 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$13
 $4
 $—
 $17
 
 Debt Securities        
 Government Obligations113
 3
 —
 116
 
 Other Debt Securities45
 2
 —
 47
 
 Total Debt Securities158
 5
 —
 163
 
 Other Securities3
 —
 —
 3
 
 Total Rabbi Trust Available-for-Sale Securities$174
 $9
 $—
 $183
 
          

         
  As of March 31, 2013 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$13
 $6
 $—
 $19
 
 Debt Securities        
 Government Obligations113
 2
 —
 115
 
 Other Debt Securities46
 1
 —
 47
 
 Total Debt Securities159
 3
 —
 162
 
 Other Securities15
 —
 —
 15
 
 Total Rabbi Trust Available-for-Sale Securities$187
 $9
 $—
 $196
 
          


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(UNAUDITED)


          
  As of December 31, 2011 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$16
 $3
 $—
 $19
 
 Debt Securities148
 5
 —
 153
 
 Total Rabbi Trust Available-for-Sale Securities$164
 $8
 $—
 $172
 
          


         
  As of December 31, 2012 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$13
 $5
 $—
 $18
 
 Debt Securities        
 Government Obligations114
 3
 —
 117
 
 Other Debt Securities45
 2
 —
 47
 
 Total Debt Securities159
 5
 —
 164
 
 Other Securities3
 —
 —
 3
 
 Total Rabbi Trust Available-for-Sale Securities$175
 $10
 $—
 $185
 
          
As of September 30, 2012March 31, 2013, amounts in the above table do not include Accounts Receivable of $47 million and Accounts Payable of $56 million for Rabbi Trust Fund transactions which had not yet settled. These amounts are included on the Condensed Consolidated Balance Sheets.

In March 2012, PSEG restructured the fixed income component of the Rabbi Trust. 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, 
  2012 2011 2012 2011 
  Millions 
 Proceeds from Rabbi Trust Sales$6
 $—
 $221
 $—
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$—
 $—
 $6
 $—
 
 Gross Realized Losses—
 —
 —
 —
 
 Net Realized Gains (Losses) on Rabbi Trust$—
 $—
 $6
 $—
 
          

      
  Three Months Ended 
  March 31, 
  2013 2012 
  Millions 
 Proceeds from Rabbi Trust Sales$17
 $154
 
 Net Realized Gains (Losses) on Rabbi Trust:    
 Gross Realized Gains$—
 $5
 
 Gross Realized Losses—
 —
 
 Net Realized Gains (Losses) on Rabbi Trust$—
 $5
 
      
Gross realized gains disclosed in the above table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of $56 million (after-tax) were recognized ina component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of September 30, 2012March 31, 2013. The Rabbi Trust available-for-sale debt securities held as of September 30, 2012March 31, 2013 had the following maturities:

    
 Time FrameFair Value 
  Millions 
 Less than one year$—
 
 1 - 5 years58
 
 6 - 10 years31
 
 11 - 15 years10
 
 16 - 20 years5
 
 Over 20 years59
 
 Total Rabbi Trust Available-for-Sale Debt Securities$163
 
    

    
 Time FrameFair Value 
  Millions 
 Less than one year$—
 
 1 - 5 years61
 
 6 - 10 years29
 
 11 - 15 years10
 
 16 - 20 years5
 
 Over 20 years57
 
 Total Rabbi Trust Available-for-Sale Debt Securities$162
 
    
The cost of these securities was determined on the basis of specific identification.


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(UNAUDITED)


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.

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(UNAUDITED)


In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

The 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,
2012		 December 31,
2011		 
  Millions 
 Power$36
 $33
 
 PSE&G61
 57
 
 Other86
 82
 
 Total Rabbi Trust Available-for-Sale Securities$183
 $172
 
      
      
  As of As of 
  March 31,
2013		 December 31,
2012		 
  Millions 
 Power$38
 $36
 
 PSE&G61
 61
 
 Other97
 88
 
 Total Rabbi Trust Available-for-Sale Securities$196
 $185
 
      


Note 7. Pension and OPEB
PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis.
Pension and OPEB costs for PSEG are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. Federal health care legislation enacted in March 2010 eliminates the tax deductibility of retiree health care costs beginning in 2013, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. See Note 13. Income Taxes for additional information.detailed as follows:
          
  Pension Benefits OPEB 
  Three Months Ended Three Months Ended 
  March 31, March 31, 
  2013 2012 2013 2012 
  Millions 
 Components of Net Periodic Benefit Cost        
 Service Cost$29
 $25
 $5
 $4
 
 Interest Cost54
 56
 16
 16
 
 Expected Return on Plan Assets(87) (76) (5) (4) 
 Amortization of Net        
 Transition Obligation—
 —
 —
 1
 
 Prior Service Cost (Credit)(5) (5) (4) (4) 
 Actuarial Loss47
 42
 11
 8
 
 Net Periodic Benefit Cost$38
 $42
 $23
 $21
 
 Effect of Regulatory Asset—
 —
 —
 5
 
 Total Benefit Costs, Including Effect of Regulatory Asset$38
 $42
 $23
 $26
 
          


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Pension and OPEB costs for PSEG 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, 
  2012 2011 2012 2011 2012 2011 2012 2011 
  Millions 
 Components of Net Periodic Benefit Cost                
 Service Cost$26
 $22
 $5
 $3
 $76
 $69
 $13
 $10
 
 Interest Cost56
 56
 17
 15
 167
 172
 49
 45
 
 Expected Return on Plan Assets(76) (85) (4) (5) (229) (248) (13) (13) 
 Amortization of Net                
 Transition Obligation—
 —
 1
 1
 —
 —
 2
 4
 
 Prior Service Cost (Credit)(5) (4) (4) (4) (14) (6) (11) (10) 
 Actuarial Loss41
 29
 7
 4
 125
 89
 23
 11
 
 Net Periodic Benefit Cost$42
 $18
 $22
 $14
 $125
 $76
 $63
 $47
 
 Special Termination Benefits1
 0
 0
 0
 1
 0
 0
 0
 
 Effect of Regulatory Asset—
 —
 4
 5
 —
 —
 14
 15
 
 Total Benefit Costs, Including Effect of Regulatory Asset$43
 $18
 $26
 $19
 $126
 $76
 $77
 $62
 
                  

Pension and OPEB costs for Power, PSE&G and PSEG’s other subsidiaries 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, 
  2012 2011 2012 2011 2012 2011 2012 2011 
  Millions 
 Power$14
 $6
 $5
 $3
 $39
 $24
 $14
 $9
 
 PSE&G24
 9
 21
 16
 73
 41
 61
 51
 
 Other5
 3
 —
 —
 14
 11
 2
 2
 
 Total Benefit Costs$43
 $18
 $26
 $19
 $126
 $76
 $77
 $62
 
                  
          
  Pension Benefits OPEB 
  Three Months Ended Three Months Ended 
  March 31, March 31, 
  2013 2012 2013 2012 
  Millions 
 Power$11
 $13
 $6
 $5
 
 PSE&G23
 24
 16
 20
 
 Other4
 5
 1
 1
 
 Total Benefit Costs$38
 $42
 $23
 $26
 
          

During the three months ended March 31, 2012,2013, PSEG contributed its entire planned contributioncontributions for the year 20122013 of $124145 million and $1114 million into its pension and postretirement healthcare plans, respectively.


Note 8. Commitments and Contingent Liabilities
Guaranteed Obligations
Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical,

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financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.
Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to
support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
obtain credit.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to
fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and
all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).
Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Power is subject to
counterparty collateral calls related to commodity contracts, and
certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.

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The face value of Power's outstanding guarantees, current exposure and margin positions as of September 30, 2012March 31, 2013 and December 31, 20112012 are shown below:
      
  As of As of 
  September 30,
2012		 December 31,
2011		 
  Millions 
 Face Value of Outstanding Guarantees$1,514
 $1,756
 
 Exposure under Current Guarantees$214
 $315
 
 Letters of Credit Margin Posted$178
 $135
 
 Letters of Credit Margin Received$109
 $91
 
 Cash Deposited and Received    
 Counterparty Cash Margin Deposited$19
 $20
 
 Counterparty Cash Margin Received(3) (7) 
 Net Broker Balance Deposited (Received)12
 (92) 
 In the Event Power were to Lose its Investment Grade Rating:    
 Additional Collateral that could be Required$610
 $812
 
 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral$3,429
 $3,415
 
 Additional Amounts Posted    
 Other Letters of Credit$45
 $52
 
      
      
  As of As of 
  March 31,
2013		 December 31,
2012		 
  Millions 
 Face Value of Outstanding Guarantees$1,564
 $1,508
 
 Exposure under Current Guarantees$259
 $226
 
 Letters of Credit Margin Posted$119
 $124
 
 Letters of Credit Margin Received$61
 $69
 
 Cash Deposited and Received    
 Counterparty Cash Margin Deposited$6
 $15
 
 Counterparty Cash Margin Received(1) (4) 
 Net Broker Balance Deposited (Received)149
 26
 
 In the Event Power were to Lose its Investment Grade Rating:    
 Additional Collateral that Could be Required$675
 $654
 
 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral$3,536
 $3,531
 
 Additional Amounts Posted    
 Other Letters of Credit$45
 $45
 
      

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. In accordance with PSEG's accounting

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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 twothree level downgrade from its current S&P ratings or a three level downgrade from its current&P's, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.
In addition, during 2012, theThe SEC and the Commodity Futures Trading Commission (CFTC) are continuingcontinue efforts to implement new rules to enact stricter regulation over swaps and derivatives. TheIn 2012, the CFTC has issued Final Rules regarding the definition of a swap dealer and the definition of a swap. However, inswap, and established reporting and record-keeping requirements for commercial end users including PSEG. In September 2012, a federal court vacated the CFTC's rule on monitoring of position limits for several commodities, including natural gas, thereby indefinitely delaying the effectiveness of these position limits rules. PSEG is carefully monitoring all of these new rules as they are issued to analyze the potential impact on its swap and derivatives transactions, including any potential increase in its collateral requirements.
In addition to amounts for outstanding guarantees, current exposure and margin positions, Power had posted letters of credit to support various other non-energy contractual and environmental obligations. See table above.
Environmental Matters
Passaic River
Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by federalFederal and stateState agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex.
Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)
The EPA has determined that an eight-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under CERCLA. The EPA has determined the need to perform a study of the entire 17-mile tidal reach of the lower Passaic River.

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PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.
The EPA believes that certain hazardous substances were released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its Remedial Investigation and Feasibility Study (RI/FS) would greatly exceed the original estimated cost of $20 million. The total cost of the RI/FS is now estimated at approximately $110 million. 73Seventy-three PRPs, including Power and PSE&G, agreed to assume responsibility for the 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 70 members, is presently executing the RI/FS. Approximately five percent of the RI/FS costs are attributable to PSE&G’s former MGP sites and approximately one percent percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim.
In 2007, the EPA released a draft “Focused Feasibility Study” (FFS) that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The EPA estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the FFS is not subject to the cost sharing agreement discussed above. The EPA is conducting aEPA's revised proposed FFS which may be released for public comment as early as the fourthsecond quarter of 2012.2013.
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. ThatPhase I of the removal work has been completed. Phase II is underway.contingent on the approval of an appropriate sediment disposal facility. Tierra/Maxus have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.
The EPA has advised that the levels of contaminants at Passaic River mile 10.9 will require removal in advance of the completion of the RI/FS or the issuance of a revised draft FFS.FS. The CPG members, with the exception of Tierra/Maxus, which are no longer members, of the CPG, have agreed to fund the removal, currently estimated at approximately $30 million. PSEG’s share of that effort is approximately three percent.
Except for the Passaic River 10.9 mile removal, Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to the Passaic River matters.

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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 discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed hazardous substances to a total of 11 sites or facilities that impacted these water bodies. In February 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances it allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaints in June 2010. A special master for discovery has been appointed by the court and document production has commenced. In October 2012, the Court issued a 90 day stay of discovery for the third-partythird party defendants to explore a possible settlement of this matter with the State of New Jersey. That settlement effort is ongoing. On March 22, 2013, Power and PSE&G signed an agreement to settle the NJDEP vs. OCC litigation at a nominal cost. That settlement is contingent upon a public comment and NJDEP response period that will extend for at least 120 days and the issuance of an order approving the settlement by the Court after conducting a fairness hearing. The 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 the third party complaints and will vigorously assert those defenses. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.
Natural Resource Damage Claims
In 2003, the NJDEP directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the Spill Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural

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resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&GPSEG is unable to estimate its portion of the possible loss or range of loss related to this matter.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC)OCC to discuss participating in the Remedial Investigation/Feasibility StudyRI/FS that OCC was conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but it is uncertain at this time whether the PSEG companies will consent to fund the third phase. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.
MGP Remediation Program
PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $610513 million and $697649 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $610513 million as of September 30, 2012March 31, 2013. Of this amount, $107111 million was recorded in Other Current Liabilities and $503402 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $610513 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 to $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,

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alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the Clean Air Act.CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air ActCAA 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 United StatesU.S. Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation on 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 Clean Air Act.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 Court of Appeals in support of the EPA's implementation of MATS. The CourtLitigation of Appeals has split the litigation related to these matters into three cases, addressing separately the existing source NESHAP, new source NESHAPremains pending and the NSPS.  These cases remain pending. The EPA has stayedimpact on the implementation of the new source NESHAP rule pending its reconsideration until November 2, 2012.schedule is unknown at this time.
Power believes that the back-end technology environmental controls recently installed at its Hudson and Mercer coal facilities will meet the rule’s requirements. Power also believes that it will not be necessary to install any additional material controls at its other New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulators, a decision was reached to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal-fired generating facility at Conemaugh

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in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. Power's share of this investment is approximately $147 million.
New Jersey regulations required coal-fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012.
With newly installed controls at its plants in New Jersey, Power has achieved the required mercury reductions that are part of Power’s multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.
Nitrogen Oxide (NOx)NOx Regulation
In April 2009, the NJDEP finalized revisions to NOxemission control regulations that impose new NOxemission reduction requirements and limits for New Jersey fossil fuel-fired electric generatinggeneration units. The rule will have a significanthas an impact on Power’s generation fleet, as it imposes NOx emissions limits that will require significant capital investment for controls or the retirement of up to 10286combustion turbines (approximately 2,0001,750MW) and fourolder New Jersey steam electric generatinggeneration units (approximately 400 MW) by May 30, 2015. Power is currently evaluating its compliance options.Retirement notifications for the combustion turbines, except for Salem Unit 3, have been filed with the PJM Interconnection, LLC (PJM). The Salem Unit 3 combustion turbine (38 MW) will be transitioning to an emergency generator. Evaluations are ongoing for the steam electric generation units.
Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that were incorporated into the facilities’ operating permits. In 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.
Cross-State Air Pollution Rule (CSAPR)
In July 2011, the EPA issued the Cross-State Air Pollution Rule (CSAPR) that limits power plant emissions in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards. In August 2012, the Court of Appeals vacated CSAPR and ordered that the Clean Air Interstate Rule (CAIR) requirements remain in effect until an appropriate substitute rule has been promulgated. On October 5, 2012, the EPA filed a request for rehearing with the court with the support from several states, cities, environmental groups and industry. The matter remains pending.
The continuation of CAIR affects Power's generating stations in Connecticut, New Jersey and New York. The purpose of CAIR is to improve Ozone and Fine Particulate (PM2.5) air quality within states that have not demonstrated achievement of the National Ambient Air Quality Standards (NAAQS). CAIR was implemented through a cap-and-trade program and to date the

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impact has not been material to Power as the allowances allocated to its stations were sufficient. If 2012 operations are similar to those in the past three years, it is expected that the impact to operations from the implementation of CAIR in 2012 will not be significant.
Clean Water Act Permit Renewals
Pursuant to the Federal Water Pollution Control Act (FWPCA), New JerseyNational Pollutant Discharge Elimination System (NJPDES)(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 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. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.
As a result of several legal challenges to the 2004 316(b) rule by certain northeast states, environmentalists and industry groups, the rule has been suspended and has been returned to the EPA to be consistent with a 2009 United States Supreme Court decision which concluded that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations.
In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012. In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power’s electric generating stations would be affected. In June 2012, the EPA posted a Noticetwo Notices of Data Availability (NODA) requesting comment on a series of technical issues related to the impingement mortality proposed standards. In June 2012, the EPA also posted a second NODA outlining its plans to finalize a “Willingness to Pay” survey it initiated to develop non-use benefits data in supportaspects of the April 2011 rule proposal.proposed rule. In July 2012, PSEG and industry trade associations submitted comments on both NODAs and the EPA and environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.
Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition, results of operations or cash flows. The results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Power’s share would have been approximately $575 million. These cost estimates have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.
Power has received a preliminary draft of the Delaware River Basin Commission (DRBC) water discharge permit that would revise Mercer Generating Station's thermal discharge limits and require compliance within five years of approval. Power is reviewing the proposed revisions with NJDEP and DRBC staff. Power cannot at this time determine the final form of the permit that will be presented to the DRBC commissioners for approval and what, if any, impact this permit would have on Mercer's operations.
New Generation and Development
Nuclear
Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-

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owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed in October 2011. Unit 2 upgrades were completed in October 2012. The balance of work to ensure efficient operations will be completed in 2013 and 2014, respectively. Total expenditures through September 30, 2012 were $138 million.Capital Expenditures
Power has also approved the expenditure of $419 million for an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to result in an increase in Power’s share of nominal capacity by approximately 130 MW. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Total expenditures through September 30, 2012 were $56 million.
Connecticut
Power was selected by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control, in a regulatory process to build 130 MW of gas-fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project was placed in service in June 2012. Power’s total capitalized expenditures for these generating units, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheetsprograms of PSEG and Power,its subsidiaries are approximately $150 million as of September 30, 2012 (not including the capitalized costcurrently estimated to finance during construction).
PJM Interconnection L.L.C. (PJM)
In June 2012, Power completed construction and placed in service new 267 MW gas-fired peaking facilities at its Kearny site. Power’sinclude a base level total capitalized expenditures for these generating units, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power, are approximately $247 million as of September 30, 2012.
PSE&G—Solar
As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G estimates the total cost of this project to be $249 million. Approximately 33 MW have been installed as of September 30, 2012. PSE&G’s cumulative investments for these solar units were approximately $232 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available.
Another aspect of the Solar 4 All program is the installation of 40 MW of solar systems on land and buildings owned by PSE&G and third parties. PSE&G estimates the total cost of this phase of the program to be $194 million. Through September 30, 2012, 38 MW representing 22 projects had been placed into service with an investment of approximately $1906.1 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 2,040
 1,680
 1,180
 
 Other 95
 40
 30
 
 Total PSEG $2,535
 $2,085
 $1,515
 
         
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.
Power
During the three months ended March 31, 2013, Power made $102 million. of capital expenditures, including interest capitalized during construction (IDC) but excluding $41 million for nuclear fuel, primarily related to various projects at its fossil and nuclear generation stations.
PSE&G
During the three months ended March 31, 2013, PSE&G made $583 million of capital expenditures, including $572 million of investment in plant, primarily for reliability of transmission and distribution systems and $11 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $24 million, which is included in operating cash flows.
Energy Holdings—SolarHoldings
In September 2012, Energy Holdings acquiredIncluded in Other for 2013 in the preceding table is a 15 MW19MW solar project currently under construction in Delaware. Energy Holdings expects to complete construction of this project in the first quarter of 2013. Energy Holdings issued guarantees of up to $37 millionArizona for payment of obligations related to the construction of the project, all of which were outstanding as of September 30, 2012. The total investment for the project is expected to be approximately $47 million.
In October 2012, Energy Holdings began commercial operation of its newly constructed 25 MW solar project in Arizona. Energy Holdings had issued guaranteesan outstanding guarantee of up to $7241 million for payment of obligations related to the construction of the project, of which $17 million was outstanding as of September 30, 2012. The total investment for the project was approximately $75 million.March 31, 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.

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

           
  Auction Year  
  2009 2010 2011 2012  
 36-Month Terms EndingMay 2012
 May 2013
 May 2014
 May 2015
(A)  
 Load (MW)2,900
 2,800
 2,800
 2,900
   
 $ per kWh0.10372
 0.09577
 0.09430
 0.08388
   
           
           
  Auction Year  
  2010 2011 2012 2013  
 36-Month Terms EndingMay 2013
 May 2014
 May 2015
 May 2016
(A)  
 Load (MW)2,800
 2,800
 2,900
 2,800
   
 $ per kWh0.09577
 0.09430
 0.08388
 0.09218
   
           
(A)Prices set in the 20122013 BGS auction becamewill become effective on June 1, 20122013 when the 20092010 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. For additional information, see Note 17. Related-Party Transactions. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 17. Related-Party Transactions.
Minimum Fuel Purchase Requirements
Power has various long-term fuel purchase commitments for coal through 20162017 to support its fossil generation stations and for supply of nuclear fuel for the Salem, and Hope Creek and Peach Bottom nuclear generating stations and for firm transportation and storage capacity for natural gas.
Power’s strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to belowin 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 and a portion for 2016through 2017 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.
As of September 30, 2012March 31, 2013, the total minimum purchase requirements included in these commitments were as follows:
    
 Fuel Type
Power’s Share of
Commitments
through 2016
 
  Millions 
 Nuclear Fuel  
 Uranium$452
 
 Enrichment$445
 
 Fabrication$145
 
 Natural Gas$876
 
 Coal$533
 
    

Regulatory Proceedings
Electric Discount and Energy Competition Act (Competition Act)
In 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. The Superior Court subsequently granted PSE&G’s motion to dismiss the Complaint, which dismissal was upheld by the Appellate Division.
In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of
    
 Fuel Type
Power’s Share of
Commitments
through 2017
 
  Millions 
 Nuclear Fuel  
 Uranium$483
 
 Enrichment$444
 
 Fabrication$145
 
 Natural Gas$1,035
 
 Coal$508
 
    

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the same stranded cost charges. In June 2010, the BPU granted PSE&G’s motion to dismiss, and the plaintiff/petitioner subsequently appealed this dismissal to the Appellate Division. In June 2012, the Appellate Division affirmed the BPU’s decision, concluding that the BPU had correctly found that the plaintiff’s claims failed as a matter of law. The petitioner has filed a Notice of Petition for Certification with the New Jersey Supreme Court.
Regulatory Proceedings
New Jersey Clean Energy Program
In 2008, the BPU approved funding requirements for each New Jersey EDC applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. In late 2012, the BPU approved additional funding requirements for these programs for the first half of 2013. The aggregate funding amountfor the first half of 2013 is $1.2 billion for all years. PSE&G’s share is $705195 million. PSE&G has recorded a current liability of $8992 million as of September 30, 2012March 31, 2013. for its outstanding share of the 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 expected to be recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).
The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. The proceeding has no impact on current SBC assessments.
Long-Term Capacity Agreement Pilot Program (LCAPP)
In 2011, New Jersey enacted the LCAPP Act that resulted in the selection of three generators to build a total of approximately 2,000 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the three selected generators, but did so under protest preserving their legal rights. The SOCA provides for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement. Legal challenges to the BPU’s implementation of the LCAPP Act were filed in New Jersey appellate court and the challenge filed by the EDCs has been remanded back to the BPU for consideration of certain procedural issues.this appeal is pending. In addition, the LCAPP Act itself has been challenged on constitutional grounds in federal court. On September 28, 2012, the federal court denied all motions for summary judgment. All issues in this litigation will now be scheduled for hearing.and that proceeding is ongoing.
In May 2012, two of the three generators cleared the Reliability Pricing Model auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300MW of installed capacity. SOCA payments are for a 15 year-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. Based upon the expected percentage of state load that PSE&G will be serving during the term of these contracts, PSE&G would be responsible for approximately 52% or 676 MW of this amount.
UnderThe current accounting guidance, the estimated fair value of the SOCAs is recorded as a Derivative Asset or Liability with an offsetting Regulatory Asset or Liability on PSE&G’s Condensed Consolidated Balance Sheets. See Note 11. Fair Value Measurements for additional information.
Superstorm Sandy
In late October 2012, Superstorm Sandy caused severe damage to PSE&G's transmission and distribution system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds resulted in a storm surge that caused damage to switching stations, substations and generating infrastructure.
Power incurred an additional $28 million of storm-related expense for the three months ended March 31, 2013, primarily for repairs at certain generating stations in Power's fossil fleet. These costs were recognized in Operation and Maintenance Expense. Power expects it will incur additional future costs, primarily relating to repairs to, and replacement of, equipment and property, which could be material.
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 received $25 million from its insurance carriers as an advance payment which was recorded in the fourth quarter of 2012. PSEG believes that additional insurance recoveries are not estimable as of March 31, 2013. PSEG is documenting its insurance claim which then will need to be submitted to and reviewed by its insurers. PSEG does not believe that it has a basis for estimating additional probable insurance recoveries at this time.

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Leveraged Lease Investments
On January 31, 2012, PSEG entered into a specific matter closing agreement settling the dispute with the IRS over previously challenged leveragedInternal Revenue Service (IRS) settling all matters related to cross border lease transactions. This agreement settlessettled the leasing dispute with finality for all tax periods in which PSEG realized tax deductions from these transactions. On January 31, 2012, PSEG also signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements concludeconcluded ten years of audits for PSEG and the leasing issue for all tax years. For PSEG, the impact of these agreements iswas 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 $245246 million with respect to these tax years. Accordingly, the settlement resulted in a net $7071 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 for tax years from 2004 through 2006. Based on the settlement of the leasing dispute, for tax years 2007 through 2010, the IRS owes PSEG approximately $676 million. It is possible that PSEG wouldhas filed amended returns for tax years 2007-2010 reflecting the impact of the settlement. These returns have to pay $620 million over the next year tobeen audited by the IRS and file claims for refunds for $676 million whichaccepted as filed. As required by statute, the IRS would process inpresented the normal course; it could take several yearsrefund claim to the Joint Committee on Taxation for approval. On October 16, 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 process these claims.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 will claim a tax deduction for the accrued deficiency interest associated with this settlement in 2012, which will givegives rise to a cash tax savings of approximately $100 million.

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Note 9. Changes in Capitalization
The following capital transactions occurred in the first ninefirstthree months of 2012:
Power
paid $66 million of 5.00%2013 Pollution Control Revenue Refunding bond at maturity, and:
Power
paid cash dividends of $600250 million to PSEG.
PSE&G
paid $300150 million of 5.13%5.00% Secured Medium-Term Notes at maturity,
issued $350400 million of 3.65%3.80% Secured Medium-Term Notes, Series H due September 2042January 2043,
refinanced at parreceived $50100 million of 5.45% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due February 1, 2032, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor, with $50 million of weekly-reset variable rate demand bonds due April 1, 2046, which are serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor,
redeemed and retired at par $23 million of 5.20% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due March 1, 2025, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor,
issued $450 million of 3.95% Secured Medium-Term Notes, Series H due May 2042,
paid $149 million of Transition Funding’s securitization debt,capital contribution from PSEG, and
paid $551 million of Transition Funding II’sFunding’s securitization debt.

Energy Holdings
was released fromreclassified $5018 million of nonrecourse projectnon-recourse long-term debt relatedassociated with a commercial real estate property held for sale to the Dynegy Leases.Other Current Liabilities. For additional information, see Note 11. Fair Value Measurements.


Note 10. Financial Risk Management Activities
The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions.

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Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Commodity Prices
The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power uses physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Derivative contracts that do not qualify for hedge accounting or normal purchases/normal sales treatment are marked to market (MTM) with changes in fair value recorded in the income statement. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists.
Cash Flow Hedges
Power uses forward sale and purchase contracts, swaps and futures contracts to hedge
forecasted energy sales from its generation stations and the related load obligations,
the price of fuel to meet its fuel purchase requirements, and
certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G.
TheseCertain of these derivative transactions are designated and effective as cash flow hedges. During the second quarter of 2012, Power de-designated certain of its commodity derivative transactions that had previously qualified as cash flow hedges as they were deemed to no longer be highly effective as required by the relevant accounting guidance. As a result, subsequent to June 1, 2012, Power recognizes all gains and losses from changes in the fair value of these derivatives immediately in earnings rather than deferring any such amounts in Accumulated Other Comprehensive Income (Loss). The fair values of Power’s de-designated hedges were frozen in Accumulated Other Comprehensive Income (Loss) as the original forecasted transactions are still expected to occur and are reclassified into earnings as the original derivative transactions settle.

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As of September 30, 2012March 31, 2013 and December 31, 20112012, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows:
      
  As of As of 
  September 30,
2012		 December 31,
2011		 
  Millions 
 Fair Value of Cash Flow Hedges$—
 $57
 
 Impact on Accumulated Other Comprehensive Income (Loss) (after tax)$13
 $33
 
      
      
  As of As of 
  March 31,
2013		 December 31,
2012		 
  Millions 
 Fair Value of Cash Flow Hedges$—
 $3
 
 Impact on Accumulated Other Comprehensive Income (Loss) (after tax)$5
 $9
 
      

The expiration date of the longest-dated cash flow hedge at Power is in 2014.2014. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $104 million. There was no ineffectiveness associated with qualifying hedges as of September 30, 2012March 31, 2013.
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 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.

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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 8. Commitments and Contingent Liabilities, PSE&G was directed to execute long-term SOCAs with certain generators to support the LCAPP Act. These contracts qualify as derivatives and are marked to fair 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, 2012March 31, 2013, PSEG had eight7 interest rate swaps outstanding totaling $1.1 billion850 million. These swaps convert Power’s $250 million of 5% Senior Notes due April 2014, Power’s $300 million of 5.5% Senior Notes due December 2015, $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of September 30, 2012March 31, 2013 and December 31, 20112012, the fair value of all the underlying hedges was $7052 million and $6257 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 $(2) million as of September 30, 2012March 31, 2013 and December 31, 20112012.



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Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets: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 our 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 Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables.







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  As of March 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$—
 $356
 $(304) $52
 $10
 $15
 $77
 
 Noncurrent Assets—
 50
 (44) 6
 59
 37
 102
 
 Total Mark-to-Market Derivative Assets$—
 $406
 $(348) $58
 $69
 $52
 $179
 
 Derivative Contracts              
 Current Liabilities$—
 $(343) $316
 $(27) $—
 $—
 $(27) 
 Noncurrent Liabilities—
 (72) 58
 (14) (109) —
 (123) 
 Total Mark-to-Market Derivative (Liabilities)$—
 $(415) $374
 $(41) $(109) $—
 $(150) 
 Total Net Mark-to-Market Derivative Assets (Liabilities)$—
 $(9) $26
 $17
 $(40) $52
 $29
 
                
                
  As of September 30, 2012 
  Power PSE&G PSEG Consolidated 
  
Cash Flow
Hedges
 
Non
Hedges
     
Non
Hedges
 
Fair Value
Hedges
   
 Balance Sheet Location
Energy-
Related
Contracts
 
Energy-
Related
Contracts
 
Netting
(A)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
  Millions 
 Derivative Contracts              
 Current Assets$3
 $354
 $(255) $102
 $3
 $18
 $123
 
 Noncurrent Assets—
 81
 (59) 22
 70
 52
 144
 
 Total Mark-to-Market Derivative Assets$3
 $435
 $(314) $124
 $73
 $70
 $267
 
 Derivative Contracts              
 Current Liabilities$(3) $(303) $255
 $(51) $—
 $—
 $(51) 
 Noncurrent Liabilities—
 (63) 57
 (6) (106) —
 (112) 
 Total Mark-to-Market Derivative (Liabilities)$(3) $(366) $312
 $(57) $(106) $—
 $(163) 
 Total Net Mark-to-Market Derivative Assets (Liabilities)$—
 $69
 $(2) $67
 $(33) $70
 $104
 
                

                
  As of December 31, 2011 
  Power PSE&G PSEG Consolidated 
  
Cash Flow
Hedges
 
Non
Hedges
     
Non
Hedges
 
Fair Value
Hedges
   
 Balance Sheet Location
Energy-
Related
Contracts
 
Energy-
Related
Contracts
 
Netting
(A)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
  Millions 
 Derivative Contracts              
 Current Assets$55
 $532
 $(448) $139
 $—
 $17
 $156
 
 Noncurrent Assets8
 121
 (74) 55
 4
 47
 106
 
 Total Mark-to-Market Derivative Assets$63
 $653
 $(522) $194
 $4
 $64
 $262
 
 Derivative Contracts              
 Current Liabilities$(5) $(506) $387
 $(124) $(7) $—
 $(131) 
 Noncurrent Liabilities(1) (76) 53
 (24) —
 (2) (26) 
 Total Mark-to-Market Derivative (Liabilities)$(6) $(582) $440
 $(148) $(7) $(2) $(157) 
 Total Net Mark-to-Market Derivative Assets (Liabilities)$57
 $71
 $(82) $46
 $(3) $62
 $105
 
                

                
  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
 
                
(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 March 31, 2013 and December 31, 2012. 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

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(UNAUDITED)


the right of collateral.offset exists, has been offset in the statement of financial position. As of September 30, 2012March 31, 2013 and December 31, 20112012, net cash collateral receivedpaid of$26 million and $2 million and $82 million, respectively, waswere netted against the corresponding net derivative contract positions. Of the $26 million as of March 31, 2013, cash collateral of $12 million and $14 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $2 million as of September 30,December 31, 2012, cash collateral of $(4)(3) million and $(2)5 million were netted against current assets and noncurrent assets, respectively, and cash collateral of $4 million was netted against current liabilities. Of the $82 million as of December 31, 2011, cash collateral of $(77) million and $(23) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $16 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.
Certain of 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 NYMEX and ICE must adhere to comprehensive collateral and marginingmargin 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 $13080 million and $28598 million as of September 30, 2012March 31, 2013 and December 31, 20112012, respectively. As of September 30, 2012March 31, 2013 and December 31, 20112012, Power had the contractual right of offset of $8861 million and $149 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded or lost its investment grade rating, it would have had additional collateral obligations of $4219 million and $13637 million as of September 30, 2012March 31, 2013 and December 31, 20112012, 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 $610675 million and $812654 million as of September 30, 2012March 31, 2013 and December 31, 20112012, respectively, discussed in Note 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, 2012March 31, 2013 and 20112012:

                  
 
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, 
 2012 2011   2012 2011   2012 2011 
  Millions 
 PSEG and Power                
 Energy-Related Contracts$(3) $21
 Operating Revenues $15
 $60
 Operating Revenues $(1) $—
 
 Total PSEG and Power$(3) $21
   $15
 $60
   $(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, 
 2013 2012                                2013 2012   2013 2012 
  Millions 
 PSEG                
 Energy-Related Contracts$—
 $38
 Operating Revenues $6
 $39
 Operating Revenues $—
 $(1) 
 Energy-Related Contracts—
 (4) Energy Costs —
 (4)   —
 —
 
 Total PSEG$—
 $34
   $6
 $35
   $—
 $(1) 
 Power                
 Energy-Related Contracts$—
 $38
 Operating Revenues $6
 $39
 Operating Revenues $—
 $(1) 
 Energy-Related Contracts—
 (4) Energy Costs —
 (4)   —
 —
 
 Total Power$—
 $34
   $6
 $35
   $—
 $(1) 
                  

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the nine months ended September 30, 2012 and 2011:
                  
 
Derivatives in
Cash Flow Hedging
Relationships
Amount of
Pre-Tax
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective
Portion)
 
Location
of Pre-Tax Gain
(Loss)  Reclassified
from AOCI into
Income
 
Amount of
Pre-Tax
Gain (Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Location of
Pre-Tax Gain
(Loss) Recognized in
Income on
Derivatives
(Ineffective Portion)
 
Amount of
Pre-Tax
Gain (Loss)
Recognized in
Income on
Derivatives
(Ineffective
Portion)
 
 Nine Months
Ended		   Nine Months
Ended		   Nine Months
Ended		 
 September 30,   September 30,   September 30, 
 2012 2011                                2012 2011   2012 2011 
  Millions 
 PSEG (A)                
 Energy-Related Contracts$27
 $18
 Operating Revenues $67
 $152
 Operating Revenues $(1) $1
 
 Energy-Related Contracts(4) 1
 Energy Costs (9) 2
   —
 —
 
 Interest Rate Swaps—
 —
 Interest Expense (1) (1)   —
 —
 
 Total PSEG$23
 $19
   $57
 $153
   $(1) $1
 
 Power                
 Energy-Related Contracts$27
 $18
 Operating Revenues $67
 $152
 Operating Revenues $(1) $1
 
 Energy-Related Contracts(4) 1
 Energy Costs (9) 2
   —
 —
 
 Total Power$23
 $19
   $58
 $154
   $(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 IncomePre-Tax After-Tax 
  Millions 
 Balance as of December 31, 2011$54
 $31
 
 Gain Recognized in AOCI26
 15
 
 Less: Gain Reclassified into Income(42) (25) 
 Balance as of June 30, 2012$38
 $21
 
 Loss Recognized in AOCI(3) (2) 
 Less: Gain Reclassified into Income(15) (8) 
 Balance as of September 30, 2012$20
 $11
 
      
      
 Accumulated Other Comprehensive IncomePre-Tax After-Tax 
  Millions 
 Balance as of December 31, 2011$54
 $31
 
 Gain Recognized in AOCI28
 17
 
 Less: Gain Reclassified into Income(70) (41) 
 Balance as of December 31, 2012$12
 $7
 
 Less: Gain Reclassified into Income(6) (4) 
 Balance as of March 31, 2013$6
 $3
 
      


40
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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 ninethree months ended September 30, 2012March 31, 2013 and 20112012:
             
 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, 
     2012 2011 2012 2011 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $(90) $24
 $145
 $(18) 
 Energy-Related Contracts Energy Costs 6
 (11) (17) (10) 
 Total PSEG and Power   $(84) $13
 $128
 $(28) 
             
          
 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, 
 ��    2013
 2012
 
     Millions 
 PSEG and Power        
 Energy-Related Contracts Operating Revenues  $(209) $195
 
 Energy-Related Contracts Energy Costs  58
 (26) 
 Total PSEG and Power    $(151) $169
 
          

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 $65 million and $6 million for the three month periods and $17 million and $19 million for the ninethree month periods ended September 30, 2012March 31, 2013 and 20112012, respectively.

39
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2012March 31, 2013 and December 31, 20112012: 
            
 TypeNotional Total PSEG Power PSE&G 
  Millions 
 As of September 30, 2012          
 Natural GasDth 588
 —
 385
 203
 
 ElectricityMWh 179
 —
 179
 —
 
 CapacityMW days 4
 —
 —
 4
 
 FTRsMWh 28
 —
 28
 —
 
 Interest Rate SwapsUS Dollars 1,100
 1,100
 —
 —
 
 CoalTons 1
 —
 1
 —
 
 As of December 31, 2011          
 Natural GasDth 612
 —
 377
 235
 
 ElectricityMWh 137
 —
 137
 —
 
 FTRsMWh 12
 —
 12
 —
 
 Interest Rate SwapsUS Dollars 1,100
 1,100
 —
 —
 
 CoalTons 1
 —
 1
 —
 
            
            
 TypeNotional Total PSEG Power PSE&G 
  Millions 
 As of March 31, 2013          
 Natural GasDth 625
 —
 444
 181
 
 ElectricityMWh 231
 —
 231
 —
 
 CapacityMW days 4
 —
 —
 4
 
 FTRsMWh 8
 —
 8
 —
 
 Interest Rate SwapsU.S. Dollars 850
 850
 —
 —
 
 As of December 31, 2012          
 Natural GasDth 596
 —
 404
 192
 
 ElectricityMWh 208
 —
 208
 —
 
 CapacityMW days 4
 —
 —
 4
 
 FTRsMWh 19
 —
 19
 —
 
 Interest Rate SwapsU.S. Dollars 850
 850
 —
 —
 
 CoalTons 1
 —
 1
 —
 
            

Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

41
Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


As of September 30, 2012March 31, 2013, 99%96% of the credit for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).
The following table provides information on Power’s credit risk from others, net of cash collateral, as of September 30, 2012March 31, 2013. 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$311
 $85
 $309
 2
 $153
(A)  
 Non-Investment Grade—External Rating3
 —
 3
 —
 —
   
 Investment Grade—No External Rating9
 —
 9
 —
 —
   
 Non-Investment Grade—No External Rating—
 —
 —
 —
 —
   
 Total$323
 $85
 $321
 2
 $153
   
             
             
 Rating
Current
Exposure
 
Securities
held as
Collateral
 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
  Millions   Millions  
 Investment Grade—External Rating$311
 $60
 $310
 1
 $200
(A)  
 Non-Investment Grade—External Rating12
 —
 12
 —
 —
   
 Investment Grade—No External Rating3
 —
 3
 —
 —
   
 Non-Investment Grade—No External Rating1
 —
 1
 —
 —
   
 Total$327
 $60
 $326
 1
 $200
   
             
(A)
IncludesRepresents net exposure of $108 millionwith PSE&G. The remaining net exposure of $45 million is with one nonaffiliated power purchaser which is a regulated investment grade counterparty.


40
Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would be no exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of September 30, 2012March 31, 2013, Power had 177172 active counterparties.


Note 11. Fair Value Measurements
PSEG, Power and PSE&G adopted accounting standard “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)” effective January 1, 2012. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities.
Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of September 30, 2012March 31, 2013, these consist primarily of electric swaps whose basis is deemed significant to the fair value measurement, long-term electric capacityload contracts and long-term gas supply 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, 2012March 31, 2013 and December 31, 20112012, 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


            
  Recurring Fair Value Measurements as of September 30, 2012 
 DescriptionTotal 
Cash
Collateral
Netting (E)
 
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)$197
 $(6) $—
 $116
 $87
 
 Interest Rate Swaps (B)$70
 $—
 $—
 $70
 $—
 
 NDT Fund (C)          
 Equity Securities$749
 $—
 $749
 $—
 $—
 
 Debt Securities—Govt Obligations$288
 $—
 $—
 $288
 $—
 
 Debt Securities—Other$333
 $—
 $—
 $333
 $—
 
 Other Securities$123
 $—
 $—
 $123
 $—
 
 Rabbi Trust (C)          
 Equity Securities—Mutual Funds$17
 $—
 $17
 $—
 $—
 
 Debt Securities—Govt Obligations$116
 $—
 $—
 $116
 $—
 
 Debt Securities—Other$47
 $—
 $—
 $47
 $—
 
 Other Securities$3
 $—
 $—
 $3
 $—
 
 Liabilities:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$(163) $4
 $—
 $(59) $(108) 
 Power          
 Assets:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$124
 $(6) $—
 $116
 $14
 
 NDT Fund (C)          
 Equity Securities$749
 $—
 $749
 $—
 $—
 
 Debt Securities—Govt Obligations$288
 $—
 $—
 $288
 $—
 
 Debt Securities—Other$333
 $—
 $—
 $333
 $—
 
 Other Securities$123
 $—
 $—
 $123
 $—
 
 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)$(57) $4
 $—
 $(59) $(2) 
 PSE&G          
 Assets:          
 Derivative Contracts:          
 Energy Related Contracts (A)$73
 $—
 $—
 $—
 $73
 
 Rabbi Trust (C)          
 Equity Securities—Mutual Funds$6
 $—
 $6
 $—
 $—
 
 Debt Securities—Govt Obligations$38
 $—
 $—
 $38
 $—
 
 Debt Securities—Other$16
 $—
 $—
 $16
 $—
 
 Other Securities$1
 $—
 $—
 $1
 $—
 
 Liabilities:          
 Derivative Contracts:          
 Energy Related Contracts (A)$(106) $—
 $—
 $—
 $(106) 
            
            
  Recurring Fair Value Measurements as of March 31, 2013 
 DescriptionTotal 
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)$127
 $—
 $—
 $56
 $71
 
 Interest Rate Swaps (B)$52
 $—
 $—
 $52
 $—
 
 NDT Fund (C)          
 Equity Securities$829
 $—
 $829
 $—
 $—
 
 Debt Securities—Govt Obligations$378
 $—
 $—
 $378
 $—
 
 Debt Securities—Other$327
 $—
 $—
 $327
 $—
 
 Other Securities$68
 $—
 $—
 $68
 $—
 
 Rabbi Trust (C)          
 Equity Securities—Mutual Funds$19
 $—
 $19
 $—
 $—
 
 Debt Securities—Govt Obligations$115
 $—
 $—
 $115
 $—
 
 Debt Securities—Other$47
 $—
 $—
 $47
 $—
 
 Other Securities$2
 $—
 $—
 $2
 $—
 
 Liabilities:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$(150) $26
 $—
��$(48) $(128) 
 Power          
 Assets:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$58
 $—
 $—
 $56
 $2
 
 NDT Fund (C)          
 Equity Securities$829
 $—
 $829
 $—
 $—
 
 Debt Securities—Govt Obligations$378
 $—
 $—
 $378
 $—
 
 Debt Securities—Other$327
 $—
 $—
 $327
 $—
 
 Other Securities$68
 $—
 $—
 $68
 $—
 
 Rabbi Trust (C)          
 Equity Securities—Mutual Funds$4
 $—
 $4
 $—
 $—
 
 Debt Securities—Govt Obligations$22
 $—
 $—
 $22
 $—
 
 Debt Securities—Other$9
 $—
 $—
 $9
 $—
 
 Other Securities$—
 $—
 $—
 $—
 $—
 
 Liabilities:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$(41) $26
 $—
 $(48) $(19) 
 PSE&G          
 Assets:          
 Derivative Contracts:          
 Energy Related Contracts (A)$69
 $—
 $—
 $—
 $69
 
 Rabbi Trust (C)          
 Equity Securities—Mutual Funds$6
 $—
 $6
 $—
 $—
 
 Debt Securities—Govt Obligations$38
 $—
 $—
 $38
 $—
 
 Debt Securities—Other$16
 $—
 $—
 $16
 $—
 
 Other Securities$1
 $—
 $—
 $1
 $—
 
 Liabilities:          
 Derivative Contracts:          
 Energy Related Contracts (A)$(109) $—
 $—
 $—
 $(109) 
            

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)



            
  Recurring Fair Value Measurements as of December 31, 2011 
 DescriptionTotal 
Cash
Collateral
Netting (E)
 
Quoted Market
Prices of
Identical Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
  Millions 
 PSEG          
 Assets:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$198
 $(100) $—
 $257
 $41
 
 Interest Rate Swaps (B)$64
 $—
 $—
 $64
 $—
 
 NDT Fund: (C)          
 Equity Securities$685
 $—
 $685
 $—
 $—
 
 Debt Securities-Govt Obligations$359
 $—
 $—
 $359
 $—
 
 Debt Securities-Other$281
 $—
 $—
 $281
 $—
 
 Other Securities$24
 $—
 $—
 $24
 $—
 
 Rabbi Trust—Mutual Funds (C)$172
 $—
 $19
 $153
 $—
 
 Liabilities:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$(155) $18
 $—
 $(153) $(20) 
 Interest Rate Swaps (B)$(2) $—
 $—
 $(2) $—
 
 Non-Recourse Debt (D)$(50) $—
 $—
 $—
 $(50) 
 Power          
 Assets:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$194
 $(100) $—
 $257
 $37
 
 NDT Fund: (C)          
 Equity Securities$685
 $—
 $685
 $—
 $—
 
 Debt Securities-Govt Obligations$359
 $—
 $—
 $359
 $—
 
 Debt Securities-Other$281
 $—
 $—
 $281
 $—
 
 Other Securities$24
 $—
 $—
 $24
 $—
 
 Rabbi Trust—Mutual Funds (C)$33
 $—
 $4
 $29
 $—
 
 Liabilities:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$(148) $18
 $—
 $(153) $(13) 
 PSE&G          
 Assets:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$4
 $—
 $—
 $—
 $4
 
 Rabbi Trust—Mutual Funds (C)$57
 $—
 $6
 $51
 $—
 
 Liabilities:          
 Derivative Contracts:          
 Energy-Related Contracts (A)$(7) $—
 $—
 $—
 $(7) 
            
            
  Recurring Fair Value Measurements as of December 31, 2012 
 DescriptionTotal 
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) 
            
(A)Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

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Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.
(B)Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
(C)
The fair value measurements table excludes cash of $8 million which is part of the NDT Fund as of September 30, 2012. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). The fair value measurements table excludes a $13 million cash contribution made to the Rabbi Trust Fund as of March 31, 2013. Of the $13 million, $3 million and $10 million were contributed to Power's and Services' portions of the Rabbi Trust Fund, respectively.
Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price (primarily Level 1). The Rabbi Trust equity index fund is valued based on quoted prices in an active market (Level 1).
Level 2—NDT and Rabbi Trust fixed income securities are limited to investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backedasset-backed securities with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes, and issuer spreads (primarily Level 2). Short-term investments and certain commingled temporary investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2).
(D)For Non-Recourse Debt, see Fair Value Option below.
(E)Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under the accounting guidance for Offsetting of Amounts Related to Certain Contracts.
Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the 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 risk were not material to the financial statements.
Disclosed below is detailThe following tables provide details surrounding significant Level 3 valuations as of which the most significant positions are electric swaps for PowerMarch 31, 2013 and long-term electric capacity contracts and long-term natural gas supply contracts for PSE&G.December 31, 2012. For Power, in general, electric swaps are valued based on at least two pricing inputs, basis and underlying. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as Level 3. The remaining balance of Power’s Level 3 positions consist primarily ofPower's electric load contracts in which load consumption may change hourly are fair valued using certain unobservable inputs, such as historic load variability. For Power, long-term electric capacity contracts and certain long-term natural gas supply contracts. Long-term electric capacity contracts are measured at fair value using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For Power and PSE&G, long-term gas supply contracts are measured at fair value using both actively traded pricing points as well as unobservable inputs such as gas prices beyond observable periods and long-term basis quotes and accordingly, the fair value measurements are classified in Level 3. For PSE&G, long-term electric capacity contracts are measured at fair value using both observable capacity prices and unobservable inputs consisting of forecasts of future long-term electric capacity prices and include

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adjustments for contingencies, such as litigation risk and plant construction risk. Accordingly, the fair value

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measurements are classified as Level 3.
The table below discloses the significant unobservable inputs used in developing the fair value of these Level 3 positions:
              
  Quantitative Information About Level 3 Fair Value Measurements   
 CommodityLevel 3 Position Fair Value as of March 31, 2013 
Valuation
Technique(s)
 
Significant
Unobservable Input
 Range 
    Assets (Liabilities)       
    Millions       
 Power            
                 Electricity             Electric Swaps $—
 $(13) Discounted cash flow Power Basis                     $0 to $10/MWh 
                  ElectricityElectric Load Contracts —
 (6) Discounted cash flow Historic Load Variability -5% to +10% 
 OtherVarious (A) 2
 —
       
 Total Power  $2
 $(19)       
 PSE&G            
 Gas and Capacity   Forward Contracts (B) $69
 $(109) Discounted cash flow Long-Term Gas Basis and Capacity Prices (B) 
 Total PSE&G  $69
 $(109)       
 TOTAL PSEG  $71
 $(128)       
              
              
  Quantitative Information About Level 3 Fair Value Measurements   
 CommodityLevel 3 Position Fair Value at September 30, 2012 
Valuation
Technique(s)
 
Significant
Unobservable Input
 Range 
    Assets (Liabilities)       
    Millions       
 Power            
 ElectricityElectric Swaps $10
 $(1) Discounted cash flow Power Basis $0 -$10/MWh 
 OtherVarious (A) 4
 (1)       
 Total Power  $14
 $(2)       
 PSE&G            
 Gas and CapacityForward Contracts (B) $73
 $(106) Discounted cash flow Long-Term Gas Basis and Capacity Prices (B) 
 Total PSE&G  $73
 $(106)       
 TOTAL PSEG  $87
 $(108)       
              
              
  Quantitative Information About Level 3 Fair Value Measurements   
 CommodityLevel 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 
                  ElectricityElectric Load Contracts 1
 (2) Discounted cash flow Historic Load Variability -5% to +10% 
 OtherVarious (A) 5
 (1)       
 Total Power  $13
 $(4)       
 PSE&G            
 Gas and Capacity                     Forward Contracts (B)  $67
 $(107) Discounted cash flow Long-Term Gas Basis and Capacity Prices (B) 
 Total PSE&G  $67
 $(107)       
 TOTAL PSEG  $80
 $(111)       
              
(A)
Includes long-term electric capacity and long-term gas supply positions which are immaterial.immaterial as of March 31, 2013 and December 31, 2012. Also includes long-term electric capacity positions which are immaterial as of December 31, 2012.    
(B)
Includes long-term gas supply and long-term electric capacity positions with various unobservable inputs. Significant unobservable inputs for the gas supply contracts include long-term basis prices in the range of $0 to $2/MMBTU of natural gas. Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of $100 to $400/MW day.

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Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power and PSE&G are sellers, an increase in either the power basis or the load variability or the longer-term basis amounts would decrease the fair value. For long-term electric capacity contracts where Power or PSE&G are buyers,is a buyer, an increase in the capacity price would increase the fair value.
A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months ended March 31, 2013and nine months ended September 30, 2012 follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months EndedMarch 31, 2013
                 
     
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) 
                 

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Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months Ended September 30,March 31, 2012
                
    
Total Gains or (Losses)
Realized/Unrealized
         
 DescriptionBalance as of
July 1,
2012		 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases,
(Sales) (C)
 
Issuances
(Settlements)
(D)
 
Transfers
In (Out)
(E)
 Balance as of
September 30,
2012		 
  Millions   
 PSEG              
 Net Derivative Assets (Liabilities)$(36) $(1) $25
 $—
 $(9) $—
 $(21) 
 Power              
 Net Derivative Assets (Liabilities)$22
 $(1) $—
 $—
 $(9) $—
 $12
 
 PSE&G              
 Net Derivative Assets (Liabilities)$(58) $—
 $25
 $—
 $—
 $—
 $(33) 
                



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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
         
 DescriptionBalance as of
January 1,
2012		 
Included in
Income (F)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases,
(Sales) (C)
 
Issuances
(Settlements)
(D)
 
Transfers
In (Out)
(E)
 Balance as of
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) 
                

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and nine months ended September 30, 2011 follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months EndedSeptember 30, 2011

                
    
Total Gains or (Losses)
Realized/Unrealized
         
 DescriptionBalance as of
July 1,
2011		 
Included in
  Income (A)  
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases,
(Sales) (C)
 
Issuances
(Settlements)
(D)
 
Transfers
In (Out)
(E)
 Balance as of
September 30,
2011		 
  Millions   
 PSEG              
 Net Derivative Assets (Liabilities)$(3) $13
 $(27) $10
 $3
 $—
 $(4) 
 Power              
 Net Derivative Assets (Liabilities)$(4) $13
 $—
 $10
 $3
 $—
 $22
 
 PSE&G              
 Net Derivative Assets (Liabilities)$1
 $—
 $(27) $—
 $—
 $—
 $(26) 
                





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Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Nine Months EndedSeptember 30, 2011
                
    
Total Gains or (Losses)
Realized/Unrealized
         
 DescriptionBalance as of
January 1,
2011		 
Included in
  Income (F)  
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases,
(Sales) (C)
 
Issuances
(Settlements)
(D)
 
Transfers
In (Out)
(E)
 Balance as of
September 30,
2011		 
  Millions   
 PSEG              
 Net Derivative Assets (Liabilities)$47
 $(27) $(31) $29
 $(22) $—
 $(4) 
 NDT Funds$8
 $—
 $—
 $—
 $—
 $(8) $—
 
 Power              
 Net Derivative Assets (Liabilities)$42
 $(27) $—
 $29
 $(22) $—
 $22
 
 NDT Funds$8
 $—
 $—
 $—
 $—
 $(8) $—
 
 PSE&G              
 Net Derivative Assets (Liabilities)$5
 $—
 $(31) $—
 $—
 $—
 $(26) 
                
                 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of
January 1,
2012		 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances
(Settlements)
(C)
 
Transfers
In (Out)
(D)
 Balance as of March 31, 2012 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $21
 $34
 $35
 $—
 $(29) $—
 $61
 
 Non-Recourse Debt $(50) $—
 $—
 $—
 $—
 $—
 $(50) 
 Power               
 Net Derivative Assets (Liabilities) $24
 $34
 $—
 $—
 $(29) $—
 $29
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(3) $—
 $35
 $—
 $—
 $—
 $32
 
                 
(A)
PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $(1)(34) million and $1234 million in Operating Income in 20122013 and 20112012, respectively,respectively. Of the $1(34) million in OCI and less thanOperating Income in 2013, $1(24) million in Income from Discontinued Operations in 2011.is unrealized. Of the $(1)34 million in Operating Income in 2012, $(10)5 million is unrealized. Of the $12 million in Operating Income in 2011, $31 million is unrealized. Energy Holdings’ release from its obligations under the non-recourse debt is included in PSEG’s Operating Income and is offset by the write-off of the related assets.
(B)Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or OCI, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.
(C)
IncludesRepresents $10 million in purchasessettlements in 2013 and $0(29) million in sales for the three months endedsettlements in September 30, 2011. Includes $65 million in purchases and $(36) million in sales for the nine months months ended September 30, 20112012.
(D)
Includes $0 million and $(5) million in issuances and $(9) million and $8 million in settlements for the three months ended September 30, 2012 and 2011, respectively. Includes $0 million and $(25) million in issuances and $(52) million and $3 million in settlements forDuring the ninethree months ended September 30, 2012 and 2011, respectively.
(E)
There were no transfers among levels during the three months ended September 30, 2012 and 2011 and the nine months ended September 30, 2012. During the nine months ended September 30, 2011March 31, 2013, $82 million of net derivatives assets in the NDT fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. The transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred), as per PSEG’s policy.
(F)
PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include There were $40 millionno and $(28) million in Operating Income in 2012 and 2011, respectively, $(2) million in OCI and $3 million in Income from Discontinued Operations in 2011. Oftransfers among levels for the $40 millionthree months in Operating Income inended March 31, 2012, $(12) million is unrealized. Of the $(28) million in Operating Income in 2011, $(25) million is unrealized. Energy Holdings’ release from its obligations under the non-recourse debt is included in PSEG’s Operating Income and is offset by the write-off of the related assets..
As of September 30,March 31, 2013, PSEG carried $1.8 billion of net assets that are measured at fair value on a recurring basis, of which $57 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of March 31, 2012, PSEG carried $1.8 billion of net assets that are measured at fair value on a recurring basis, of which $2111 million of net liabilitiesassets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of September 30, 2011, PSEG carried $1.5 billion of net assets that are measured at fair value on a recurring basis, of which $4 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
Fair Value Option
As of December 31, 2011, the effective date of the Dynegy lease rejections, the leases of the Roseton and Danskammer generation facilities were effectively terminated and no longer qualified for leveraged lease accounting under the guidance for leases. As the owner of the facilities, Energy Holdings was required to recognize the underlying assets and nonrecourse notes payable (Notes Payable) associated with these leases at their respective fair values on the effective date of the rejection. Energy

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


Holdings has elected to record the Notes Payable at fair value each reporting period under the fair value option in accordance with guidance for Financial Instruments. The fair value option permits the irrevocable fair value election for selected eligible financial assets or liabilities. Any changes in the fair value of the Notes Payable will be included in earnings each period. The $550 million of contractual principal outstanding on the Notes Payable is valued at $50 million as of December 31, 2011. Energy Holdings elected this option to eliminate certain complexities in applying the effective interest method of amortization given the uncertain payment streams between the election date and the expected foreclosure date. There were no other debt instruments of this type eligible for the fair value option as of December 31, 2011. The $50 million fair value of these Notes Payable is included on PSEG’s Condensed Consolidated Balance Sheet as of December 31, 2011. The fair values of the Notes Payable include significant internal assumptions based on expected cash flows and the fair values of the underlying collateral.Changes to projected capacity factors, capacity and energy prices, fuel costs and other required cash outflows could significantly impact the fair value of the collateral which would increase or decrease the fair value of the Notes. These Notes Payable are classified as Level 3 in the fair value hierarchy as a result of mainly unobservable inputs. As of the June 5, 2012 effective date of the amended settlement agreement, the Notes Payable and related assets were written off.
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, 2012March 31, 2013 and December 31, 20112012.

          
  September 30, 2012 December 31, 2011 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (Parent) (A)$49
 $70
 $39
 $62
 
 Power -Recourse Debt (B)2,686
 3,205
 2,751
 3,158
 
 PSE&G (B)4,744
 5,631
 4,270
 4,905
 
 Transition Funding (PSE&G) (B)746
 832
 895
 1,016
 
 Transition Funding II (PSE&G) (B)39
 41
 44
 47
 
 Energy Holdings:        
 Project Level, Non-Recourse Debt (C)45
 45
 95
 95
 
 Total Long-Term Debt$8,309
 $9,824
 $8,094
 $9,283
 
          
          
  March 31, 2013 December 31, 2012 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (Parent) (A)$35
 $52
 $38
 $57
 
 Power -Recourse Debt (B)2,340
 2,781
 2,340
 2,818
 
 PSE&G (B)5,042
 5,750
 4,795
 5,606
 
 Transition Funding (PSE&G) (B)639
 703
 690
 765
 
 Transition Funding II (PSE&G) (B)32
 34
 32
 34
 
 Energy Holdings:        
 Project Level, Non-Recourse Debt (C)26
 26
 44
 44
 
 Total Long-Term Debt$8,114
 $9,346
 $7,939
 $9,324
 
          
(A)Fair value represents net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power andPower. 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)
Fair value amounts as of December 31, 2011 include $50 million of non-recourse project debt related to Dynegy which is classified as a Level 3 measurement. See “Fair Value Option” above for more details on Dynegy debt. Non-recourse project debt of $45 million is valued as equivalent to the amortized cost and is classified as a Level 3 measurement. The $18 million of Non-Recourse Debt associated with a commercial real estate property held for sale was reclassified to Other Current Liabilities in 2013.


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Note 12. Other Income and Deductions
          
 Other IncomePower PSE&G Other (A) Consolidated 
  Millions 
 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
 
 Other1
 5
 1
 7
 
 Total Other Income$104
 $16
 $1
 $121
 
 Three Months Ended September 30, 2011        
 NDT Fund Gains, Interest, Dividend and Other Income$36
 $—
 $—
 $36
 
 Allowance of Funds Used During Construction—
 2
 —
 2
 
 Solar Loan Interest—
 3
 —
 3
 
 Other1
 2
 1
 4
 
 Total Other Income$37
 $7
 $1
 $45
 
 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
 
 Other4
 9
 6
 19
 
 Total Other Income$171
 $39
 $6
 $216
 
 Nine Months Ended September 30, 2011        
 NDT Fund Gains, Interest, Dividend and Other Income$153
 $—
 $—
 $153
 
 Allowance of Funds Used During Construction—
 4
 —
 4
 
 Solar Loan Interest—
 7
 —
 7
 
 Other3
 5
 4
 12
 
 Total Other Income$156
 $16
 $4
 $176
 
          
          
 Other IncomePower PSE&G Other (A) Consolidated 
  Millions 
 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
 
 Three Months Ended March 31, 2012        
 NDT Fund Gains, Interest, Dividend and Other Income$28
 $���
 $—
 $28
 
 Allowance of Funds Used During Construction—
 4
 —
 4
 
 Solar Loan Interest—
 4
 —
 4
 
 Other2
 3
 3
 8
 
 Total Other Income$30
 $11
 $3
 $44
 
          


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


          
 Other DeductionsPower PSE&G Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2012        
 NDT Fund Realized Losses and Expenses$20
 $—
 $—
 $20
 
 Other—
 6
 —
 6
 
 Total Other Deductions$20
 $6
 $—
 $26
 
 Three Months Ended September 30, 2011        
 NDT Fund Realized Losses and Expenses$10
 $—
 $—
 $10
 
 Other—
 1
 —
 1
 
 Total Other Deductions$10
 $1
 $—
 $11
 
 Nine Months Ended September 30, 2012        
 NDT Fund Realized Losses and Expenses$45
 $—
 $—
 $45
 
 Other7
 8
 1
 16
 
 Total Other Deductions$52
 $8
 $1
 $61
 
 Nine Months Ended September 30, 2011        
 NDT Fund Realized Losses and Expenses$32
 $—
 $—
 $32
 
 Other5
 2
 —
 7
 
 Total Other Deductions$37
 $2
 $—
 $39
 
          
          
 Other DeductionsPower PSE&G Other (A) Consolidated 
  Millions 
 Three Months Ended March 31, 2013        
   NDT Fund Realized Losses and Expenses$20
 $—
 $—
 $20
 
   Other8
 1
 —
 9
 
 Total Other Deductions$28
 $1
 $—
 $29
 
 Three Months Ended March 31, 2012        
   NDT Fund Realized Losses and Expenses$8
 $—
 $—
 $8
 
   Other7
 1
 —
 8
 
 Total Other Deductions$15
 $1
 $—
 $16
 
          
(A)Other primarily consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations.


Note 13. Income Taxes
PSEG’s, Power’s and PSE&G’s effective tax rates for the three months and nine monthsended September 30, 2012March 31, 2013 and 20112012 were as follows: 

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2012 2011 2012 2011 
 PSEG41.0% 43.1% 36.3% 42.0% 
 Power42.4% 40.7% 41.0% 41.0% 
 PSE&G39.9% 40.1% 35.4% 40.5% 
          
      
  Three Months Ended 
  March 31, 
  2013 2012 
 PSEG40.7% 30.1% 
 Power39.8% 39.8% 
 PSE&G41.1% 29.4% 
      


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


ForPSEG's and PSE&G's effective tax rates for the three months ended September 30,March 31, 2012, the increase in Power's were lower than their more typical 2013 effective tax rate wasrates due primarily to NDT revenue, while the decreasea settlement in PSEG was due to the 2011 Energy Holdings' charge against earnings applicable to the Dynegy leases.
For the nine months ended September 30, 2012, the decrease in PSEG’s and PSE&G’s effective tax rate was due primarily to with the IRS in regards to leveraged leases and the federal tax audit settlements discussed below.for tax years 1997 through 2006.
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 iswas 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 the 50% bonus depreciation for property placed into service before January 1, 2014. These provisions have generated cash for PSEG through tax benefits related to the accelerated depreciation in 2011 and will for 2012.depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period.
PSE&G has accrued $21 million of Investment Tax Credits (ITC) associated with alternative energy projects in the first nine months of 2012. Prior to 2012, the law provided an option to claim either a grant or the ITC. For years prior to 2012, the ITC had been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense. As the grant program expired at the end of 2011, ITC for 2012 has been accounted for as an accumulated deferred investment credit on

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


the balance sheet which is amortized as a reduction of tax expense over the life of the related project.
PSEG’s unrecognized tax benefits decreased by approximately $533 million through the first nine months of 2012, primarily attributable to PSEG. This decrease was primarily due to the settlement with the IRS, in the amount of $387 million, of the leasing issue (See Note 8. Commitments and Contingent Liabilities) and the federal audits for tax years 1997 through 2006. The remaining unrecognized tax benefit of $146 million represents a decrease of prior period positions. As a result, as of September 30, 2012, there is no material increase or decrease in unrecognized tax benefits that is reasonably possible to occur within the next twelve months. The interest and penalties associated with the decrease in the uncertain tax position was $356 million. The impact on the accumulated deferred income taxes and regulatory asset associated with the unrecognized tax benefit decrease is $216 million. The change in the total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $317 million.
On June 26, 2009, September 15, 2008 and December 17, 2007, PSEG made tax deposits with the IRS in the amounts of $140 million, $80 million and $100 million, respectively, to defray potential interest costs associated with disputed tax assessments associated with certain lease investments. On January 31, 2012, PSEG signed a specific matter closing agreement with the IRS regarding this matter. Based on this agreement, these deposits will bewere applied against tax and interest due pursuant to the closing agreement. Further, on the same date, PSEG signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements concludeconcluded ten years of audits for PSEG and the leasing issue for all tax years. The financial statement impacts of these agreements, net of existing financial statement reserves, iswas a net decrease in tax expense in the first quarter of approximately2012 of $7071 million for PSEG, including $30 million and $1 million for PSE&G and Power, respectively.


Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax
            
  Balance as of December 31, 2011 
Other Comprehensive Income (Loss)
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) 
 NDT Funds66
 11
 —
 —
 77
 
 Other4
 —
 —
 1
 5
 
 Accumulated Other Comprehensive Income (Loss)$(337) $11
 $—
 $4
 $(322) 
            

            
  Balance as of December 31, 2010 
Other Comprehensive Income (Loss)
Nine Months Ended
September 30, 2011
 Balance as of September 30, 2011 
  Power PSE&G Other  
  Millions 
 Derivative Contracts$111
 $(80) $—
 $—
 $31
 
 Pension and OPEB Plans(377) 45
 —
 8
 (324) 
 NDT Fund109
 (77) —
 —
 32
 
 Other1
 —
 2
 2
 5
 
 Accumulated Other Comprehensive Income (Loss)$(156) $(112) $2
 $10
 $(256) 
            
          
  Other Comprehensive Income (Loss) 
 PSEGThree Months Ended March 31, 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—
 —
 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) 
 PowerThree Months Ended March 31, 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—
 —
 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) 
          

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(UNAUDITED)


           
      Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
 PSEG   Three Months Ended March 31, 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 
     Millions 
 Derivative Contracts         
 Gains (Losses) on Cash Flow Hedges Operating Revenues $6
 $(2) $4
 
 Pension and OPEB Plans         
 Amortization of Prior Service Cost (Credit) Operation and Maintenance Expense 4
 (2) 2
 
   Amortization of Actuarial Loss Operation and Maintenance Expense (21) 9
 (12) 
 Available-for-Sale Securities         
 Realized Gains (Losses) on NDT Fund Other Income 2
 (1) 1
 
 Other-Than-Temporary Impairments on NDT Fund Other-Than-Temporary Impairments (2) 1
 (1) 
 Total   $(11) $5
 $(6) 
           
           
      Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
 Power   Three Months Ended March 31, 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 
     Millions 
 Derivative Contracts         
 Gains (Losses) on Cash Flow Hedges Operating Revenues $6
 $(2) $4
 
 Pension and OPEB Plans         
 Amortization of Prior Service Cost (Credit) Operation and Maintenance Expense 2
 (1) 1
 
    Amortization of Actuarial Loss Operation and Maintenance Expense (16) 6
 (10) 
 Available-for-Sale Securities         
 Realized Gains (Losses) on NDT Fund Other Income 2
 (1) 1
 
 Other-Than-Temporary Impairments on NDT Fund Other-Than-Temporary Impairments (2) 1
 (1) 
 Total   $(8) $3
 $(5) 
           

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(UNAUDITED)


            
  Balance as of December 31, 2011 
Other Comprehensive Income (Loss)
Three Months Ended
March 31, 2012
 Balance as of March 31, 2012 
  Power PSE&G Other  
  Millions 
 Derivative Contracts$31
 $—
 $—
 $—
 $31
 
 Pension and OPEB Plans(438) 7
 —
 —
 (431) 
 Available-for-Sale Securities70
 37
 (1) 1
 107
 
 Accumulated Other Comprehensive Income (Loss)$(337) $44
 $(1) $1
 $(293) 
            


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 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, 
  2012 2011 2012 2011 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator
(Millions)
                
 Continuing Operations$347
 $347
 $265
 $265
 $1,051
 $1,051
 $1,047
 $1,047
 
 Discontinued Operations—
 —
 29
 29
 —
 —
 96
 96
 
 Net Income$347
 $347
 $294
 $294
 $1,051
 $1,051
 $1,143
 $1,143
 
 
EPS Denominator
(Thousands)
                
 Weighted Average Common Shares Outstanding505,914
 505,914
 505,909
 505,909
 505,942
 505,942
 505,959
 505,959
 
 Effect of Stock Based Compensation Awards—
 1,197
 —
 1,090
 —
 1,095
 —
 1,004
 
 Total Shares505,914
 507,111
 505,909
 506,999
 505,942
 507,037
 505,959
 506,963
 
                  
 EPS                
 Continuing Operations$0.69
 $0.68
 $0.52
 $0.52
 $2.08
 $2.07
 $2.07
 $2.06
 
 Discontinued Operations—
 —
 0.06
 0.06
 —
 —
 0.19
 0.19
 
 Net Income$0.69
 $0.68
 $0.58
 $0.58
 $2.08
 $2.07
 $2.26
 $2.25
 
                  
          
  Three Months Ended March 31, 
  2013 2012 
  Basic Diluted Basic Diluted 
 
EPS Numerator (Millions)
        
 Net Income$320
 $320
 $493
 $493
 
 
EPS Denominator (Thousands)
        
 Weighted Average Common Shares Outstanding505,942
 505,942
 506,010
 506,010
 
 Effect of Stock Based Compensation Awards—
 1,278
 —
 1,019
 
 Total Shares505,942
 507,220
 506,010
 507,029
 
          
 EPS        
 Net Income$0.63
 $0.63
 $0.97
 $0.97
 
          

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Dividend Payments on Common Stock2012 2011 2012 2011 
 Per Share$0.3550
 $0.3425
 $1.0650
 $1.0275
 
 in Millions$180
 $173
 $538
 $520
 
          

      
  Three Months Ended 
  March 31, 
 Dividend Payments on Common Stock2013 2012 
 Per Share$0.3600
 $0.3550
 
 in Millions$182
 $179
 
      

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(UNAUDITED)



Note 16. Financial Information by Business Segments

            
  Power PSE&G 
Energy
Holdings
 Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2012          
 Total Operating Revenues$1,038
 $1,683
 $15
 $(334) $2,402
 
 Income (Loss) From Continuing Operations181
 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 Assets149
 499
 30
 11
 689
 
 Three Months Ended September 30, 2011          
 Total Operating Revenues$1,398
 $1,841
 $(247) $(372) $2,620
 
 Income (Loss) From Continuing Operations273
 154
 (166) 4
 265
 
 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax29
 —
 —
 —
 29
 
 Net Income (Loss)302
 154
 (166) 4
 294
 
 Segment Earnings (Loss)302
 154
 (166) 4
 294
 
 Gross Additions to Long-Lived Assets207
 265
 1
 4
 477
 
 Nine Months Ended September 30, 2012          
 Total Operating Revenues$3,584
 $5,029
 $49
 $(1,287) $7,375
 
 Income (Loss) From Continuing Operations538
 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 Assets493
 1,369
 85
 22
 1,969
 
 Nine Months Ended September 30, 2011          
 Total Operating Revenues$4,650
 $5,718
 $(206) $(1,719) $8,443
 
 Income (Loss) From Continuing Operations775
 422
 (164) 14
 1,047
 
 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax96
 —
 —
 —
 96
 
 Net Income (Loss)871
 422
 (164) 14
 1,143
 
 Segment Earnings (Loss)871
 422
 (164) 14
 1,143
 
 Gross Additions to Long-Lived Assets530
 939
 2
 8
 1,479
 
 As of September 30, 2012          
 Total Assets$10,994
 $18,115
 $1,974
 $(377) $30,706
 
 Investments in Equity Method Subsidiaries$41
 $—
 $99
 $—
 $140
 
 As of December 31, 2011          
 Total Assets$11,087
 $17,487
 $1,888
 $(641) $29,821
 
 Investments in Equity Method Subsidiaries$31
 $—
 $106
 $—
 $137
 
            
            
  Power PSE&G 
Energy
Holdings
 Other (A) Consolidated 
  Millions 
 Three Months Ended March 31, 2013          
 Total Operating Revenues$1,447
 $1,995
 $16
 $(672) $2,786
 
 Income (Loss) From Continuing Operations137
 179
 —
 4
 320
 
 Net Income (Loss)137
 179
 —
 4
 320
 
 Segment Earnings (Loss)137
 179
 —
 4
 320
 
 Gross Additions to Long-Lived Assets143
 572
 6
 3
 724
 
 Three Months Ended March 31, 2012          
 Total Operating Revenues$1,561
 $1,939
 $20
 $(645) $2,875
 
 Income (Loss) From Continuing Operations253
 197
 40
 3
 493
 
 Net Income (Loss)253
 197
 40
 3
 493
 
 Segment Earnings (Loss)253
 197
 40
 3
 493
 
 Gross Additions to Long-Lived Assets237
 435
 11
 4
 687
 
 As of March 31, 2013          
 Total Assets$10,865
 $19,488
 $1,437
 $(78) $31,712
 
 Investments in Equity Method Subsidiaries$40
 $—
 $97
 $—
 $137
 
 As of December 31, 2012          
 Total Assets$11,032
 $19,223
 $1,454
 $16
 $31,725
 
 Investments in Equity Method Subsidiaries$40
 $—
 $94
 $—
 $134
 
            
(A)Other activities include amounts applicable to PSEG (as parent company), Services and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are priced in accordance with applicable regulations, including affiliate pricing rules, or at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 17. Related-Party Transactions.

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Note 17. Related-Party Transactions
The following discussion relates to intercompany transactions, the majority of which are eliminated during the PSEG consolidation process in accordance with GAAP.
Power
The financial statements for Power include transactions with related parties presented as follows:

       
   Three Months Ended 
   March 31, 
 Related-Party Transactions 2013 2012 
  Millions 
 Revenue from Affiliates:     
 Billings to PSE&G through BGSS (A) $478
 $451
 
 Billings to PSE&G through BGS (A) 193
 189
 
 Total Revenue from Affiliates $671
 $640
 
 Expense Billings from Affiliates:     
 Administrative Billings from Services (B) $(45) $(34) 
 Total Expense Billings from Affiliates $(45) $(34) 
       
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2012 2011 2012 2011 
  Millions 
 Revenue from Affiliates:        
 Billings to PSE&G through BGSS (A)$67
 $91
 $630
 $958
 
 Billings to PSE&G through BGS (A)258
 272
 639
 734
 
 Total Revenue from Affiliates$325
 $363
 $1,269
 $1,692
 
 Expense Billings from Affiliates:        
 Administrative Billings from Services (B)$(38) $(37) $(110) $(109) 
 Total Expense Billings from Affiliates$(38) $(37) $(110) $(109) 
          
      
  As of As of 
 Related-Party TransactionsMarch 31, 2013 December 31, 2012 
  Millions 
 Receivables from PSE&G through BGS and BGSS Contracts (A)$223
 $238
 
 Receivables from (Payable to) PSE&G Related to Gas Supply Hedges for BGSS (A)(23) 27
 
 Receivable from (Payable to) Services (B)(26) (31) 
 Tax Receivable from (Payable to) PSEG (C)(6) 111
 
 Receivable from (Payable to) PSEG2
 (5) 
 Accounts Receivable (Payable)—Affiliated Companies, net$170
 $340
 
 
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)
$748
 $574
 
 
Working Capital Advances to Services (E)
$17
 $17
 
 
Long-Term Accrued Taxes Receivable (Payable) (C)
$(38) $(50) 
      

      
  As of As of 
 Related-Party TransactionsSeptember 30, 2012 December 31, 2011 
  Millions 
 Receivables from PSE&G through BGS and BGSS Contracts (A)$96
 $247
 
 Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A)21
 109
 
 Receivable from (Payable to) Services (B)(23) (26) 
 Tax Receivable from (Payable to) PSEG (C)7
 58
 
 Receivable from (Payable to) PSEG(1) (7) 
 Accounts Receivable—Affiliated Companies, net$100
 $381
 
 
Short-Term Loan to Affiliate (Demand Note to PSEG) (D)
$890
 $907
 
 
Working Capital Advances to Services (E)
$17
 $17
 
 
Long-Term Accrued Taxes Receivable (Payable) (C)
$(66) $(8) 
      

















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PSE&G
The financial statements for PSE&G include transactions with related parties presented as follows: 
       
   Three Months Ended 
   March 31, 
 Related-Party Transactions 2013 2012 
  Millions 
 Expense Billings from Affiliates:     
 Billings from Power through BGSS (A) $(478) $(451) 
 Billings from Power through BGS (A) (193) (189) 
 Administrative Billings from Services (B) (61) (50) 
 Total Expense Billings from Affiliates $(732) $(690) 
       

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  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2012 2011 2012 2011 
  Millions 
 Expense Billings from Affiliates:        
 Billings from Power through BGSS (A)$(67) $(91) $(630) $(958) 
 Billings from Power through BGS (A)(258) (272) (639) (734) 
 Administrative Billings from Services (B)(58) (53) (165) (154) 
 Total Expense Billings from Affiliates$(383) $(416) $(1,434) $(1,846) 
          

      
  As of As of 
 Related-Party TransactionsSeptember 30, 2012 December 31, 2011 
  Millions 
 Payable to Power through BGS and BGSS Contracts (A)$(96) $(247) 
 Payable to Power Related to Gas Supply Hedges for BGSS (A)(21) (109) 
 Payable to Power for SREC Liability (F)(7) (7) 
 Receivable from (Payable to) Services (B)(47) (56) 
 Tax Receivable from (Payable to) PSEG (C)8
 131
 
 Receivable from PSEG6
 8
 
 Receivable from Energy Holdings2
 —
 
 Accounts Payable—Affiliated Companies, net$(155) $(280) 
 
Working Capital Advances to Services (E)
$33
 $33
 
 
Long-Term Accrued Taxes Payable (C)
$(19) $(83) 
      
      
  As of As of 
 Related-Party TransactionsMarch 31, 2013 December 31, 2012 
  Millions 
 Payable to Power through BGS and BGSS Contracts (A)$(223) $(238) 
 Receivable from (Payable to) Power Related to Gas Supply Hedges for BGSS (A)23
 (27) 
 Payable to Power for SREC Liability (F)(7) (7) 
 Receivable from (Payable to) Services (B)(52) (65) 
 Tax Receivable from (Payable to) PSEG (C)160
 256
 
 Receivable from (Payable to) PSEG7
 6
 
 Receivable from Energy Holdings3
 2
 
 Accounts Receivable (Payable)—Affiliated Companies, net$(89) $(73) 
 
Working Capital Advances to Services (E)
$33
 $33
 
 
Long-Term Accrued Taxes Receivable (Payable) (C)
$(39) $(32) 
      
(A)PSE&G has entered into a requirements contract with Power under which Power providedprovides 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)
In 2008, thePursuant to a BPU issued a decision thatOrder, certain BGS suppliers will 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. The BPU order further provided that the2010 and such excess cost maywill be passed on to ratepayers. Following an appeal,In a December 2012 order, the BPU approved a Stipulation of Settlement (Stipulation) that describes the mechanism by which BGS suppliers are to recover reasonable and prudently-incurred costs for these SRECs. In accordance with the Stipulation, New Jersey's EDCs, including PSE&G, made a Verification Filing defining the proposed BGS Supplier payments. PSE&G has estimated and accrued a total liability for the excess SREC cost expected to be recovered from ratepayers of $17 million as of March 31, 2013 and December 31, 2012, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies as of March 31, 2013 and December 31, 2012. Under current accounting guidance, Power was unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G’s liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG’s Condensed Consolidated Balance Sheet as of March 10, 2011, the New Jersey Supreme Court reversed31, 2013 and remanded the BPU’s 2008 order. The Court did not rule on theDecember 31, 2012.


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substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court’s ruling. On May 1, 2012, the BPU affirmed its earlier order and ruled that BGS suppliers could recover verified SREC expenditures above $300 per SREC. The BPU further directed the state’s Electric Distribution Companies (EDCs), including PSE&G, to file by July 1, 2012 a proposed rate recovery mechanism and a method for BGS suppliers to demonstrate that any incremental costs were reasonably and prudently incurred. Such a proposal was filed by the EDCs on June 26, 2012. On October 23, 2012, the EDCs filed a stipulation with the BPU seeking approval of a methodology for reviewing and approving incremental costs owed to BGS suppliers. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of September 30, 2012 and December 31, 2011, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies as of September 30, 2012 and December 31, 2011. Under current accounting guidance, Power was unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G’s liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG’s Condensed Consolidated Balance Sheet as of September 30, 2012 and December 31, 2011.


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Note 18. Guarantees of Debt
Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, (Fossil), PSEG Nuclear LLC (Nuclear) and ER&T.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, 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 Subsidiaries191
 —
 —
 (191) —
 
 Other Income11
 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
 
 Three Months Ended September 30, 2011          
 Operating Revenues$—
 $1,725
 $29
 $(356) $1,398
 
 Operating Expenses1
 1,241
 29
 (356) 915
 
 Operating Income (Loss)(1) 484
 —
 —
 483
 
 Equity Earnings (Losses) of Subsidiaries315
 29
 —
 (344) —
 
 Other Income9
 38
 —
 (10) 37
 
 Other Deductions(1) (8) —
 (1) (10) 
 Other-Than-Temporary Impairments1
 (9) —
 —
 (8) 
 Interest Expense(33) (17) (3) 11
 (42) 
 Income Tax Benefit (Expense)12
 (200) 1
 —
 (187) 
 Income (Loss) on Discontinued Operations, net of tax—
 —
 29
 —
 29
 
 Net Income (Loss)$302
 $317
 $27
 $(344) $302
 
 Comprehensive Income (Loss)$222
 $233
 $27
 $(260) $222
 
            












            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 Three Months Ended March 31, 2013          
 Operating Revenues$—
 $1,803
 $33
 $(389) $1,447
 
 Operating Expenses2
 1,562
 30
 (388) 1,206
 
 Operating Income (Loss)(2) 241
 3
 (1) 241
 
 Equity Earnings (Losses) of Subsidiaries149
 —
 —
 (149) —
 
 Other Income9
 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)$137
 $149
 $—
 $(149) $137
 
 Comprehensive Income (Loss)$169
 $172
 $—
 $(172) $169
 
 Three Months Ended March 31, 2013          
 Net Cash Provided By (Used In) Operating Activities$189
 $574
 $(2) $(189) $572
 
 Net Cash Provided By (Used In) Investing Activities$61
 $(353) $—
 $(29) $(321) 
 Net Cash Provided By (Used In) Financing Activities$(250) $(221) $2
 $217
 $(252) 
 Three Months Ended March 31, 2012        
 
 Operating Revenues$—
 $1,873
 $26
 $(338) $1,561
 
 Operating Expenses(2) 1,433
 27
 (338) 1,120
 
 Operating Income (Loss)2
 440
 (1) —
 441
 
 Equity Earnings (Losses) of Subsidiaries260
 (3) —
 (257) —
 
 Other Income13
 31
 —
 (14) 30
 
 Other Deductions(7) (8) —
 —
 (15) 
 Other-Than-Temporary Impairments—
 (5) —
 —
 (5) 
 Interest Expense(29) (10) (4) 13
 (30) 
 Income Tax Benefit (Expense)14
 (185) 2
 1
 (168) 
 Net Income (Loss)$253
 $260
 $(3) $(257) $253
 
 Comprehensive Income (Loss)$297
 $297
 $(3) $(294) $297
 
 Three Months Ended March 31, 2012          
 Net Cash Provided By (Used In) Operating Activities$124
 $723
 $2
 $(118) $731
 
 Net Cash Provided By (Used In) Investing Activities$242
 $(656) $(13) $62
 $(365) 
 Net Cash Provided By (Used In) Financing Activities$(366) $(73) $10
 $56
 $(373) 
            

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  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 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 Subsidiaries567
 (4) —
 (563) —
 
 Other Income35
 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) 
 Nine Months Ended September 30, 2011        —
 
 Operating Revenues$—
 $5,622
 $106
 $(1,078) $4,650
 
 Operating Expenses2
 4,278
 109
 (1,078) 3,311
 
 Operating Income (Loss)(2) 1,344
 (3) —
 1,339
 
 Equity Earnings (Losses) of Subsidiaries917
 88
 —
 (1,005) —
 
 Other Income28
 159
 —
 (31) 156
 
 Other Deductions(4) (32) —
 (1) (37) 
 Other-Than-Temporary Impairments—
 (10) —
 —
 (10) 
 Interest Expense(115) (38) (13) 32
 (134) 
 Income Tax Benefit (Expense)47
 (592) 6
 —
 (539) 
 Income (Loss) on Discontinued Operations, net of tax—
 —
 96
 —
 96
 
 Net Income (Loss)$871
 $919
 $86
 $(1,005) $871
 
 Comprehensive Income (Loss)$759
 $761
 $86
 $(847) $759
 
 Nine Months Ended September 30, 2011          
 Net Cash Provided By (Used In) Operating Activities$370
 $2,029
 $(319) $(593) $1,487
 
 Net Cash Provided By (Used In) Investing Activities$86
 $(935) $652
 $(821) $(1,018) 
 Net Cash Provided By (Used In) Financing Activities$(456) $(1,091) $(332) $1,413
 $(466) 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 As of March 31, 2013          
 Current Assets$3,926
 $8,180
 $942
 $(10,996) $2,052
 
 Property, Plant and Equipment, net80
 5,972
 941
 —
 6,993
 
 Investment in Subsidiaries4,240
 733
 —
 (4,973) —
 
 Noncurrent Assets189
 1,722
 59
 (150) 1,820
 
 Total Assets$8,435
 $16,607
 $1,942
 $(16,119) $10,865
 
 Current Liabilities$529
 $10,334
 $1,001
 $(10,992) $872
 
 Noncurrent Liabilities508
 2,032
 208
 (153) 2,595
 
 Long-Term Debt2,040
 —
 —
 —
 2,040
 
 Member’s Equity5,358
 4,241
 733
 (4,974) 5,358
 
 Total Liabilities and Member’s Equity$8,435
 $16,607
 $1,942
 $(16,119) $10,865
 
 As of December 31, 2012          
 Current Assets$3,922
 $8,084
 $940
 $(10,712) $2,234
 
 Property, Plant and Equipment, net80
 5,988
 950
 —
 7,018
 
 Investment in Subsidiaries4,317
 733
 —
 (5,050) —
 
 Noncurrent Assets201
 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 Liabilities559
 1,960
 207
 (140) 2,586
 
 Long-Term Debt2,040
 —
 —
 —
 2,040
 
 Member’s Equity5,439
 4,318
 733
 (5,051) 5,439
 
 Total Liabilities and Member’s Equity$8,520
 $16,465
 $1,950
 $(15,903) $11,032
 
            


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(UNAUDITED)


            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 As of September 30, 2012          
 Current Assets$4,182
 $7,926
 $919
 $(10,646) $2,381
 
 Property, Plant and Equipment, net88
 5,835
 948
 1
 6,872
 
 Investment in Subsidiaries4,193
 740
 —
 (4,933) —
 
 Noncurrent Assets175
 1,631
 62
 (127) 1,741
 
 Total Assets$8,638
 $16,132
 $1,929
 $(15,705) $10,994
 
 Current Liabilities$403
 $10,183
 $984
 $(10,643) $927
 
 Noncurrent Liabilities456
 1,754
 204
 (126) 2,288
 
 Long-Term Debt2,386
 —
 —
 —
 2,386
 
 Member’s Equity5,393
 4,195
 741
 (4,936) 5,393
 
 Total Liabilities and Member’s Equity$8,638
 $16,132
 $1,929
 $(15,705) $10,994
 
 As of December 31, 2011          
 Current Assets$4,311
 $7,248
 $951
 $(9,823) $2,687
 
 Property, Plant and Equipment, net66
 5,715
 950
 —
 6,731
 
 Investment in Subsidiaries4,185
 804
 —
 (4,989) —
 
 Noncurrent Assets179
 1,557
 51
 (118) 1,669
 
 Total Assets$8,741
 $15,324
 $1,952
 $(14,930) $11,087
 
 Current Liabilities$172
 $9,549
 $1,003
 $(9,822) $902
 
 Noncurrent Liabilities440
 1,589
 145
 (118) 2,056
 
 Long-Term Debt2,685
 —
 —
 —
 2,685
 
 Member’s Equity5,444
 4,186
 804
 (4,990) 5,444
 
 Total Liabilities and Member’s Equity$8,741
 $15,324
 $1,952
 $(14,930) $11,087
 
            


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(UNAUDITED)


Note 19. Subsequent Event
In late October 2012, high winds, heavy rainfall and the related flooding throughout PSE&G's service territory associated with Hurricane Sandy caused severe damage to PSE&G's transmission and distribution system throughout its service territory as well as to some of Power's generation infrastructure mainly in the northern part of New Jersey. The walls of water created by the storm surge flooded a large number of substations along the Passaic, Raritan and Hudson rivers. The magnitude of the flooding in contiguous areas is unprecedented. During the course of the storm, approximately 1.7 million of PSE&G's customers were without power. In terms of customer outages, this was the most in PSE&G's history, surpassing both Tropical Storm Irene and the October snowstorm in 2011. With the assistance of mutual aid crews from other utilities, PSE&G's associates are working to minimize the length of time its customers are without electric or gas service. PSE&G and Power are unable to estimate the possible loss or range of loss related to Hurricane Sandy; however, such costs could be material.
On October 26, 2012, PSE&G filed a petition with the BPU seeking authorization to defer on its books actually incurred, uninsured, incremental storm restoration costs associated with its gas and electric distribution systems. PSE&G requested similar relief in August 2011 as Tropical Storm Irene approached. Both requests are currently pending before the BPU. Power and PSE&G maintain property insurance for both nuclear and non-nuclear property. PSE&G and Power intend to seek recovery from their insurers for any property damage above their self-insured retentions; however, no assurances can be given relative to the timing or amount of such recoveries.



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ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
This combined MD&A is separately filed by PSEG, Power and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG’s business consists of three reportable segments, which are:
Power, our wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid AtlanticMid-Atlantic United States,
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
Energy Holdings, which principally owns our energy-related leveraged leases and other investments.solar generation projects.
Our business discussion in Part I, Item 1. Business of our 20112012 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 III Item 1A of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Overview of 20112012 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 20122013 and any changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes, the 2011 Form 10-K and the Quarterly Reports on2012 Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.10-K.

OVERVIEW OF 20122013 AND FUTURE OUTLOOK
DuringOur business plan is designed to maintain earnings stability while achieving growth in recognition of market, regulatory and economic trends. We continue to focus on operational excellence to provide the foundation for our financial strength, which enables us to invest in a disciplined way.
Our financial results for the first ninethree months of 2013 were lower when compared to the first quarter of 2012. In the power markets in which our generation fleet operates, natural gas prices have a major impact on the price that generators receive for their output. While wholesale natural gas prices during the period remained low relative to historic prices following multiple years of steep declines, our generation fleet was able to capitalize on price volatility in the quarter resulting from operating conditions on the interstate pipelines in New York and New England. Financial results for our generation operations were also favorably impacted by increased output and higher market prices driven by colder winter weather in the period as compared to the same period in 2012, our results continued to be adversely impactedpartially offset by lower prices for electricityon basic generation service (BGS) and natural gasother contracted positions. Despite the modest improvements in pricing in the marketsfirst quarter, the financial results for our generation operations include significant mark-to-market losses due to the impact of the rising prices on our forward sale positions.
Our utility business benefited from favorable weather and transmission formula rates, but financial results were impacted by the absence of last year's tax settlement. In the first quarter of 2013 we serve.continued to invest capital in transmission and distribution infrastructure projects, aimed at maintaining the reliability and resiliency of our service to our customers. We receive contemporaneous and reasonable risk-adjusted returns on these projects. Over the past few years, these types of investments at our regulated utility have altered the business mix of our operations.
Partially offsetting this lower commodity pricingAt year-end 2012, we were higherseverely impacted by Superstorm Sandy, which resulted in the highest level of customer outages in our history. We sustained significant damage to some of our generation, transmission revenuesand distribution facilities. On February 20, 2013, we filed a petition with the New Jersey Board of Public Utilities (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 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.
In developing and implementing our 2012 Annual Formula Rate Update with the Federal Energy Regulatory Commission (FERC), which provided for approximately $94 million in increased annual transmission revenues effective January 1, 2012. We filed our 2013 Annual Formula Rate Update with FERC in October 2012, which would provide for approximately $174 million in increased annual transmission revenues effective January 1, 2013.
Under the Reliability Pricing Model capacity auction in May 2012, for the 2015-2016 period, Power cleared approximately 9,000 MW of its generating capacity at an average price of $167 per MW-day.
Our volumes of gas sales were lower in the first nine months of 2012, but the decline in gas revenues was significantly mitigated by the favorable impact of a $57 million increase due to recovery of deficiency revenues through the Weather Normalization Charge (WNC). PSE&G’s WNC is a rate mechanism that allows us to increase our rates, subject to an earnings test, to compensate for lower revenuesstrategy, we receive from customers as a result of warmer-than-normal winters and to decrease our rates to make up for higher revenues we receive as a result of colder-than-normal winters.
For the remainder of 2012 and beyond, the key issues we expect our business to confront include:
the continuing potential for sustained lower natural gas and electricity prices, both at market hubs and at locations where we operate,
customer migration away from our BGS supply contracts,
uncertainty in the national and regional economic recovery and continuing customer conservation efforts, which impacts customer demand,
regulatory and political uncertainty, particularly with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, and
challenges to competitive markets, including support for subsidized generation in many states, particularly in New Jersey.
Our future success will depend on our ability to respond to these challenges and take advantage of opportunities presented by these and othermonitor significant regulatory and legislative initiatives. In orderdevelopments which may affect our operations and financial results. Competitive wholesale power market design is of particular importance to do this,our results and we must:
continue to focus on controlling costs while maintaining our safety, reliabilityadvocate for policies and compliance standards,
successfully re-contract our open supply positions,rules in response to subsidized generation and procurement activities in

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execute our capital investment program, including investments for growth that yield contemporaneous and attractive risk adjusted returns.
There have also been certain significant regulatory and legislative developments duringNew Jersey in connection with the year which may affect our operations in the future as new rules and regulations are adopted. For additional information on these issues, see Item 5. Other Information.
New Jersey’s Long-Term Capacity Agreement Pilot Program Act (LCAPP Act), actions by(LCAPP) and in Maryland through the Maryland Public Service Commission'sCommission Request for Proposal or similar activity in other states(RFP), as well as at the Federal Energy Regulatory Commission (FERC) with regard to subsidize new generation may artificially depress energy and capacity prices in the competitive wholesale market and have the potentialmodifications to harm competitive markets and adversely impact our generation business, on both a short-term and long-term basis.
These efforts to artificially depress the wholesale capacity auction were intended to be mitigated by the Minimum Offer Price Rule (MOPR) approved by FERC. The, changes which we believe are necessary to avoid artificial price suppression and other distortions in the capacity markets. Our involvement in litigation with respect to LCAPP, MOPR was intendedand the Maryland RFP continues.
We continued to restrict new natural gas-fired generation from bidding in RPM at less than an established minimum level established by Tariff, or a cost-based bid to the extent that the generator can demonstrate that its costs are lower than the MOPR. The MOPR was in placemonitor and advocate for the May 2012 auction, butdevelopment and implementation of fair and reasonable rules by the U.S. Environmental Protection Agency (EPA). 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 regulations governing hazardous air pollutants under the EPA's Maximum Achievable Control Technology (MACT) rules are also of significance; however, we believe it did not operate to protect the market against these suppression efforts. As a result, discussions among a diverse group of PJM Interconnection L.L.C. (PJM) stakeholders to improve the MOPR ensuedour generation business remains well-positioned for such regulations if and a settlement was recently reached among those stakeholders. PJM is currently educating its stakeholders on the settlement and PJM plans to bring the settlement to a stakeholder vote in November 2012. If this settlement is approved by the when they are implemented.
FERC it will change how the MOPR will be applied in the RPM auction in May 2013 and should enhance the competitiveness of the auction. We cannot predict the outcome of this matter.
FERC'srules under Order 1000 (Order 1000), issued in July 2011, among other things directs regional planners such as PJMaltered the right of first refusal previously held by incumbent utilities to (i) be more flexible in how they plan for future transmission build (ii) eliminate any Right of First Refusal, which permits incumbent transmission owners, like us, the first opportunity to constructall transmission within their respective service territories, subject to certain exceptions,territories. We are opposing these rules in litigation and (iii) allocate costs for transmission projects in a way that roughly matches costshave worked with benefits, while leaving flexibility to the regions to determine precise cost allocation methodologies. In June 2012, PSEG appealed Order 1000 in federal court. Other companies and state commissions have filed appeals as well. PJM has concluded a stakeholder process to develop implementing details regardingrules that mitigate the adverse impact of Order 1000. An expected outcome of this process is the construction of more transmission and the opening up of transmission construction and ownership to third party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specificSpecific implementation of Order 1000 in the various regions, including within our service territory, may expose us to competition within our service territory but could also provide opportunities for constructionus to construct transmission outside of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.
On March 30, 2012, the FERC issued an order finding that allocation of costs associated with high voltage (500 kV and higher) transmission projects in PJM to all customers in PJM is just and reasonable. This order, which has been challenged on rehearing, therefore preserves the current cost allocation for the Susquehanna-Roseland project discussed below. However, the FERC also stated in its order that other cost allocation methodologies could be just and reasonable and this may lead to the adoption of a different cost allocation methodology for transmission in PJM in the future. On October 11, 2012, PSE&G joined with other PJM transmission owners to file with FERC for approval of a consensus cost allocation methodology for transmission projects in PJM.
As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the Nuclear Regulatory Commission (NRC) has been performing additional operational and safety reviews of nuclear facilities in the United States. These reviews and the lessons learned from the events in Japan will result in a series of additional regulations for the nuclear industry. The first regulations have already been issued, and in conjunction with additional regulations, could impact future operations and capital requirements for our facilities. We believe that our nuclear plants currently meet the stringent applicable design and safety specifications of the NRC.
During 2012, the Securities and Exchange Commission and the Commodity Futures Trading Commission (CFTC) continued efforts to enact stricter regulation over swaps and derivatives. The CFTC has issued Notices of Proposed Rulemakings on many of the key issues and is in the process of issuing Final Rules on these issues. In May 2012, the CFTC issued Final Rules regarding the definition of a swap dealer and the definition of a swap. However, in September 2012, a federal court vacated the CFTC's rule on monitoring of position limits for several commodities, including natural gas, thereby indefinitely delaying the effectiveness of these position limits rules. We are carefully monitoring all of these new rules as they are issued to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements.

service territory.
Operational Excellence
Our nuclearWe emphasize operational performance while developing opportunities in our competitive and fossil facilities continued their strong operating performance throughregulated businesses. Flexibility in our generating fleet has allowed us to take advantage of market opportunities presented in the first nine months of 2012. Our

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nuclear units have achieved a capacity factor of 92.5% and our combined cycle units have continued to improve their forced outage rates. Overall, generation volumes forquarter as we remain diligent in managing costs. In the first nine months of 2012 were 40.8 terawatt hours, approximately 2.4% lower than in 2011 due primarily to reduced demand due to milder weather in 2012.
In the second quarter of 2012, we received the final approvals for the 10-year contract that we won in December 20112013, our
outstanding performance allowed us to manage Long Island Power Authority’s electricincrease generation to meet loads, and
construction of transmission and distribution system in Long Island, New York. The contract, which commences January 1, 2014, represents an opportunity to improve returnssolar projects proceeded on schedule and is recognition of our history of strong reliability and customer satisfaction.
In October 2012, we extended the current collective bargaining agreements with three of our labor unions for four years through April 2017. Collectively, these three unions represent approximately 5,200 employees of PSE&G, Power and PSEG Services Corporation.  The extension of these agreements should help to ensure stability and predictability of union costs at a time when we have pressure on earnings caused by the fall in gas and electric prices.
In late October 2012, high winds, heavy rainfall and the related flooding throughout our service territory associated with Hurricane Sandy caused severe damage to our transmission and distribution system throughout our service territory as well as to some of our generation infrastructure mainly in the northern part of New Jersey. The walls of water created by the storm surge flooded a large number of substations along the Passaic, Raritan and Hudson rivers. The magnitude of the flooding in contiguous areas is unprecedented. During the course of the storm, approximately 1.7 million of our customers were without power. In terms of customer outages, this was the most in PSE&G's history, surpassing both Tropical Storm Irene and the October snowstorm in 2011. With the assistance of mutual aid crews from other utilities, our associates are working to minimize the length of time our customers are without electric or gas service. PSE&G and Power are unable to estimate the possible loss or range of loss related to Hurricane Sandy; however, such costs could be material.
On October 26, 2012, we filed a petition with the BPU seeking authorization to defer on our books actually incurred, uninsured, incremental storm restoration costs associated with our gas and electric distribution systems. We requested similar relief in August 2011 as Tropical Storm Irene approached. Both requests are currently pending before the BPU. We maintain property insurance for both nuclear and non-nuclear property. PSE&G and Power intend to seek recovery from their insurers for any property damage above our self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery.within budget.
Financial Strength
Our cash from operations has financial positionremained strong. Duringstrong during the first nine monthsquarter of 2012, we made2013 as we:
had cash on hand of $420 million as of the end of the first quarter of 2013,
extended the expiration date of approximately half of our$2.0 billioncredit facilities, 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 capital expenditures, paid dividends of $538 millionLiquidity and made our entire plannedCapital Resources—Credit Ratings,
completed pension and other postretirement employee benefit contributionsOPEB funding for 2013,
refinanced PSE&G maturing debt at historically low rates and early in the year 2012 of $135 million.
In March 2012, Power’s $1.525 billion and PSEG’s $477 million credit facilities that were set to expire in December 2012 were replacedsecond quarter repaid Power's maturing debt with $1.6 billion and $500 million credit facilities, respectively, expiring in March 2017. As of September 30, 2012, our total credit capacity was $4.3 billion and we had $780 million of cash on hand.hand, and
On January 31, 2012, we entered into a specific matter closing agreement settlingincreased our disputeindicated annual dividend to $1.44.
We expect to be able to fund our proposed Energy Strong program with the IRS over certain lease transactions. This agreement settles the international leveraged lease dispute with finality for all tax periods in which we realized tax deductions from these transactions. Also on January 31, 2012, we signed a settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, we executed a formal settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements conclude 10 years of audits for usinternally generated cash and the leasing issue for all tax years.external debt financing.
Disciplined Investment
We seek to invest in areas that complement our existing businessesbusiness and provide attractivereasonable risk-adjusted returns. These areas include upgrading criticalour energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. We also have several projects where we are investingIn addition to continue to improve our operational performance. Over the past few years, we have shifted our focus to investing at the utility. Our capital expenditure forecast includes over $6.7 billion in spending over the next three years, over 75% of which is at PSE&G.
On October 1, 2012, the National Park Service (NPS) issued a final Environmental Impact Statement (EIS), affirming our and PPL Electric Utilities Corporation's choice of route for the Susquehanna-Roseland transmission line project that follows the existing right-of-way. On October 15, 2012, several environmental groups filed a complaint in federal court challenging the NPS' issuance of the final EIS, seeking to set aside the EIS and to enjoin implementation of the NPS' decision. If this request for injunctive relief is granted, the construction schedule for the project could be impacted. We have also recently obtained environmental permits for the project from the New Jersey Department of Environmental Protection (NJDEP). We have begun construction in those areas where necessary permits have been obtained. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. The cost of construction is up to

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an estimated $790 million for this project. As of September 30, 2012, total capital expenditures were $261 million.
We are continuing the process of obtaining regulatory approvals for the North East Grid project, a 230 kV project running from Roseland to Hudson with an expected in-service date of June 2015 and an estimated cost of construction of $895 million. As of September 30, 2012, total capital expenditures were $73 million. In June 2012, we obtained the major regulatory approvals for another 230 kV project, the North-Central Reliability project, locatedproposed Energy Strong program discussed above, in the northern and central portionsfirst quarter of New Jersey with an expected in-service date of June 2014 and an estimated cost of construction of up to $390 million. Construction of this project has commenced. As of September 30, 2012, total capital expenditures for this project were $117 million.
2013 we
We have made additional investments in solar power transmission infrastructure projects,
continued to execute our existing BPU-approved utility programs,
in New Jersey. Under our solar loan program we have providedApril 2013, reached a total of $192 million in loans for 812 projects as of September 30, 2012, representing 61 MW to date. Under our Solar 4 All program, we have made total capital expenditures of approximately $422 million as of September 30, 2012. Approximately 33 MW of solar panels have been installed on distribution poles and another 38 MW representing 22 projects have been placed into service. Additional projects are in various stages of development. Our total anticipated expenditures to develop all approved 80 MW are approximately $443 million.
On July 23, 2012, the Governor of New Jersey signed legislation that, among other things, requires energy providers, including BGS providers and third party suppliers, to increase the amount of power in their portfolios derived from solar electricity, increasing the demand for Solar Renewable Energy Credits and increasing the potential for additional utility solar generation investment.
On July 31, 2012, we filed for an extension of our Solar 4 All program. In this filing, we are seeking BPU approval for up to $690 million to develop 136 MW of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistentsettlement with the existing Solar 4 All program, we proposeBPU Staff and several parties with respect to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets which will offset the cost of the program.
We also filed for an additional extension of our Solar Loan program (Solar Loan III) on July 31, 2012. In the filing, we are seeking BPU approval to provide financing support for the installation of 98 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, projects are built and loans are closed.
The estimated project costs included in the July 31, 2012 filings for extensions of our Solar 4 All and Solar Loan III programs are not includedas disclosed below in our $6.7 billion three-year capital forecast.
Our Capital Infrastructure Program (CIP II) provides for approximately $273 million in accelerated capital investments in our electric and gas infrastructure through 2012. In early November 2012, dye ti the impacts of Hurricane Sandy, we filed for an extension of time to complete the CIP II projects with the BPU. As of September 30, 2012, total capital expenditures since inception of this program were $224 million.
We made additional expenditures under our Energy Efficiency and Demand Response programs. As of September 30, 2012, total capital expenditures since inception of these projects were $152 million for Energy Efficiency Economic Stimulus (EEE), $4 million for EEE Extension and $44 million for Carbon Abatement and $26 million for Demand Response.
We continued various construction activities at Power, including an extended power uprate at Peach Bottom.  We completed construction of new gas-fired peaking units at Kearny and in Connecticut and primary installation of the Peach Bottom steam path retrofit (see Note 8. Commitments and Contingent Liabilities and Part II. Item 5. Other Information for additional information). This additional capacity at Kearny was bid intoInformation—State Regulation, and has cleared the RPM capacity auction, and the additional capacity in Connecticut is subject to a contract with a Connecticut utility.
We are continuing our efforts to obtain an Early Site Permit for a new nuclear generating station to be located at the current site of Salem and Hope Creek stations. The NRC acceptance review is complete and agency evaluation is underway. There were no petitions filed for permission to intervene. The current schedule supports issuance of the Early Site Permit in 2015.
In September 2012, we acquired a 15 MW solar project currently under construction in Delaware. We expect to completeinitiated construction of this project in the first quarter of 2013. Effective with commencement of commercial operation, the project has a 20-year power purchase agreement for energy and the majority of renewable energy credits with a wholesale electric utility servicing municipal electric distribution utilities in Delaware. We issued guarantees of up to $37 million for payment of obligations related to the construction of the project. The total investment for the project is expected to be approximately $47 million.
In October 2012, we began commercial operation of our newly constructed 25 MW19MW solar project in Arizona. All of the energy, capacity and environmental attributes generated by the project in the first 20 years were sold to an Arizona electric utility under a long-term power purchase agreement. We had issued guarantees of up to $72 million for payment of obligations related to the construction of the project, of which $17 million was outstanding as of

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September 30, 2012. The total investment for the project was approximately $75 million.
There is no guarantee that theour projects described abovecurrently underway or any future initiatives will be achieved since many issues need to be favorably resolved, such as regulatory approvals. Delays in the construction schedules of our projects could impact their costs as well as the timing of expected revenues.

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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 and to respond to the issues and challenges described below and take advantage of these and other regulatory and legislative initiatives. 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 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 FERC of market design rules that continue to protect competition and achieve appropriate RPM and BGS pricing, and
reach out to and engage multiple stakeholders, including regulators, government officials, customers and investors.

For 2013 and beyond, the key issues and challenges we expect our business to confront 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 national and regional economic recovery and continuing customer conservation efforts, 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 projects, including in connection with permitting and regulatory approvals, and
the successful transition to our management of the Long Island Power Authority's (LIPA) transmission and distribution system.


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RESULTS OF OPERATIONS
The results for PSEG, PSE&G, Power and Energy Holdings for the three months and nine monthsended September 30, 2012March 31, 2013 and 20112012 are presented below:

      
  Three Months Ended 
  March 31, 
 Earnings (Losses)2013 2012 
  Millions 
 Power$137
 $253
 
 PSE&G179
 197
 
 Energy Holdings—
 40
 
 Other (A)4
 3
 
 PSEG Net Income$320
 $493
 
      
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Earnings (Losses)2012
 2011
 2012
 2011
 
  Millions 
 Power$181
 $273
 $538
 $775
 
 PSE&G155
 154
 453
 422
 
 Energy Holdings7
 (166) 49
 (164) 
 Other (A)4
 4
 11
 14
 
 PSEG Income from Continuing Operations347
 265
 1,051
 1,047
 
 Income (Loss) from Discontinued Operations (B)—
 29
 —
 96
 
 PSEG Net Income$347
 $294
 $1,051
 $1,143
 
          

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Earnings Per Share (Diluted)2012
 2011
 2012
 2011
 
 PSEG Income from Continuing Operations$0.68
 $0.52
 $2.07
 $2.06
 
 Income (Loss) from Discontinued Operations (B)—
 0.06
 —
 0.19
 
 PSEG Net Income$0.68
 $0.58
 $2.07
 $2.25
 
          
      
  Three Months Ended 
  March 31, 
 Earnings Per Share (Diluted)2013 2012 
 PSEG Net Income$0.63
 $0.97
 
      
(A)Other primarily includes parent company interest and financing costs, donationsactivity and certain administrative and general expenses.
(B)See Note 4. Discontinued Operations and Dispositions.
Our results include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity. This includes the net realized gains, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions. This also includes credit-related impairments on certain NDT securities which are included in Other-Than-Temporary Impairments and the interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO), which is recorded in Operation and Maintenance Expense and the depreciation related to the ARO asset.In September 2012, we restructured a portion of our NDT Fund and realized gains of $59 million.  The investments were transitioned to new investment managers to remove under-performing managers. 
Our results also include the after-tax impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with forward delivery dates.

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The quarter-over-quarter and nine month-over-nine month variances in our Net Income from Continuing Operations include the changes related to NDT and MTM shown in the chart below:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2012 2011 2012 2011 
  Millions, after tax 
 NDT Fund Income (Expense)$40
 $7
 $49
 $49
 
 Non-Trading MTM Gains (Losses)$(76) $8
 $(34) $16
 
          
      
  Three Months Ended 
  March 31, 
  2013 2012 
  Millions, after tax 
 NDT Fund Income (Expense)$9
 $5
 
 Non-Trading MTM Gains (Losses)$(105) $52
 
      

In addition to the changes in NDT and MTM, our $82173 million increase and $4 millionincreasedecrease in Net Income from Continuing Operations for the three months and ninethree months ended September 30, 2012March 31, 2013, respectively, were was driven primarily by:by
higher Operation and Maintenance Costs, including repairs related to damage caused by Superstorm Sandy, and
higher Income Tax Expense due to the absence of the after-tax charge on leveraged leasestax benefits related to Dynegythe settlement of the 1997-2006 Internal Revenue Service (IRS) audits in the prior year,2012.
The decrease was partially offset by
higher capacity revenues and operating reserve revenues in PJM, and
higher transmission formula rates at PSE&G,
partially offset by:
lower average pricing and volumes for electricity sold under our BGS contracts,
lower average prices realized on generation sold into various power pools, and
lower gas volumes and demandrevenues due to milder winter weather.increased investments in transmission projects.

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The increase for the nine months ended September 30, 2012 also includes lower tax expense due to the settlement of 10 years of IRS audits in the first quarter of 2012.


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

          
  Three Months Ended 
Increase/
(Decrease)
 
  March 31,  
  2013 2012 2013 vs. 2012 
  Millions Millions % 
 Operating Revenues$2,786
 $2,875
 $(89) (3) 
 Energy Costs1,155
 1,179
 (24) (2) 
 Operation and Maintenance710
 628
 82
 13
 
 Depreciation and Amortization290
 256
 34
 13
 
 Taxes Other than Income Taxes21
 29
 (8) (28) 
 Income from Equity Method Investments2
 —
 2
 N/A
 
 Other Income and (Deductions)32
 28
 4
 14
 
 Other-Than-Temporary Impairments2
 5
 (3) (60) 
 Interest Expense102
 101
 1
 1
 
 Income Tax Expense220
 212
 8
 4
 
          
Power
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2012 2011 2012 vs. 2011 2012 2011
 2012 vs. 2011 
  Millions Millions % Millions Millions % 
 Operating Revenues$2,402
 $2,620
 $(218) (8) $7,375
 $8,443
 $(1,068) (13) 
 Energy Costs879
 1,167
 (288) (25) 2,819
 3,740
 (921) (25) 
 Operation and Maintenance619
 603
 16
 3
 1,876
 1,829
 47
 3
 
 Depreciation and Amortization286
 263
 23
 9
 797
 739
 58
 8
 
 Taxes Other than Income Taxes24
 31
 (7) (23) 73
 102
 (29) (28) 
 Income from Equity Method Investments7
 1
 6
 N/A
 9
 8
 1
 13
 
 Other Income and (Deductions)95
 34
 61
 N/A
 155
 137
 18
 13
 
 Other-Than-Temporary Impairments2
 8
 (6) (75) 14
 13
 1
 8
 
 Interest Expense106
 117
 (11) (9) 310
 361
 (51) (14) 
 Income Tax Expense241
 201
 40
 20
 599
 757
 (158) (21) 
 Income (Loss) from Discontinued Operations—
 29
 (29) (100) —
 96
 (96) (100) 
                  

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Power

              
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended  
Increase/
(Decrease)
 
  September 30,  September 30,  
  2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 
  Millions 
 Income from Continuing Operations$181
 $273
 $(92) $538
 $775
 $(237) 
 Income (Loss) from Discontinued Operations, net of tax—
 29
 (29) —
 96
 (96) 
 Net Income$181
 $302
 $(121) $538
 $871
 $(333) 
              
        
  Three Months Ended  
Increase/
(Decrease)
 
  March 31,  
  2013 2012 2013 vs. 2012 
  Millions 
 Net Income$137
 $253
 $(116) 
        

For the three months and nine monthsended September 30, 2012March 31, 2013, the primary reasons for the $92 milliondecrease and $237116 million decrease in Net Income from Continuing Operations werewere:
lower average prices realized on generation sold into the PJM and New York power pools and MTM losses due in part to adverse changes2013 resulting from an increase in unrealized prices in 2012 foron forward positions in the PJM region,
lower average pricing and lower volumes of electricity sold under our BGS contracts, net of lower cost to serve,
lower volumes on wholesale load contracts in PJM, lower operating reserve, ancillary and Reliability Must Run (RMR) revenues primarily in PJM and New England, and
lower average pricinghigher Operation and volumes of gas sold under our BGSS contracts, net of lower costMaintenance Costs, including costs related to serve.
These decreases were partially offsetdamage caused by
lower operation and maintenance costs in 2012 Superstorm Sandy at our fossil plants.
The decrease for the three months ended September 30, 2012 wasThese decreases in Net Income were partially offset by higher net realized gains on the NDT Fund. The decrease for the nine months ended September 30, 2012 was also attributable to higher operationcapacity revenues and maintenance costs at our nuclear plants and was partially offset by lower interest expense due to the redemptionPJM operating reserve revenues.


62
Table of Senior Notes in April 2011 and December 2011.Contents



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

                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30, 2012  
  2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,038
 $1,398
 $(360) (26) $3,584
 $4,650
 $(1,066) (23) 
 Energy Costs456
 597
 (141) (24) 1,725
 2,335
 (610) (26) 
 Operation and Maintenance255
 262
 (7) (3) 780
 810
 (30) (4) 
 Depreciation and Amortization60
 56
 4
 7
 175
 166
 9
 5
 
 Other Income (Deductions)84
 27
 57
 N/A
 119
 119
 —
 —
 
 Other-Than-Temporary Impairments2
 8
 (6) (75) 14
 10
 4
 40
 
 Interest Expense35
 42
 (7) (17) 97
 134
 (37) (28) 
 Income Tax Expense133
 187
 (54) (29) 374
 539
 (165) (31) 
 Income (Loss) from Discontinued Operations—
 29
 (29) (100) —
 96
 (96) (100) 
                  
          
  Three Months Ended 
Increase/
(Decrease)
 
  March 31,  
  2013 2012 2013 vs. 2012 
  Millions Millions % 
 Operating Revenues$1,447
 $1,561
 $(114) (7) 
 Energy Costs860
 822
 38
 5
 
 Operation and Maintenance282
 241
 41
 17
 
 Depreciation and Amortization64
 57
 7
 12
 
 Other Income (Deductions)19
 15
 4
 27
 
 Other-Than-Temporary Impairments2
 5
 (3) (60) 
 Interest Expense30
 30
 —
 —
 
 Income Tax Expense91
 168
 (77) (46) 
          


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Three Months Ended September 30, 2012March 31, 2013 As Compared to 20112012

Operating Revenues decreased $360114 million due to
Generation Revenues decreased $323185 million due primarily to
lower net revenues of $226$244 million due primarily to lower average realized prices for our generation sold into the PJM and New York power pools and MTM losses due in part to adverse changes2013 resulting from an increase in unrealized prices in 2012 foron forward positions in the PJM region, partially offset by higher generation sold in the PJM and New England regions at lower average realized prices in PJM,
a decrease of $78$32 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts, as a result of customer migration, and
a net decrease of $47$43 million due primarily to lower volumes on wholesale load contracts in both the PJM and New England regions,
partially offset by a net increase of $28$134 million due to higher capacity payments received in the PJM power poolrevenues resulting from higher auction prices partly offset by lowerand an increase in operating reserve revenue in 2012 resulting from lower demand and lower market prices, lower ancillary revenues and lower RMR revenuesPJM in the PJM region.2013.
Gas Supply Revenues decreasedincreased $3771 million due primarily to
a decreasenet increase of $29$50 million in sales under the BGSS contract, substantially comprised of higher sales volumes due to colder average temperatures during 2013, partially offset by lower average gas prices, on lower volumesand
an increase of sales in the third quarter of 2012, and
a net decrease of $8$21 million due primarily to higher volumes ofaverage prices from sales to third party customers offset by lower average prices.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 decreasedincreased $14138 million due to
Generation costsdecreased$105 million due primarily to $55 million of lower fuel costs, reflecting the utilization of lower volumes of coal and oil and lower average natural gas prices, partially offset by the utilization of higher volumes of natural gas and higher nuclear fuel prices. The decrease was also attributable to $38 million in lower energy purchases in the PJM region as a result of lower load contract volumes in 2012, and $12 million of lower emission charges due to lower coal generation in the PJM and New England regions.
Gas costs decreasedincreased $3631 million, principally related to obligations under the BGSS contract, reflecting higher sales volumes in 2013 due to colder average temperatures in 2013, partially offset by lower average gas inventory costs coupled with lower sales volumes in the third quarter of 2012.costs.
Operation and Maintenancedecreased$7 million due primarily to lower fossil outage and maintenance costs in 2012, primarily at our coal/gas-fired Hudson facility in New Jersey and our co-owned coal-fired Conemaugh plant in Pennsylvania.
Depreciation and AmortizationGeneration costs increased$4 million due primarily to placing the new gas-fired peaking units at Kearny, New Jersey and New Haven, Connecticut into service on June 1, 2012, as well as completion of the steam path retrofit upgrade at Peach Bottom Unit 3 in October 2011.
Other Income and (Deductions) net increase of $57 million was due primarily to higher net realized gains from the restructuring of our NDT Fund in September 2012.
Other-Than-Temporary Impairmentsdecreased $6 million due to lower impairments on the NDT Fund in 2012.
Interest Expensedecreased$7 million due to a decrease of $11 million primarily from the early redemption of $600 million of 6.95% Senior Notes in December 2011, partially offset byto an increase of $4$56 million, due to the issuance of $250 million of 2.75% Senior Notes and $250 million of 4.15% Senior Notes in September 2011.
Income Tax Expensedecreased$54 million in 2012 due primarily to lower pre-tax income.
Income (Loss) from Discontinued Operations
In 2011, we sold our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions. In March 2011, we completed the sale of one plant for proceeds of $352 million and an after-tax gain of $54 million. In July 2011, we completed the sale of the second plant for proceeds of $335 million and an after-tax gain of $25 million. The sale of the second plant was reflected in Power’s Condensed Consolidated Financial Statements for the third quarter of 2011. The results of operations for the second plant through sale date, including the after-tax gain on its sale, are included for the third quarter of 2011 in this category. See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions for additional information.


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Nine Months EndedSeptember 30, 2012 As Compared to 2011
Operating Revenuesdecreased$1,066 million due to
Generation Revenuesdecreased$752 million due primarily to
lower net revenues of $355 million due primarily to lower average realized prices for our generation sold into the PJM and New York power pools and MTM losses due in part to adverse changes in unrealized prices in 2012 for forward positions in the PJM region,
a decrease of $215 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts primarily as a result of warmer winter weather in 2012 as well as customer migration,
a net decrease of $132 million due to lower volumes on wholesale load contracts in the PJM and New England regions, and
a decrease of $50 million due to lower operating reserve revenue in 2012 resulting from lower demand and lower average market prices, lower ancillary revenues, lower Reliability Must Run revenues and lower capacity payments received in the PJM region resulting from lower auction prices.
Gas Supply Revenuesdecreased$347 million due primarily to
a decrease of $319 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2012 due to warmer average temperatures during the first quarter of 2012, and
a net decrease of $28 million due to lower average prices partially offset by higher sales volumes to third party customers.
Trading Revenuesincreased$33 million in 2012 due to the discontinuation of trading activities in the second quarter of 2011. As a result, the increase is due primarily to the absence of losses on electric energy supply contracts recognized in 2011.
Operating Expenses
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$610 million due to
Gas costsdecreased$308 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2012 due primarily to warmer average temperatures during the first quarter of 2012.
Generation costsdecreased$302 million due primarily to $237 million of lower fuel costs, reflecting the utilization of lower volumes of both coal and oil and lower average natural gas prices, partially offset by the utilization of higher volumes of coal, natural gas and oil and higher nuclear fuelrealized natural gas prices, partly offset by the favorable MTM impact from higher natural gas prices on forward positions in 2012. The decrease2013. This increase was also attributable to $105largely offset by $38 million of lower congestion costs in the PJM region and $12 million in lower energy purchases, primarily in the PJM region, as a result of lower load contract volumes in 2012, and $26 million of lower emission charges due to lower coal generation in the PJM and New England regions. These decreases were partially offset by an increase of $66 million due primarily to higher congestion costs in the PJM region.2013.
Operation and Maintenance decreasedincreased $3041 million due primarily to lower$28 million in costs incurred from Superstorm Sandy in 2013 at our fossil plants, and higher outage and maintenance costs in 2012,2013, mainly at our gas-fired Bethlehem facility in New York, Bergen and Linden gas-fired plants and Mercer coal-fired plant and coal/gas-fired Hudson plant in New Jersey, and our coal-fired Keystone and Conemaugh plantsplant in Pennsylvania. This decrease was partially offset by refueling costs in 2012 for our 100%-owned Hope Creek nuclear facility as compared to our portion

63
Table of refueling costs in 2011 for our 57%-owned Salem 2 nuclear unit.Contents



Depreciation and Amortization increased $97 million due primarily to a higher depreciable asset bases at Fossil and Nuclear,base, including placing into service the new gas-fired peaking units at Kearny, New Jersey and New Haven, Connecticut on June 1, 2012 and completion of the steam path retrofit upgrade at our co-owned Peach Bottom Unit 32 in October 2011.2012.
Other-Than-Temporary Impairmentsincreased$4 million due primarily to impairments on the NDT Fund in 2012.
Interest Expensedecreased$37 million due primarily to a decrease of $47 million resulting primarily from the maturity of $606 million of 7.75% Senior Notes in early April 2011 and the early redemption of $600 million of 6.95% Senior Notes in December 2011, partially offset by an increase of $12 million due to two $250 million Senior Notes issuances in September 2011.
Income Tax Expensedecreased$165 million in 2012 due primarily to lower pre-tax income.
Income (Loss) from Discontinued Operations
As discussed above, we sold our two Texas plants in March 2011 and July 2011, respectively. The results of operations of both plants, including the after-tax gains from their sales, are included in this category for 2011. See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions for additional information.

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PSE&G

              
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2012 2011 2012 vs. 2011 2012 2011 2012 vs. 2011 
  Millions 
 Income from Continuing Operations$155
 $154
 $1
 $453
 $422
 $31
 
 Net Income$155
 $154
 $1
 $453
 $422
 $31
 
              
For the three months ended September 30, 2012, the primary reason for the $1 millionincrease in Income from Continuing Operations was
higher transmission formula rates.
For the nine months ended September 30, 2012, the primary reasons for the $31 millionincrease in Income from Continuing Operations were
higher transmission formula rates, and
tax benefits related to settlement of IRS audits,
partially offset by lower gas volumes and demands due to milder winter weather.
The quarter and year-to-date details for these variances are discussed below:

                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,683
 $1,841
 $(158) (9) $5,029
 $5,718
 $(689) (12) 
 Energy Costs756
 943
 (187) (20) 2,380
 3,124
 (744) (24) 
 Operation and Maintenance366
 342
 24
 7
 1,092
 1,014
 78
 8
 
 Depreciation and Amortization216
 197
 19
 10
 594
 548
 46
 8
 
 Taxes Other Than Income Taxes24
 31
 (7) (23) 73
 102
 (29) (28) 
 Other Income (Deductions)10
 6
 4
 67
 31
 14
 17
 N/A
 
 Other-Than Temporary Impairments—
 —
 —
 N/A
 —
 1
 (1) (100) 
 Interest Expense73
 77
 (4) (5) 220
 234
 (14) (6) 
 Income Tax Expense (Benefit)103
 103
 —
 —
 248
 287
 (39) (14) 
                  

Three Months EndedSeptember 30, 2012 As Compared to 2011
Operating Revenuesdecreased$158 million due primarily to
Commodity Revenuedecreased$187 million due to lower Electric and Gas revenues. This is entirely offset by savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
Electric revenues decreased$158 million due primarily to $141 million in lower BGS revenues and $17 million in lower revenues from the sale of Non-Utility Generation (NUG) energy and collections of Non-Utility Generation Charges (NGC) due primarily to lower prices. BGS sales decreased11% due primarily to customer migration to third party suppliers (TPS); in contrast, delivery sales decreased only 1%.
Gas revenues decreased$29 million due to lower BGSS prices of $26 million and lower BGSS volumes of $3 million due to weather.

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Other Operating Revenues decreased $3 million due primarily to a decrease in impairments on the NDT Fund in 2013.
lowerInterest Expensewas flat miscellaneous electric operatingdue primarily to a decrease from lower outstanding debt in 2013 resulting from certain debt redeemed prior to maturity in 2012, offset by an increase due to the absence in 2013 of capitalized interest on the Kearny and New Haven gas-fired peaking projects that were put into service on June 1, 2012.
Income Tax Expensedecreased$77 million in 2013 due primarily to lower pre-tax income.
PSE&G
        
  Three Months Ended 
Increase/
(Decrease)
 
  March 31,  
  2013 2012 2013 vs. 2012 
  Millions 
 Net Income$179
 $197
 $(18) 
        
For the three months ended March 31, 2013, the primary reasons for the $18 milliondecrease in Net Income were
higher Income Tax Expense due to the absence of tax benefits related to the settlement of the 1997-2006 IRS audits in 2012, and
higher Operation and Maintenance costs,
partially offset by higher transmission revenues and due to increased investments in transmission projects.

The quarter-over-quarter details for these variances are discussed below:
          
  Three Months Ended 
Increase/
(Decrease)
 
  March 31,  
  2013 2012 2013 vs. 2012 
  Millions Millions % 
 Operating Revenues$1,995
 $1,939
 $56
 3
 
 Energy Costs967
 1,002
 (35) (3) 
 Operation and Maintenance427
 376
 51
 14
 
 Depreciation and Amortization215
 190
 25
 13
 
 Taxes Other Than Income Taxes21
 29
 (8) (28) 
 Other Income (Deductions)12
 10
 2
 20
 
 Interest Expense73
 73
 —
 —
 
 Income Tax Expense (Benefit)125
 82
 43
 52
 
          

Three Months EndeddecreasedMarch 31, 2013 revenues from our appliance repair business.As Compared to 2012
Operating Revenuesincreased$56 million due primarily to
Delivery Revenues increased $2352 million due primarily to an increase in transmission revenues.
Transmission revenues were $2240 million higher due primarily to net rate increases. resulting primarily from increased capital investments.

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Gas distribution revenues increased $418 million due primarily to a$52 million from higher WNC revenue of $6 million and higher Capital Infrastructure Program (CIP) revenue of $1 million sales volumes, partially offset by lower sales volumeWeather Normalization Clause (WNC) revenue of $333 million.
Electric distribution revenues decreased $36 million due primarily to lower Transitional Energy Facilities Assessment (TEFA) revenue of $75 million due to a lower TEFA rate and lower sales volumes Capital Infrastructure Program (CIP) revenue of $65 million, partially offset by higher sales volumes Solar, Energy Efficiency and Conservation Program (Solar/EE) revenue of $7 million and higher CIP revenue of $34 million.
Clause Revenues increased $935 million due primarily tohigher Societal Benefit Charges (SBC) of $20 million and higher Securitization Transition Charge (STC) revenues of $7 million and higher Societal Benefit Charges (SBC) of $5 million, partially offset by a lower Margin Adjustment Clause (MAC) of $314 million. The changes in STC, MACSBC and SBCSTC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC MAC or STC collections.
Energy Costsdecreased$187 million. This is entirely offset by Commodity Revenue.
Electric costs decreased$158 million due to $75 million or 10% in lower BGS and NUG volumes due to customer migration to TPS, $47 million of lower BGS prices, and $36 million for decreased deferred cost recovery.
Gas costs decreased$29 million due to $26 million or 25% in lower prices and $3 million or 3% in lower sales volumes due primarily to weather.
Operation and MaintenanceOther Operating Revenues increased$24 million due primarily to
a $10 millionincrease in pension and other postretirement benefits (OPEB) expenses,
a $9 millionincrease in costs recognized related to SBC, Solar/EE and CIP,
a $6 millionincrease in transmission related costs, and
a $3 millionincrease in gas bad debt expense,
partially offset by the absence of $13 million in storm damages in prior year.
Depreciation and Amortizationincreased$19 million due primarily to
an increase of $13 million for amortization of Regulatory Assets, and
an increase of $6 million for additional plant in service.
Taxes Other Than Income Taxesdecreased$7 million due to a lower TEFA rate and lower sales volumes for electric and gas.
Other Income and (Deductions) net increase of $4 million was due primarily to an increase in capitalized allowance for Equity Funds used during construction.
Interest Expensedecreased $4 million due primarily to the partial redemption of securitization debt. See Note 9. Changes in Capitalization for details.
Nine Months EndedSeptember 30, 2012increased As Compared to 2011
Operating Revenuesdecreased$689 million due primarily torevenues from our appliance repair business.
Commodity Revenue decreased $74435 million due to lower Electric andrevenues, 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.
Electric revenues decreased $417118 million due primarily to $37195 million in lower BGS revenues and $4623 million in lower revenues from the salea lower volume of NUGsales of Non-Utility Generation (NUG) energy and collections of NGClower Non-Utility Generation Charges (NGC) due primarily to lower prices.tariff rates. BGS sales decreased 14%7% due primarily to customer migration to TPS;third party suppliers (TPS); in contrast, delivery sales decreasedincreased onlyby 2%.
Gas revenues decreasedincreased $32783 million due to lowerhigher BGSS volumes of $16679 million and lowerhigher BGSS prices of $1614 million. The average price of natural gas was 17%lower in 2012 than in 2011.
Clause Revenuesincreased$4 million due primarily to higher STC revenues of $13 million, partially offset by lower SBC of $8 million and lower MAC of $1 million. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC or STC collections.
Delivery Revenuesincreased$51 million due primarily to an increase in transmission revenues.
Transmission revenues were $64 million1% higher due primarily to net rate increases.in 2013 than in 2012.

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Electric distribution revenues decreased$10 million due primarily to lower TEFA revenue of $20 million due to a lower TEFA rate and lower sales volumes of $16 million, partially offset by higher Solar/EE revenue of $17 million and higher CIP revenue of $9 million.
Gas distribution revenues decreased$3 million due primarily to lower sales volume of $57 million, lower TEFA revenue of $11 million due to a lower TEFA rate, partially offset by higher WNC revenue of $57 million and higher CIP revenue of $8 million.
Other Operating Revenueswas flat due primarily to increased revenues from our appliance repair business, offset by lower miscellaneous electric operating revenues.
Energy Costs decreased $74435 million. This is entirely offset by Commodity Revenue.
Electric costs decreased $417118 million or 21% due to $21050 million or 10% in lower BGS and NUG volumes, due to customer migration to TPS, $14522 million of lower BGS and NUG prices, and $6246 million for decreased deferred cost recovery. BGS and NUG volumes decreased 9% due primarily to customer migration to TPS.
Gas costs decreasedincreased $32783 million or 19% due to $16679 million or 17%18% in lowerhigher sales volumes due primarily to weather and $1614 million or 17%1% in lowerhigher prices.
Operation and Maintenance increased $7851 million, of which the most significant components were
a $30 millionincrease in costs recognized related primarily to SBC and CIP,
a $7 millionincrease in costs relating to repairs from Superstorm Sandy and snow removal, and
a $4 millionincrease in appliance service costs.
Depreciation and Amortizationincreased$25 million due primarily to
a $2317 million increase in costs recognized related to SBC, Solar/EEamortization of Regulatory Assets, and CIP,
a$19 millionincrease in transmission related costs,
an $18 millionincrease in pension and OPEB expenses, and
an $7 million increase in payroll costs,
partially offset by the absence of $13 million in storm damages in prior year.

Depreciation and Amortizationincreased$46 million due primarily to
an increase of $30 million for amortization of Regulatory Assets, and
an increase of $18 million for additional plant in service.
Taxes Other Than Income Taxes decreased $298 million due to a lower TEFA rate for gas and lower sales volumes for electric and gas.electric.
Other Income and (Deductions) net increase of $172 million was due primarily to aan $13 millionincrease in capitalized allowance for Equity Funds used during construction and a $6 millionincrease in Solar Loan interest income.
Other-Than-Temporary Impairments experienced no material change.
Interest Expense decreased$14 millionwas flat due primarily to the partial redemption of securitization debt.debt and higher interest capitalized related to higher construction work in progress, offset by new debt issued in 2013. See Note 9. Changes in Capitalization for details.
Income Tax Expense decreasedincreased $3943 million due primarily to tax benefits related to settlement of IRS tax audits.
Energy Holdings

              
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30  September 30  
  2012 2011 2012 vs. 2011 2012 2011 2012 vs. 2011 
  Millions 
 Income from Continuing Operations$7
 $(166) $173
 $49
 $(164) $213
 
 Net Income$7
 $(166) $173
 $49
 $(164) $213
 
              

For the three months ended September 30, 2012, the primary reason for the $173 million increase in Income from Continuing Operations was the absence of the after-tax charge on leveraged leases related to Dynegy in the prior year.

For the and nine months ended September 30, 2012, the primary reasons for the $213 millionincrease in Income from Continuing Operations were the absence of the after-tax charge on leveraged leases related to Dynegy in prior year and the tax benefits related to the settlement of the 1997-2006 IRS tax audits in the first quarter of 2012.2012 and higher pre-tax income.


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Energy Holdings
        
  Three Months Ended 
Increase/
(Decrease)
 
  March 31,  
  2013 2012 2013 vs. 2012 
  Millions 
 Net Income$—
 $40
 $(40) 
        

For the three months ended March 31, 2013, the primary reason for the $40 milliondecrease 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 direct operating subsidiaries.
Operating Cash Flows
Our operating cash flows combined with cash on hand and financing activities are expected to be sufficient to fund capital expenditures and shareholder dividend payments.
For the ninethree months ended September 30, 2012March 31, 2013, our operating cash flow decreased $98211 million as compared to the same period in 2011.2012. The net change was due primarily to net changes from Power and PSE&G, as discussed below.
Power
Power’s operating cash flow decreased $315159 million from $1,487731 million to $1,172572 million for the ninethree months ended September 30, 2012,March 31, 2013, as compared to the same period in 2011,2012, primarily resulting from lower earnings partially offset byand a decreasean increase of $8783 million in benefit plan funding.margin deposits, partially offset by a net increase of $71 million due primarily to higher fuel inventories used to satisfy our gas supply obligations.
PSE&G
PSE&G’s operating cash flow increaseddecreased $16937 million from $872366 million to $1,041329 million for the ninethree months ended September 30, 2012March 31, 2013, as compared to the same period in 2011,2012, due primarily to a higher earnings combined with
a decrease of $174186 million related to higher customer billings due to colder weather in benefit plan funding, and2013, partially offset by an
a decreaseincrease of $175 million in net prepayments,
partially offset by a decrease of $164106 million due to lower collectionsa net change in Regulatory Assets and Liabilities primarily related to the overrecovery of customer receivables.gas costs and collection of Gas Weather Normalization Charges.
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. Both commercial paper programs are fully back-stopped by their own separate credit facilities.
The commitments under our credit facilities are provided by a diverse bank group. 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 March 31, 2013, our total credit capacity was $4.3 billion.
As of September 30, 2012March 31, 2013, no single institution represented more than 8% of the total commitments in our credit facilities.
As of September 30, 2012March 31, 2013, 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; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of September 30, 2012March 31, 2013 were as follows:

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  As of September 30, 2012   
 Company/Facility
Total
Facility
 Usage  
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
  Millions     
 PSEG           
 5-year Credit Facility$500
 $4
(A)  $496
 Mar 2017 Commercial Paper (CP) Support/Funding/Letters of Credit 
 5-year Credit Facility500
 —
   500
 Apr 2016 CP Support/Funding/Letters of Credit 
 Total PSEG$1,000
 $4
   $996
     
 Power           
 5-year Credit Facility$1,600
 $119
(A)  $1,481
 Mar 2017 Funding/Letters of Credit 
 5-year Credit Facility1,000
 —
   1,000
 Apr 2016 Funding/Letters of Credit 
 Bilateral Credit Facility100
 100
(A)  —
 Sept 2015 Letters of Credit 
 Total Power$2,700
 $219
   $2,481
     
 PSE&G           
 5-year Credit Facility$600
 $1
(A)  $599
 Apr 2016 CP Support/Funding/Letters of Credit 
 Total PSE&G$600
 $1
   $599
     
 Total$4,300
 $224
   $4,076
     
             
             
  As of March 31, 2013   
 Company/Facility
Total
Facility
 Usage  
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
  Millions     
 PSEG           
   5-year Credit Facility$500
 $4
(D)  $496
 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
 $4
   $996
     
 Power           
   5-year Credit Facility$1,600
 $60
(D)  $1,540
 Mar 2017 Funding/Letters of Credit 
   5-year Credit Facility (B)1,000
 —
   1,000
 Mar 2018 Funding/Letters of Credit 
   Bilateral Credit Facility100
 100
(D)  —
  Sept 2015 Letters of Credit 
 Total Power$2,700
 $160
   $2,540
     
 PSE&G           
  5-year Credit Facility (C)$600
 $178
(E)  $422
 Mar 2018 CP Support/Funding/Letters of Credit 
 Total PSE&G$600
 $178
   $422
     
 Total$4,300
 $342
   $3,958
     
             
(A)In April 2016, this facility will be reduced by $23 million.
(B)In April 2016, this facility will be reduced by $48 million.
(C)In April 2016, this facility will be reduced by $29 million.
(D)Includes amounts related to letters of credit outstanding.

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(E)Includes amounts related to CP and letters of credit.
Long-Term Debt Financing
Power had $300 million of 2.50%Senior Notes that matured in April 2013. PSE&G has $150 million5.00%Medium Term Notes maturing in January 2013 and $300 million of 5.38% Medium Term Notes maturing in September 2013. Power has and $300275 million of 2.50%6.33% SeniorMedium Term Notes maturing in AprilNovember 2013. For a discussion of our long-term debt transactions during 2012,2013, see Note 9. Changes in Capitalization.
Common Stock Dividends
For information related to cash dividends on our common stock, see Note 15. Earnings Per Share. On July 17, 2012, the Board of Directors declared a quarterly dividend of $0.3550 per share of common stock for the third quarter of 2012. Share and Dividends.
We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies' ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
In May 2012, S&P published an updated credit opinion for PSEG that left its ratings and outlook unchanged. In October 2012, S&P published updated credit opinions that left the ratings and outlooks for Power and PSE&G unchanged. In May 2012, Moody's published updated credit opinions on PSEG, Power and PSE&G. Moody's upgraded PSE&G's Mortgage Bond Rating to A1 from A2 and revised the outlook to stable from positive. PSEG's and Power's ratings and outlooks remained unchanged. In July 2012,January 2013, Fitch published updated credit opinions on PSEG, Power and PSE&G. Fitch upgradedPSEG's, Power's and PSE&G's Mortgage Bond Rating to A+ from A and its stable outlook remained unchanged. PSEG's and Power's ratings and outlooks remained unchanged. In April 2013, S&P upgraded the corporate credit ratings on PSEG, Power and PSE&G to BBB+ from BBB and PSE&G's Mortgage Bond rating to A from A-. PSEG's, Power's and PSE&G's outlooks were changed to stable from positive.

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   Moody’s (A)  S&P (B)  Fitch (C) 
 PSEG         
 Outlook Stable  PositiveStable  Stable 
 Commercial Paper P2  A2  F2 
 Power         
 Outlook Stable  PositiveStable  Stable 
 Senior Notes Baa1  BBBBBB+  BBB+ 
 PSE&G         
 Outlook Stable  PositiveStable  Stable 
 Mortgage Bonds A1  A–A  A+ 
 Commercial Paper P2  A2  F2 
           
(A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.
(B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.
(C)Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities.

CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There have been no material changes to our projected construction and investment amounts through 20142015 as disclosed in our Form 10-K for the year ended December 31, 2011.
Power
During the nine months ended September 30, 2012, Power made $322 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $171 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see. See Note 8. Commitments and Contingent Liabilities.

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PSE&G
During the nine months ended September 30, 2012, PSE&G made $1,433 million of capital expenditures, including $1,369 million of investment in plant, primarilyLiabilities for reliability of transmission and distribution systems and $64 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $71 million, which is included in operating cash flows.additional information.


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


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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.

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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.

    
 Three Months Ended September 30, 2012MTM VaR (A) 
  Millions 
 95% Confidence Level,  
 Loss could exceed VaR one day in 20 days  
 Period End$11
 
 Average for the Period$12
 
 High$18
 
 Low$7
 
 99.5% Confidence Level,  
 Loss could exceed VaR one day in 200 days  
 Period End$16
 
 Average for the Period$19
 
 High$28
 
 Low$11
 
    
    
 Three Months Ended March 31, 2013MTM VaR 
  Millions 
 95% Confidence Level,  
 Loss could exceed VaR one day in 20 days  
 Period End$10
 
 Average for the Period$19
 
 High$29
 
 Low$10
 
 99.5% Confidence Level,  
 Loss could exceed VaR one day in 200 days  
 Period End$15
 
 Average for the Period$29
 
 High$46
 
 Low$15
 
    
(A)
As of September 30, 2012 and December 31, 2011, there was no trading VaR since we discontinued trading activities in the second quarter of 2011.
See Note 10. Financial Risk Management Activities for a discussion of credit risk.


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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 Chief Financial OfficerCFO and Chief Executive OfficerCEO of each of Public Service Enterprise Group Incorporated, PSEG Power LLC, and Public Service Electric and Gas Company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial OfficerCFO and Chief Executive OfficerCEO 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 thirdfirst quarter of 20122013 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.


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PART II. OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS
We are party to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported underin Item 3 of Part I of the 20112012 Form 10-K, and Item 5 of Part II of Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012, see Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.
Certain information reported under the 2011 Form 10-K is updated below. References are to the related pages on the Form 10-K as printed and distributed.

ITEM 1A.RISK FACTORS
There no additional Risk Factors to be added to those disclosed in Part I Item 1A of our 20112012 Annual Report on Form 10-K and in Part II Item 1A of our June 30, 2012 Quarterly Report on Form 10-Q.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 thirdfirst quarter of 20122013:

      
 Three Months Ended September 30, 2012
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 July 1-July 31—
 $—
 
 August 1-August 3167,900
 $32.65
 
 September 1-September 3026,000
 $31.59
 
      
      
 Three Months Ended March 31, 2013
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 January 1 - January 31—
 $—
 
 February 1 - February 2893,189
 $32.12
 
 March 1 - March 31117,330
 $33.15
 
      

ITEM 5.OTHER INFORMATION
Certain information reported underin the 20112012 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012 areis updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 20112012 Annual Report on Form 10-K and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012.10-K. References are to the related pages on the Form 10-K or Forms 10-Q as printed and distributed.
EMPLOYEE RELATIONS
December 31, 2011 Form 10-K page 17. In October 2012, we extended the current collective bargaining agreements with three of our labor unions for four years through April 2017. Collectively, these three unions represent approximately 5,200 employees of PSE&G, Power and PSEG Services Corporation.   
FEDERAL REGULATION
FERC
Capacity Market Issues—LCAPP
PJM, NYISO,the New York Independent System Operator (NYISO), and ISO-NEthe Independent System Operator-New England (ISO-NE) each have capacity markets that have been approved by the FERC.
Capacity Market Issues—Long-Term Capacity Agreement Pilot Program Act (LCAPP)
December 31, 20112012 Form 10-K page 19, March 31, 2012 Form 10-Q page 77 and16. June 30, 2012 Form 10-Q page 84.In 2011, the State of New Jersey concluded that new natural gas-fired generation was needed and enacted the Long-Term Capacity Agreement Pilot ProgramLCAPP Act (LCAPP Act) to subsidize approximately 2,000 MW of new generation. The LCAPP Act provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey Electric Distribution Companies (EDCs). The SOCA requires that the generator bid in and clear in the PJM RPM base residual auction in each year of the SOCA term in order to receive the subsidized payment. The SOCA requiresrequired each New Jersey EDC to provide the generators with guaranteed capacity payments funded by ratepayers. Each of the New Jersey EDCs, including PSE&G, entered into the SOCAs as directed by the State, but did so under protest reserving their rights. In May 2012, two of the three generators, CPV Shore, LLC (CPV), a subsidiary of Competitive Power Ventures, Inc.

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and Hess Newark, LLC (Hess), a subsidiary of Hess Corporation, that received SOCA contracts cleared the Reliability Pricing ModelRPM auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300 MW of installed capacity. SOCA payments are for a 15 year term, which are scheduled to commence for CPV in the 2015/2016 delivery year and for Hess in the 2016/2017 delivery year, provided that they satisfy their obligations under the SOCA and that the SOCA remains in effect.
Legal challenges to the BPU’sBPU's implementation of the LCAPP Act were filed in New Jersey appellate court and the challenge filed by the EDCs has been remanded back to the BPU for consideration of certain procedural issues.appeal remains pending. In addition, the LCAPP Act has been challenged on constitutional grounds in federal court. On September 28, 2012, the judge in the federal action denied all motions for summary judgmentcourt and set the issues for a full hearing.that proceeding is ongoing.
Maryland ishas also takingtaken action to subsidize above-market new generation. InOn April 2012,16, 2013, the Maryland PUCPublic Service Commission (PSC) issued an order requiringdirecting the Maryland utility companies to enter intoexecute a contract with CPV to build a new 661 MW natural gas-fired, combined cycle station in Maryland with an in-service date of June 2015. In the May 2012 RPM auction, the CPV generator cleared the auction. We have joined other generators in challenging this orderMaryland's actions on constitutional grounds in federal court.

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Transmission Regulations—Transmission Policy Developments
December 31, 2012 Form 10-K page 17. In 2010, the FERC initiated a proceeding to evaluate whether reforms to current transmission planning and cost allocation rules were necessary to stimulate additional transmission development. The Maryland EDCs have also appealed the April 12, 2012 orderFERC ultimately concluded in state court. Developments in Maryland may stimulateOrder No. 1000 that the construction of subsidized generation and impact energy and capacity prices in PJM.
These effortstransmission should be opened up to artificially depresscompetition by eliminating the wholesale capacity auction were intended to be mitigated by the Minimum Offer Price Rule (MOPR) approved by FERC. The MOPR was intended to restrict new natural gas-fired generation from bidding in RPM at less than an established minimum level established by Tariff, or a cost-based bid to the extent that the generator can demonstrate that its costs are lower than the MOPR. The MOPR was in place for the May 2012 auction, but we believe it did not operate to protect the market against these suppression efforts. As a result, discussions among a diverse group of PJM stakeholders to improve the MOPR ensued and a settlement was recently reached among those stakeholders. PJM is currently educating its stakeholders on the settlement and PJM plans to bring the settlement to a stakeholder vote in November 2012. If this settlement is approved by the FERC, it will change how the MOPR will be applied in the RPM auction in May 2013 and should enhance the competitiveness of the auction. We cannot predict the outcome of this matter.
Transmission Regulation—Transmission Policy Development
December 31, 2011 Form 10-K page 20 and June 30, 2012 Form 10-Q page 84. In July 2011, FERC issued Order 1000 (Order 1000) which, among other things (i) directs regional planners, such as PJM, to modify their planning processes to “consider transmission needs driven by public policy requirements established by state or federal laws or regulations” (ii) directs regional planners to remove the “ right“right of first refusal” (ROFR) from its tariffs and agreements, subject to certain exceptions, under which incumbent transmission companies such as PSE&G have a ROFR to build transmission located within their respective service territories, subject to certain exceptions (iii) requires regional planners to develop regional cost allocation methodologies that take into consideration that costs be “roughly commensurate” with project benefits and (iv) requires regional plannersterritories. We have challenged the FERC's elimination of the ROFR in neighboring regions to have a common interregional cost allocation method for new interregional facilities. We, along with many other parties to the proceeding, sought rehearing of Order 1000. In May 2012, thefederal court. The FERC has recently issued an order that denied rehearing in this proceeding. In June 2012, we filed a Petition for Reviewregarding PJM's implementation of Order 1000 in federal appellate court, inthese new transmission planning and cost allocation rules, under which we plan to challenge the legal basis for the FERC’s actions. Other companies and state commissions have filed appeals as well. PJM has recently concluded a stakeholder process to finalize the rules implementing Order 1000. An expected outcome of this proceeding is the construction of more transmission through “public policy” planning and the opening upcertain types of transmission construction and ownership to third-party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 in the various regions, including within our service territory, may expose usprojects have been opened to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.in PJM.
Transmission Regulation—Regulations—Transmission Expansion
December 31, 20112012 Form 10-K page 21, March 31, 2012 Form 10-Q page 78 and17. June 30, 2012 Form 10-Q page 85.  OnIn October 1, 2012, the National Park Service (NPS) issued a final Environmental Impact Statement (EIS) for the new 500 kiloVolt (kV) Susquehanna-Roseland transmission line, selecting our and PPL Electric Utilities Corporation's choice of route in certain federal park lands subject to the NPS' jurisdiction that follows the existing right of way. On October 15, 2012, severalSeveral environmental groups had filed a complaint in federal court challenging the NPS' issuance of the final EIS, seeking to set aside the EIS and to enjoin implementationasking the court for an injunction that would generally prohibit construction of the NPS' decision. If thisproject within the federal park lands at issue. On February 25, 2013, the federal court denied the environmental groups' request for injunctive relief is granted, the constructionan injunction (without prohibiting seeking an injunction at a later date) and set a schedule for all filings to be before the project could be impacted. We have also recently obtained environmental permits for the project from the New Jersey Department of Environmental Protection (NJDEP). We have begun constructioncourt by June 28, 2013. Construction has been underway in those areas where necessary permits have been obtained. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. Delays in the construction schedule could impact the cost of construction and the timing of expected transmission revenues.
In 2010, certain environmental groups appealed the BPU’s approval of the Susquehanna-Roseland line, although no stay was sought. This appeal remains pending.

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In June 2012, the BPU approved our petition to site the North Central Reliability project. We have also obtained NJDEP approval for the project. This project, which will involve upgrading certain circuits and switching stations from 138 kV to 230 kV, is currently estimated to cost $390 million and has an in-service date of June 2014.
We had previously been directed by PJM to build a 500 kV reliability project from Branchburg to Roseland to Hudson. The scope of this project has since changed; it is now a 230 kV project referred to as the Northeast Grid project, for which we are currently seeking to obtain municipal siting approvals. On July 19, 2012, we filed with FERC seeking to recover about $3.6 million of costs associated with the abandonment of the Branchburg-Roseland-Hudson project. In an order dated September 17, 2012, the FERC granted our request to recover prudently-incurred abandonment costs. However, consistent with recent abandonment decisions involving other companies, the FERC found that the filing lacked sufficient information for FERC to determine the reasonableness of certain abandonment plant costs and set that issue for hearing and settlement judge procedures. On October 17, 2012, we sought rehearing of this decision. We have also begun settlement discussions with other parties to the proceeding.
Transmission Regulations—Transmission Rate Proceedings
June 30,December 31, 2012 Form 10-Q10-K page 18. 85. In September 2011, the Massachusetts Attorney General, along withFebruary 2013, several state utility commissions and consumer advocates, including the BPU and consumer groups from sixthe New England states,Jersey Division of Rate Counsel, filed a complaint at FERC against a group of New England transmission owners seeking to reducechallenging the base return on equity used in calculating these transmission owners’and formula transmission rates. The matter has been set for hearing. rate implementation protocols of transmission owners in Maryland, Pennsylvania, Delaware and New Jersey.
While we are not the subject of this complaint this matternor those reported in our 2012 Form 10-K, the results of these proceedings could set a precedent for the FERC-regulated transmission owners with formula rates in place, such as ours.
Commodity Futures Trading Commission (CFTC)
December 31, 20112012 Form 10-K page 22, March 31, 2012 Form 10-Q page 79 and18. June 30, 2012 Form 10-Q page 85. In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), the SEC and the CFTC are in the process of implementing new rules to effectuate stricter regulation over swaps and derivatives including potentially significant reporting and record-keeping requirements and clearing/collateral requirements. Additionally,To implement the Dodd-Frank Act, will require many swaps and other derivative transactions to be standardized and traded on exchanges or other Derivative Clearing Organizations. Thethe CFTC has issued Notices of Proposed Rulemaking on many ofrules defining the key issues, including defining swapsterm “swap dealer” and swap dealers;“commercial end user.” We are subject to record keeping and data reporting requirements; and margin requirements as well as Final Rules. Specifically, in May 2012, the CFTC issued a Final Rule regarding the definition of a swap dealer. In addition, in August 2012, the CFTC issued a Final Rule regardingapplicable to commercial end users, the definition of a swap and a proposed order regarding exemptions from Commodity Exchange Act provisions for specified Regional Transmission Owners (RTO) / Independent System Operators (ISO) transactions. In September 2012, several industry trade groups filed a request withbut the CFTC has extended the compliance deadline to delay the final implementation dates until all required rules are final. In addition, a federal district court recently vacated the CFTC'sbe phased in from August 19, 2013 to October 31, 2013. The CFTC also issued rules establishing position limits for trading in certain commodities, such as natural gas. Thus,gas, but a federal court vacated these rules. The CFTC has appealed this decision to vacate the effective date of these position limits rules, has been delayed indefinitely.which appeal is pending.
Nuclear Regulatory Commission (NRC)
December 31, 2012 Form 10-K page 19. On March 19, 2013, the NRC initiated a rulemaking process for improvements to venting systems at 31 U.S. boiling water reactors (BWRs) with “Mark I” and “Mark II” containments (similar to those at Fukushima), which include our Hope Creek Unit and Peach Bottom Units 2 and 3. The CFTCNRC expects to finalize an order by June 2013 requiring Mark I and Mark II licensees to upgrade or replace their reliable hardened vent with a containment venting system designed and installed to remain functional during severe accident conditions. The NRC is also issuedplanning to perform a series of no action letters in October 2012 which delay various implementation timeframes through the balance of 2012.
We are continuingtechnical evaluation to analyze the potential impact of these rules, including whether we will fallsupport rulemaking on filtering within the commercial end-user exemption recognized in the Dodd-Frank Act.next year.
STATE REGULATION
Rates
Connecticut Project
June 30, 2012 Form 10-Q page 86. We were selected by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control, in a regulatory process to build 130 MW of gas-fired peaking capacity. The project was placed in service in June 2012. The first of the annual filings to recover the capital and operating costs of the project was submitted in December 2011 to PURA. PURA issued a final decision in early June 2012, authorizing us to recover $14.5 million for the period June 1, 2012 to December 31, 2012. On July 31, 2012, we filed a petition and testimony seeking approval from PURA of a 2013 annual fixed revenue requirement of approximately $20 million, which represents the facility’s fixed operation and maintenance (O&M) costs along with the return of and return on the investment for the calendar year 2013. Variable costs (e.g., fuel, Connecticut’s generation tax, and certain non-fuel O&M expenses) are recovered through a contract for differences. Evidentiary hearings were held in October 2012 and PURA is expected to issue a final decision by the end of 2012 effective January 1, 2013.
Rate Adjustment Clauses
Societal Benefits Charge-Universal Service Fund (USF)Energy Strong Program
December 31, 20112012 Form 10-K page 25 and20. June 30, 2012 Form 10-Q page 86. The USF is an energy assistance program mandated by the BPU to provide payment assistance to low income customers. The Lifeline program is a separate mandated

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energy assistance program to provide payment assistance to elderly and disabled customers. On June 22, 2012, New Jersey’s electric and gas utilities, including us, filed requests to reset the statewide rates for the USF and the Lifeline program. The filed USF rates were set to recover approximately $226 million on a statewide basis. Of this amount, the statewide electric rates are set to recover $169 million with the remaining $57 million recovered through gas rates. The rates for the Lifeline program were set to recover $66 million, $46 million electric and $20 million gas. The filed rates were subsequently updated and approved effective October 1, 2012. We earn no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.
Gas Weather Normalization Charge (WNC)
December 31, 2011 Form 10-K page 25 and June 30, 2012 Form 10-Q page 86. Our WNC is a rate mechanism that allows us to increase our rates to compensate for lower revenues we receive from customers as a result of warmer-than-normal winters and to decrease our rates to make up for higher revenues we receive as a result of colder-than-normal winters. The payments and refunds are subject to certain limitations and rate caps. Unrecovered balances associated with application of the rate cap are deferred until the next recovery period.
The WNC requires us to calculate, at the end of each October – May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. On June 27, 2012, we filed a petition and testimony with the BPU seeking BPU approval to recover $56.6 million in deficiency revenues through the WNC. On September 13, 2012,the BPU approved our recovery of $40.7 million in deficiency revenues which would be recovered from our customers during the 2012-2013 Winter Period (October 1 – May 31). The remaining $15.9 million expected to be recovered will be applied to the 2013-2014 Winter Period, pursuant to the WNC tariff provisions approved by the BPU on July 9, 2010, as part of the Stipulation of Settlement of PSE&G’s 2009 Rate Case. On September 13, 2012, a Decision and Order approving the stipulation for provisional rates was signed effective October 1, 2012.
Solar/EE Recovery Charge
December 31, 2011 Form 10-K page 25 and June 30, 2012 Form 10-Q page 86. On July 2, 2012,In February 2013, we filed a petition with the BPU requesting an increase indescribing the Solar/EE Recovery Charge seekinginvestments we recommend making to recover approximately $61.6 million in electric revenue and $8.5 million in gas revenue on an annual basis. These changes are the result of adjustments in the components of the Solar/EE Recovery Charges including: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic Extension Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All) and Solar Loan II Program. The discovery phase of this proceeding is underway and in October 2012 the matter was assigned to an Administrative Law Judge (ALJ).
Recent Rate Adjustments-Remediation Adjustment Charge (RAC)
December 31, 2011 Form 10-K page 26, March 31, 2012 Form 10-Q page 80 and June 30, 2012 Form 10-Q page 87. In November 2011, we filed a RAC 19 petition with theour BPU requesting a decrease injurisdictional electric and gas RAC revenues on an annual basis of $8.9 millionsystem to harden and $10.1 million, respectively. On October 11, 2012, we receivedimprove resiliency for the Administrative Law Judge's (ALJ) Initial Decision allowing full recovery of RAC 19 costs including costs of the Passaic River and Newark Bay superfund (CERCLA) matters and the Occidental litigation that were allocatedfuture. We have submitted information to PSE&G and included in this request. On October 23, 2012, the BPU issued a final Order approvingwith regard to the ALJ's Initial Decision.
expected impact of Energy Supply
BGSS
December 31, 2011 Form 10-K page 27, March 31, 2012 Form 10-Q page 80 and June 30, 2012 Form 10-Q page 87. On June 1, 2012, we made our annual BGSS filing with the BPU.Strong build on customers. The filing requested a decrease in annual BGSS revenue of $70.7 million, excluding sales and use tax, to be effective October 1, 2012. This represents a reduction of approximately 5.2% for a typical residential gas heating customer. This BGSS reduction will be the ninth consecutive reduction since January 2009. We entered into a Stipulation with the parties which put the requested lower BGSS rate into effect as filed on October 1, 2012 on a provisional basis. A final decision is expected in early 2013.
Energy Policy
Solar Initiatives
December 31, 2011 Form 10-K page 28, March 31, 2012 Form 10-Q page 80 and June 30, 2012 Form 10-Q page 87.
On July 23, 2012, the Governor of New Jersey signed legislation that, among other things, requires energy providers, including BGS providers and third party suppliers,Division of Rate Counsel has stated its opposition to increase the amount of power in their portfolios derived from solar electricity, increasing the demand for Solar Renewable Energy Credits and increasing the potential for additional utility solar generation investment.
On July 31, 2012, we filed for an extensioncertain aspects of our Solar 4 All program. Inproposal, including implementation without a base rate case. We cannot predict the outcome of this filing, we are seeking BPU approval for up tomatter which remains pending before the BPU.

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Energy Policy
Solar
PSE&G has reached an agreement with the Staff of the BPU and certain other parties on its proposal to increase spending on renewable energy under its Solar Loan and Solar 4 All investment programs. Under the agreement, which will now be subject to comment by all parties, PSE&G will invest up to $199 million on new solar (98 MW) as part of the Solar Loan III program. The agreement also provides for PSE&G to invest approximately $247 million to develop 136new solar capacity (42 MW) on landfills and brownfields and 3 MW in smaller pilot programs as part of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistent with the existing Solar 4 All program, we propose to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets.
We also filed for an additional extensionextension. The capital investment would occur over a three year period of our Solar Loan program (Solar Loan III) on July 31, 2012. In the filing, we are seeking BPU approval to provide financing support for the installation of 97.5 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, the projects are built and the loans are closed.
Solar Pilot Recovery Charge (SPRC)
June 30, 2012 Form 10-Q page 87. On July 18, 2012, the BPU approved a Stipulation regarding our March 2010 Solar I filing, effective August 1, 2012. This Order will result in an increase in rates of $2.5 million for our electric customers. On July 2, 2012, we filed a petition with the BPU for an increase in the electric SPRC for the Solar Loan I program. If our filing is approvedtime. A decision by the BPU as filed,is anticipated no later than May 31, 2013.
BPU Storm Generic Proceedings
In March 2013, the result wouldBPU initiated two generic proceedings with the New Jersey utilities, including PSE&G. The first was an Order to evaluate the prudency of storm costs incurred in 2011 and 2012 and the second to evaluate major storm event mitigation proposals. We anticipate that our Energy Strong proposal will be an increaseevaluated in rates to be paid by our electric customers of $17.0 million on an annual basis. The discovery phasethe context of this proceeding is underway and in October 2012 the matter was assigned to an ALJ.latter generic proceeding.
BPU Audits
Management/Affiliate Audit
December 31, 2011 Form 10-K page 29 and June 30, 2012 Form 10-Q page 87. In 2009, the BPU, in accordance with New Jersey statutes, initiated audits of PSE&G with respect to the effectiveness of its management and its compliance with rules governing PSE&G’s interactions with its affiliated companies. The audits were conducted on a combined basis by a consultant who was retained by the BPU. On May 23, 2012, the BPU issued the consultant’s audit report for public comment. The audit report makes a number of findings and recommendations, including the finding that no violations of either the state or federal affiliate rules were found. In accordance with the BPU’s procedural schedule, the comment period ended on September 28, 2012. The BPU is expected to issue an order addressing the audit report's findings and recommendations, although the procedural schedule does not establish a date for a final order in this matter.  
ENVIRONMENTAL MATTERS
Air Pollution Control
Demand Response (DR) Reciprocating Internal Combustion Engines (RICE) Litigation
On March 29 and April 1, 2013, we filed petitions at the EPA and in federal court, respectively, challenging the National Emission Standards for Hazardous Air Pollutants (NESHAP) forRICE issued on January 30, 2013. The finalEPA rule allows owners and operators of stationary emergency RICE to operate their engines as part of an emergency DR program without the installation and operation of emission controls or compliance with emission limits otherwise applicable to non-emergency counterparts. This waiver of NESHAP standards results in disparate treatment of different generation technology types. In our appeal, we are seeking more stringent emission control standards for RICE to support more competitive markets, particularly the PJM capacity market.
Bridgeport Opacity Litigation
Pursuant to the Clean Air Act (CAA), in January 2013 several environmental groups commenced litigation against us with regard to levels of opacity above the required standard at the Bridgeport Harbor Station. We believe the allegations contain many factual inaccuracies. While we cannot predict the outcome of this litigation, we do not expect any material impact on us.
Hazardous Air Pollutants Regulation
December 31, 20112012 Form 10-K page 3024. .In February 2012, the In accordance with a ruling of the United States Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. Thesethe NESHAP Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources. In addition, the EPA published revisions to the New Source Performance Standards (NSPS) for newly-built electric generating units. The MATS are scheduled to go into effect on April 16, 2015 for existing sources and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the Clean Air Act.CAA. The NSPS establishes limits for non-hazardous air pollutants such as sulfur dioxide (SO2), nitrogen oxides (NOx) and particulate matter (PM). In February 2012, members of the electric generating industry filed a petition challenging the MATS for existing source National Emission Standardelectric generating units, the MATS 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 Court of Appeals in support of the EPA's implementation of MATS. The Court of Appeals has split the litigation related to these matters into three cases, addressing separately the existing source NESHAP, new source NESHAPnewly-built electric generating units and the NSPS. These cases remain pending. The EPA has stayed implementation ofrevised the new source NESHAP rule pending its reconsideration until November 2, 2012.MATS for newly-built electric generating units and the NSPS on March 28, 2013. The litigation regarding the MATS and NSPS remains pending.
Cross-State Air Pollution Rule (CSAPR)
December 31, 20112012 Form 10-K page 31, March 31, 2012 Form 10-Q page 81 and24. June 30, 2012 Form 10-Q page 88.On July 6, 2011, the EPA issued the final CSAPR. CSAPR which limits power plant emissions of Sulfur Dioxide (SOSO2) and annual and ozone season NOXNOx in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone National Ambient Air Quality Standards.Standards (NAAQS).
On December 30, 2011,In August 2012, the Court of Appeals issued a ruling to stay CSAPR. On August 21, 2012 the court vacated CSAPR and ordered that the existing Clean Air Interstate Rule (CAIR) requirements remain in effect until an appropriate substitute rule has been promulgated. OnIn October 5, 2012, the EPA filed a request for rehearing. The matter remains pending.rehearing which the Court denied on January 24, 2013.On March 29, 2013, the EPA, as well as a number of environmental groups, petitioned the Supreme Court for review.
Fuel and Waste DisposalWe currently anticipate that CSPAR, if implemented, will not have a material adverse impact to our capital investment program or our units’ operations.
Coal Combustion Residuals (CCRs)


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Climate Change
Regional Greenhouse Gas Initiative (RGGI)
December 31, 20112012 Form 10-K page 34,25. Certain northeastern states (RGGI States), including New York and Connecticut where we have generation facilities, havestate-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO2 emissions.
These rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO2 emissions. Generators are required to submit an allowance for each ton emitted over a three year period (e.g. 2009, 2010, and 2011). Allowances are available through the auction or through secondary markets and were required to be submitted to states by March 31, 2012 Form 10-Q page 82 and for the first compliance period.
On February 7, 2013, the RGGI States released an updated Model Rule that, among other things, reduces the amount of available regional COJune 30, 2012 Form 10-Q page2 90.allowances beginning in 2014. Each RGGI State must implement the changes through state-specific regulations. We do not expect these changes, or any future changes, to the RGGI rules will have a material impact on us.  
Water Pollution Control
Steam Electric Effluent Guidelines
On April 5, 2012, several environmental organizations and CCR marketers (Environmental and Marketer Plaintiffs) brought a citizens' suit against19, 2013, the EPA issued notice of a proposed rule that would further limit the discharge of pollutants in federal court arguingwastewater from the operation of coal-fired generating facilities. Our co-owned Keystone and Conemaugh facilities continue to use technologies that generate these wastewater discharges. However, our other coal-fired facilities no longer discharge many of these types of wastewater pollutants. We are evaluating the EPA has a non-discretionary dutyproposed rule. We are unable to issuepredict the CCR rules by a certain date. On May 15, 2012, the Utility Solid Waste Activities Group (USWAG) Policy Committee filed a Motion to Intervene in order toimpact on Keystone and Conemaugh but do not believe there would be in alignment with the EPA in defending against the environmental organizations' action. After May 2012, all parties agreed to a schedule for submitting briefs in this case. Motions for summary judgment remain pending.any material impact on our other coal-fired facilities.

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ITEM 6.EXHIBITS
A listing of exhibits being filed with this document is as follows:

a. PSEG:  
Exhibit 10:2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013
Exhibit 12: Computation of Ratios of Earnings to Fixed Charges
Exhibit 31: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1: Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United StatesU.S. Code
Exhibit 32.1: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United StatesU.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 10:2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013
Exhibit 12.1: Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.2: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3: Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United StatesU.S. Code
Exhibit 32.3: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United StatesU.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 10:2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013
Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.4: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5: Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.4: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United StatesU.S. Code
Exhibit 32.5: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United StatesU.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



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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)
  
By:
/S/ DEREK M. DIRISIO
 
Derek M. DiRisio
Vice President and Controller
(Principal Accounting Officer)
Date: November 2, 2012April 30, 2013

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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PSEG POWER LLC
(Registrant)
  
By:
/S/ DEREK M. DIRISIO
 
Derek M. DiRisio
Vice President and Controller
(Principal Accounting Officer)
Date: November 2, 2012April 30, 2013


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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)
  
By:
/S/ DEREK M. DIRISIO
 
Derek M. DiRisio
Vice President and Controller
(Principal Accounting Officer)
Date: November 2, 2012April 30, 2013


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