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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, 20142015
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
001-34232
PSEG POWER LLC
(A Delaware Limited Liability Company)
80 Park Plaza
Newark, New Jersey 07102-4194
973 430-7000
http://www.pseg.com
22-3663480
 
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 LLCPublic Service Electric and Gas Company
Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o
     
Public Service Electric and Gas CompanyPSEG Power LLC
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 October 15, 2014,20, 2015, Public Service Enterprise Group Incorporated had outstanding 505,959,967505,961,856 shares of its sole class of Common Stock, without par value.
As of October 15, 2014,20, 2015, 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 and PSEG Power LLC 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.



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Page
FORWARD-LOOKING STATEMENTS
ii
  
PART I. FINANCIAL INFORMATION 
Item 1.Financial Statements 
 
Public Service Enterprise Group Incorporated
1
 
PSEG Power LLCPublic Service Electric and Gas Company
6
 
Public Service Electric and Gas CompanyPSEG Power LLC
11
 Notes to Condensed Consolidated Financial Statements 
 
Note 1. Organization and Basis of Presentation
16
 
Note 2. Recent Accounting Standards
1716
 
Note 3. Variable Interest Entities (VIEs)
1817
 
Note 4. Rate Filings
1918
 
Note 5. Financing Receivables
2019
 
Note 6. Available-for-Sale Securities
2221
 
Note 7. Pension and Other Postretirement Benefits (OPEB)
2827
 
Note 8. Commitments and Contingent Liabilities
2928
 
Note 9. Changes in Capitalization
3635
 
Note 10. Financial Risk Management Activities
3736
 
Note 11. Fair Value Measurements
43
 
Note 12. Other Income and Deductions
51
 
Note 13. Income Taxes
5352
 
Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax
5453
 
Note 15. Earnings Per Share (EPS) and Dividends
5857
 
Note 16. Financial Information by Business Segments
5958
 
Note 17. Related-Party Transactions
6059
 
Note 18. Guarantees of Debt
6261
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
7064
 
Executive Overview of 20142015 and Future Outlook
7064
 
Results of Operations
7670
 
Liquidity and Capital Resources
8175
 
Capital Requirements
8377
 
Accounting Matters
8477
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
8478
Item 4.
Controls and Procedures
8579
  
PART II. OTHER INFORMATION 
Item 1.
Legal Proceedings
8679
Item 1A.
Risk Factors
8679
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
8679
Item 5.
Other Information
8680
Item 6.
Exhibits
9284
 
Signatures
9385


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FORWARD-LOOKING STATEMENTS
Certain of the matters discussed in this report about our and our subsidiaries' future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical 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 filings we make with the United States Securities and Exchange Commission (SEC), including our Annual Report on Form 10-K and subsequent reports on Form 10-Q and Form 8-K and available on our website: http://www.pseg.com. 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,regulations, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, capacity market design, transmission planning, and cost allocation rules, including how transmission projects are 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 and enforcement 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 manage our energy obligations, available supply and risks,
adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry,
any deterioration in our credit quality or the credit quality of our counterparties,
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 and reliable service to our customers, and any inability to obtain sufficient insurance coverage or recover proceeds of insurance with respect to such events,
acts of terrorism, cybersecurity attacks or intrusions that could adversely impact our businesses,
increases in competition in energy supply markets as well as competition for certain 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,
changes in technology, such as distributed generation and micro grids, and greater reliance on these technologies, and
changes in customer behaviors, including increases in energy efficiency, net-metering and demand response.

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

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

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions, except per share data
(Unaudited)
 
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2014 2013 2014 2013 
 OPERATING REVENUES$2,641
 $2,554
 $8,113
 $7,650
 
 OPERATING EXPENSES        
 Energy Costs863
 801
 3,008
 2,711
 
 Operation and Maintenance714
 713
 2,370
 2,069
 
 Depreciation and Amortization318
 313
 919
 886
 
 Taxes Other Than Income Taxes—
 15
 —
 50
 
 Total Operating Expenses1,895
 1,842
 6,297
 5,716
 
 OPERATING INCOME746
 712
 1,816
 1,934
 
 Income from Equity Method Investments3
 4
 10
 9
 
 Other Income75
 59
 185
 172
 
 Other Deductions(9) (12) (31) (54) 
 Other-Than-Temporary Impairments(10) (3) (14) (7) 
 Interest Expense(100) (100) (291) (303) 
 INCOME BEFORE INCOME TAXES705
 660
 1,675
 1,751
 
 Income Tax Expense(261) (270) (633) (708) 
 NET INCOME$444
 $390
 $1,042
 $1,043
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):        
 BASIC505,862
 505,858
 505,937
 505,900
 
 DILUTED507,422
 507,694
 507,402
 507,433
 
 NET INCOME PER SHARE:        
 BASIC$0.88
 $0.77
 $2.06
 $2.06
 
 DILUTED$0.87
 $0.77
 $2.05
 $2.06
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.37
 $0.36
 $1.11
 $1.08
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2015 2014 2015 2014 
 OPERATING REVENUES$2,688
 $2,641
 $8,137
 $8,113
 
 OPERATING EXPENSES        
 Energy Costs815
 863
 2,577
 3,008
 
 Operation and Maintenance746
 714
 2,170
 2,370
 
 Depreciation and Amortization313
 318
 960
 919
 
 Total Operating Expenses1,874
 1,895
 5,707
 6,297
 
 OPERATING INCOME814
 746
 2,430
 1,816
 
 Income from Equity Method Investments3
 3
 10
 10
 
 Other Income47
 75
 171
 185
 
 Other Deductions(14) (9) (36) (31) 
 Other-Than-Temporary Impairments(30) (10) (45) (14) 
 Interest Expense(96) (100) (291) (291) 
 INCOME BEFORE INCOME TAXES724
 705
 2,239
 1,675
 
 Income Tax Expense(285) (261) (869) (633) 
 NET INCOME$439
 $444
 $1,370
 $1,042
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:        
 BASIC505
 506
 505
 506
 
 DILUTED508
 507
 508
 507
 
 NET INCOME PER SHARE:        
 BASIC$0.87
 $0.88
 $2.71
 $2.06
 
 DILUTED$0.87
 $0.87
 $2.70
 $2.05
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.39
 $0.37
 $1.17
 $1.11
 
          

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, 
  2014 2013 2014 2013 
 NET INCOME$444
 $390
 $1,042
 $1,043
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $33, $(16), $21 and $(27) for the three and nine months ended 2014 and 2013, respectively(30) 16
 (17) 27
 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1), $1, $(3) and $4 for the three and nine months ended 2014 and 2013, respectively1
 (1) 4
 (5) 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(2), $(6), $(5) and $(20) for the three and nine months ended 2014 and 2013, respectively3
 9
 9
 28
 
 Other Comprehensive Income (Loss), net of tax(26) 24
 (4) 50
 
 COMPREHENSIVE INCOME$418
 $414
 $1,038
 $1,093
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2015 2014 2015 2014 
 NET INCOME$439
 $444
 $1,370
 $1,042
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $33, $33, $35 and $21 for the three and nine months ended 2015 and 2014, respectively(31) (30) (32) (17) 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1), $(1), $6 and $(3) for the three and nine months ended 2015 and 2014, respectively—
 1
 (9) 4
 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(5), $(2), $(17) and $(5) for three and nine months ended 2015 and 2014, respectively9
 3
 25
 9
 
 Other Comprehensive Income (Loss), net of tax(22) (26) (16) (4) 
 COMPREHENSIVE INCOME$417
 $418
 $1,354
 $1,038
 
          

See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  September 30,
2014		 December 31,
2013		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$703
 $493
 
 Accounts Receivable, net of allowances of $55 and $56 in 2014 and 2013, respectively1,267
 1,203
 
 Tax Receivable14
 109
 
 Unbilled Revenues228
 300
 
 Fuel530
 545
 
 Materials and Supplies, net495
 479
 
 Prepayments175
 89
 
 Derivative Contracts71
 98
 
 Deferred Income Taxes128
 24
 
 Regulatory Assets211
 243
 
 Other24
 31
 
 Total Current Assets3,846
 3,614
 
 PROPERTY, PLANT AND EQUIPMENT31,328
 29,713
 
      Less: Accumulated Depreciation and Amortization(8,492) (8,068) 
 Net Property, Plant and Equipment22,836
 21,645
 
 NONCURRENT ASSETS    
 Regulatory Assets2,569
 2,612
 
 Regulatory Assets of Variable Interest Entities (VIEs)270
 476
 
 Long-Term Investments1,309
 1,313
 
 Nuclear Decommissioning Trust (NDT) Fund1,739
 1,701
 
 Long-Term Receivable of VIE401
 —
 
 Other Special Funds675
 613
 
 Goodwill16
 16
 
 Other Intangibles102
 33
 
 Derivative Contracts29
 163
 
 Restricted Cash of VIEs24
 24
 
 Other331
 312
 
 Total Noncurrent Assets7,465
 7,263
 
 TOTAL ASSETS$34,147
 $32,522
 
      
      
  September 30,
2015		 December 31,
2014		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$271
 $402
 
 Accounts Receivable, net of allowances of $59 and $52 in 2015 and 2014, respectively1,199
 1,254
 
 Tax Receivable5
 211
 
 Unbilled Revenues203
 284
 
 Fuel451
 538
 
 Materials and Supplies, net472
 484
 
 Prepayments180
 108
 
 Derivative Contracts162
 240
 
 Deferred Income Taxes23
 11
 
 Regulatory Assets189
 323
 
 Regulatory Assets of Variable Interest Entities (VIEs)—
 249
 
 Restricted Cash of VIEs26
 —
 
 Other23
 15
 
 Total Current Assets3,204
 4,119
 
 PROPERTY, PLANT AND EQUIPMENT34,625
 32,196
 
      Less: Accumulated Depreciation and Amortization(9,020) (8,607) 
 Net Property, Plant and Equipment25,605
 23,589
 
 NONCURRENT ASSETS    
 Regulatory Assets3,161
 3,192
 
 Long-Term Investments1,235
 1,307
 
 Nuclear Decommissioning Trust (NDT) Fund1,715
 1,780
 
 Long-Term Tax Receivable165
 64
 
 Long-Term Receivable of VIE601
 580
 
 Other Special Funds230
 212
 
 Goodwill16
 16
 
 Other Intangibles122
 84
 
 Derivative Contracts91
 77
 
 Restricted Cash of VIEs—
 24
 
 Other279
 289
 
 Total Noncurrent Assets7,615
 7,625
 
 TOTAL ASSETS$36,424
 $35,333
 
      

See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  September 30,
2014		 December 31,
2013		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$316
 $544
 
 Securitization Debt of VIEs Due Within One Year258
 237
 
 Commercial Paper and Loans—
 60
 
 Accounts Payable1,111
 1,222
 
 Derivative Contracts109
 76
 
 Accrued Interest117
 95
 
 Accrued Taxes168
 37
 
 Clean Energy Program185
 142
 
 Obligation to Return Cash Collateral120
 119
 
 Regulatory Liabilities271
 43
 
 Other481
 488
 
 Total Current Liabilities3,136
 3,063
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)7,298
 7,107
 
 Regulatory Liabilities141
 233
 
 Regulatory Liabilities of VIEs12
 11
 
 Asset Retirement Obligations704
 677
 
 Other Postretirement Benefit (OPEB) Costs1,073
 1,095
 
 OPEB Costs of Servco321
 —
 
 Accrued Pension Costs121
 121
 
 Accrued Pension Costs of Servco78
 —
 
 Environmental Costs438
 414
 
 Derivative Contracts37
 31
 
 Long-Term Accrued Taxes183
 180
 
 Other132
 119
 
 Total Noncurrent Liabilities10,538
 9,988
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT
   
 Long-Term Debt8,321
 7,587
 
 Securitization Debt of VIEs68
 259
 
 Project Level, Non-Recourse Debt—
 16
 
 Total Long-Term Debt8,389
 7,862
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000,000,000 shares; issued, 2014 and 2013—533,556,660 shares4,873
 4,861
 
 Treasury Stock, at cost, 2014— 27,674,968 shares; 2013— 27,699,398 shares(629) (615) 
 Retained Earnings7,938
 7,457
 
 Accumulated Other Comprehensive Loss(99) (95) 
 Total Common Stockholders’ Equity12,083
 11,608
 
 Noncontrolling Interest1
 1
 
 Total Stockholders’ Equity12,084
 11,609
 
 Total Capitalization20,473
 19,471
 
 TOTAL LIABILITIES AND CAPITALIZATION$34,147
 $32,522
 
  

   
      
  September 30,
2015		 December 31,
2014		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$1,038
 $624
 
 Securitization Debt of VIEs Due Within One Year68
 259
 
 Commercial Paper and Loans20
 —
 
 Accounts Payable1,046
 1,178
 
 Derivative Contracts70
 132
 
 Accrued Interest123
 95
 
 Accrued Taxes204
 21
 
 Deferred Income Taxes—
 173
 
 Clean Energy Program185
 142
 
 Obligation to Return Cash Collateral126
 121
 
 Regulatory Liabilities208
 186
 
 Regulatory Liabilities of VIEs3
 —
 
 Other513
 547
 
 Total Current Liabilities3,604
 3,478
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)7,672
 7,303
 
 Regulatory Liabilities181
 258
 
 Regulatory Liabilities of VIEs—
 39
 
 Asset Retirement Obligations776
 743
 
 Other Postretirement Benefit (OPEB) Costs1,250
 1,277
 
 OPEB Costs of Servco480
 452
 
 Accrued Pension Costs373
 440
 
 Accrued Pension Costs of Servco118
 126
 
 Environmental Costs438
 417
 
 Derivative Contracts23
 33
 
 Long-Term Accrued Taxes287
 208
 
 Other156
 112
 
 Total Noncurrent Liabilities11,754
 11,408
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 CAPITALIZATION
   
 LONG-TERM DEBT    
 Total Long-Term Debt8,132
 8,261
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000,000,000 shares; issued, 2015 and 2014—533,556,660 shares4,894
 4,876
 
 Treasury Stock, at cost, 2015— 28,238,912 shares; 2014— 27,720,068 shares(667) (635) 
 Retained Earnings9,005
 8,227
 
 Accumulated Other Comprehensive Loss(299) (283) 
 Total Common Stockholders’ Equity12,933
 12,185
 
 Noncontrolling Interest1
 1
 
 Total Stockholders’ Equity12,934
 12,186
 
 Total Capitalization21,066
 20,447
 
 TOTAL LIABILITIES AND CAPITALIZATION$36,424
 $35,333
 
  

   

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, 
  2014 2013 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$1,042
 $1,043
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization919
 886
 
 Amortization of Nuclear Fuel151
 145
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC103
 242
 
 Non-Cash Employee Benefit Plan Costs36
 182
 
 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes(30) (7) 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives237
 3
 
 Change in Accrued Storm Costs(3) (87) 
 Net Change in Other Regulatory Assets and Liabilities276
 134
 
 Cost of Removal(68) (66) 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(99) (76) 
 Net Change in Margin Deposit(173) 17
 
 Net Change in Certain Current Assets and Liabilities119
 158
 
 Employee Benefit Plan Funding and Related Payments(76) (210) 
 Other102
 71
 
 Net Cash Provided By (Used In) Operating Activities2,536
 2,435
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(1,922) (2,102) 
 Proceeds from Sales of Investments11
 42
 
 Proceeds from Sales of Available-for-Sale Securities1,224
 914
 
 Investments in Available-for-Sale Securities(1,241) (922) 
 Other(60) (20) 
 Net Cash Provided By (Used In) Investing Activities(1,988) (2,088) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans(60) (263) 
 Issuance of Long-Term Debt1,000
 1,500
 
 Redemption of Long-Term Debt(500) (750) 
 Redemption of Securitization Debt(170) (162) 
 Cash Dividends Paid on Common Stock(561) (546) 
 Other(47) (57) 
 Net Cash Provided By (Used In) Financing Activities(338) (278) 
 Net Increase (Decrease) in Cash and Cash Equivalents210
 69
 
 Cash and Cash Equivalents at Beginning of Period493
 379
 
 Cash and Cash Equivalents at End of Period$703
 $448
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$284
 $222
 
 Interest Paid, Net of Amounts Capitalized$269
 $274
 
 Accrued Property, Plant and Equipment Expenditures$286
 $258
 
      

      
  Nine Months Ended 
  September 30, 
  2015 2014 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$1,370
 $1,042
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization960
 919
 
 Amortization of Nuclear Fuel162
 151
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC230
 103
 
 Non-Cash Employee Benefit Plan Costs121
 36
 
 Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes6
 (30) 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(87) 237
 
 Change in Accrued Storm Costs15
 (3) 
 Net Change in Other Regulatory Assets and Liabilities26
 276
 
 Cost of Removal(82) (68) 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(2) (99) 
 Net Change in Certain Current Assets and Liabilities:    
           Tax Receivable206
 95
 
           Accrued Taxes127
 127
 
           Margin Deposit142
 (173) 
           Other Current Assets and Liabilities15
 (103) 
 Employee Benefit Plan Funding and Related Payments(87) (76) 
 Other106
 102
 
 Net Cash Provided By (Used In) Operating Activities3,228
 2,536
 
 CASH FLOWS FROM INVESTING ACTIVITIES

   
 Additions to Property, Plant and Equipment(2,782) (1,922) 
 Proceeds from Sales of Capital Leases and Investments12
 11
 
 Proceeds from Sales of Available-for-Sale Securities1,120
 1,224
 
 Investments in Available-for-Sale Securities(1,163) (1,241) 
 Other(28) (60) 
 Net Cash Provided By (Used In) Investing Activities(2,841) (1,988) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans20
 (60) 
 Issuance of Long-Term Debt600
 1,000
 
 Redemption of Long-Term Debt(300) (500) 
 Redemption of Securitization Debt(191) (170) 
 Cash Dividends Paid on Common Stock(592) (561) 
 Other(55) (47) 
 Net Cash Provided By (Used In) Financing Activities(518) (338) 
 Net Increase (Decrease) in Cash and Cash Equivalents(131) 210
 
 Cash and Cash Equivalents at Beginning of Period402
 493
 
 Cash and Cash Equivalents at End of Period$271
 $703
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$292
 $284
 
 Interest Paid, Net of Amounts Capitalized$265
 $269
 
 Accrued Property, Plant and Equipment Expenditures$321
 $286
 
      
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, 
  2014 2013 2014 2013 
 OPERATING REVENUES$1,138
 $1,174
 $3,824
 $3,818
 
 OPERATING EXPENSES        
 Energy Costs472
 430
 2,036
 1,785
 
 Operation and Maintenance242
 305
 871
 868
 
 Depreciation and Amortization71
 69
 215
 202
 
 Total Operating Expenses785
 804
 3,122
 2,855
 
 OPERATING INCOME353
 370
 702
 963
 
 Income from Equity Method Investments4
 4
 11
 12
 
 Other Income56
 45
 135
 127
 
 Other Deductions(6) (11) (25) (49) 
 Other-Than-Temporary Impairments(10) (3) (14) (7) 
 Interest Expense(31) (26) (92) (85) 
 INCOME BEFORE INCOME TAXES366
 379
 717
 961
 
 Income Tax Expense(144) (153) (277) (384) 
 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED$222
 $226
 $440
 $577
 
      

   

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


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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, 
  2014 2013 2014 2013 
 NET INCOME$222
 $226
 $440
 $577
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $34, $(18), $23 and $(29) for the three and nine months ended 2014 and 2013, respectively(30) 17
 (19) 30
 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $1, $(2) and $4 for the three and nine months ended 2014 and 2013, respectively1
 (1) 4
 (6) 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(1), $(6), $(4) and $(17) for the three and nine months ended 2014 and 2013, respectively2
 8
 7
 25
 
 Other Comprehensive Income (Loss), net of tax(27) 24
 (8) 49
 
 COMPREHENSIVE INCOME$195
 $250
 $432
 $626
 
          

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


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PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
      
  September 30,
2014		 December 31,
2013		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$12
 $6
 
 Accounts Receivable385
 338
 
 Accounts Receivable—Affiliated Companies, net52
 333
 
 Short-Term Loan to Affiliate623
 790
 
 Fuel530
 545
 
 Materials and Supplies, net360
 362
 
 Derivative Contracts50
 57
 
 Prepayments20
 13
 
 Deferred Income Taxes97
 30
 
 Other1
 2
 
 Total Current Assets2,130
 2,476
 
 PROPERTY, PLANT AND EQUIPMENT10,613
 10,278
 
 Less: Accumulated Depreciation and Amortization(3,229) (2,911) 
 Net Property, Plant and Equipment7,384
 7,367
 
 NONCURRENT ASSETS    
 Nuclear Decommissioning Trust (NDT) Fund1,739
 1,701
 
 Long-Term Investments122
 123
 
 Goodwill16
 16
 
 Other Intangibles102
 33
 
 Other Special Funds159
 139
 
 Derivative Contracts11
 72
 
 Other87
 75
 
 Total Noncurrent Assets2,236
 2,159
 
 TOTAL ASSETS$11,750
 $12,002
 
      

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


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PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2014		 December 31,
2013		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$—
 $44
 
 Accounts Payable435
 516
 
 Derivative Contracts109
 76
 
 Accrued Interest43
 28
 
 Other160
 136
 
 Total Current Liabilities747
 800
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)2,092
 2,031
 
 Asset Retirement Obligations415
 400
 
 Other Postretirement Benefit (OPEB) Costs215
 206
 
 Derivative Contracts37
 31
 
 Accrued Pension Costs35
 35
 
 Long-Term Accrued Taxes57
 53
 
 Other94
 91
 
 Total Noncurrent Liabilities2,945
 2,847
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 LONG-TERM DEBT    
 Total Long-Term Debt2,543
 2,497
 
 MEMBER’S EQUITY    
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings4,358
 4,693
 
 Accumulated Other Comprehensive Loss(71) (63) 
 Total Member’s Equity5,515
 5,858
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$11,750
 $12,002
 
      

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


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PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
      
  Nine Months Ended 
  September 30, 
  2014 2013 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$440
 $577
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization215
 202
 
 Amortization of Nuclear Fuel151
 145
 
 Provision for Deferred Income Taxes and ITC5
 96
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives237
 3
 
 Non-Cash Employee Benefit Plan Costs10
 50
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(99) (76) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies17
 (38) 
 Margin Deposit(173) 17

 Accounts Receivable49
 68
 
 Accounts Payable(135) (70) 
 Accounts Receivable/Payable—Affiliated Companies, net299
 329
 
 Other Current Assets and Liabilities28
 21
 
 Employee Benefit Plan Funding and Related Payments(5) (45) 
 Other71
 35
 
 Net Cash Provided By (Used In) Operating Activities1,110
 1,314
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(414) (458) 
 Proceeds from Sales of Available-for-Sale Securities882
 849
 
 Investments in Available-for-Sale Securities(898) (864) 
 Short-Term Loan—Affiliated Company, net167
 157
 
 Other(63) (13) 
 Net Cash Provided By (Used In) Investing Activities(326) (329) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Redemption of Long-Term Debt—
 (300) 
 Cash Dividend Paid(775) (705) 
 Contributed Capital—
 24
 
 Other(3) (2) 
 Net Cash Provided By (Used In) Financing Activities(778) (983) 
 Net Increase (Decrease) in Cash and Cash Equivalents6
 2
 
 Cash and Cash Equivalents at Beginning of Period6
 7
 
 Cash and Cash Equivalents at End of Period$12
 $9
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$87
 $107
 
 Interest Paid, Net of Amounts Capitalized$78
 $72
 
 Accrued Property, Plant and Equipment Expenditures$66
 $64
 
      

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


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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, 
  2014 2013 2014 2013 
 OPERATING REVENUES$1,655
 $1,666
 $5,235
 $5,084
 
 OPERATING EXPENSES        
 Energy Costs668
 661
 2,278
 2,208
 
 Operation and Maintenance366
 408
 1,190
 1,204
 
 Depreciation and Amortization238
 236
 682
 658
 
 Taxes Other Than Income Taxes—
 15
 —
 50
 
 Total Operating Expenses1,272
 1,320
 4,150
 4,120
 
 OPERATING INCOME383
 346
 1,085
 964
 
 Other Income16
 13
 44
 41
 
 Other Deductions(2) (1) (3) (3) 
 Interest Expense(71) (75) (206) (223) 
 INCOME BEFORE INCOME TAXES326
 283
 920
 779
 
 Income Tax Expense(126) (115) (355) (311) 
 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED$200
 $168
 $565
 $468
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2015 2014 2015 2014 
 OPERATING REVENUES$1,766
 $1,655
 $5,234
 $5,235
 
 OPERATING EXPENSES        
 Energy Costs740
 668
 2,176
 2,278
 
 Operation and Maintenance391
 366
 1,171
 1,190
 
 Depreciation and Amortization231
 238
 712
 682
 
 Total Operating Expenses1,362
 1,272
 4,059
 4,150
 
 OPERATING INCOME404
 383
 1,175
 1,085
 
 Other Income22
 16
 59
 44
 
 Other Deductions—
 (2) (2) (3) 
 Interest Expense(67) (71) (203) (206) 
 INCOME BEFORE INCOME TAXES359
 326
 1,029
 920
 
 Income Tax Expense(137) (126) (398) (355) 
 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED$222
 $200
 $631
 $565
 
          

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 COMPREHENSIVE INCOME
Millions
(Unaudited)

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2014 2013 2014 2013 
 NET INCOME$200
 $168
 $565
 $468
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0, $0 and $1 for the three and nine months ended 2014 and 2013, respectively1
 —
 1
 (1) 
 COMPREHENSIVE INCOME$201
 $168
 $566
 $467
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2015 2014 2015 2014 
 NET INCOME$222
 $200
 $631
 $565
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 for the three and nine months ended 2015 and 2014, respectively—
 1
 (1) 1
 
 COMPREHENSIVE INCOME$222
 $201
 $630
 $566
 
          

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 BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2014		 December 31,
2013		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$305
 $18
 
 Accounts Receivable, net of allowances of $55 and $56 in 2014 and 2013, respectively836
 832
 
 Unbilled Revenues228
 300
 
 Materials and Supplies130
 115
 
 Prepayments116
 24
 
 Regulatory Assets211
 243
 
 Derivative Contracts5
 25
 
 Deferred Income Taxes20
 16
 
 Other20
 12
 
 Total Current Assets1,871
 1,585
 
 PROPERTY, PLANT AND EQUIPMENT20,347
 19,071
 
 Less: Accumulated Depreciation and Amortization(5,057) (4,964) 
 Net Property, Plant and Equipment15,290
 14,107
 
 NONCURRENT ASSETS    
 Regulatory Assets2,569
 2,612
 
 Regulatory Assets of VIEs270
 476
 
 Long-Term Investments349
 361
 
 Other Special Funds385
 354
 
 Derivative Contracts8
 69
 
 Restricted Cash of VIEs24
 24
 
 Other151
 132
 
 Total Noncurrent Assets3,756
 4,028
 
 TOTAL ASSETS$20,917
 $19,720
 
      
      
  September 30,
2015		 December 31,
2014		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$14
 $310
 
 Accounts Receivable, net of allowances of $59 and $52 in 2015 and 2014, respectively938
 864
 
 Accounts Receivable-Affiliated Companies7
 274
 
 Unbilled Revenues203
 284
 
 Materials and Supplies146
 133
 
 Prepayments109
 42
 
 Regulatory Assets189
 323
 
 Regulatory Assets of VIEs—
 249
 
 Derivative Contracts4
 18
 
 Deferred Income Taxes47
 24
 
 Restricted Cash of VIEs26
 —
 
 Other17
 7
 
 Total Current Assets1,700
 2,528
 
 PROPERTY, PLANT AND EQUIPMENT22,940
 21,103
 
 Less: Accumulated Depreciation and Amortization(5,419) (5,183) 
 Net Property, Plant and Equipment17,521
 15,920
 
 NONCURRENT ASSETS    
 Regulatory Assets3,161
 3,192
 
 Long-Term Investments335
 348
 
 Other Special Funds52
 53
 
 Derivative Contracts—
 8
 
 Restricted Cash of VIEs—
 24
 
 Other140
 150
 
 Total Noncurrent Assets3,688
 3,775
 
 TOTAL ASSETS$22,909
 $22,223
 
      

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 BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2014		 December 31,
2013		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$300
 $500
 
 Securitization Debt of VIEs Due Within One Year258
 237
 
 Commercial Paper and Loans—
 60
 
 Accounts Payable520
 535
 
 Accounts Payable—Affiliated Companies, net99
 190
 
 Accrued Interest73
 67
 
 Clean Energy Program185
 142
 
 Deferred Income Taxes—
 30
 
 Obligation to Return Cash Collateral120
 119
 
 Regulatory Liabilities271
 43
 
 Other296
 314
 
 Total Current Liabilities2,122
 2,237
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC4,538
 4,406
 
 Other Postretirement Benefit (OPEB) Costs807
 839
 
 Accrued Pension Costs26
 27
 
 Regulatory Liabilities141
 233
 
 Regulatory Liabilities of VIEs12
 11
 
 Environmental Costs386
 363
 
 Asset Retirement Obligations286
 274
 
 Long-Term Accrued Taxes78
 72
 
 Other63
 47
 
 Total Noncurrent Liabilities6,337
 6,272
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT    
 Long-Term Debt5,763
 5,066
 
 Securitization Debt of VIEs68
 259
 
 Total Long-Term Debt5,831
 5,325
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150,000,000 shares authorized; issued and outstanding, 2014 and 2013—132,450,344 shares892
 892
 
 Contributed Capital695
 520
 
 Basis Adjustment986
 986
 
 Retained Earnings4,052
 3,487
 
 Accumulated Other Comprehensive Income2
 1
 
 Total Stockholder’s Equity6,627
 5,886
 
 Total Capitalization12,458
 11,211
 
 TOTAL LIABILITIES AND CAPITALIZATION$20,917
 $19,720
 
      
      
  September 30,
2015		 December 31,
2014		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$171
 $300
 
 Securitization Debt of VIEs Due Within One Year68
 259
 
 Commercial Paper and Loans20
 —
 
 Accounts Payable567
 574
 
 Accounts Payable—Affiliated Companies208
 379
 
 Accrued Interest80
 68
 
 Clean Energy Program185
 142
 
 Deferred Income Taxes—
 165
 
 Obligation to Return Cash Collateral126
 121
 
 Regulatory Liabilities208
 186
 
 Regulatory Liabilities of VIEs3
 —
 
 Other357
 381
 
 Total Current Liabilities1,993
 2,575
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC4,896
 4,575
 
 Other Postretirement Benefit (OPEB) Costs929
 967
 
 Accrued Pension Costs131
 173
 
 Regulatory Liabilities181
 258
 
 Regulatory Liabilities of VIEs—
 39
 
 Environmental Costs387
 364
 
 Asset Retirement Obligations304
 290
 
 Long-Term Accrued Taxes165
 116
 
 Derivative Contracts7
 —
 
 Other58
 67
 
 Total Noncurrent Liabilities7,058
 6,849
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT
   
 Total Long-Term Debt6,441
 6,012
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150,000,000 shares authorized; issued and outstanding, 2015 and 2014—132,450,344 shares892
 892
 
 Contributed Capital695
 695
 
 Basis Adjustment986
 986
 
 Retained Earnings4,843
 4,212
 
 Accumulated Other Comprehensive Income1
 2
 
 Total Stockholder’s Equity7,417
 6,787
 
 Total Capitalization13,858
 12,799
 
 TOTAL LIABILITIES AND CAPITALIZATION$22,909
 $22,223
 
      

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, 
  2014 2013 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$565
 $468
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization682
 658
 
 Provision for Deferred Income Taxes and ITC93
 153
 
 Non-Cash Employee Benefit Plan Costs21
 117
 
 Cost of Removal(68) (66) 
 Change in Accrued Storm Costs(3) (87) 
 Net Change in Other Regulatory Assets and Liabilities276
 134
 
 Net Change in Certain Current Assets and Liabilities:    
 Accounts Receivable and Unbilled Revenues71
 48
 
 Materials and Supplies(15) (4) 
 Prepayments(92) (109) 
 Accounts Payable(3) 3
 
 Accounts Receivable/Payable—Affiliated Companies, net(113) (171) 
 Other Current Assets and Liabilities(6) 29
 
 Employee Benefit Plan Funding and Related Payments(67) (147) 
 Other2
 23
 
 Net Cash Provided By (Used In) Operating Activities1,343
 1,049
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(1,493) (1,628) 
 Proceeds from Sales of Available-for-Sale Securities98
 35
 
 Investments in Available-for-Sale Securities(96) (16) 
 Solar Loan Investments2
 (11) 
 Restricted Funds(1) —
 
 Net Cash Provided By (Used In) Investing Activities(1,490) (1,620) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt(60) (263) 
 Issuance of Long-Term Debt1,000
 1,500
 
 Redemption of Long-Term Debt(500) (450) 
 Redemption of Securitization Debt(170) (162) 
 Contributed Capital175
 100
 
 Other(11) (17) 
 Net Cash Provided By (Used In) Financing Activities434
 708
 
 Net Increase (Decrease) In Cash and Cash Equivalents287
 137
 
 Cash and Cash Equivalents at Beginning of Period18
 116
 
 Cash and Cash Equivalents at End of Period$305
 $253
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$174
 $174
 
 Interest Paid, Net of Amounts Capitalized$188
 $199
 
 Accrued Property, Plant and Equipment Expenditures$238
 $200
 
      
      
  Nine Months Ended 
  September 30, 
  2015 2014 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$631
 $565
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization712
 682
 
 Provision for Deferred Income Taxes and ITC96
 93
 
 Non-Cash Employee Benefit Plan Costs71
 21
 
 Cost of Removal(82) (68) 
 Change in Accrued Storm Costs15
 (3) 
 Net Change in Other Regulatory Assets and Liabilities26
 276
 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues30
 71
 
 Materials and Supplies(13) (15) 
 Prepayments(67) (92) 
 Accounts Payable34
 (3) 
 Accounts Receivable/Payable—Affiliated Companies, net190
 (113) 
 Other Current Assets and Liabilities(18) (6) 
 Employee Benefit Plan Funding and Related Payments(72) (67) 
 Other(35) 2
 
 Net Cash Provided By (Used In) Operating Activities1,518
 1,343
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(1,946) (1,493) 
 Proceeds from Sales of Available-for-Sale Securities16
 98
 
 Investments in Available-for-Sale Securities(18) (96) 
 Other13
 1
 
 Net Cash Provided By (Used In) Investing Activities(1,935) (1,490) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt20
 (60) 
 Issuance of Long-Term Debt600
 1,000
 
 Redemption of Long-Term Debt(300) (500) 
 Redemption of Securitization Debt(191) (170) 
 Contributed Capital—
 175
 
 Other(8) (11) 
 Net Cash Provided By (Used In) Financing Activities121
 434
 
 Net Increase (Decrease) In Cash and Cash Equivalents(296) 287
 
 Cash and Cash Equivalents at Beginning of Period310
 18
 
 Cash and Cash Equivalents at End of Period$14
 $305
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(29) $174
 
 Interest Paid, Net of Amounts Capitalized$186
 $188
 
 Accrued Property, Plant and Equipment Expenditures$251
 $238
 
      

See disclosures regarding Public Service Electric and Gas Company included in the 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, 
  2015 2014 2015 2014 
 OPERATING REVENUES$1,096
 $1,138
 $3,846
 $3,824
 
 OPERATING EXPENSES        
 Energy Costs367
 472
 1,669
 2,036
 
 Operation and Maintenance263
 242
 748
 871
 
 Depreciation and Amortization75
 71
 226
 215
 
 Total Operating Expenses705
 785
 2,643
 3,122
 
 OPERATING INCOME391
 353
 1,203
 702
 
 Income from Equity Method Investments3
 4
 11
 11
 
 Other Income25
 56
 109
 135
 
 Other Deductions(14) (6) (32) (25) 
 Other-Than-Temporary Impairments(30) (10) (45) (14) 
 Interest Expense(30) (31) (94) (92) 
 INCOME BEFORE INCOME TAXES345
 366
 1,152
 717
 
 Income Tax Expense(139) (144) (445) (277) 
 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED$206
 $222
 $707
 $440
 
      

   

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


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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, 
  2015 2014 2015 2014 
 NET INCOME$206
 $222
 $707
 $440
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $32, $34, $33 and $23 for the three and nine months ended 2015 and 2014, respectively(29) (30) (29) (19) 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1), $0, $6 and $(2) for the three and nine months ended 2015 and 2014, respectively—
 1
 (9) 4
 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(1), $(15) and $(4) for the three and nine months ended 2015 and 2014, respectively7
 2
 21
 7
 
 Other Comprehensive Income (Loss), net of tax(22) (27) (17) (8) 
 COMPREHENSIVE INCOME$184
 $195
 $690
 $432
 
          

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


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PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
      
  September 30,
2015		 December 31,
2014		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$15
 $9
 
 Accounts Receivable218
 334
 
 Accounts Receivable—Affiliated Companies158
 313
 
  Tax Receivable3
 3
 
 Short-Term Loan to Affiliate865
 584
 
 Fuel451
 538
 
 Materials and Supplies, net324
 350
 
 Derivative Contracts147
 207
 
 Prepayments36
 17
 
 Other7
 4
 
 Total Current Assets2,224
 2,359
 
 PROPERTY, PLANT AND EQUIPMENT11,273
 10,732
 
 Less: Accumulated Depreciation and Amortization(3,366) (3,217) 
 Net Property, Plant and Equipment7,907
 7,515
 
 NONCURRENT ASSETS    
 Nuclear Decommissioning Trust (NDT) Fund1,715
 1,780
 
 Long-Term Investments116
 121
 
 Goodwill16
 16
 
 Other Intangibles122
 84
 
 Other Special Funds56
 49
 
 Derivative Contracts91
 62
 
 Other67
 60
 
 Total Noncurrent Assets2,183
 2,172
 
 TOTAL ASSETS$12,314
 $12,046
 
      

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


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PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2015		 December 31,
2014		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$853
 $300
 
 Accounts Payable315
 424
 
  Accounts Payable-Affiliated Companies117
 118
 
 Derivative Contracts70
 132
 
 Deferred Income Taxes44
 43
 
 Accrued Interest43
 27
 
 Other132
 140
 
 Total Current Liabilities1,574
 1,184
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)2,148
 2,065
 
 Asset Retirement Obligations469
 450
 
 Other Postretirement Benefit (OPEB) Costs258
 248
 
 Derivative Contracts16
 33
 
 Accrued Pension Costs134
 153
 
 Long-Term Accrued Taxes54
 41
 
 Other121
 71
 
 Total Noncurrent Liabilities3,200
 3,061
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 LONG-TERM DEBT    
 Total Long-Term Debt1,691
 2,243
 
 MEMBER’S EQUITY    
 Contributed Capital2,215
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings4,865
 4,558
 
 Accumulated Other Comprehensive Loss(245) (228) 
 Total Member’s Equity5,849
 5,558
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$12,314
 $12,046
 
      

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


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PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
      
  Nine Months Ended 
  September 30, 
  2015 2014 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$707
 $440
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization226
 215
 
 Amortization of Nuclear Fuel162
 151
 
 Provision for Deferred Income Taxes and ITC109
 5
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(87) 237
 
 Non-Cash Employee Benefit Plan Costs36
 10
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(2) (99) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies113
 17
 
 Margin Deposit142
 (173)
 Accounts Receivable54
 49
 
 Accounts Payable(99) (135) 
 Accounts Receivable/Payable—Affiliated Companies, net115
 299
 
 Other Current Assets and Liabilities(26) 28
 
 Employee Benefit Plan Funding and Related Payments(9) (5) 
 Other117
 71
 
 Net Cash Provided By (Used In) Operating Activities1,558
 1,110
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(797) (414) 
 Proceeds from Sales of Available-for-Sale Securities1,057
 882
 
 Investments in Available-for-Sale Securities(1,083) (898) 
 Short-Term Loan—Affiliated Company, net(281) 167
 
 Other(46) (63) 
 Net Cash Provided By (Used In) Investing Activities(1,150) (326) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Cash Dividend Paid(400) (775) 
 Other(2) (3) 
 Net Cash Provided By (Used In) Financing Activities(402) (778) 
 Net Increase (Decrease) in Cash and Cash Equivalents6
 6
 
 Cash and Cash Equivalents at Beginning of Period9
 6
 
 Cash and Cash Equivalents at End of Period$15
 $12
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$284
 $87
 
 Interest Paid, Net of Amounts Capitalized$76
 $78
 
 Accrued Property, Plant and Equipment Expenditures$70
 $66
 
      

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


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Tabletable of Contentscontents (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) and PSEG Power LLC (Power). Information relating to any individual company is filed by such company on its own behalf. PowerPSE&G and PSE&GPower each is only responsible for information about itself and its subsidiaries.

Note 1. Organization and Basis of Presentation
Organization
PSEG is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are:
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 Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU.
Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy trading functions through its principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC),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 also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU.
PSEG's other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which effective January 1, 2014, operates the Long Island Power Authority's (LIPA) transmission and distribution (T&D) system under a twelve-year Amended and Restatedan Operations Services Agreement (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
Basis of Presentation
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, 2013 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014 and June 30, 2014.
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. 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, 2013.
On December 31, 2013, Energy Holdings distributed the outstanding equity of its 50% interest in a partnership that owns and operates a generation facility in Hawaii and its wholly owned interest in PSEG Solar Source LLC to PSEG. PSEG in turn contributed this distribution to Power as an additional equity investment. This transaction was accounted for as a non-cash transfer of equity interest between entities under common control with prior period financial statements for Power retrospectively adjusted to include the earnings related to the transfer. As a result, Power’s Operating Revenues increased $5 million and $12 million for the three months and nine months ended September 30, 2013, respectively, and Power's Net Income increased $5 million and $15 million for the three months and nine months ended September 30, 2013, respectively.

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Table of Contents (UNAUDITED)2014.


Note 2. Recent Accounting Standards
New Standards Adopted during 2014
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists
This accounting standard was issued to address diversity in practice related to the presentation of an unrecognized tax benefit in certain cases. This standard requires entities to present an unrecognized tax benefit or a portion thereof on the Balance Sheet as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward.
However, the unrecognized tax benefit will be presented on the Balance Sheet as a liability and will not be combined with deferred tax assets in cases where that tax benefit cannot or will not, if permissible, be used to settle any additional income taxes that would result from the disallowance of a tax position.
The standard was effective for fiscal years and interim periods beginning after December 15, 2013. The impact of adopting this standard was immaterial.
New Standards Issued But Not Yet Adopted
Revenue from Contracts with Customers
This accounting standard was issued to clarify the principles for recognizing revenue and to develop a common standard that would remove inconsistencies in revenue requirements; improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provide improved disclosures.
The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.
The update iswas originally to be effective for annual and interim reporting periods beginning after December 15, 2016.2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application is not permitted.will be permitted as of the original effective date. We are currently analyzing the impact of this standard on our financial statements.

Presentation
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table of Financial Statements and Property, Plant and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entitycontents (UNAUDITED)

Amendments to the Consolidation Analysis
This accounting standard was issued to changerespond to concerns regarding the criteriacurrent accounting for consolidation of certain legal entities. Under the new standard, all legal entities are subject to reevaluation under a revised consolidation model which will determine whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities; eliminate the presumption that a general partner should consolidate a limited partnership; affect the consolidation analysis of reporting entities that are involved with VIEs and provide a scope exception from consolidation guidance for reporting discontinued operations. The standard requires that a component of an entity be reportedentities with interests in discontinued operations if the disposal represents a strategic shift that has, or will have, a major effect on the entity’s operations and financial results, including a disposal of a major geographical area, a major line of business, a major equity method investment, orcertain legal entities who must comply with other major parts of an entity.
The amendment should be applied prospectively for all disposals of an entity that occur within interim and annual periods beginning on or after December 15, 2014; and all businesses that, on acquisition, are classified as held for sale that occur within interim and annual periods beginning on or after December 15, 2014. We will evaluate all future disposals under the new guidance beginning on January 1, 2015.
Transfers and Servicing - Repurchase-to-Maturity Transactions, Repurchase-Financings and Disclosures
This standard changes the accounting for repurchase-to-maturity transactions and linked repurchase-financings to secured borrowing accounting, which is consistent with the accounting for other repurchase agreements. It also requires disclosures for repurchase agreements, securities lending transactions, and repurchase-to-maturity transactions that are accounted for as secured borrowings.
This standard is effective for the first interim or annual period beginning after December 15, 2014.
We are currently analyzing this standard but do not expect its impact to be material to our financial statements.
Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern
The amendments in this standard provide guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year after the date that its financial statements are issued.requirements.
The update is effective for annual and interim reporting periods beginning after December 15, 2016.2015. We are currently analyzing the impact of this standard on our financial statements.
Simplifying the Presentation of Debt Issuance Costs
This standard was issued to simplify presentation of debt issuance costs. The standard will require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard.
The update requires that we identify, assessis effective for annual and evaluate uncertainties and their impact, if any, on our ability to meet financial obligations. However, weinterim reporting periods beginning after December 15, 2015. We do not expect the impact of adoption of this standard to impactbe material to our financial statements.Condensed Consolidated Balance Sheets.

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Table of Contents (UNAUDITED)



Note 3. Variable Interest Entities (VIEs)
Variable Interest Entities for which PSE&G is the Primary Beneficiary
PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which is pledged as collateral to a trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.
The assets and liabilities of Transition Funding and Transition Funding II are presented separately on the face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the assets of these VIEs are restricted and can only be used to settle their respective obligations. No Transition Funding or Transition Funding II creditor has any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding or Transition Funding II.
PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16$16 million as of September 30, 20142015 and December 31, 2013.2014. The risk of actual loss to PSE&G is considered remote. PSE&G did not provide any financial support to Transition Funding or Transition Funding II during the first nine months of 20142015 or in 2013.2014. PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II. In June 2015, Transition Funding II paid its final securitization bond payment and Transition Funding I is scheduled to make its final securitization bond payment in December 2015.
Variable Interest Entity for which PSEG LI is the Primary Beneficiary
PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA's T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco's economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.
Pursuant to the OSA, Servco's operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI's risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco's annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.

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PSEG recognized a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and other postretirement benefit (OPEB) liabilities. This receivable is presented separately on the Condensed Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted. See Note 7. Pension and Other Postretirement Benefits for additional information.
For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB relatedOPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and OperationsOperation and Maintenance (O&M) Expense, respectively. Servco recorded $96 million and $107 million for the three months and $262 million and $307 million for the nine months ended September 30, 2015 and 2014, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG's Condensed Consolidated Statement of Operations.


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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 6.5. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 20132014.
SignificantIn addition to items previously reported in the Annual Report on Form 10-K, significant 2015 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G in 2014 are as follows:
Storm Damage DeferralEnergy Strong Recovery Filing—In September 2014, theJune 2015, PSE&G updated its Energy Strong electric and gas cost recovery petition filed in March 2015 seeking BPU approved a Stipulation of Settlement finding that PSE&G's 2010 through 2012 major storm incremental O&M costs of $240 million (deferred as Regulatory Assets) and capital expenditures of $126 million were prudent and recoverable in a future base rate proceeding, subject to offset for the amount of insurance proceeds received.
Weather Normalization Clause (WNC)—In April 2014, the BPU approved PSE&G's filing with respect to deficiency revenues from the 2012-2013 Winter Period. The BPU’s approval of a final WNC resulted in no change to the provisional rate previously approved by the BPU and implemented effective October 1, 2013, which was set to recover $26in base rates estimated annual increases in electric revenues of $6 million and gas revenues of $17 million. These increases represent a return on investment and recovery of Energy Strong capitalized investment costs placed in service from customers during the 2013-2014 Winter Period (OctoberDecember 1, 20132014 through May 31, 2014).
2015 for electric and from June 1, 2014 through May 31, 2015 for gas. In September 2014,August 2015, the BPU provisionally approved PSE&G’s filing&G's request effective September 1, 2015.
In September 2015, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with respectEnergy Strong capitalized investment costs placed in service from June 1, 2015 through November 30, 2015. The annualized requested increase in electric revenue requirements is $14 million. The petition requests rates to excess revenues collected duringbe effective March 1, 2016, consistent with the colder than normal 2013-2014 Winter Period. Effective October 1, 2014, PSE&G will return $45 million in revenues to its customers duringBPU Order of approval of the 2014-2015 Winter Period as a result of excess revenues collected during the colder than normal 2013-2014 Winter Period (October 1, 2014 through May 31, 2015).Energy Strong Program. This matter is pending.
Basic Gas Supply Service (BGSS)—In January and February 2014,March 2015, PSE&G filed self-implementing one-month BGSS residential customer bill creditsa letter with the BPU for 25to extend the 28 cents per therm residential rate reduction via a bill credit for one additional month through April 30, 2015, which provided an additional approximate $31 million credit to customers.
In April 2015, the months of February and March 2014. These credits provided approximately $93 million in total credits to residential customers, reducing the BGSS deferred balance. On April 1, 2014, theBPU issued an Order approving PSE&G’s provisional BGSS rate reverted back to the current rate.
of 45 cents per therm which had been implemented on October 1, 2014.
In May 2014,June 2015, PSE&G made its annualAnnual BGSS filingFiling with the BPU requesting a reduction of $112$70 million in annual BGSS revenues. In September 2014,2015, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 54 cents to 45 cents to 40 cents per therm effective October 1, 2014.2015.
Weather Normalization Clause—On April 15, 2015, the BPU approved PSE&G's final filing with respect to excess revenues collected during the colder than normal 2013-2014 Winter Period (October 1, 2013 through May 31, 2014). Effective October 1, 2014, PSEG commenced returning $45 million in revenues to its customers during the 2014-2015 Winter Period (October 1, 2014 through May 31, 2015).
In September 2015, the BPU approved PSE&G's filing on a provisional basis with respect to excess revenues collected during the colder than normal 2014-2015 Winter Period. Effective October 1, 2015, PSE&G commenced returning $40 million in revenues to its customers during the 2015-2016 Winter Period (October 1, 2015 through May 31, 2016).
Solar and Energy Efficiency - Green Program Recovery Charges (GPRC) and Solar Pilot Recovery Charge
(SPRC)—In April 2015, the BPU approved PSE&G’s petition for an Energy Efficiency Economic Stimulus Extension II Program (EEE Ext II) to extend three EEE subprograms (multi-family, direct install and hospital efficiency). The Order allows PSE&G to extend the subprogram offerings under the same clause recovery process as its existing EEE Program and allows for $95 million of additional capital expenditures over the next three years and an allowance for

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$12 million of additional administrative expenses over the next 15 years. The EEE Ext II program was added as a ninth component of the GPRC rate effective May 1, 2015.
In July of each year, PSE&G files for annual recovery for its Green Program investments which include a return on its investment and recovery of expenses. In May 2015, the BPU approved PSE&G’s July 2014 filing requesting recovery of costs and investments in the first eight combined components of the electric and gas GPRC for the period October 1, 2014 through September 30, 2015. In July 2015, PSE&G filed a self-implementing three-month bill credit for residential customers to be effective during Novemberits annual GPRC and December 2014SPRC cost recovery petitions with the BPU, requesting recovery of costs and January 2015. This credit will be 28 cents per therminvestments for the three-monthfirst eight combined components of the electric and gas GPRC, as well as the electric SPRC. The filings proposed rates for the period October 1, 2015 through September 30, 2016 designed to recover approximately $66 million and is estimated$10 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU approved programs. In September 2015, the BPU approved the July 2015 filings on a provisional basis, with new rates effective October 1, 2015.
Transmission Formula Rate Filings—In June 2015, PSE&G filed its 2014 true-up adjustment pertaining to provideits formula rates in effect for 2014, which resulted in an adjustment of $19 million less than the 2014 filed revenues. The adjustment was primarily due to the impact of bonus depreciation and lower interest rates which PSE&G had recognized in its Consolidated Statement of Operations for the year ended December 31, 2014.
The 2016 Annual Formula Rate Update was filed with FERC in October 2015 and provides for approximately $160$146 million in increased annual transmission revenues effective January 1, 2016.
Remediation Adjustment Charge (RAC)—In August 2015, the BPU approved PSE&G's filing with respect to customers. The specific amount returned will depend on actual usage over that period.its RAC 22 petition allowing recovery of $85 million effective September 1, 2015 related to net Manufactured Gas Plant expenditures from August 1, 2013 through July 31, 2014.
Universal Service Fund (USF)/Lifeline—In September 2014,2015, the BPU approved rates set to recover costs incurred under the USF/Lifeline energy assistance programs effective October 1, 2014.2015. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.
Capital Stimulus Infrastructure Programs (CIP II)—In June 2014, the BPU approved PSE&G’s petition to recover annual revenue requirements of approximately $28 million for program costs incurred for its CIP II investments through September 30, 2013, which represents the final phase of the program. Base rates were adjusted effective July 1, 2014 to reflect the recovery.
SBC and Non-Utility Generation Charge (NGC)—In May 2014, the BPU approved PSE&G’s petition to recover actual SBC and NGC costs incurred through December 31, 2013 under its Energy Efficiency & Renewable Energy Programs, Social Programs and NGC. New rates were implemented on June 1, 2014 to recover approximately $400 million over the succeeding 12 months.

Significant pending rate filings are as follows:
Transmission Formula Rate Filings—In May 2014, PSE&G filed its 2014 True-Up Adjustment pertaining to its formula rates in effect for 2013, which resulted in an adjustment of $5 million above the 2013 filed revenues. In accordance with PSE&G’s formula rate protocols, this Rate Year 2013 True-Up Adjustment has been incorporated into its Annual Formula Rate Update for the 2015 Rate Year. The 2015 Annual Formula Rate Update was filed with the FERC in October 2014 and provides for approximately $182 million in increased annual transmission revenues effective January 1, 2015.
Energy Strong Recovery Filing—On September 30, 2014, PSE&G filed its initial Energy Strong cost recovery petition, seeking BPU approval to recover in base rates an estimated annual revenue increase of $1.6 million effective

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March 1, 2015. This increase represents capitalized Energy Strong electric investment costs expected to be in service through November 30, 2014. This request will be updated in December 2014 for actual costs.
Solar and Energy Efficiency-Green Program Recovery Charges (GPRC)—In June 2014, PSE&G filed a petition with the BPU requesting recovery of costs and investments in the combined eight components of the electric and gas GPRC for the period October 1, 2014 through September 30, 2015. The rates proposed in our filing are designed to recover $111 million and $18 million in electric and gas revenues, respectively, on an annual basis. 
Remediation Adjustment Charge (RAC)—On April 18, 2014, PSE&G filed a petition with the BPU requesting recovery of $66 million related to RAC 21 net manufactured gas plant expenditures through July 31, 2013.

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 generated from the installed solar electric system. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG's and PSE&G's Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”
       
 Credit Risk Profile Based on Payment Activity 
   As of As of 
 Consumer Loans September 30,
2014		 December 31,
2013		 
   Millions 
 Commercial/Industrial$187
 $192
 
 Residential 14
 15
 
 Total $201
 $207
 
       
       
 Credit Risk Profile Based on Payment Activity 
   As of As of 
 Consumer Loans September 30,
2015		 December 31,
2014		 
   Millions 
 Commercial/Industrial$180
 $188
 
 Residential 13
 13
 
 Total $193
 $201
 
       

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Energy Holdings
Energy Holdings, through several 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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The following table shows Energy Holdings’ gross and net lease investment as of September 30, 20142015 and December 31, 20132014, respectively.
      
  As of As of 
  September 30,
2014		 December 31,
2013		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$698
 $701
 
 Estimated Residual Value of Leased Assets529
 529
 
 Unearned and Deferred Income(393) (405) 
 Gross Investment in Leases834
 825
 
 Deferred Tax Liabilities(705) (727) 
 Net Investment in Leases$129
 $98
 
      
      
  As of As of 
  September 30,
2015		 December 31,
2014		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$631
 $691
 
 Estimated Residual Value of Leased Assets519
 525
 
 Unearned and Deferred Income(368) (380) 
 Gross Investment in Leases782
 836
 
 Deferred Tax Liabilities(706) (738) 
 Net Investment in Leases$76
 $98
 
      
The corresponding receivables associated with the lease portfolio are reflected in the following table, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. "Not Rated" counterparties represent investments in lease receivables related to commercial real estate properties.
     
   
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating (Standard & Poor's (S&P)) As of 
 As of September 30, 2014 September 30, 2014 
   Millions 
 AA $18
 
 AA- 56
 
 BBB+ - BBB- 316
 
 BB- 134
 
 B 165
 
 Not Rated 9
 
 Total $698
 
     
     
   
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating (Standard & Poor's (S&P)) As of 
 As of September 30, 2015 September 30, 2015 
   Millions 
 AA $17
 
 BBB+ — BBB- 316
 
 BB- 134
 
 B- 164
 
 Total $631
 
     
The “BB-” and the "B""B-" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of September 30, 20142015, the gross investment in the leases of such assets, net of non-recourse debt, was $563573 million ($13(13) million, net of deferred taxes). A more detailed description of such assets under lease, as of September 30, 2015, is presented in the following table.

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 Asset Location 
Gross
Investment
 
%
Owned
 Total 
Fuel
Type
 
Counter-parties’
S&P Credit
Ratings
 Counterparty 
     Millions   MW       
 Powerton Station Units 5 and 6 IL $134
 64% 1,538
 Coal BB- NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $84
 64% 1,044
 Coal BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $117
 17% 1,711
 Coal B GenOn REMA, LLC 
 Conemaugh Station Units 1 and 2 PA $118
 17% 1,711
 Coal B GenOn REMA, LLC 
 Shawville Station Units 1, 2, 3 and 4 PA $110
 100% 603
 Coal B GenOn REMA, LLC 
                 
                 
 Asset Location 
Gross
Investment
 
%
Owned
 Total 
Fuel
Type
 
Counter-parties’
S&P Credit
Ratings As of September 30, 2015 (A)
 Counterparty 
     Millions   MW       
 Powerton Station Units 5 and 6 IL $134
 64% 1,538
 Coal BB- NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $84
 64% 1,044
 Coal BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $121
 17% 1,711
 Coal B- NRG REMA, LLC 
 Conemaugh Station Units 1 and 2 PA $121
 17% 1,711
 Coal B- NRG REMA, LLC 
 Shawville Station Units 1, 2, 3 and 4 PA $113
 100% 603
 Coal B- NRG REMA, LLC 
                 
(A)On October 2, 2015, S&P lowered the B- rating for NRG REMA, LLC, an indirect subsidiary of NRG Energy, Inc., to CCC+. Potential adverse consequences relevant to the downgrade are discussed in the following paragraph.
The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, the indirect subsidiary companies of Energy Holdings would exercise their rights and attempt to seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital investments and trigger certain material tax obligations. A bankruptcy of a lessee would likely delay any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities to the Internal Revenue Service (IRS).
Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges fromin the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and the quality and condition of assets under lease.
GenOnIn early 2014, NRG REMA, LLC an indirect subsidiary ofhad disclosed its plan to place the Shawville generating facility in a “long-term protective layup” by April 2015 as it evaluated its alternatives under the lease. However, NRG Energy, Inc. (NRG)has since notified PJM that it no longer intends to placedeactivated the coal-fired units at the Shawville generating facility in long-term protective layup. Instead, thoseJune 2015 and has disclosed that it expects to return the Shawville units will be shut down temporarily beginning in April 2015, with an expected return to service no later than June 2016 using an alternative fuel.
Nesbitt Asset Recovery, LLC (Nesbitt), (an indirect, wholly owned subsidiary of Energy Holdings), owns approximately 64% of the lease interest in the Powerton and Joliet coal units in Illinois. These facilities are leasedsummer of 2016 with the ability to Midwest Generation (MWG), which was an indirect subsidiary of Edison Mission Energy (EME). In December 2012, EME and MWG filed for relief under Chapter 11 of the U.S. Bankruptcy Code. In October 2013, NRG, EME, MWG, Nesbitt and other creditor parties involved in the bankruptcy executed a new agreement under which NRG would acquire substantially all of EME’s assets, including the Powerton and Joliet leased assets. In March 2014, the Bankruptcy Court approved the transaction. As part of the transaction, (i) the leases for the Powerton and Joliet coal units were assumed on their existing terms, (ii) all past due rent under the leases was paid in full, (iii) NRG assumed EME’s tax indemnity and guarantee obligations, and (iv) NRG agreed to invest up to $350 million in the Powerton and Joliet coal units so they can be operated in compliance with environmental regulations. On April 1, 2014, NRG and EME closed on the transaction in accordance with these terms, bringing the lease payments current.use natural gas.

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 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.

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Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.
          
  As of September 30, 2014 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$652
 $240
 $(9) $883
 
 Debt Securities        
 Government Obligations471
 5
 (4) 472
 
 Other Debt Securities344
 12
 (2) 354
 
 Total Debt Securities815
 17
 (6) 826
 
 Other Securities30
 —
 —
 30
 
 Total NDT Available-for-Sale Securities$1,497
 $257
 $(15) $1,739
 
          
          
  As of September 30, 2015 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$667
 $176
 $(18) $825
 
 Debt Securities        
 Government Obligations445
 10
 (1) 454
 
 Other Debt Securities402
 6
 (7) 401
 
 Total Debt Securities847
 16
 (8) 855
 
 Other Securities35
 —
 —
 35
 
 Total NDT Available-for-Sale Securities$1,549
 $192
 $(26) $1,715
 
          
          
  As of December 31, 2013 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$609
 $290
 $(2) $897
 
 Debt Securities        
 Government Obligations438
 3
 (12) 429
 
 Other Debt Securities285
 10
 (4) 291
 
 Total Debt Securities723
 13
 (16) 720
 
 Other Securities84
 —
 —
 84
 
 Total NDT Available-for-Sale Securities$1,416
 $303
 $(18) $1,701
 
          
          
  As of December 31, 2014 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$685
 $220
 $(8) $897
 
 Debt Securities        
 Government Obligations430
 9
 (1) 438
 
 Other Debt Securities333
 9
 (3) 339
 
 Total Debt Securities763
 18
 (4) 777
 
 Other Securities106
 —
 —
 106
 
 Total NDT Available-for-Sale Securities$1,554
 $238
 $(12) $1,780
 
          
The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.
      
  As of As of 
  September 30,
2014		 December 31,
2013		 
  Millions 
 Accounts Receivable$41
 $39
 
 Accounts Payable$35
 $36
 
      
      
  As of As of 
  September 30,
2015		 December 31,
2014		 
  Millions 
 Accounts Receivable$10
 $10
 
 Accounts Payable$4
 $2
 
      


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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.
                  
  As of September 30, 2014 As of December 31, 2013 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Equity Securities (A)$116
 $(9) $1
 $—
 $30
 $(2) $2
 $—
 
 Debt Securities                
 Government Obligations (B)148
 (2) 68
 (2) 300
 (11) 1
 (1) 
 Other Debt Securities (C)101
 (1) 32
 (1) 107
 (4) 3
 —
 
 Total Debt Securities249
 (3) 100
 (3) 407
 (15) 4
 (1) 
 NDT Available-for-Sale Securities$365
 $(12) $101
 $(3) $437
 $(17) $6
 $(1) 
                  
                  
  As of September 30, 2015 As of December 31, 2014 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Equity Securities (A)$143
 $(18) $1
 $—
 $162
 $(8) $1
 $—
 
 Debt Securities                
 Government Obligations (B)90
 (1) 15
 —
 95
 —
 28
 (1) 
 Other Debt Securities (C)164
 (5) 29
 (2) 99
 (1) 30
 (2) 
 Total Debt Securities254
 (6) 44
 (2) 194
 (1) 58
 (3) 
 NDT Available-for-Sale Securities$397
 $(24) $45
 $(2) $356
 $(9) $59
 $(3) 
                  
(A)
Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 20142015.
(B)
Debt Securities (Government)—Unrealized losses on Power’s NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 20142015.
(C)
Debt Securities (Corporate)(Other)—Power’s investments in corporate bonds, collateralized mortgage obligations, asset-backed securities and municipal government obligations are limited to investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 20142015.
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, 
  2014 2013 2014 2013 
  Millions 
 
Proceeds from NDT Fund Sales (A)
$221
 $220
 $779
 $837
 
 Net Realized Gains (Losses) on NDT Fund:        
 Gross Realized Gains45
 35
 101
 95
 
 Gross Realized Losses(3) (9) (12) (34) 
 Net Realized Gains (Losses) on NDT Fund$42
 $26
 $89
 $61
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2015 2014 2015 2014 
  Millions 
 Proceeds from NDT Fund Sales (A)$215
 $221
 $1,037
 $779
 
 Net Realized Gains (Losses) on NDT Fund:        
 Gross Realized Gains14
 45
 47
 101
 
 Gross Realized Losses(11) (3) (24) (12) 
 Net Realized Gains (Losses) on NDT Fund$3
 $42
 $23
 $89
 
          
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managersmanagers.
Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $12182 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of September 30, 20142015.


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The NDT available-for-sale debt securities held as of September 30, 20142015 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $20
 
 1 - 5 years 239
 
 6 - 10 years 217
 
 11 - 15 years 62
 
 16 - 20 years 42
 
 Over 20 years 246
 
 Total NDT Available-for-Sale Debt Securities$826
 
     
     
 Time Frame Fair Value 
   Millions 
 Less than one year $8
 
 1 - 5 years 236
 
 6 - 10 years 201
 
 11 - 15 years 51
 
 16 - 20 years 51
 
 Over 20 years 308
 
 Total NDT Available-for-Sale Debt Securities$855
 
     
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). For the nine months ended September 30, 2014,2015, other-than-temporary impairments of $1445 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 a “Rabbi Trust.”
PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.
          
  As of September 30, 2014 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$12
 $10
 $—
 $22
 
 Debt Securities        
 Government Obligations88
 1
 —
 89
 
 Other Debt Securities75
 1
 —
 76
 
 Total Debt Securities163
 2
 —
 165
 
 Other Securities1
 —
 —
 1
 
 Total Rabbi Trust Available-for-Sale Securities$176
 $12
 $—
 $188
 
          
          
  As of September 30, 2015 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$11
 $9
 $—
 $20
 
 Debt Securities        
 Government Obligations106
 1
 (1) 106
 
 Other Debt Securities86
 —
 (2) 84
 
 Total Debt Securities192
 1
 (3) 190
 
 Other Securities1
 —
 —
 1
 
 Total Rabbi Trust Available-for-Sale Securities$204
 $10
 $(3) $211
 
          

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  As of December 31, 2013 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$14
 $9
 $—
 $23
 
 Debt Securities        
 Government Obligations109
 —
 (2) 107
 
 Other Debt Securities46
 1
 (1) 46
 
 Total Debt Securities155
 1
 (3) 153
 
 Other Securities3
 —
 —
 3
 
 Total Rabbi Trust Available-for-Sale Securities$172
 $10
 $(3) $179
 
          
          
  As of December 31, 2014 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$12
 $11
 $—
 $23
 
 Debt Securities        
 Government Obligations89
 2
 —
 91
 
 Other Debt Securities74
 1
 —
 75
 
 Total Debt Securities163
 3
 —
 166
 
 Other Securities2
 —
 —
 2
 
 Total Rabbi Trust Available-for-Sale Securities$177
 $14
 $—
 $191
 
          
The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.
      
  As of As of 
  September 30,
2014		 December 31,
2013		 
  Millions 
 Accounts Receivable$2
 $1
 
 Accounts Payable$1
 $2
 
      

      
  As of As of 
  September 30,
2015		 December 31,
2014		 
  Millions 
 Accounts Receivable$1
 $1
 
 Accounts Payable$1
 $—
 
      
The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months.
                  
  As of September 30, 2014 As of December 31, 2013 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Equity Securities (A)$—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 
 Debt Securities                
 Government Obligations (B)26
 —
 —
 —
 47
 (2) 2
 —
 
 Other Debt Securities (C)25
 —
 —
 —
 18
 (1) 1
 —
 
 Total Debt Securities51
 —
 —
 —
 65
 (3) 3
 —
 
 Rabbi Trust Available-for-Sale Securities$51
 $—
 $—
 $—
 $65
 $(3) $3
 $—
 
                  
                  
  As of September 30, 2015 As of December 31, 2014 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Equity Securities (A)$—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 
 Debt Securities                
 Government Obligations (B)47
 (2) 2
 —
 2
 —
 —
 —
 
 Other Debt Securities (C)41
 (1) 9
 —
 24
 —
 —
 —
 
 Total Debt Securities88
 (3) 11
 —
 26
 —
 —
 —
 
 Rabbi Trust Available-for-Sale Securities$88
 $(3) $11
 $—
 $26
 $—
 $—
 $—
 
                  
(A)Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors.
(B)Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of September 30, 2015.

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Tabletable of Contentscontents (UNAUDITED)


nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of September 30, 2014.
(C)Debt Securities (Corporate)(Other)—PSEG’s investments in corporate bonds, collateralized mortgage obligations, asset-backed securities and municipal government obligations are primarily inlimited to investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2014.2015.
The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2014 2013 2014 2013 
  Millions 
 
Proceeds from Rabbi Trust Sales (A)
$419
 $13
 $445
 $77
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$2
 $—
 $4
 $4
 
 Gross Realized Losses(2) —
 (3) (3) 
 Net Realized Gains (Losses) on Rabbi Trust$—
 $—
 $1
 $1
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2015 2014 2015 2014 
  Millions 
 Proceeds from Rabbi Trust Sales (A)$20
 $419
 $83
 $445
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$—
 $2
 $2
 $4
 
 Gross Realized Losses(1) (2) (1) (3) 
 Net Realized Gains (Losses) on Rabbi Trust$(1) $—
 $1
 $1
 
          
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managersmanagers.
Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains of $74 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of September 30, 20142015.
The Rabbi Trust available-for-sale debt securities held as of September 30, 20142015 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $—
 
 1 - 5 years 51
 
 6 - 10 years 28
 
 11 - 15 years 7
 
 16 - 20 years 7
 
 Over 20 years 72
 
 Total Rabbi Trust Available-for-Sale Debt Securities$165
 
     
     
 Time Frame Fair Value 
   Millions 
 Less than one year $5
 
 1 - 5 years 49
 
 6 - 10 years 39
 
 11 - 15 years 8
 
 16 - 20 years 9
 
 Over 20 years 80
 
 Total Rabbi Trust Available-for-Sale Debt Securities$190
 
     
The cost of these securities was determined on the basis of specific identification.
PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

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Tabletable of Contentscontents (UNAUDITED)


The fair value of assets in the Rabbi Trust related to PSEG, PowerPSE&G and PSE&GPower are detailed as follows:
      
  As of As of 
  September 30,
2014		 December 31,
2013		 
  Millions 
 Power$44
 $39
 
 PSE&G40
 42
 
 Other104
 98
 
 Total Rabbi Trust Available-for-Sale Securities$188
 $179
 
      
      
  As of As of 
  September 30,
2015		 December 31,
2014		 
  Millions 
 PSE&G$42
 $41
 
 Power52
 45
 
 Other117
 105
 
 Total Rabbi Trust Available-for-Sale Securities$211
 $191
 
      

Note 7. Pension and Other Postretirement Benefits (OPEB)
PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis.
Pension and OPEB costs for PSEG, except for Servco, are detailed as follows:
                  
  Pension Benefits OPEB Pension Benefits OPEB 
  Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended 
  September 30, September 30, September 30, September 30, 
  2014
 2013 2014
 2013 2014 2013 2014 2013 
  Millions 
 Components of Net Periodic Benefit Cost                
 Service Cost$26
 $29
 $5
 $6
 $78
 $87
 $14
 $16
 
 Interest Cost58
 54
 18
 15
 176
 161
 52
 47
 
 Expected Return on Plan Assets(99) (87) (7) (6) (299) (261) (20) (16) 
 Amortization of Net                
 Prior Service Cost (Credit)(5) (5) (4) (4) (14) (14) (11) (11) 
 Actuarial Loss14
 47
 6
 11
 42
 141
 18
 32
 
 Total Benefit Costs$(6) $38
 $18
 $22
 $(17) $114
 $53
 $68
 
                  
                  
  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, 
  2015
 2014 2015
 2014 2015 2014 2015 2014 
  Millions 
 Components of Net Periodic Benefit Costs (Credit)                
 Service Cost$30
 $26
 $5
 $5
 $92
 $78
 $16
 $14
 
 Interest Cost59
 58
 16
 18
 176
 176
 50
 52
 
 Expected Return on Plan Assets(103) (99) (7) (7) (310) (299) (22) (20) 
 Amortization of Net                
 Prior Service Cost (Credit)(5) (5) (4) (4) (14) (14) (11) (11) 
 Actuarial Loss38
 14
 11
 6
 112
 42
 32
 18
 
 Total Benefit Costs (Credit)$19
 $(6) $21
 $18
 $56
 $(17) $65
 $53
 
                  
 

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Table of Contents (UNAUDITED)


Pension and OPEB costs for Power, PSE&G, Power and PSEG’s other subsidiaries, except for Servco, are detailed as follows:
                  
  Pension Benefits OPEB Pension Benefits OPEB 
  Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended 
  September 30, September 30, September 30, September 30, 
  2014 2013 2014 2013 2014 2013 2014 2013 
  Millions 
 Power$(2) $11
 $5
 $6
 $(5) $33
 $15
 $17
 
 PSE&G(4) 23
 12
 16
 (14) 68
 35
 49
 
 Other—
 4
 1
 —
 2
 13
 3
 2
 
 Total Benefit Costs$(6) $38
 $18
 $22
 $(17) $114
 $53
 $68
 
                  
                  
  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, 
  2015 2014 2015 2014 2015 2014 2015 2014 
  Millions 
 PSE&G$10
 $(4) $13
 $12
 $30
 $(14) $41
 $35
 
 Power5
 (2) 7
 5
 16
 (5) 20
 15
 
 Other4
 —
 1
 1
 10
 2
 4
 3
 
 Total Benefit Costs (Credit)$19
 $(6) $21
 $18
 $56
 $(17) $65
 $53
 
                  

27

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contentsPSEG does not anticipate making any significant contributions into its pension plan during 2014. However, during (UNAUDITED)

During the three months ended March 31, 2014,2015, PSEG contributed its entire planned contributioncontributions for the year 20142015 of $14$15 million into its postretirement healthcare plan.

pension plans and $14 million into its OPEB plan for 2015.
Servco Pension and OPEB
At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco's employees had worked under NGES' T&D operations services arrangement with LIPA, Servco's plans provide certain of those employees with pension and OPEB vested credit for prior years' services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 3. Variable Interest Entities (VIEs).Entities. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.
Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. TheServco's pension-related revenues and costs were $17 million and $30 million for the three months and nine months ended September 30, 2015, respectively, completing its entire planned contribution for the year 2015. Servco's pension-related revenues and costs were $21 million and $67 million for the three months and nine months ended September 30, 2014, were $21 million and $67 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2014. There were noThe OPEB-related revenues earned orand costs incurred for each of the three months and nine months ended September 30, 2014.2015 and 2014 were immaterial.

Note 8. Commitments and Contingent Liabilities
Guaranteed Obligations
Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.
Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to
support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
obtain credit.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to
fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and

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Table of Contents (UNAUDITED)


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.

28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contents (UNAUDITED)

The face value of Power's outstanding guarantees, current exposure and margin positions as of September 30, 20142015 and December 31, 20132014 are shown as follows:
      
  As of As of 
  September 30,
2014		 December 31,
2013		 
  Millions 
 Face Value of Outstanding Guarantees$1,719
 $1,639
 
 Exposure under Current Guarantees$222
 $246
 
 Letters of Credit Margin Posted$138
 $132
 
 Letters of Credit Margin Received$17
 $25
 
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(25) $—
 
    Net Broker Balance Deposited (Received)$278
 $80
 
 In the Event Power were to Lose its Investment Grade Rating:    
 Additional Collateral that could be Required$851
 $691
 
 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral$3,516
 $3,522
 
 Additional Amounts Posted:    
 Other Letters of Credit$45
 $45
 
      
      
  As of As of 
  September 30,
2015		 December 31,
2014		 
  Millions 
 Face Value of Outstanding Guarantees$1,733
 $1,814
 
 Exposure under Current Guarantees$184
 $273
 
      
 Letters of Credit Margin Posted$178
 $159
 
 Letters of Credit Margin Received$80
 $40
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $��
 
 Counterparty Cash Margin Received$(44) $(13) 
    Net Broker Balance Deposited (Received)$4
 $115
 
      
 In the Event Power were to Lose its Investment Grade Rating:    
 Additional Collateral that could be Required$796
 $945
 
 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral$3,375
 $3,495
 
      
 Additional Amounts Posted:    
 Other Letters of Credit$47
 $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 policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.
In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P Moody’s and FitchMoody’s ratings, many of these agreements allow the counterparty to demand further performance assurance. See preceding table.table above.
The SEC and the Commodity Futures Trading Commission (CFTC) continue efforts to implement new rules to effect stricter regulation over swaps and derivatives, including imposing reporting and record-keeping requirements. In August 2013, PSEG began reporting its swap transactions to a CFTC-approved swap data repository. PSEG continues to monitor developments in this area, as the CFTC considers additional requirements such as a new position limits rule for physical commodity futures contracts and swaps that are economically equivalent to those contracts.

30
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)


In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power had posted letters of credit to support Power's various other non-energy contractual and environmental obligations. See preceding table. PSEG had also issued a $106 million guarantee to support Power's payment obligations related to its equity interest in the PennEast natural gas pipeline and a $21 million guarantee to support Power's payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit.
Environmental Matters
Passaic River
Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows.




29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contents (UNAUDITED)

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)
In 2002, the U.S. Environmental Protection Agency (EPA) determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Super Fund”“Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA.
The EPA further determined that there was a need to perform a comprehensive study of the entire 17-miles of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites.
In early 2007, 73 Potentially Responsible Parties (PRPs), including PowerPSE&G and PSE&G,Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic RiverRiver. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the RI/FS among theits members of the CPG on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent of the RI/FS costs wereare currently deemed attributable to PSE&G’s former MGP sites and approximately one percent was attributedis attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PowerPSEG has provided notice to insurers concerning this potential claim.
The CPG, which consisted of 61 members as of September 30, 2014, continues to conduct the RI/FS and is expected to be completed by the first quarter of 2015 at an estimated cost of approximately $136 million. Of the estimated $136 million, as of August 31, 2014, the CPG Group had spent approximately $124 million, of which PSEG's total share had been approximately $9 million.
In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra and Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA Tierra and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G. This agreement and the work undertaken pursuant to the action agreement has no impact onwill not affect the ultimate remedy that the EPA will select for the remediation of the 17 mile17-mile stretch of the lower Passaic River.
In 2012, Tierra and Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than inwith respect ofto their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. PSEG’s share of the cost of that effort is approximately three percent. The remaining CPG members have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal.
On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17 mile17-mile stretch of the Passaic River that had originally been designated as a Super Fund site.River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River. The EPA’s estimated costs to remediate the lower eight miles of the Passaic River range from $365 million for a targeted remedy to $3.25$3.3 billion for a deep dredge of this portion of the Passaic River. The EPA also identified in the revised draft FFS its preferred alternative, which would involve dredging the lower eight miles of the river bank to bankbank-to-bank and installing an engineered cap. The estimated cost in the revised draft FFS for itsthe EPA's preferred alternative is $1.7 billion. No provisional cost allocation has been made by the CPG for the work contemplated by the revised draft FFS, and the work contemplated by the revised draft FFS is not subject to the CPG’s cost sharing allocation agreed to in connection with the removal work for River Mile 10.9 or in connection with the conduct of the RI/FS.

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


The revised draft FFS was subject to a public comment period, and remains subject to the EPA’s response to comments submitted, a design phase and at least an estimated five years for completion of the work. The public comment period onfor the revised draft FFS closed on August 21, 2014. Over 300 comments were submitted by a variety of entities potentially impacted by the revised draft FFS, including the CPG, individual companies, municipalities, public officials, citizens groups, Amtrak, NJ Transit and others.
The CPG, which consisted of 60 members as of September 30, 2015, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $151 million, which the CPG continues to incur. Of the estimated $151 million, as of August 31, 2015, the CPG had spent approximately $141 million, of which PSEG's total share was approximately $9 million.
The draft FS sets forth various alternatives for remediating the lower Passaic River. The draft FS sets forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranges from approximately $518 million to $772 million. No provisional cost allocation has been made

30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contents (UNAUDITED)

by the CPG for the work contemplated by the draft FS. However, based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G's and Power's estimates of their share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015.
The EPA will consider the comments received on its revised draft FFS and is expected to consider the CPG’s RI/FS prior to issuing a Record of Decision (ROD) of a selected remedy for the lower eight miles.Passaic River. The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact Power's and PSE&G's and Power's ultimate liability.
Based on the facts and circumstance known at this time, and calculated in reference to the EPA estimate set forth in the FFS for its preferred remedy, Power and PSE&G believe that their respective shares of the costs to clean up the Passaic River will be immaterial. However, until Until (i) the RI/FS is completed,finalized, (ii) a final remedy is determined by the EPA or through litigation, (iii) PowerPSE&G's and PSE&G’sPower’s respective shareshares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on our financial statements.
New Jersey Spill Compensation It is possible that PSE&G and Control Act (Spill Act)
In 2005,Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the New Jersey Departmentcurrent time estimate the amount or range of Environmental Protection (NJDEP) filed suit in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of a certain PRP’s discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. In 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances it allegedly discharged into the Passaic River and the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed to a total of 11 sites or facilities that impacted these water bodies. The third party complaints sought statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. In December 2013, the Court approved a settlement of the entire third party action. Power and PSE&G's contributions to the settlement, either individually or in the aggregate, were immaterial.any additional costs. 
Natural Resource Damage Claims
In 2003, the NJDEPNew Jersey Department of Environmental Protection (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 New Jersey Spill Compensation and Control 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 (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSEG isPSE&G and Power are unable to estimate its portiontheir respective portions 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. 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 PSEG has not consented to fund the third phase. PowerPSE&G and PSE&GPower are unable to estimate their portionrespective portions 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 $452$450 million and $524$518 million through 2021.2021, including its $10 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $452$450 million as ofSeptember 30, 2014.2015. Of this amount, $75$73 million was recorded in Other Current Liabilities and $377 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $452$450 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.

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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, 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 the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.
Hazardous Air Pollutants Regulation
In accordance with a ruling of the U.S. Court of Appeals of the District of Columbia (D.C. Court), the EPA published a Maximum Achievable Control Technology (MACT) regulation in February 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the D.C. Court in support of the EPA's implementation of MATS. In April 2014, the D.C. Court denied all petitions for review of the existing source NESHAP. Several parties, including 21 states, have filed petitions for review with the U.S. Supreme Court.
Power believes that it will not be necessary to install any material controls at its New Jersey facilities. Additional controls are being installed at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulations, the co-owners group, including Power, agreed to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction systems at Power’s jointly owned coal-fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be operational in the first quarter of 2015. Power's share of this investment is approximately $110 million.
Nitrogen Oxide (NOX) Regulation
In 2009, the NJDEP finalized revisions to NOx emission control regulations that impose new NOx emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on Power’s generation fleet, as it imposes NOx emissions limits that will require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) by May 30, 2015. Retirement notifications for the combustion turbines have been submitted to PJM Interconnection L.L.C. (PJM). PJM was notified that the Salem Unit 3 combustion turbine will no longer be available as a capacity resource and will be transitioned to an emergency generator for site use only. Based upon Power’s recently-completed evaluations of its steam electric generation units, an immaterial investment will be required to consistently reduce NOx emissions below required limits beginning on May 1, 2015.
Clean Water Act Permit Renewals
Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System (NPDES) permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The New Jersey Department of Environmental Protection (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.
In October 2013, On June 30, 2015, the Delaware Riverkeeper NetworkNJDEP issued a draft Salem permit. The draft permit does not require installation of cooling towers and several other environmental groups filedallows Salem to continue to operate utilizing the existing once-through cooling water system with certain required system modifications. The draft permit was subject to a lawsuitpublic notice and comment period. The NJDEP may make revisions before issuing the final permit expected during the first half of 2016. Power participated in the Superior Court in New Jersey seeking to compelNJDEP’s August 5, 2015 public hearing and submitted comments on the NJDEP to take actiondraft permit on Power's pending application for permit renewal at Salem

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either by denying the application or issuing a draft for public comments. At the NJDEP's request, the case was transferred to the Appellate Division in December 2013. Power is unable to predict the outcome of this proceeding.September 18, 2015.
On May 19, 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. FourthSecond Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule.
State permitting decisions could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1$1.0 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.
Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power's future capital requirements, financial condition or results of operations.
Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance
In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station's NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the Connecticut Department of Energy and Environmental Protection of the

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issues and has taken actions to investigate and resolve the potential non-compliance. At this early stage Power cannot predict the impact of this matter.
Steam Electric Effluent Guidelines
On September 30, 2015, the EPA issued a new Effluent Guidelines Limitation Rule for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power's Mercer and Bridgeport Harbor stations have bottom ash transport water discharges that are regulated under this rule. Power is unable to predict if these new standards will have a material impact on Power's future capital requirements, financial condition or results of operations.
Coal Combustion Residuals (CCRs)
On December 19, 2014, the EPA issued a final rule which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power's Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who dochoose not to purchase electric supply from third party suppliers through the annual New Jersey BGS auctions.suppliers. The first category, which represents about 80% of PSE&G's load requirement, are residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category are larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Pricing (CIEP)). 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, including Power, 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.
The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2015 is $272.78 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2015 of $282.04 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.
PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:
           
  Auction Year  
  2012 2013 2014 2015  
 36-Month Terms EndingMay 2015
 May 2016
 May 2017
 May 2018
(A)  
 Load (MW)2,900
 2,800
 2,800
 2,900
   
 $ per MWh$83.88 $92.18 $97.39 $99.54   
           
(A)Prices set for the 2015 BGS auction year became effective on June 1, 2015 when the 2012 BGS auction agreements expired.
Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.

PSE&G has contracted for its anticipated BGS-Fixed Price eligible load, as follows:
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  Auction Year  
  2011 2012 2013 2014  
 36-Month Terms EndingMay 2014
 May 2015
 May 2016
 May 2017
(A)  
 Load (MW)2,800
 2,900
 2,800
 2,800
   
 $ per kWh0.09430
 0.08388
 0.09218
 0.09739
   
           
(A)Prices set for the 2014 BGS auction year became effective on June 1, 2014 when the 2011 BGS auction agreements expired.

PSE&G has a full requirementsfull-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 17. Related-Party Transactions.
Minimum Fuel Purchase Requirements
Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium,

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enrichment and fabrication requirements through 2017 and a significant portion through 20182020 at Salem, Hope Creek and Peach Bottom.
Power has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations and for firm transportation and storage capacity for natural gas.stations.
Power’sPower also has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategyWhen there is excess delivery capacity available, Power can use the gas to enter into contracts forsupply its fuel supply in comparable volumes to its sales contracts.fossil generating stations.
As of September 30, 20142015, the total minimum purchase requirements included in these commitments were as follows:
     
 Fuel Type Power's Share of Commitments through 2018 
   Millions 
 Nuclear Fuel   
 Uranium $450
 
 Enrichment $369
 
 Fabrication $174
 
 Natural Gas $877
 
 Coal $367
 
     
     
 Fuel Type Power's Share of Commitments through 2019 
   Millions 
 Nuclear Fuel   
 Uranium $440
 
 Enrichment $345
 
 Fabrication $179
 
 Natural Gas $1,001
 
 Coal $331
 
     
Regulatory Proceedings
FERC Compliance
In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. PSEG notified the FERC, PJM and the PJM Independent Market Monitor (IMM) of this issue. During the three months ended March 31, 2014, Power recorded a charge to income in the amount of $25 million related to these findings for these past errors based upon its best estimate available at the time. PSEG cannot provide any assurances that the total liability associated with this matter will not increase or decrease over the amount recorded.
Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter. As the investigation proceeded, additional pricing errors in the bids were identified and itidentified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed the FERC, PJM and the IMMPJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors and has corrected these errors.modified the bid quantities for its peaking units. Power is also in the process of implementingcontinues to implement procedures to help mitigate the risk of similar issues occurring in the future.
On September 2, 2014, the FERC Staff verbally informed PSEG that they have initiated a preliminary, non-public staff investigation into the matter. This investigation, which is ongoing, could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies.
During the three months ended March 31, 2014, based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. It is not possible at this time to reasonably estimate the ultimatepotential range of loss or full impact or predict any resulting penalties or other costs associated with this matter, or the applicability of mitigating factors. ItAs new information becomes available or future developments occur in this investigation, it is possible that Power willincur record additional estimated losses and that such additional losses may be material, but PSEG cannot at the current time estimate the amount or range of any additional losses. material.
New Jersey Clean Energy Program
In June 2014,2015, the BPU established the funding level for fiscal year 20152016 applicable to its Renewable Energy and Energy Efficiency programs. The fiscal year 20152016 aggregate funding for all EDCs is $345 million with PSE&G's share of the funding at $200 million. PSE&G has a current liability of $185 million as of September 30, 20142015 for its outstanding share of the fiscal

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year 20152016 and remaining fiscal year 2014 funding.2015 funding, respectively. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

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Superstorm Sandy
In late October 2012, Superstorm Sandy caused severe damage to PSE&G's T&D system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds and the resulting storm surge caused damage to switching stations, substations and generating infrastructure.
Power had incurred $79 million and $85 million of storm-related expense in 2013 and 2012, respectively, primarily for repairs at certain generating stations in Power's fossil fleet. These costs were recognized in O&M Expense, offset by $25 million and $19 million of insurance recoveries in 2013 and 2012, respectively.
Power incurred an additional $4 million and $23 million for the three months and nine months ended September 30, 2014, primarily for repairs at certain generating stations in Power's fossil fleet.
PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. As previously reported, PSEG is seeking recovery from its insurers for the property damage resulting from Superstorm Sandy, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. In June 2013, PSEG, PowerPSE&G and PSE&GPower filed suit in New Jersey state court (NJ Court) against its insurance carriers seeking an interpretation that the insurance policies cover their losses resulting from damage caused by Superstorm Sandy's storm surge. In that lawsuit, PSEG stated that
As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its estimate ofinfrastructure and return it to pre-storm conditions. Of the total costs related to damaged facilitiesincurred, approximately $40 million was approximately $426recognized in O&M Expense, $75 million. was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. Of these costs, $364the $295 million, and $62 million related to Power and PSE&G, respectively. In August 2013, the insurance carriers filed an answer in which they denied most of the allegations made in the Complaint. In April 2014, PSEG notified the insurance carriers of a revised estimate of $579 million for total costs related to damaged facilities, of which $484 million and $95 $36 million related to Power andinsured property. In 2012, PSE&G respectively. Discoveryrecognized $6 million of insurance recoveries, which were deferred. There were no significant additional costs incurred since 2012.
PSE&G made a filing with the BPU to review the prudency of unreimbursed incremental storm restoration costs, including O&M and capital expenditures associated with Superstorm Sandy and certain other extreme weather events, for recovery in its next base rate case or sooner through a BPU-approved cost recovery mechanism. In September 2014, the BPU approved its filing.
Power had incurred a total of $193 million of storm-related costs from 2012 through 2014, primarily for repairs at certain generating stations in Power's fossil fleet. These costs were recognized primarily in O&M Expense, offset by $44 million of insurance recoveries in 2013 and 2012. Power incurred an additional $2 million of storm-related costs in 2015 which were recognized primarily in O&M Expense.
In the first half of 2015, PSEG reached settlements with its insurers with respect to claims for coverage of its Superstorm Sandy-related losses. PSEG received an additional $214 million under these settlements (consisting of $159 million and $55 million recognized in the case has been completed. On October 7, 2014,three months ended March 31, 2015 and June 30, 2015, respectively), bringing cumulative insurance proceeds to $264 million. Of the $214 million recognized in 2015, PSE&G and Power recorded $35 million and $179 million, respectively. In addition to the $35 million recognized in 2015, PSE&G recognized the aforementioned $6 million of previously deferred insurance recoveries, resulting in reductions in Regulatory Assets of $20 million, O&M Expense of $10 million and Property, Plant and Equipment of $11 million. Power recorded reductions in both partiesO&M Expense of $145 million and Property, Plant and Equipment of $6 million and an increase in Other Income of $28 million.
The claim filed cross-motions for summary judgment. We cannot predict the outcome of this proceeding.by PSEG, PSE&G and Power related to Superstorm Sandy insurance coverage is now fully resolved. 

Note 9. Changes in Capitalization
The following capital transactions occurred in the nine months ended September 30, 20142015:
PSE&G
issued $350 million of 3.00% Secured Medium-Term Notes, Series K due May 2025,
issued $250 million of 4.05% Secured Medium-Term Notes, Series K due May 2045,
paid $300 million of 2.70% Secured Medium-Term Notes at maturity,
paid $183 million of Transition Funding's securitization debt, and
paid the final $8 million of Transition Funding II's securitization debt.
Power
paid cash dividends of $775400 million to PSEG.
PSE&G
issued $250 million of 1.80% Secured Medium-Term Notes, Series I due June 2019,
issued $250 million of 4.00% Secured Medium-Term Notes, Series I due June 2044,
issued $250 million of 2.00% Secured Medium-Term Notes, Series J due August 2019,
issued $250 million of 3.15% Secured Medium-Term Notes, Series J due August 2024,
paid $250 million of 0.85% Secured Medium-Term Notes at maturity,
paid $250 million of 5.00% Secured Medium-Term Notes at maturity,
paid $164 million of Transition Funding's securitization debt,
paid $6 million of Transition Funding II's securitization debt, and
received a $175 million capital contribution from PSEG.
In October 2014, Power executed an extension of the letter of credit backing $44 million of Pennsylvania Economic Development Financing Authority Variable Rate Demand Bonds. The existing letter of credit, which was scheduled to expire on November 30, 2014, has now been extended through November 30, 2019.


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Note 10. Financial Risk Management Activities
The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchase normal sale (NPNS), cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. Power and PSE&G enter into additional contracts that are derivatives, but do not qualify for or are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and changes in the fair value of these contracts are recorded in earnings each period.
Commodity Prices
The availabilityWithin PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of energy commodities are subject to fluctuations due to various factors, including but not limited to, weather, environmental policies,electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, market conditionsenvironmental policies, transmission availability and transmission availability.other factors. Power uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including 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 with changes in fair value recorded in the Consolidated Statements of Operations. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists.
Cash Flow Hedges
PSEG and Power usesuse forward sale and purchase contracts, swaps and futures contracts to hedge
forecasted energy sales from its generation stations and the related load obligations,
the price of fuel to meet its fuel purchase requirements, and
certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G.
These derivative transactions qualify and 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, since June 1, 2012, Power recognizes all gains and losses from changes in the fair value of these derivatives immediately in earnings rather than deferring any such amounts in Accumulated Other Comprehensive Income (Loss). The fair values of Power’s de-designated hedges were frozen in Accumulated Other Comprehensive Income (Loss) as the original forecasted transactions are still expected to occur and are reclassified into earnings as the original derivative transactions settle.
As of September 30, 20142015 and December 31, 2013,2014, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity were as follows:
      
  As of As of 
  September 30,
2014		 December 31,
2013		 
  Millions 
 Fair Value of Cash Flow Hedges$3
 $(4) 
 Impact on Accumulated Other Comprehensive Income (Loss) (after tax)$2
 $(1) 
      
      
  As of As of 
  September 30,
2015		 December 31,
2014		 
  Millions 
 Fair Value of Cash Flow Hedges$2
 $18
 
 Impact on Accumulated Other Comprehensive Income (Loss) (after tax)$1
 $10
 
      
The expiration date of the longest-dated cash flow hedge at Power is in JuneDecember 2015. Power’s remaining $21 million of after-tax unrealized gains on these derivatives is expected to be reclassified to earnings during the next 12 months. There was no ineffectiveness associated with qualifying hedges as of September 30, 20142015.

Other Derivatives
36

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contents (UNAUDITED)

Economic Hedges
Power enters into additionalderivative contracts that are derivatives, but do not qualify for or are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of itsPower's expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to certain long-term natural gas sales derivative contracts to optimize its pipeline capacity utilization. These natural gas contracts qualify as derivatives and are marked toChanges in the fair market value with the offsetof these contracts are recorded toin Regulatory Assets and Regulatory Liabilities.

37
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)


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.swaps.
Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of September 30, 2014,2015, PSEG had interest rate swaps outstanding totaling $850 million.$850 million. These swaps convert Power’s $300$300 million of 5.5% Senior Notes due December 2015, $300$300 million of Power’s $303$303 million of 5.32% Senior Notes due September 2016 and Power’s $250$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, 20142015 and December 31, 2013,2014, the fair value of all the underlying hedges was $2611 million and $3822 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 less than $(1) million and $(1) millionimmaterial as of September 30, 20142015 and December 31, 20132014, respectively.
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with our accounting policy, these positions have been offset inon the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG.

37

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contents (UNAUDITED)

The following tabular disclosure does not include the offsetting of trade receivables and payables.
                 
   As of September 30, 2015 
   Power (A) PSE&G (A) PSEG (A) Consolidated 
   
Cash Flow
Hedges
 Not Designated     Not Designated 
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 $2
 $413
 $(268) $147
 $4
 $11
 $162
 
 Noncurrent Assets —
 284
 (193) 91
 —
 —
 91
 
 Total Mark-to-Market Derivative Assets $2
 $697
 $(461) $238
 $4
 $11
 $253
 
 Derivative Contracts               
 Current Liabilities $—
 $(311) $241
 $(70) $—
 $—
 $(70) 
 Noncurrent Liabilities —
 (178) 162
 (16) (7) —
 (23) 
 Total Mark-to-Market Derivative (Liabilities) $—
 $(489) $403
 $(86) $(7) $—
 $(93) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $2
 $208
 $(58) $152
 $(3) $11
 $160
 
                 
                 
   As of September 30, 2014 
   Power (A) PSE&G (A) PSEG (A) Consolidated 
   
Cash Flow
Hedges
 
Non
Hedges
     
Non
Hedges
 
Fair Value
Hedges
   
 Balance Sheet Location 
Energy-
Related
Contracts
 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
   Millions 
 Derivative Contracts               
 Current Assets $4
 $517
 $(471) $50
 $5
 $16
 $71
 
 Noncurrent Assets —
 166
 (155) 11
 8
 10
 29
 
 Total Mark-to-Market Derivative Assets $4
 $683
 $(626) $61
 $13
 $26
 $100
 
 Derivative Contracts               
 Current Liabilities $(1) $(702) $594
 $(109) $—
 $—
 $(109) 
 Noncurrent Liabilities —
 (175) 138
 (37) —
 —
 (37) 
 Total Mark-to-Market Derivative (Liabilities) $(1) $(877) $732
 $(146) $—
 $—
 $(146) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $3
 $(194) $106
 $(85) $13
 $26
 $(46) 
                 

38
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)


                 
   As of December 31, 2013 
   Power (A) PSE&G (A) PSEG (A) Consolidated 
   
Cash Flow
Hedges
 
Non
Hedges
     
Non
Hedges
 
Fair Value
Hedges
   
 Balance Sheet Location 
Energy-
Related
Contracts
 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
   Millions 
 Derivative Contracts               
 Current Assets $—
 $323
 $(266) $57
 $25
 $16
 $98
 
 Noncurrent Assets —
 155
 (83) 72
 69
 22
 163
 
 Total Mark-to-Market Derivative Assets $—
 $478
 $(349) $129
 $94
 $38
 $261
 
 Derivative Contracts               
 Current Liabilities $(4) $(343) $271
 $(76) $—
 $—
 $(76) 
 Noncurrent Liabilities —
 (111) 80
 (31) —
 —
 (31) 
 Total Mark-to-Market Derivative (Liabilities) $(4) $(454) $351
 $(107) $—
 $—
 $(107) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $(4) $24
 $2
 $22
 $94
 $38
 $154
 
                 
                 
   As of December 31, 2014 
   Power (A) PSE&G (A) PSEG (A) Consolidated 
   
Cash Flow
Hedges
 Not Designated     Not Designated 
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 $18
 $597
 $(408) $207
 $18
 $15
 $240
 
 Noncurrent Assets —
 171
 (109) 62
 8
 7
 77
 
 Total Mark-to-Market Derivative Assets $18
 $768
 $(517) $269
 $26
 $22
 $317
 
 Derivative Contracts               
 Current Liabilities $—
 $(568) $436
 $(132) $—
 $—
 $(132) 
 Noncurrent Liabilities —
 (138) 105
 (33) —
 —
 (33) 
 Total Mark-to-Market Derivative (Liabilities) $—
 $(706) $541
 $(165) $—
 $—
 $(165) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $18
 $62
 $24
 $104
 $26
 $22
 $152
 
                 
(A)
Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of September 30, 20142015 and December 31, 20132014. PSE&G does not have any derivative contracts subject to master netting or similar agreements.
(B)
Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset inon the Condensed Consolidated Balance Sheets. As of September 30, 20142015 andDecember 31, 2013, net cash collateral (received) paid of $106 million and $2 million, respectively, were netted against the corresponding net derivative contract positions. Of the $106 million as of September 30, 2014, $(12) million and $(21) million of cash collateral was netted against current assets and noncurrent assets, respectively, and $135

38

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contents (UNAUDITED)

December 31, 2014, net cash collateral (received) paid of $(58) million and $24 million, respectively, were netted against the corresponding net derivative contract positions. Of the $(58) million as of September 30, 2015, $(32) million and $(38) million of cash collateral were netted against current assets and noncurrent assets, respectively, and $5 million and $7 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $24 million as of December 31, 2014, $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and $32 million and $4 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $2 million as of December 31, 2013, cash collateral of $(3) million and $5 million were netted against noncurrent assets and current liabilities, respectively.
Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded or lose itsto a below investment grade credit rating, it would be required to provide additional collateral. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.
The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $14078 million and $91$127 million as of September 30, 20142015 and December 31, 20132014, respectively. As of September 30, 20142015 and December 31, 2013,2014, Power had the contractual right of offset of $31$12 million and $39$18 million, respectively, related to derivative instruments that are assets with the same counterparty under agreements and net of margin posted. If Power had been downgraded or lost itsto a below investment grade rating, it would have had additional collateral obligations of $10966 million and $52$109 million as of September 30, 20142015 and December 31, 20132014, 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 $851796 million and $691945 million as of September 30, 20142015 and December 31, 20132014, respectively, discussed in Note 8. Commitments and Contingent Liabilities.

39
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)


The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended September 30, 20142015 and 2013.2014.
                   
 
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, 
  2014 2013                                2014 2013   2014 2013 
   Millions 
 PSEG                 
 Energy-Related Contracts $3
 $1
 Operating Revenues $1
 $3
 Operating Revenues $—
 $(1) 
 Total PSEG $3
 $1
   $1
 $3
   $—
 $(1) 
 Power                 
 Energy-Related Contracts $3
 $1
 Operating Revenues $1
 $3
 Operating Revenues $—
 $(1) 
 Total Power $3
 $1
   $1
 $3
   $—
 $(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 
  September 30,   September 30,   September 30, 
  2015 2014                                2015 2014   2015 2014 
   Millions 
 PSEG                 
 Energy-Related Contracts $1
 $3
 Operating Revenues $—
 $1
 Operating Revenues $—
 $—
 
 Total PSEG $1
 $3
   $—
 $1
   $—
 $—
 
 Power                 
 Energy-Related Contracts $1
 $3
 Operating Revenues $—
 $1
 Operating Revenues $—
 $—
 
 Total Power $1
 $3
   $—
 $1
   $—
 $—
 
                   

39

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contents (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, 20142015 and 2013.
                   
 
Derivatives in
Cash Flow Hedging
Relationships
 
Amount of
Pre-Tax
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective
Portion)
 
Location
of Pre-Tax Gain
(Loss) Reclassified
from AOCI into
Income
 
Amount of
Pre-Tax
Gain (Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Location of
Pre-Tax Gain
(Loss) Recognized in
Income on
Derivatives
(Ineffective Portion)
 
Amount of
Pre-Tax
Gain (Loss)
Recognized in
Income on
Derivatives
(Ineffective
Portion)
 
  Nine Months Ended   Nine Months Ended   Nine Months Ended 
  September 30,   September 30,   September 30, 
  2014 2013                                2014 2013   2014 2013 
   Millions 
 PSEG                 
 Energy-Related Contracts $(4) $1
 Operating Revenues $(11) $11
 Operating Revenues $—
 $(1) 
 Interest Rate Swaps —
 —
 Interest Expense —
 (1)   —
 —
 
 Total PSEG $(4) $1
   $(11) $10
   $—
 $(1) 
 Power                 
 Energy-Related Contracts $(4) $1
 Operating Revenues $(11) $11
 Operating Revenues $—
 $(1) 
 Total Power $(4) $1
   $(11) $11
   $—
 $(1) 
                   

40
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)2014.

                   
 
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, 
  2015 2014                                2015 2014   2015 2014 
   Millions 
 PSEG                 
 Energy-Related Contracts $2
 $(4) Operating Revenues $17
 $(11) Operating Revenues $—
 $—
 
 Total PSEG $2
 $(4)   $17
 $(11)   $—
 $—
 
 Power                 
 Energy-Related Contracts $2
 $(4) Operating Revenues $17
 $(11) Operating Revenues $—
 $—
 
 Total Power $2
 $(4)   $17
 $(11)   $—
 $—
 
                   

The following reconciles the Accumulated Other Comprehensive Income for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis.
       
 Accumulated Other Comprehensive Income Pre-Tax After-Tax 
   Millions 
 Balance as of December 31, 2013 $(4) $(2)
 Net Loss Recognized in AOCI (7) (4) 
 Loss Reclassified into Income 12
 7
 
 Balance as of June 30, 2014 $1
 $1
 
 Gain Recognized in AOCI 3
 2
 
 Gain Reclassified into Income (1) (1) 
 Balance as of September 30, 2014 $3
 $2
 
       
       
 Accumulated Other Comprehensive Income Pre-Tax After-Tax 
   Millions 
 Balance as of December 31, 2014 $17
 $10

 Gain Recognized in AOCI 1
 1
 
 Less: Gain Reclassified into Income (17) (10) 
 Balance as of June 30, 2015 $1
 $1
 
 Gain Recognized in AOCI 1
—
—
 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of September 30, 2015 $2
 $1
 
       

40

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
table of contents (UNAUDITED)

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months and nine months ended September 30, 20142015 and 2014.2013.
             
 Derivatives Not Designated as Hedges 
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives
 Pre-Tax Gain (Loss) Recognized in Income on Derivatives 
     Three Months Ended Nine Months Ended 
     September 30, September 30, 
     2014 2013 2014 2013 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $93
 $14
 $(759) $(32) 
 Energy-Related Contracts Energy Costs (12) 10
 65
 63
 
 Total PSEG and Power   $81
 $24
 $(694) $31
 
             
             
 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, 
     2015 2014 2015 2014 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $154
 $93
 $202
 $(759) 
 Energy-Related Contracts Energy Costs (4) (12) (4) 65
 
 Total PSEG and Power   $150
 $81
 $198
 $(694) 
             
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 salesNPNS exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $5 million and $4$5 million for each of the three months and $15 million and $14 million for each of the nine months ended September 30, 20142015 and 2013,2014, respectively.

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


The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 20142015 and December 31, 20132014..
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of September 30, 2014           
 Natural Gas Dth 341
 —
 277
 64
 
 Electricity MWh 329
 —
 329
 —
 
 Financial Transmission Rights (FTRs) MWh 21
 —
 21
 —
 
 Interest Rate Swaps U.S. Dollars 850
 850
 —
 —
 
 As of December 31, 2013           
 Natural Gas Dth 614
 —
 466
 148
 
 Electricity MWh 243
 —
 243
 —
 
 FTRs MWh 16
 —
 16
 —
 
 Interest Rate Swaps U.S. Dollars 850
 850
 —
 —
 
             
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of September 30, 2015           
 Natural Gas Dth 193
 —
 154
 39
 
 Electricity MWh 291
 —
 291
 —
 
 Financial Transmission Rights (FTRs) MWh 21
 —
 21
 —
 
 Interest Rate Swaps U.S. Dollars 850
 850
��—
 —
 
 As of December 31, 2014           
 Natural Gas Dth 274
 —
 216
 58
 
 Electricity MWh 310
 —
 310
 —
 
 FTRs MWh 15
 —
 15
 —
 
 Interest Rate Swaps U.S. Dollars 850
 850
 —
 —
 
             

Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.
As of September 30, 20142015, 99%98% of the credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

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The following table provides information on Power’s credit risk from others, net of cash collateral, as of September 30, 20142015. 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 $89
 $27
 $77
 2
 $52
(A)  
 Non-Investment Grade—External Rating 1
 —
 1
 —
 —
   
 Investment Grade—No External Rating 1
 —
 1
 —
 —
   
 Non-Investment Grade—No External Rating —
 —
 —
 —
 —
   
 Total $91
 $27
 $79
 2
 $52
   
              
              
 Rating 
Current
Exposure
 
Securities
Held as
Collateral
 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
   Millions   Millions  
 Investment Grade—External Rating $348
 $118
 $230
 2
 $127
(A)  
 Non-Investment Grade—External Rating 1
 —
 1
 —
 —
   
 Investment Grade—No External Rating 11
 —
 11
 —
 —
   
 Non-Investment Grade—No External Rating 4
 —
 4
 —
 —
   
 Total $364
 $118
 $246
 2
 $127
   
              
(A)IncludesRepresents net exposure of $21$87 million with PSE&G. The remaining net exposure of $31$40 million is with a nonaffiliatednon- affiliated power purchaser which is a regulatedan investment grade counterparty.
As of September 30, 2015, collateral held from counterparties where Power had credit exposure included $43 million in cash collateral and $75 million in letters of credit.
As of September 30, 2015, Power had 133 active counterparties.
PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure listedis greater than the supplier’s unsecured credit limit. As of September 30, 2015, primarily all of the posted collateral was in the preceding table, in some cases, will not beform of parental guarantees. The unsecured credit used by the difference betweensuppliers represents PSE&G’s net credit exposure. PSE&G's suppliers’ credit exposure is calculated each business day. As of September 30, 2015, PSE&G had no net credit exposure with suppliers, including Power.
PSE&G is permitted to recover its costs of procuring energy through the current exposure and the collateral held. ABPU-approved BGS tariffs. PSE&G’s counterparty may have posted more cash collateral than the outstanding exposure, in which case there wouldcredit risk is mitigated by its ability to recover realized energy costs through customer rates.


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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, 2014, Power had 136 active counterparties.

Note 11. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PowerPSE&G and PSE&GPower have the ability to access. These consist primarily of listed equity securities.securities and money market mutual funds.
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, 2014,2015, these consisted primarily of long-term gas supply contracts and certain electric load contracts and long-term gas supply contracts.
The following tables present information about PSEG’s, Power’sPSE&G’s and PSE&G’sPower's respective assets and (liabilities) measured at fair value on a recurring basis as of September 30, 20142015 and December 31, 2013,2014, 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 PowerPSE&G and PSE&G.

Power.

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   Recurring Fair Value Measurements as of September 30, 2014 
 Description Total 

Netting (E)
 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) 
Significant Unobservable Inputs
(Level 3)
 
   Millions 
 PSEG           
 Assets:           
 Cash Equivalents (A) $667
 $—
 $667
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $74
 $(626) $—
 $687
 $13
 
 Interest Rate Swaps (C) $26
 $—
 $—
 $26
 $—
 
 NDT Fund (D)           
 Equity Securities $883
 $—
 $876
 $7
 $—
 
 Debt Securities—Govt Obligations $472
 $—
 $—
 $472
 $—
 
 Debt Securities—Other $354
 $—
 $—
 $354
 $—
 
 Other Securities $30
 $—
 $30
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $22
 $—
 $22
 $—
 $—
 
 Debt Securities—Govt Obligations $89
 $—
 $—
 $89
 $—
 
 Debt Securities—Other $76
 $—
 $—
 $76
 $—
 
 Other Securities $1
 $—
 $—
 $1
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(146) $732
 $—
 $(857) $(21) 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $61
 $(626) $—
 $687
 $—
 
 NDT Fund (D)           
 Equity Securities $883
 $—
 $876
 $7
 $—
 
 Debt Securities—Govt Obligations $472
 $—
 $—
 $472
 $—
 
 Debt Securities—Other $354
 $—
 $—
 $354
 $—
 
 Other Securities $30
 $—
 $30
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $21
 $—
 $—
 $21
 $—
 
 Debt Securities—Other $18
 $—
 $—
 $18
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(146) $732
 $—
 $(857) $(21) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $293
 $—
 $293
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $13
 $—
 $—
 $—
 $13
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $19
 $—
 $—
 $19
 $—
 
 Debt Securities—Other $16
 $—
 $—
 $16
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
             
             
   Recurring Fair Value Measurements as of September 30, 2015 
 Description Total 

Netting  (E)
 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) 
Significant Unobservable Inputs
(Level 3)
 
   Millions 
 PSEG           
 Assets:           
 Cash Equivalents (A) $226
 $—
 $226
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $242
 $(461) $—
 $694
 $9
 
 Interest Rate Swaps (C) $11
 $—
 $—
 $11
 $—
 
 NDT Fund (D)           
 Equity Securities $825
 $—
 $824
 $1
 $—
 
 Debt Securities—Govt Obligations $454
 $—
 $—
 $454
 $—
 
 Debt Securities—Other $401
 $—
 $—
 $401
 $—
 
 Other Securities $35
 $—
 $35
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $20
 $—
 $20
 $—
 $—
 
 Debt Securities—Govt Obligations $106
 $—
 $—
 $106
 $—
 
 Debt Securities—Other $84
 $—
 $—
 $84
 $—
 
 Other Securities $1
 $—
 $1
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(93) $403
 $—
 $(489) $(7) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $—
 $—
 $—
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $4
 $—
 $—
 $—
 $4
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $4
 $—
 $4
 $—
 $—
 
 Debt Securities—Govt Obligations $21
 $—
 $—
 $21
 $—
 
 Debt Securities—Other $17
 $���
 $—
 $17
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(7) $—
 $—
 $—
 $(7) 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $238
 $(461) $—
 $694
 $5
 
 NDT Fund (D)           
 Equity Securities $825
 $—
 $824
 $1
 $—
 
 Debt Securities—Govt Obligations $454
 $—
 $—
 $454
 $—
 
 Debt Securities—Other $401
 $—
 $—
 $401
 $—
 
 Other Securities $35
 $—
 $35
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $26
 $—
 $—
 $26
 $—
 
 Debt Securities—Other $21
 $—
 $—
 $21
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(86) $403
 $—
 $(489) $—
 
             

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   Recurring Fair Value Measurements as of December 31, 2013 
 Description Total Netting (E) 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) 
Significant Unobservable Inputs
(Level 3)
 
   Millions 
 PSEG           
 Assets:           
 Cash Equivalents (A) $439
 $—
 $439
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $223
 $(349) $—
 $474
 $98
 
 Interest Rate Swaps (C) $38
 $—
 $—
 $38
 $—
 
 NDT Fund (D)           
 Equity Securities $897
 $—
 $892
 $5
 $—
 
 Debt Securities—Govt Obligations $429
 $—
 $—
 $429
 $—
 
 Debt Securities—Other $291
 $—
 $—
 $291
 $—
 
 Other Securities $84
 $—
 $57
 $27
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $23
 $—
 $23
 $—
 $—
 
 Debt Securities—Govt Obligations $107
 $—
 $—
 $107
 $—
 
 Debt Securities—Other $46
 $—
 $—
 $46
 $—
 
 Other Securities $3
 $—
 $—
 $3
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(107) $351
 $—
 $(448) $(10) 
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $129
 $(349) $—
 $474
 $4
 
 NDT Fund (D)           
 Equity Securities $897
 $—
 $892
 $5
 $—
 
 Debt Securities—Govt Obligations $429
 $—
 $—
 $429
 $—
 
 Debt Securities—Other $291
 $—
 $—
 $291
 $—
 
 Other Securities $84
 $—
 $57
 $27
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $23
 $—
 $—
 $23
 $—
 
 Debt Securities—Other $10
 $—
 $—
 $10
 $—
 
 Other Securities $1
 $—
 $—
 $1
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(107) $351
 $—
 $(448) $(10) 
 PSE&G           
 Assets:           
 Derivative Contracts:           
 Energy Related Contracts (B) $94
 $—
 $—
 $—
 $94
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $25
 $—
 $—
 $25
 $—
 
 Debt Securities—Other $11
 $—
 $—
 $11
 $—
 
 Other Securities $1
 $—
 $—
 $1
 $—
 
             
             
   Recurring Fair Value Measurements as of December 31, 2014 
 Description Total Netting  (E) 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) 
Significant Unobservable Inputs
(Level 3)
 
   Millions 
 PSEG           
 Assets:           
 Cash Equivalents (A) $365
 $—
 $365
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $295
 $(517) $—
 $774
 $38
 
 Interest Rate Swaps (C) $22
 $—
 $—
 $22
 $—
 
 NDT Fund (D)           
 Equity Securities $897
 $—
 $896
 $1
 $—
 
 Debt Securities—Govt Obligations $438
 $—
 $—
 $438
 $—
 
 Debt Securities—Other $339
 $—
 $—
 $339
 $—
 
 Other Securities $106
 $—
 $106
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $23
 $—
 $23
 $—
 $—
 
 Debt Securities—Govt Obligations $91
 $—
 $—
 $91
 $—
 
 Debt Securities—Other $75
 $—
 $—
 $75
 $—
 
 Other Securities $2
 $—
 $—
 $2
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(165) $541
 $—
 $(705) $(1) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $294
 $—
 $294
 $—
 $—
 
 Derivative Contracts:           
 Energy Related Contracts (B) $26
 $—
 $—
 $—
 $26
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $20
 $—
 $—
 $20
 $—
 
 Debt Securities—Other $16
 $—
 $—
 $16
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $269
 $(517) $—
 $774
 $12
 
 NDT Fund (D)           
 Equity Securities $897
 $—
 $896
 $1
 $—
 
 Debt Securities—Govt Obligations $438
 $—
 $—
 $438
 $—
 
 Debt Securities—Other $339
 $—
 $—
 $339
 $—
 
 Other Securities $106
 $—
 $106
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $21
 $—
 $—
 $21
 $—
 
 Debt Securities—Other $18
 $—
 $—
 $18
 $—
 
 Other Securities $1
 $—
 $—
 $1
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(165) $541
 $—
 $(705) $(1) 
             
(A)Represents money market mutual funds.
(B)Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis

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absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.
Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.
(C)Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
(D)The fair value measurement table excludes cash of less than $1 million which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).
Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.
Level 2—NDT and Rabbi Trust fixed income securities are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and United States Treasurygovernment obligations or Federal Agency asset-backed securities with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.
(E)Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of September 30, 2014,2015, net cash collateral (received) paid of $106$(58) million, was netted against the corresponding net derivative contract positions. Of the $106$(58) million as of September 30, 2014, $(33)2015, $(70) million of cash collateral was netted against assets, and $139$12 million was netted against liabilities. As of December 31, 2013,2014, net cash collateral (received) paid of $2$24 million, was netted against the corresponding net derivative contract positions. Of the $2$24 million as of December 31, 2013, $(3)2014, $(12) million of cash collateral was netted against assets, and $5$36 million was netted against liabilities.

Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and non-performancenonperformance risk were not material to the financial statements.
For PSE&G and Power, in general, electric swapsnatural gas supply contracts are measured at fair value based on at least two pricing inputs,using modeling techniques taking into account the underlyingcurrent price of electricity at a liquid reference pointnatural gas adjusted for appropriate risk factors, as applicable, and the basis difference between electricity prices at the liquid reference point and electricity prices at the respective delivery locations. To the extent the basis component is based on a single broker quote and isinternal assumptions about transportation

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significant tocosts, and accordingly, the fair value of the electric swap, it is categorized asmeasurements are classified in Level 3. The fair value of certain of Power's electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. For Power, long-term electric capacity contracts are measured using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For Power and PSE&G, natural gas supply contracts are measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The following tables provide details surrounding significant Level 3 valuations as of September 30, 20142015 and December 31, 20132014.
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position September 30, 2014 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 Power             
                  Electricity Electric Load Contracts $—
 $(21) Discounted Cash Flow Historic Load Variability 0% to +10% 
 Other Various (A) —
 —
       
 Total Power   $—
 $(21)       
 PSE&G             
 Gas Forward Contracts  $13
 $—
 Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm 
 Total PSE&G   $13
 $—
       
 Total PSEG   $13
 $(21)       
               
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position September 30, 2015 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 PSE&G             
 Gas Natural Gas Supply Contracts  $4
 $(7) Discounted Cash Flow Transportation Costs $0.60 to $0.90/dekatherm 
 Total PSE&G   $4
 $(7)       
 Power             
                  Electricity Electric Load Contracts $4
 $—
 Discounted Cash flow Historic Load Variability 0% to +10% 
 Other Various (A) 1
 —
       
 Total Power   $5
 $—
       
 Total PSEG   $9
 $(7)       
               
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position December 31, 2013 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 Power             
                 Electricity                Electric Swaps $3
 $(1) Discounted Cash Flow Power Basis                     $0 to $10/MWh 
                  Electricity Electric Load Contracts —
 (8) Discounted Cash Flow Historic Load Variability -5% to +10% 
 Other Various (B) 1
 (1)       
 Total Power   $4
 $(10)       
 PSE&G             
 Gas                      Forward Contracts $94
 $—
 Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm 
 Total PSE&G   $94
 $—
       
 Total PSEG   $98
 $(10)       
               
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position December 31, 2014 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 PSE&G             
 Gas Natural Gas Supply Contracts  $26
 $—
 Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm 
 Total PSE&G   $26
 $—
       
 Power             
                  Electricity Electric Load Contracts $12
 $(1) Discounted Cash Flow Historic Load Variability 0% to +10% 
 Other Various (B) —
 —
       
 Total Power   $12
 $(1)       
 Total PSEG   $38
 $(1)       
               
(A)Includes long-term electric positions which were immaterial as of September 30, 2015.
(A)(B)Includes gas supply positions and long-term electric capacity positions which were immaterial as of September 30,December 31, 2014.
(B)
Includes gas supply positions which were immaterial as of December 31, 2013.

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Table of Contents (UNAUDITED)


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

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table of contents (UNAUDITED)

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, 20142015 and September 30, 2013,2014, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months and andNine Months Ended September 30, 20142015
                 
   Three Months Ended September 30, 2014   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2014 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of September 30, 2014 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $13
 $(8) $(9) $—
 $(4) $—
 $(8) 
 Power               
 Net Derivative Assets (Liabilities) $(9) $(8) $—
 $—
 $(4) $—
 $(21) 
 PSE&G               
 Net Derivative Assets (Liabilities) $22
 $—
 $(9) $—
 $—
 $—
 $13
 
                 
   Nine Months Ended September 30, 2014   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of
January 1, 2014		 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of September 30, 2014 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $88
 $(66) $(81) $—
 $54
 $(3) $(8) 
 Power               
 Net Derivative Assets (Liabilities) $(6) $(66) $—
 $—
 $54
 $(3) $(21) 
 PSE&G               
 Net Derivative Assets (Liabilities) $94
 $—
 $(81) $—
 $—
 $—
 $13
 
                 
                 
   Three Months Ended September 30, 2015   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2015 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
 Balance as of September 30, 2015 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $8
 $4
 $(8) $—
 $(2) $—
 $2
 
 PSE&G               
 Net Derivative Assets (Liabilities) $5
 $—
 $(8) $—
 $—
 $—
 $(3) 
 Power               
 Net Derivative Assets (Liabilities) $3
 $4
 $—
 $—
 $(2) $—
 $5
 
                 
   Nine Months Ended September 30, 2015   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2015 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
 Balance as of September 30, 2015 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $37
 $12
 $(29) $—
 $(18) $—
 $2
 
 PSE&G               
 Net Derivative Assets (Liabilities) $26
 $—
 $(29) $—
 $—
 $—
 $(3) 
 Power               
 Net Derivative Assets (Liabilities) $11
 $12
 $—
 $—
 $(18) $—
 $5
 
                 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)



Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months and andNine Months Ended September 30, 20132014
                 
   Three Months Ended September 30, 2013   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of
July 1, 2013		 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of September 30, 2013 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $(35) $1
 $(11) $—
 $(1) $—
 $(46) 
 Power               
 Net Derivative Assets (Liabilities) $6
 $1
 $—
 $—
 $(1) $—
 $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(41) $—
 $(11) $—
 $—
 $—
 $(52) 
                 
   Nine Months Ended September 30, 2013   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of
January 1, 2013		 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of September 30, 2013 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $(31) $(16) $(12) $—
 $9
 $4
 $(46) 
 Power               
 Net Derivative Assets (Liabilities) $9
 $(16) $—
 $—
 $9
 $4
 $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(40) $—
 $(12) $—
 $—
 $—
 $(52) 
                 
                 
   Three Months Ended September 30, 2014   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2014 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of September 30, 2014 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $13
 $(8) $(9) $—
 $(4) $—
 $(8) 
 PSE&G               
 Net Derivative Assets (Liabilities) $22
 $—
 $(9) $—
 $—
 $—
 $13
 
 Power               
 Net Derivative Assets (Liabilities) $(9) $(8) $—
 $—
 $(4) $—
 $(21) 
                 
   Nine Months Ended September 30, 2014   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2014 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2014 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $88
 $(66) $(81) $—
 $54
 $(3) $(8) 
 PSE&G               
 Net Derivative Assets (Liabilities) $94
 $—
 $(81) $—
 $—
 $—
 $13
 
 Power               
 Net Derivative Assets (Liabilities) $(6) $(66) $—
 $—
 $54
 $(3) $(21) 
                 
(A)PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities includes $4 million and $12 million in Operating Income for the three months and nine months ended September 30, 2015, respectively. Of the $4 million in Operating Income, $3 million is unrealized. Of the $12 million in Operating Income, $(6) million is unrealized.
(B)Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.

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(C)Represents $(2) million and $(18) million in settlements for the three months and nine months ended September 30, 2015. Includes $(4) million and $54 million in settlements for the three months and nine months ended September 30, 2014.
(D)There were no transfers among levels during the three months ended September 30, 2015 and 2014 and the nine months ended September 30, 2015. During the nine months ended September 30, 2014, $(3) million of net derivative assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters in which the transfers first occurred as per PSEG's policy.
(E)PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $(8) million and $(66) million in Operating Income for the three months and nine months ended September 30, 2014, respectively. Of the $(8) million in Operating Income, $(12) million is unrealized. Of the $(66) million in Operating Income, $(11) million is unrealized.
(B)Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
TableAs of Contents (UNAUDITED)September 30, 2015, PSEG carried $2.3 billion of net assets that are measured at fair value on a recurring basis, of which $2 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.


(C)
Represents $(4) million and $54 million in settlements for the three months and nine months ended September 30, 2014. Represents $(1) million and $9 million in settlements for the three months and nine months ended September 30, 2013.
(D)
There were no transfers among levels during the three months ended September 30, 2014 and 2013. During the nine months ended September 30, 2014, $(3) million, of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. During the nine months ended September 30, 2013, $4 million, of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters in which the transfers first occurred, as per PSEG's policy.
(E)PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1 million and $(16) million in Operating Income for the three months and nine months ended September 30, 2013, respectively. The $1 million in Operating Income is unrealized. Of the $(16) million in Operating Income, $(7) million is unrealized.
As of September 30, 2014, PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $8 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of September 30, 2013, PSEG carried $1.9 billion of net assets that are measured at fair value on a recurring basis, of which $46 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

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, 20142015 and December 31, 20132014.
          
  As of As of 
  September 30, 2014 December 31, 2013 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (Parent) (A)$15
 $26
 $24
 $38
 
 Power -Recourse Debt (B)2,543
 2,916
 2,541
 2,846
 
 PSE&G (B)6,063
 6,497
 5,566
 5,629
 
 Transition Funding (PSE&G) (B)312
 327
 476
 511
 
 Transition Funding II (PSE&G) (B)14
 15
 20
 21
 
 Energy Holdings:        
   Project Level, Non-Recourse Debt (C)16
 16
 16
 16
 
 Total Long-Term Debt$8,963
 $9,797
 $8,643
 $9,061
 
          
          
  As of As of 
  September 30, 2015 December 31, 2014 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (Parent) (A)$7
 $11
 $14
 $22
 
 PSE&G (B)6,612
��7,102
 6,312
 6,912
 
 Transition Funding (PSE&G) (B)68
 69
 251
 261
 
 Transition Funding II (PSE&G) (B)—
 —
 8
 8
 
 Power - Recourse Debt (B)2,544
 2,856
 2,543
 2,930
 
 Energy Holdings:        
   Project Level, Non-Recourse Debt (C)7
 7
 16
 16
 
 Total Long-Term Debt$9,238
 $10,045
 $9,144
 $10,149
 
          
(A)Fair value represents net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. Carrying amount represents such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.
(B)The debt fair valuation is based on the present value of each bond’s future cash flows. The discount rates used in the present value analysis are based on an estimate of new issue bond yields across the treasury curve. When a bond has embedded options, an interest rate model is used to reflect the impact of interest rate volatility into the analysis (primarily Level 2 measurements).
(C)Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.


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Note 12. Other Income and Deductions
          
 Other IncomePower PSE&G Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2014        
 NDT Fund Gains, Interest, Dividend and Other Income$55
 $—
 $—
 $55
 
 Allowance for Funds Used During Construction—
 8
 —
 8
 
 Solar Loan Interest—
 6
 —
 6
 
 Other1
 2
 3
 6
 
 Total Other Income$56
 $16
 $3
 $75
 
 Three Months Ended September 30, 2013        
 NDT Fund Gains, Interest, Dividend and Other Income$45
 $—
 $—
 $45
 
 Allowance for Funds Used During Construction—
 5
 —
 5
 
 Solar Loan Interest—
 7
 —
 7
 
 Other—
 1
 1
 2
 
   Total Other Income$45
 $13
 $1
 $59
 
 Nine Months Ended September 30, 2014        
 NDT Fund Gains, Interest, Dividend and Other Income$133
 $—
 $—
 $133
 
 Allowance for Funds Used During Construction—
 21
 —
 21
 
 Solar Loan Interest—
 18
 —
 18
 
 Other2
 5
 6
 13
 
 Total Other Income$135
 $44
 $6
 $185
 
 Nine Months Ended September 30, 2013        
 NDT Fund Gains, Interest, Dividend and Other Income$125
 $—
 $—
 $125
 
 Allowance for Funds Used During Construction—
 17
 —
 17
 
 Solar Loan Interest—
 18
 —
 18
 
 Other2
 6
 4
 12
 
 Total Other Income$127
 $41
 $4
 $172
 
          

          
 Other IncomePSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2015        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $24
 $—
 $24
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Solar Loan Interest6
 —
 —
 6
 
 Other2
 1
 —
 3
 
 Total Other Income$22
 $25
 $—
 $47
 
 Nine Months Ended September 30, 2015        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $78
 $—
 $78
 
 Allowance for Funds Used During Construction36
 —
 —
 36
 
 Solar Loan Interest18
 —
 —
 18
 
      Gain on Insurance Recovery—
 28
 —
 28
 
 Other5
 3
 3
 11
 
   Total Other Income$59
 $109
 $3
 $171
 
 Three Months Ended September 30, 2014        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $55
 $—
 $55
 
 Allowance for Funds Used During Construction8
 —
 —
 8
 
 Solar Loan Interest6
 —
 —
 6
 
 Other2
 1
 3
 6
 
 Total Other Income$16
 $56
 $3
 $75
 
 Nine Months Ended September 30, 2014        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $133
 $—
 $133
 
 Allowance for Funds Used During Construction21
 —
 —
 21
 
 Solar Loan Interest18
 —
 —
 18
 
 Other5
 2
 6
 13
 
 Total Other Income$44
 $135
 $6
 $185
 
          

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 Other DeductionsPower PSE&G Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2014        
   NDT Fund Realized Losses and Expenses$4
 $—
 $—
 $4
 
   Other2
 2
 1
 5
 
     Total Other Deductions$6
 $2
 $1
 $9
 
 Three Months Ended September 30, 2013        
   NDT Fund Realized Losses and Expenses$11
 $—
 $—
 $11
 
   Other—
 1
 —
 1
 
     Total Other Deductions$11
 $1
 $—
 $12
 
 Nine Months Ended September 30, 2014        
   NDT Fund Realized Losses and Expenses$18
 $—
 $—
 $18
 
   Other7
 3
 3
 13
 
   Total Other Deductions$25
 $3
 $3
 $31
 
 Nine Months Ended September 30, 2013        
   NDT Fund Realized Losses and Expenses$40
 $—
 $—
 $40
 
   Other9
 3
 2
 14
 
   Total Other Deductions$49
 $3
 $2
 $54
 
          
          
 Other DeductionsPSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2015        
   NDT Fund Realized Losses and Expenses$—
 $13
 $—
 $13
 
   Other—
 1
 —
 1
 
     Total Other Deductions$—
 $14
 $—
 $14
 
 Nine Months Ended September 30, 2015        
   NDT Fund Realized Losses and Expenses$—
 $30
 $—
 $30
 
   Other2
 2
 2
 6
 
     Total Other Deductions$2
 $32
 $2
 $36
 
 Three Months Ended September 30, 2014        
   NDT Fund Realized Losses and Expenses$—
 $4
 $—
 $4
 
   Other2
 2
 1
 5
 
   Total Other Deductions$2
 $6
 $1
 $9
 
 Nine Months Ended September 30, 2014        
   NDT Fund Realized Losses and Expenses$—
 $18
 $—
 $18
 
   Other3
 7
 3
 13
 
   Total Other Deductions$3
 $25
 $3
 $31
 
          
(A)Other primarily consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

52
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)



Note 13. Income Taxes
PSEG’s, Power’sPSE&G’s and PSE&G’sPower's effective tax rates for the three months and nine months ended September 30, 20142015 and 20132014 were as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2014 2013 2014 2013 
 PSEG37.0% 41.0% 37.8% 40.5% 
 Power39.4% 40.5% 38.6% 40.0% 
 PSE&G38.5% 40.6% 38.6% 40.0% 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2015 2014 2015 2014 
 PSEG39.4% 37.0% 38.8% 37.8% 
 PSE&G38.2% 38.5% 38.7% 38.6% 
 Power40.3% 39.4% 38.6% 38.6% 
          
For the three months ended September 30, 2014, as compared to the same period in the prior year, the decrease in PSEG's and2015, PSE&G's effective tax ratesrate was lower than the statutory tax rate of 40.85% due primarily to the audit settlement and depreciationbeneficial impact of plant related flow-through respectively.items.
For the nine months ended September 30, 2014,2015, PSEG's and Power’s effective tax rates were lower than the statutory tax rate of 40.85% primarily due to a manufacturing deduction under Section 199 of the Internal Revenue Code (IRC) and the tax benefit associated with the income tax rate differential of carrying back federal net operating tax losses under section 172(f) of the IRC. PSE&G's effective tax rate was lower than the statutory tax rate due primarily to the beneficial impact of plant related flow-through items.
For the three months and nine months ended September 30, 2015, as compared to the same periodperiods in the prior year, the decrease in PSEG's effective tax ratesincrease was due primarily to the absence of the 2014 audit settlement.
OnIn August 11, 2014, PSEG received notice from the Internal Revenue Service (IRS) that the audit settlement covering tax years 2007 through 2010 had been approved by the Joint Committee on Taxation. This effectively settlessettled all issues with the IRS through 2010. OnIn September 9, 2014, PSEG received refunds from the IRS totaling $121 million, representing the net settlement of all disputed amounts, including interest, through the tax year 2010. As a result of the settlement of this audit, PSEG recorded a $12 million reduction of tax expense in the quarter ended September 30, 2014.
PSEG’s unrecognized tax benefits decreased by $156 million in the third quarter 2014 inclusive of interest, of which $62 million was attributable to the settlement of the IRS audit tax liability and the remaining $94 million was due to the reversal of positions taken in prior periods. As a result, the December 31, 2013 balance of unrecognized tax benefits that was reasonably possible to increase or decrease within the next twelve months decreased to an immaterial amount as of September 30, 2014.
There is no material increase or decrease in the interest and penalties associated with the unrecognized tax benefits. The impact on the accumulated deferred income taxes and regulatory tax benefits is not material. The change in the total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is not material.
In September 2013, the U.S. Department of the Treasury and the IRS released final regulations effective in 2014 that provide guidance on applying Section 263(a) of the Internal Revenue Code to amounts paid to acquire, produce, or improve tangible property, as well as rules for materials and supplies. Implementation of these regulations did not have any material impact on PSEG’s and its subsidiaries’ results of operations, financial condition or cash flows. 
The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 included a provision making qualified property placed into service after September 8, 2010 and before January 1, 2012, eligible for 100% bonus depreciation for tax purposes. In addition, qualified property placed into service in 2012 was eligible for 50% bonus depreciation for tax purposes. The American Taxpayer Relief Act of 2012 further extended the 50% bonus depreciation for qualified property placed into service before January 1, 2014. In addition, long production property placed into service in 2014 is eligible for 50% bonus depreciation for tax purposes. These provisions have generated cash for PSEG through tax benefits related to the accelerated depreciation. These tax benefits otherwise would have been received over an estimated average 20 year period.


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Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2014 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2014 $1
 $(232) $158
 $(73) 
 Other Comprehensive Income before Reclassifications 2
 —
 (15) (13) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1) 3
 (15) (13) 
 Net Current Period Other Comprehensive Income (Loss) 1
 3
 (30) (26) 
 Balance as of September 30, 2014 $2
 $(229) $128
 $(99) 
           
   Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2013 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2013 $3
 $(466) $101
 $(362) 
 Other Comprehensive Income before Reclassifications 1
 —
 27
 28
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (2) 9
 (11) (4) 
 Net Current Period Other Comprehensive Income (Loss) (1) 9
 16
 24
 
 Balance as of September 30, 2013 $2
 $(457) $117
 $(338) 
           
   Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2014 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2013 $(2) $(238) $145
 $(95) 
 Other Comprehensive Income before Reclassifications (2) —
 19
 17
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 6
 9
 (36) (21) 
 Net Current Period Other Comprehensive Income (Loss) 4
 9
 (17) (4) 
 Balance as of September 30, 2014 $2
 $(229) $128
 $(99) 
           
   Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2013 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2012 $7
 $(485) $90
 $(388) 
 Other Comprehensive Income before Reclassifications 1
 —
 53
 54
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (6) 28
 (26) (4) 
 Net Current Period Other Comprehensive Income (Loss) (5) 28
 27
 50
 
 Balance as of September 30, 2013 $2
 $(457) $117
 $(338) 
           
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2015 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2015 $1
 $(395) $117
 $(277) 
 Other Comprehensive Income before Reclassifications —
 —
 (46) (46) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 9
 15
 24
 
 Net Current Period Other Comprehensive Income (Loss) —
 9
 (31) (22) 
 Balance as of September 30, 2015 $1
 $(386) $86
 $(299) 
           
   Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2014 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2014 $1
 $(232) $158
 $(73) 
 Other Comprehensive Income before Reclassifications 2
 —
 (15) (13) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1) 3
 (15) (13) 
 Net Current Period Other Comprehensive Income (Loss) 1
 3
 (30) (26) 
 Balance as of September 30, 2014 $2
 $(229) $128
 $(99) 
     
   Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2015 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2014 $10
 $(411) $118
 $(283) 
 Other Comprehensive Income before Reclassifications 1
 —
 (44) (43) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (10) 25
 12
 27
 
 Net Current Period Other Comprehensive Income (Loss) (9) 25
 (32) (16) 
 Balance as of September 30, 2015 $1
 $(386) $86
 $(299) 
           
   Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2014 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2013 $(2) $(238) $145
 $(95) 
 Other Comprehensive Income before Reclassifications (2) —
 19
 17
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 6
 9
 (36) (21) 
 Net Current Period Other Comprehensive Income (Loss) 4
 9
 (17) (4) 
 Balance as of September 30, 2014 $2
 $(229) $128
 $(99) 
           

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 Power Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2014 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2014 $2
 $(199) $153
 $(44) 
 Other Comprehensive Income before Reclassifications 2
 —
 (14) (12) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1) 2
 (16) (15) 
 Net Current Period Other Comprehensive Income (Loss) 1
 2
 (30) (27) 
 Balance as of September 30, 2014 $3
 $(197) $123
 $(71) 
     
   Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2013 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2013 $4
 $(405) $98
 $(303) 
 Other Comprehensive Income before Reclassifications 1
 —
 28
 29
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (2) 8
 (11) (5) 
 Net Current Period Other Comprehensive Income (Loss) (1) 8
 17
 24
 
 Balance as of September 30, 2013 $3
 $(397) $115
 $(279) 
           
   Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2014 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2013 $(1) $(204) $142
 $(63) 
 Other Comprehensive Income before Reclassifications (2) —
 17
 15
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 6
 7
 (36) (23) 
 Net Current Period Other Comprehensive Income (Loss) 4
 7
 (19) (8) 
 Balance as of September 30, 2014 $3
 $(197) $123
 $(71) 
           
   Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2013 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2012 $9
 $(422) $85
 $(328) 
 Other Comprehensive Income before Reclassifications 1
 —
 56
 57
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (7) 25
 (26) (8) 
 Net Current Period Other Comprehensive Income (Loss) (6) 25
 30
 49
 
 Balance as of September 30, 2013 $3
 $(397) $115
 $(279) 
           


           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2015 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2015 $2
 $(337) $112
 $(223) 
 Other Comprehensive Income before Reclassifications —
 —
 (43) (43) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 14
 21
 
 Net Current Period Other Comprehensive Income (Loss) —
 7
 (29) (22) 
 Balance as of September 30, 2015 $2
 $(330) $83
 $(245) 
     
   Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2014 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2014 $2
 $(199) $153
 $(44) 
 Other Comprehensive Income before Reclassifications 2
 —
 (14) (12) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1) 2
 (16) (15) 
 Net Current Period Other Comprehensive Income (Loss) 1
 2
 (30) (27) 
 Balance as of September 30, 2014 $3
 $(197) $123
 $(71) 
           
   Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2015 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2014 $11
 $(351) $112
 $(228) 
 Other Comprehensive Income before Reclassifications 1
 —
 (41) (40) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (10) 21
 12
 23
 
 Net Current Period Other Comprehensive Income (Loss) (9) 21
 (29) (17) 
 Balance as of September 30, 2015 $2
 $(330) $83
 $(245) 
           
   Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2014 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2013 $(1) $(204) $142
 $(63) 
 Other Comprehensive Income before Reclassifications (2) —
 17
 15
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 6
 7
 (36) (23) 
 Net Current Period Other Comprehensive Income (Loss) 4
 7
 (19) (8) 
 Balance as of September 30, 2014 $3
 $(197) $123
 $(71) 
           

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 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2014 September 30, 2014 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges               
 Energy-Related Contracts Operating Revenues $1
 $—
 $1
 $(11) $5
 $(6) 
 Interest Rate Swaps Interest Expense —
 —
 —
 —
 —
 —
 
 Total Cash Flow Hedges   1
 —
 1
 (11) 5
 (6) 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense 3
 (1) 2
 8
 (3) 5
 
    Amortization of Actuarial Loss O&M Expense (8) 3
 (5) (22) 8
 (14) 
 Total Pension and OPEB Plans (5) 2
 (3) (14) 5
 (9) 
 Available-for-Sale Securities             
 Realized Gains Other Income 47
 (24) 23
 105
 (54) 51
 
 Realized Losses Other Deductions (5) 2
 (3) (15) 7
 (8) 
 Other-Than-Temporary Impairments (OTTI) OTTI (10) 5
 (5) (14) 7
 (7) 
 Total Available-for-Sale Securities 32
 (17) 15
 76
 (40) 36
 
 Total   $28
 $(15) $13
 $51
 $(30) $21
 
                 
                 
 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2015 September 30, 2015 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges               
 Energy-Related Contracts Operating Revenues $—
 $—
 $—
 $17
 $(7) $10
 
 Total Cash Flow Hedges   —
 —
 —
 17
 (7) 10
 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense 3
 (1) 2
 9
 (3) 6
 
    Amortization of Actuarial Loss O&M Expense (17) 6
 (11) (51) 20
 (31) 
 Total Pension and OPEB Plans (14) 5
 (9) (42) 17
 (25) 
 Available-for-Sale Securities             
 Realized Gains Other Income 14
 (7) 7
 49
 (25) 24
 
 Realized Losses Other Deductions (12) 5
 (7) (25) 12
 (13) 
 Other-Than-Temporary Impairments (OTTI) OTTI (30) 15
 (15) (45) 22
 (23) 
 Total Available-for-Sale Securities (28) 13
 (15) (21) 9
 (12) 
 Total   $(42) $18
 $(24) $(46) $19
 $(27) 
                 
                 
 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2013 September 30, 2013 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges               
 Energy-Related Contracts Operating Revenues $3
 $(1) $2
 $11
 $(4) $7
 
 Interest Rate Swaps Interest Expense —
 —
 —
 (1) —
 (1) 
 Total Cash Flow Hedges   3
 (1) 2
 10
 (4) 6
 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense 3
 (1) 2
 8
 (3) 5
 
    Amortization of Actuarial Loss O&M Expense (18) 7
 (11) (56) 23
 (33) 
 Total Pension and OPEB Plans (15) 6
 (9) (48) 20
 (28) 
 Available-for-Sale Securities             
 Realized Gains Other Income 35
 (18) 17
 99
 (51) 48
 
 Realized Losses Other Deductions (9) 4
 (5) (37) 18
 (19) 
 OTTI OTTI (3) 2
 (1) (7) 4
 (3) 
 Total Available-for-Sale Securities 23
 (12) 11
 55
 (29) 26
 
 Total   $11
 $(7) $4
 $17
 $(13) $4
 
                 
                 
 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2014 September 30, 2014 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges               
 Energy-Related Contracts Operating Revenues $1
 $—
 $1
 $(11) $5
 $(6) 
 Total Cash Flow Hedges   1
 —
 1
 (11) 5
 (6) 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense 3
 (1) 2
 8
 (3) 5
 
    Amortization of Actuarial Loss O&M Expense (8) 3
 (5) (22) 8
 (14) 
 Total Pension and OPEB Plans (5) 2
 (3) (14) 5
 (9) 
 Available-for-Sale Securities             
 Realized Gains Other Income 47
 (24) 23
 105
 (54) 51
 
 Realized Losses Other Deductions (5) 2
 (3) (15) 7
 (8) 
 OTTI OTTI (10) 5
 (5) (14) 7
 (7) 
 Total Available-for-Sale Securities 32
 (17) 15
 76
 (40) 36
 
 Total   $28
 $(15) $13
 $51
 $(30) $21
 
                 

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 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2014 September 30, 2014 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions       
 Cash Flow Hedges               
 Energy-Related Contracts Operating Revenues $1
 $—
 $1
 $(11) $5
 $(6) 
 Total Cash Flow Hedges   1
 —
 1
 (11) 5
 (6) 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense 3
 (1) 2
 7
 (3) 4
 
    Amortization of Actuarial Loss O&M Expense (6) 2
 (4) (18) 7
 (11) 
 Total Pension and OPEB Plans (3) 1
 (2) (11) 4
 (7) 
 Available-for-Sale Securities             
 Realized Gains Other Income 45
 (23) 22
 101
 (52) 49
 
 Realized Losses Other Deductions (2) 1
 (1) (12) 6
 (6) 
 OTTI OTTI (10) 5
 (5) (14) 7
 (7) 
 Total Available-for-Sale Securities 33
 (17) 16
 75
 (39) 36
 
 Total   $31
 $(16) $15
 $53
 $(30) $23
 
                 
                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2015 September 30, 2015 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges               
 Energy-Related Contracts Operating Revenues $—
 $—
 $—
 $17
 $(7) $10
 
 Total Cash Flow Hedges   —
 —
 —
 17
 (7) 10
 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense 3
 (1) 2
 9
 (3) 6
 
    Amortization of Actuarial Loss O&M Expense (15) 6
 (9) (45) 18
 (27) 
 Total Pension and OPEB Plans (12) 5
 (7) (36) 15
 (21) 
 Available-for-Sale Securities             
 Realized Gains Other Income 14
 (7) 7
 47
 (24) 23
 
 Realized Losses Other Deductions (11) 5
 (6) (24) 12
 (12) 
 OTTI OTTI (30) 15
 (15) (45) 22
 (23) 
 Total Available-for-Sale Securities (27) 13
 (14) (22) 10
 (12) 
 Total   $(39) $18
 $(21) $(41) $18
 $(23) 
                 
                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2013 September 30, 2013 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions       
 Cash Flow Hedges               
 Energy-Related Contracts Operating Revenues $3
 $(1) $2
 $11
 $(4) $7
 
 Total Cash Flow Hedges   3
 (1) 2
 11
 (4) 7
 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense 3
 (1) 2
 7
 (3) 4
 
    Amortization of Actuarial Loss O&M Expense (17) 7
 (10) (49) 20
 (29) 
 Total Pension and OPEB Plans (14) 6
 (8) (42) 17
 (25) 
 Available-for-Sale Securities             
 Realized Gains Other Income 35
 (18) 17
 95
 (49) 46
 
 Realized Losses Other Deductions (9) 4
 (5) (34) 17
 (17) 
 OTTI OTTI (3) 2
 (1) (7) 4
 (3) 
 Total Available-for-Sale Securities 23
 (12) 11
 54
 (28) 26
 
 Total   $12
 $(7) $5
 $23
 $(15) $8
 
                 

                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2014 September 30, 2014 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges               
 Energy-Related Contracts Operating Revenues $1
 $—
 $1
 $(11) $5
 $(6) 
 Total Cash Flow Hedges   1
 —
 1
 (11) 5
 (6) 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense 3
 (1) 2
 7
 (3) 4
 
    Amortization of Actuarial Loss O&M Expense (6) 2
 (4) (18) 7
 (11) 
 Total Pension and OPEB Plans (3) 1
 (2) (11) 4
 (7) 
 Available-for-Sale Securities             
 Realized Gains Other Income 45
 (23) 22
 101
 (52) 49
 
 Realized Losses Other Deductions (2) 1
 (1) (12) 6
 (6) 
 OTTI OTTI (10) 5
 (5) (14) 7
 (7) 
 Total Available-for-Sale Securities 33
 (17) 16
 75
 (39) 36
 
 Total   $31
 $(16) $15
 $53
 $(30) $23
 
                 


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)


Note 15. Earnings Per Share (EPS) and Dividends
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under our stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS.
                  
  Three Months Ended September 30, Nine Months Ended September 30, 
  2014 2013 2014 2013 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator (Millions)
                
 Net Income$444
 $444
 $390
 $390
 $1,042
 $1,042
 $1,043
 $1,043
 
 
EPS Denominator (Thousands)
                
 Weighted Average Common Shares Outstanding505,862
 505,862
 505,858
 505,858
 505,937
 505,937
 505,900
 505,900
 
 Effect of Stock Based Compensation Awards—
 1,560
 —
 1,836
 —
 1,465
 —
 1,533
 
 Total Shares505,862
 507,422
 505,858
 507,694
 505,937
 507,402
 505,900
 507,433
 
                  
 EPS                
 Net Income$0.88
 $0.87
 $0.77
 $0.77
 $2.06
 $2.05
 $2.06
 $2.06
 
                  
                  
  Three Months Ended September 30, Nine Months Ended September 30, 
  2015 2014 2015 2014 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator (Millions)
                
 Net Income$439
 $439
 $444
 $444
 $1,370
 $1,370
 $1,042
 $1,042
 
 
EPS Denominator (Millions)
                
 Weighted Average Common Shares Outstanding505
 505
 506
 506
 505
 505
 506
 506
 
 Effect of Stock Based Compensation Awards—
 3
 —
 1
 —
 3
 —
 1
 
 Total Shares505
 508
 506
 507
 505
 508
 506
 507
 
                  
 EPS                
 Net Income$0.87
 $0.87
 $0.88
 $0.87
 $2.71
 $2.70
 $2.06
 $2.05
 
                  
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Dividend Payments on Common Stock2014 2013 2014 2013 
 Per Share$0.37
 $0.36
 $1.11
 $1.08
 
 In Millions$187
 $182
 $561
 $546
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Dividend Payments on Common Stock2015 2014 2015 2014 
 Per Share$0.39
 $0.37
 $1.17
 $1.11
 
 In Millions$198
 $187
 $592
 $561
 
          


5857

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)


Note 16. Financial Information by Business Segments
            
  Power PSE&G Other (A) Eliminations (B) Consolidated 
  Millions 
 Three Months Ended September 30, 2014          
 Total Operating Revenues$1,138
 $1,655
 $123
 $(275) $2,641
 
 Net Income (Loss)222
 200
 22
 —
 444
 
 Gross Additions to Long-Lived Assets188
 497
 8
 —
 693
 
 Nine Months Ended September 30, 2014          
 Total Operating Revenues$3,824
 $5,235
 $359
 $(1,305) $8,113
 
 Net Income (Loss)440
 565
 37
 —
 1,042
 
 Gross Additions to Long-Lived Assets414
 1,493
 15
 —
 1,922
 
 Three Months Ended September 30, 2013          
 Total Operating Revenues$1,174
 $1,666
 $3
 $(289) $2,554
 
 Net Income (Loss)226
 168
 (4) —
 390
 
 Gross Additions to Long-Lived Assets210
 480
 6
 —
 696
 
 Nine Months Ended September 30, 2013          
 Total Operating Revenues$3,818
 $5,084
 $29
 $(1,281) $7,650
 
 Net Income (Loss)577
 468
 (2) —
 1,043
 
 Gross Additions to Long-Lived Assets458
 1,628
 16
 —
 2,102
 
 As of September 30, 2014          
 Total Assets$11,750
 $20,917
 $1,907
 $(427) $34,147
 
 Investments in Equity Method Subsidiaries$122
 $—
 $3
 $—
 $125
 
 As of December 31, 2013          
 Total Assets$12,002
 $19,720
 $4,025
 $(3,225) $32,522
 
 Investments in Equity Method Subsidiaries$123
 $—
 $3
 $—
 $126
 
            
            
  PSE&G Power Other (A) Eliminations (B) Consolidated 
  Millions 
 Three Months Ended September 30, 2015          
 Total Operating Revenues$1,766
 $1,096
 $120
 $(294) $2,688
 
 Net Income (Loss)222
 206
 11
 —
 439
 
 Gross Additions to Long-Lived Assets716
 310
 13
 —
 1,039
 
 Nine Months Ended September 30, 2015          
 Total Operating Revenues$5,234
 $3,846
 $326
 $(1,269) $8,137
 
 Net Income (Loss)631
 707
 32
 —
 1,370
 
 Gross Additions to Long-Lived Assets1,946
 797
 39
 —
 2,782
 
 Three Months Ended September 30, 2014          
 Total Operating Revenues$1,655
 $1,138
 $123
 $(275) $2,641
 
 Net Income (Loss)200
 222
 22
 —
 444
 
 Gross Additions to Long-Lived Assets497
 188
 8
 —
 693
 
 Nine Months Ended September 30, 2014          
 Total Operating Revenues$5,235
 $3,824
 $359
 $(1,305) $8,113
 
 Net Income (Loss)565
 440
 37
 —
 1,042
 
 Gross Additions to Long-Lived Assets1,493
 414
 15
 —
 1,922
 
 As of September 30, 2015          
 Total Assets$22,909
 $12,314
 $2,775
 $(1,574) $36,424
 
 Investments in Equity Method Subsidiaries$—
 $116
 $1
 $—
 $117
 
 As of December 31, 2014          
 Total Assets$22,223
 $12,046
 $2,799
 $(1,735) $35,333
 
 Investments in Equity Method Subsidiaries$—
 $121
 $2
 $—
 $123
 
            
(A)Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.
(B)Intercompany eliminations, primarily related to intercompany transactions between PowerPSE&G and PSE&G.Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PowerPSE&G and PSE&G,Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PowerPSE&G and PSE&G,Power, see Note 17. Related-Party Transactions.


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)


Note 17. Related-Party Transactions
The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.
Power
The financial statements for Power include transactions with related parties presented as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2014 2013 2014 2013 
  Millions 
 Revenue from Affiliates:        
 Billings to PSE&G through BGS and BGSS Contracts (A)$280
 $284
 $1,308
 $1,275
 
 Expense Billings from Affiliates:        
 Administrative Billings from Services (B)$(41) $(43) $(129) $(131) 
          
      
  As of As of 
 Related-Party TransactionsSeptember 30, 2014 December 31, 2013 
  Millions 
 Receivables from PSE&G through BGS and BGSS Contracts (A)$132
 $267
 
 Receivable from (Payable to) Services (B)(25) (31) 
 Receivable from (Payable to) PSEG (C)(55) 97
 
 Accounts Receivable (Payable)—Affiliated Companies, net$52
 $333
 
 Short-Term Loan to Affiliate (Demand Note to PSEG) (D)$623
 $790
 
 Working Capital Advances to Services (E)$17
 $17
 
 
Long-Term Accrued Taxes Receivable (Payable) 
$(57) $(53) 
      

PSE&G
The financial statements for PSE&G include transactions with related parties presented as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2014 2013 2014 2013 
  Millions 
 Expense Billings from Affiliates:        
 Billings from Power through BGS and BGSS (A)$(280) $(284) $(1,308) $(1,275) 
 Administrative Billings from Services (B)(59) (61) (183) (184) 
 Total Expense Billings from Affiliates$(339) $(345) $(1,491) $(1,459) 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2015 2014 2015 2014 
  Millions 
 Billings from Affiliates:        
 Billings from Power primarily through BGS and BGSS (A)$294
 $280
 $1,287
 $1,308
 
 Administrative Billings from Services (B)66
 59
 197
 183
 
 Total Billings from Affiliates$360
 $339
 $1,484
 $1,491
 
          
      
  As of As of 
 Related-Party TransactionsSeptember 30, 2015 December 31, 2014 
  Millions 
 Receivable from PSEG (C)$7
 $274
 
 Payable to Power (A)$158
 $313
 
 Payable to Services (B)50
 66
 
 Accounts Payable—Affiliated Companies$208
 $379
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$165
 $116
 
      
Power
The financial statements for Power include transactions with related parties presented as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2015 2014 2015 2014 
  Millions 
 Billings to Affiliates:        
 Billings to PSE&G primarily through BGS and BGSS (A)$294
 $280
 $1,287
 $1,308
 
 Billings from Affiliates:        
 Administrative Billings from Services (B)$44
 $41
 $135
 $129
 
          

6059

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)


      
  As of As of 
 Related-Party TransactionsSeptember 30, 2014 December 31, 2013 
  Millions 
 Payable to Power through BGS and BGSS Contracts (A)$(132) $(267) 
 Receivable from (Payable to) Services (B)(48) (73) 
 Receivable from (Payable to) PSEG (C)81
 150
 
 Accounts Receivable (Payable)—Affiliated Companies, net$(99) $(190) 
 Working Capital Advances to Services (E)$33
 $33
 
 
Long-Term Accrued Taxes Receivable (Payable) 
$(78) $(72) 
      
      
  As of As of 
 Related-Party TransactionsSeptember 30, 2015 December 31, 2014 
  Millions 
 Receivables from PSE&G (A)$158
 $313
 
 Payable to Services (B)$26
 $23
 
 Payable to PSEG (C)91
 95
 
 Accounts Payable—Affiliated Companies$117
 $118
 
 Short-Term Loan Due (to) from Affiliate (E)$865
 $584
 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$54
 $41
 
      
(A)PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.
(B)Services provides and bills administrative services to PowerPSE&G and PSE&GPower at cost. In addition, PowerPSE&G and PSE&GPower 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)PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Condensed Consolidated Balance Sheets.
(E)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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)


Note 18. Guarantees of Debt
Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present 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, 2014          
 Operating Revenues$—
 $1,125
 $36
 $(23) $1,138
 
 Operating Expenses3
 772
 32
 (22) 785
 
 Operating Income (Loss)(3) 353
 4
 (1) 353
 
 Equity Earnings (Losses) of Subsidiaries225
 (1) 4
 (224) 4
 
 Other Income9
 55
 —
 (8) 56
 
 Other Deductions(3) (4) —
 1
 (6) 
 Other-Than-Temporary Impairments—
 (10) —
 —
 (10) 
 Interest Expense(24) (10) (4) 7
 (31) 
 Income Tax Benefit (Expense)18
 (161) (1) —
 (144) 
 Net Income (Loss)$222
 $222
 $3
 $(225) $222
 
 Comprehensive Income (Loss)$195
 $191
 $3
 $(194) $195
 
 Nine Months Ended September 30, 2014          
 Operating Revenues$—
 $3,781
 $118
 $(75) $3,824
 
 Operating Expenses12
 3,079
 106
 (75) 3,122
 
 Operating Income (Loss)(12) 702
 12
 —
 702
 
 Equity Earnings (Losses) of Subsidiaries459
 (4) 11
 (455) 11
 
 Other Income25
 135
 —
 (25) 135
 
 Other Deductions(7) (18) —
 —
 (25) 
 Other-Than-Temporary Impairments—
 (14) —
 —
 (14) 
 Interest Expense(79) (23) (14) 24
 (92) 
 Income Tax Benefit (Expense)54
 (329) (2) —
 (277) 
 Net Income (Loss)$440
 $449
 $7
 $(456) $440
 
 Comprehensive Income (Loss)$432
 $433
 $7
 $(440) $432
 
 Nine Months Ended September 30, 2014          
 
Net Cash Provided By (Used In)
   Operating Activities
$471
 $1,252
 $53
 $(666) $1,110
 
 
Net Cash Provided By (Used In)
   Investing Activities
$187
 $(559) $(24) $70
 $(326) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(652) $(693) $(29) $596
 $(778) 
            








            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 Three Months Ended September 30, 2015          
 Operating Revenues$—
 $1,084
 $37
 $(25) $1,096
 
 Operating Expenses3
 692
 35
 (25) 705
 
 Operating Income (Loss)(3) 392
 2
 —
 391
 
 Equity Earnings (Losses) of Subsidiaries220
 (2) 3
 (218) 3
 
 Other Income10
 26
 —
 (11) 25
 
 Other Deductions—
 (14) —
 —
 (14) 
 Other-Than-Temporary Impairments—
 (30) —
 —
 (30) 
 Interest Expense(28) (8) (5) 11
 (30) 
 Income Tax Benefit (Expense)7
 (148) 2
 —
 (139) 
 Net Income (Loss)$206
 $216
 $2
 $(218) $206
 
 Comprehensive Income (Loss)$184
 $187
 $2
 $(189) $184
 
 Nine Months Ended September 30, 2015          
 Operating Revenues$—
 $3,811
 $144
 $(109) $3,846
 
 Operating Expenses7
 2,610
 135
 (109) 2,643
 
 Operating Income (Loss)(7) 1,201
 9
 —
 1,203
 
 Equity Earnings (Losses) of Subsidiaries755
 (4) 11
 (751) 11
 
 Other Income33
 111
 —
 (35) 109
 
 Other Deductions(1) (31) —
 —
 (32) 
 Other-Than-Temporary Impairments—
 (45) —
 —
 (45) 
 Interest Expense(90) (24) (15) 35
 (94) 
 Income Tax Benefit (Expense)17
 (463) 1
 —
 (445) 
 Net Income (Loss)$707
 $745
 $6
 $(751) $707
 
 Comprehensive Income (Loss)$690
 $707
 $6
 $(713) $690
 
 Nine Months Ended September 30, 2015          
 
Net Cash Provided By (Used In)
   Operating Activities
$435
 $1,826
 $66
 $(769) $1,558
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(656) $(1,382) $(303) $1,191
 $(1,150) 
 
Net Cash Provided By (Used In)
   Financing Activities
$221
 $(446) $245
 $(422) $(402) 
            

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)


            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 Three Months Ended September 30, 2013          
 Operating Revenues$—
 $1,163
 $71
 $(60) $1,174
 
 Operating Expenses2
 797
 66
 (61) 804
 
 Operating Income (Loss)(2) 366
 5
 1
 370
 
 Equity Earnings (Losses) of Subsidiaries231
 (1) 4
 (230) 4
 
 Other Income8
 47
 —
 (10) 45
 
 Other Deductions1
 (11) —
 (1) (11) 
 
Other-Than-Temporary
   Impairments
—
 (3) —
 —
 (3) 
 Interest Expense(19) (13) (4) 10
 (26) 
 Income Tax Benefit (Expense)7
 (160) —
 —
 (153) 
 Net Income (Loss)$226
 $225
 $5
 $(230) $226
 
 Comprehensive Income (Loss)$250
 $242
 $5
 $(247) $250
 
 Nine Months Ended September 30, 2013          
 Operating Revenues$—
 $3,787
 $145
 $(114) $3,818
 
 Operating Expenses6
 2,832
 131
 (114) 2,855
 
 Operating Income (Loss)(6) 955
 14
 —
 963
 
 Equity Earnings (Losses) of Subsidiaries603
 (3) 12
 (600) 12
 
 Other Income27
 130
 —
 (30) 127
 
 Other Deductions(9) (40) —
 —
 (49) 
 
Other-Than-Temporary
   Impairments
—
 (7) —
 —
 (7) 
 Interest Expense(72) (29) (14) 30
 (85) 
 Income Tax Benefit (Expense)34
 (419) 1
 —
 (384) 
 Net Income (Loss)$577
 $587
 $13
 $(600) $577
 
 Comprehensive Income (Loss)$626
 $612
 $13
 $(625) $626
 
 Nine Months Ended September 30, 2013          
 
Net Cash Provided By (Used In)
   Operating Activities
$425
 $1,360
 $35
 $(506) $1,314
 
 
Net Cash Provided By (Used In)
   Investing Activities
$40
 $(869) $(40) $540
 $(329) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(461) $(492) $5
 $(35) $(983) 
            

            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 Three Months Ended September 30, 2014          
 Operating Revenues$—
 $1,125
 $36
 $(23) $1,138
 
 Operating Expenses3
 772
 32
 (22) 785
 
 Operating Income (Loss)(3) 353
 4
 (1) 353
 
 Equity Earnings (Losses) of Subsidiaries225
 (1) 4
 (224) 4
 
 Other Income9
 55
 —
 (8) 56
 
 Other Deductions(3) (4) —
 1
 (6) 
 
Other-Than-Temporary
   Impairments
—
 (10) —
 —
 (10) 
 Interest Expense(24) (10) (4) 7
 (31) 
 Income Tax Benefit (Expense)18
 (161) (1) —
 (144) 
 Net Income (Loss)$222
 $222
 $3
 $(225) $222
 
 Comprehensive Income (Loss)$195
 $191
 $3
 $(194) $195
 
 Nine Months Ended September 30, 2014          
 Operating Revenues$—
 $3,781
 $118
 $(75) $3,824
 
 Operating Expenses12
 3,079
 106
 (75) 3,122
 
 Operating Income (Loss)(12) 702
 12
 —
 702
 
 Equity Earnings (Losses) of Subsidiaries459
 (4) 11
 (455) 11
 
 Other Income25
 135
 —
 (25) 135
 
 Other Deductions(7) (18) —
 —
 (25) 
 Other-Than-Temporary Impairments—
 (14) —
 —
 (14) 
 Interest Expense(79) (23) (14) 24
 (92) 
 Income Tax Benefit (Expense)54
 (329) (2) —
 (277) 
 Net Income (Loss)$440
 $449
 $7
 $(456) $440
 
 Comprehensive Income (Loss)$432
 $433
 $7
 $(440) $432
 
 Nine Months Ended September 30, 2014          
 
Net Cash Provided By (Used In)
   Operating Activities
$471
 $1,252
 $53
 $(666) $1,110
 
 
Net Cash Provided By (Used In)
   Investing Activities
$187
 $(559) $(24) $70
 $(326) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(652) $(693) $(29) $596
 $(778) 
            

6362

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)


            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 As of September 30, 2014          
 Current Assets$4,163
 $1,891
 $111
 $(4,035) $2,130
 
 Property, Plant and Equipment, net81
 6,140
 1,163
 —
 7,384
 
 Investment in Subsidiaries4,358
 120
 —
 (4,478) —
 
 Noncurrent Assets293
 1,901
 139
 (97) 2,236
 
 Total Assets$8,895
 $10,052
 $1,413
 $(8,610) $11,750
 
 Current Liabilities$518
 $3,510
 $754
 $(4,035) $747
 
 Noncurrent Liabilities319
 2,379
 344
 (97) 2,945
 
 Long-Term Debt2,543
 —
 —
 —
 2,543
 
 Member's Equity5,515
 4,163
 315
 (4,478) 5,515
 
 Total Liabilities and Member's Equity$8,895
 $10,052
 $1,413
 $(8,610) $11,750
 
 As of December 31, 2013          
 Current Assets$4,413
 $2,076
 $102
 $(4,115) $2,476
 
 Property, Plant and Equipment, net81
 6,108
 1,178
 —
 7,367
 
 Investment in Subsidiaries4,645
 124
 —
 (4,769) —
 
 Noncurrent Assets222
 1,847
 138
 (48) 2,159
 
 Total Assets$9,361
 $10,155
 $1,418
 $(8,932) $12,002
 
 Current Liabilities$697
 $3,474
 $745
 $(4,116) $800
 
 Noncurrent Liabilities309
 2,247
 338
 (47) 2,847
 
 Long-Term Debt2,497
 —
 —
 —
 2,497
 
 Member's Equity5,858
 4,434
 335
 (4,769) 5,858
 
 Total Liabilities and Member's Equity$9,361
 $10,155
 $1,418
 $(8,932) $12,002
 
            
Immaterial Correction of Prior Financial Information
The financial information included in the tables above has been corrected from the disclosure provided in Power's Form 10-Q filed on October 30, 2013 and Form 10-K filed on February 26, 2014 (2013 10-K) to conform to the requirements of Section 210.3-10 of SEC Regulation S-X.
In the prior disclosure, Operating Revenues and Operating Expenses among the Guarantor Subsidiaries were eliminated in the Consolidating Adjustments column. The revised presentation eliminates this activity in the Guarantor Subsidiaries column and removes such activity from the Consolidating Adjustments column. This revised presentation decreased both Operating Revenues and Operating Expenses in both the Guarantor Subsidiaries and Consolidating Adjustments columns. This correction had no impact on Power’s consolidated Operating Revenues and Operating Expenses.
In the prior disclosure, loans payable by Power parent company to one of its guarantor subsidiaries were netted against loans receivable in net cash flows used in investing activities. The revised presentation reclassifies the increase in loans payable by the parent company to the guarantor subsidiary from net cash flows used in investing activities to net cash flows provided by financing activities. This revised presentation decreased net cash flows used in investing activities and increased net cash flows provided by financing activities in the Power column with corresponding offsets to the amounts in the Consolidating Adjustments Column.
In addition, the revised information was corrected to present the intercompany balances on a net basis when the right of offset exists in either Current Assets or Current Liabilities. This revised presentation resulted in increases (decreases) to certain categories of the condensed consolidated balance sheet.
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 As of September 30, 2015          
 Current Assets$4,678
 $1,786
 $134
 $(4,374) $2,224
 
 Property, Plant and Equipment, net82
 6,390
 1,435
 —
 7,907
 
 Investment in Subsidiaries4,555
 349
 —
 (4,904) —
 
 Noncurrent Assets264
 1,962
 133
 (176) 2,183
 
 Total Assets$9,579
 $10,487
 $1,702
 $(9,454) $12,314
 
 Current Liabilities$1,581
 $3,595
 $772
 $(4,374) $1,574
 
 Noncurrent Liabilities458
 2,563
 355
 (176) 3,200
 
 Long-Term Debt1,691
 —
 —
 —
 1,691
 
 Member's Equity5,849
 4,329
 575
 (4,904) 5,849
 
 Total Liabilities and Member's Equity$9,579
 $10,487
 $1,702
 $(9,454) $12,314
 
 As of December 31, 2014          
 Current Assets$4,263
 $2,037
 $150
 $(4,091) $2,359
 
 Property, Plant and Equipment, net81
 6,265
 1,169
 —
 7,515
 
 Investment in Subsidiaries4,516
 120
 —
 (4,636) —
 
 Noncurrent Assets278
 1,952
 137
 (195) 2,172
 
 Total Assets$9,138
 $10,374
 $1,456
 $(8,922) $12,046
 
 Current Liabilities$883
 $3,606
 $786
 $(4,091) $1,184
 
 Noncurrent Liabilities454
 2,442
 360
 (195) 3,061
 
 Long-Term Debt2,243
 —
 —
 —
 2,243
 
 Member's Equity5,558
 4,326
 310
 (4,636) 5,558
 
 Total Liabilities and Member's Equity$9,138
 $10,374
 $1,456
 $(8,922) $12,046
 
            


6463
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tabletable of Contentscontents (UNAUDITED)


The following three tables include corrected data for these aforementioned adjustments to the information previously filed in Power's Form 10-Q dated May 1, 2014 or 2013 10-K.
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Millions 
 Three Months Ended March 31, 2014          
 Operating Revenues$—
 $1,684
 $40
 $(24) $1,700
 
 Operating Expenses4
 1,404
 34
 (24) 1,418
 
 Operating Income (Loss)(4) 280
 6
 —
 282
 
 Equity Earnings (Losses) of Subsidiaries177
 —
 4
 (177) 4
 
 Other Income8
 33
 —
 (8) 33
 
 Other Deductions(4) (6) —
 —
 (10) 
 Other-Than-Temporary Impairments—
 (2) —
 —
 (2) 
 Interest Expense(28) (7) (5) 8
 (32) 
 Income Tax Benefit (Expense)15
 (125) (1) —
 (111) 
 Net Income (Loss)$164
 $173
 $4
 $(177) $164
 
 Comprehensive Income (Loss)$170
 $176
 $4
 $(180) $170
 
 Three Months Ended March 31, 2014          
 
Net Cash Provided By (Used In)
   Operating Activities
$291
 $603
 $1
 $(221) $674
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(122) $(315) $—
 $142
 $(295) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(166) $(287) $(1) $79
 $(375) 
 Three Months Ended March 31, 2013          
 Operating Revenues$—
 $1,441
 $37
 $(27) $1,451
 
 Operating Expenses2
 1,200
 33
 (26) 1,209
 
 Operating Income (Loss)(2) 241
 4
 (1) 242
 
 Equity Earnings (Losses) of Subsidiaries153
 —
 3
 (153) 3
 
 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)$141
 $149
 $4
 $(153) $141
 
 Comprehensive Income (Loss)$173
 $172
 $4
 $(176) $173
 
 Three Months Ended March 31, 2013          
 
Net Cash Provided By (Used In)
   Operating Activities
$189
 $574
 $1
 $(189) $575
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(213) $(353) $(8) $245
 $(329) 
 
Net Cash Provided By (Used In)
   Financing Activities
$24
 $(221) $7
 $(57) $(247) 
 As of March 31, 2014          
 Current Assets$4,436
 $2,097
 $107
 $(4,341) $2,299
 
 Property, Plant and Equipment, net81
 6,082
 1,172
 —
 7,335
 
 Investment in Subsidiaries4,570
 122
 —
 (4,692) —
 
 Noncurrent Assets301
 1,832
 138
 (117) 2,154
 
 Total Assets$9,388
 $10,133
 $1,417
 $(9,150) $11,788
 
 Current Liabilities$930
 $3,450
 $741
 $(4,340) $781
 
 Noncurrent Liabilities308
 2,323
 344
 (118) 2,857
 
 Long-Term Debt2,497
 —
 —
 —
 2,497
 
 Member's Equity5,653
 4,360
 332
 (4,692) 5,653
 
 Total Liabilities and Member's Equity$9,388
 $10,133
 $1,417
 $(9,150) $11,788
 
            


65
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)



            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Year Ended December 31, 2013          
 Operating Revenues$—
 $5,022
 $190
 $(149) $5,063
 
 Operating Expenses23
 3,945
 174
 (149) 3,993
 
 Operating Income (Loss)(23) 1,077
 16
 —
 1,070
 
 Equity Earnings (Losses) of Subsidiaries684
 (5) 16
 (679) 16
 
 Other Income35
 157
 —
 (38) 154
 
 Other Deductions(14) (35) —
 —
 (49) 
 Other-Than-Temporary Impairments—
 (12) —
 —
 (12) 
 Interest Expense(93) (42) (19) 38
 (116) 
 Income Tax Benefit (Expense)55
 (474) —
 —
 (419) 
 Net Income (Loss)$644
 $666
 $13
 $(679) $644
 
   Comprehensive Income (Loss)$909
 $713
 $11
 $(724) $909
 
 Year Ended December 31, 2013          
 Net Cash Provided By (Used In) Operating Activities$288
 $1,503
 $82
 $(526) $1,347
 
 Net Cash Provided By (Used In) Investing Activities$(395) $(1,092) $(71) $697
 $(861) 
 Net Cash Provided By (Used In) Financing Activities$107
 $(412) $(11) $(171) $(487) 
 Year Ended December 31, 2012          
 Operating Revenues$—
 $4,850
 $135
 $(112) $4,873
 
 Operating Expenses7
 3,730
 125
 (112) 3,750
 
 Operating Income (Loss)(7) 1,120
 10
 —
 1,123
 
 Equity Earnings (Losses) of Subsidiaries707
 (10) 15
 (697) 15
 
 Other Income45
 206
 2
 (52) 201
 
 Other Deductions(31) (59) —
 —
 (90) 
 Other-Than-Temporary Impairments—
 (18) —
 —
 (18) 
 Interest Expense(118) (51) (16) 53
 (132) 
 Income Tax Benefit (Expense)70
 (501) (2) —
 (433) 
 Net Income (Loss)$666
 $687
 $9
 $(696) $666
 
   Comprehensive Income (Loss)$614
 $681
 $9
 $(690) $614
 
 Year Ended December 31, 2012          
 Net Cash Provided By (Used In) Operating Activities$298
 $1,562
 $67
 $(474) $1,453
 
 Net Cash Provided By (Used In) Investing Activities$(14) $(1,206) $(151) $899
 $(472) 
 Net Cash Provided By (Used In) Financing Activities$(284) $(361) $83
 $(424) $(986) 
 As of December 31, 2012          
 Current Assets$4,255
 $1,898
 $104
 $(4,021) $2,236
 
 Property, Plant and Equipment, net80
 5,988
 1,154
 —
 7,222
 
 Investment in Subsidiaries4,508
 128
 —
 (4,636) —
 
 Noncurrent Assets201
 1,660
 145
 (141) 1,865
 
 Total Assets$9,044
 $9,674
 $1,403
 $(8,798) $11,323
 
 Current Liabilities$815
 $3,396
 $778
 $(4,021) $968
 
 Noncurrent Liabilities559
 1,960
 306
 (140) 2,685
 
 Long-Term Debt2,040
 —
 —
 —
 2,040
 
 Member’s Equity5,630
 4,318
 319
 (4,637) 5,630
 
 Total Liabilities and Member’s Equity$9,044
 $9,674
 $1,403
 $(8,798) $11,323
 
            


66
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)


            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Year Ended December 31, 2011          
 Operating Revenues$—
 $6,139
 $155
 $(144) $6,150
 
 Operating Expenses5
 4,360
 157
 (145) 4,377
 
 Operating Income (Loss)(5) 1,779
 (2) 1
 1,773
 
 Equity Earnings (Losses) of Subsidiaries1,186
 92
 14
 (1,278) 14
 
 Other Income40
 195
 —
 (45) 190
 
 Other Deductions(28) (51) —
 —
 (79) 
 Other-Than-Temporary Impairments(1) (19) —
 —
 (20) 
 Interest Expense(146) (56) (18) 45
 (175) 
 Income Tax Benefit (Expense)63
 (762) 9
 —
 (690) 
 Income (Loss) on Discontinued Operations, net of Tax Benefit—
 —
 97
 (1) 96
 
 Net Income (Loss)$1,109
 $1,178
 $100
 $(1,278) $1,109
 
   Comprehensive Income (Loss)$928
 $1,055
 $100
 $(1,155) $928
 
 Year Ended December 31, 2011          
 Net Cash Provided By (Used In) Operating Activities$609
 $2,427
 $(279) $(940) $1,817
 
 Net Cash Provided By (Used In) Investing Activities$(268) $(1,171) $594
 $267
 $(578) 
 Net Cash Provided By (Used In) Financing Activities$(341) $(1,256) $(314) $673
 $(1,238) 
            





















67
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)


The following two tables summarize the adjustments for all prior periods that have been revised in this Note.
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Increase (Decrease) 
  Millions 
 Three Months Ended March 31, 2014          
 Operating Revenues$—
 $(393) $—
 $393
 $—
 
 Operating Expenses$—
 $(393) $—
 $393
 $—
 
 Net Cash Provided By (Used In) Investing Activities$(209) $—
 $—
 $209
 $—
 
 Net Cash Provided By (Used In) Financing Activities$209
 $—
 $—
 $(209) $—
 
 Three Months Ended March 31, 2013          
 Operating Revenues$—
 $(362) $—
 $362
 $—
 
 Operating Expenses$—
 $(362) $—
 $362
 $—
 
 Net Cash Provided By (Used In) Investing Activities$(269) $—
 $—
 $269
 $—
 
 Net Cash Provided By (Used In) Financing Activities$269
 $—
 $—
 $(269) $—
 
 As of March 31, 2014          
 Current Assets$327
 $(7,048) $(844) $7,565
 $—
 
 Investment in Subsidiaries—
 (605) —
 605
 —
 
 Total Assets$327
 $(7,653) $(844) $8,170
 $—
 
 Current Liabilities$327
 $(7,653) $(239) $7,565
 $—
 
 Member's Equity—
 —
 (605) 605
 —
 
 Total Liabilities and Member's Equity$327
 $(7,653) $(844) $8,170
 $—
 
 Three Months Ended September 30, 2013          
 Operating Revenues$—
 $(348) $—
 $348
 $—
 
 Operating Expenses$—
 $(348) $—
 $348
 $—
 
 Nine Months Ended September 30, 2013          
 Operating Revenues$—
 $(1,062) $—
 $1,062
 $—
 
 Operating Expenses$—
 $(1,062) $—
 $1,062
 $—
 
 Net Cash Provided By (Used In) Investing Activities$(520) $—
 $—
 $520
 $—
 
 Net Cash Provided By (Used In) Financing Activities$520
 $—
 $—
 $(520) $—
 
            












68
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Table of Contents (UNAUDITED)


            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Consolidated 
  Increase (Decrease) 
  Millions 
 Year Ended December 31, 2013          
 Operating Revenues$—
 $(1,468) $—
 $1,468
 $—
 
 Operating Expenses$—
 $(1,468) $—
 $1,468
 $—
 
 Net Cash Provided By (Used In) Investing Activities$(588) $—
 $—
 $588
 $—
 
 Net Cash Provided By (Used In) Financing Activities$588
 $—
 $—
 $(588) $—
 
 As of December 31, 2013          
 Current Assets$253
 $(6,840) $(842) $7,429
 $—
 
 Investment in Subsidiaries—
 (605) —
 605
 —
 
 Total Assets$253
 $(7,445) $(842) $8,034
 $—
 
 Current Liabilities253
 $(7,445) $(237) $7,429
 $—
 
 Member's Equity—
 —
 (605) 605
 —
 
 Total Liabilities and Member's Equity$253
 $(7,445) $(842) $8,034
 $—
 
 Year Ended December 31, 2012          
 Operating Revenues$—
 $(1,388) $—
 $1,388
 $—
 
 Operating Expenses$—
 $(1,388) $—
 $1,388
 $—
 
 Net Cash Provided By (Used In) Investing Activities$(729) $—
 $—
 $729
 $—
 
 Net Cash Provided By (Used In) Financing Activities$679
 $—
 $—
 $(679) $—
 
 As of December 31, 2012          
 Current Assets$333
 $(6,186) $(838) $6,691
 $—
 
 Investment in Subsidiaries—
 (605) —
 605
 —
 
 Total Assets$333
 $(6,791) $(838) $7,296
 $—
 
 Current Liabilities$333
 $(6,791) $(233) $6,691
 $—
 
 Member's Equity—
 —
 (605) 605
 —
 
 Total Liabilities and Member's Equity$333
 $(6,791) $(838) $7,296
 $—
 
 Year Ended December 31, 2011          
 Operating Revenues$—
 $(1,313) $—
 $1,313
 $—
 
 Operating Expenses$—
 $(1,313) $—
 $1,313
 $—
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(864) $—
 $—
 $864
 $—
 
 
Net Cash Provided By (Used In)
   Financing Activities
$869
 $—
 $—
 $(869) $—
 
            
These corrections to the presentation had no impact to Power’s condensed consolidated financial statements. These corrections to the presentation had no impact on any liquidity measures of Power. There was no impact to Power's loan covenants as a result of these corrections. Management believes these corrections are immaterial.

69
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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 Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PowerPSE&G and PSE&GPower each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG's business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:
PSE&G, our public utility company which primarily provides electric transmission services and distribution of electric energy and natural gas, implements demand response and energy efficiency programs and invests in solar generation in New Jersey, and
Power, our wholesale energy supply company that integrates its nuclear, fossil and renewable generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid-Atlantic United States, and
PSE&G, our public utility company which primarily provides electric transmission services and distribution of electric energy and natural gas, implements demand response and energy efficiency programs and invests in solar generation in New Jersey.States.
PSEG's other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments; PSEG Long Island LLC (PSEG LI), which effective January 1, 2014, operates the Long Island Power Authority's (LIPA) transmission and distribution (T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and these operating subsidiaries with certain management, administrative and general services at cost.
Our business discussion in Part I, Item 1. Business of our 20132014 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part I, Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of 20132014 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 20142015 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the 20132014 Form 10-K and the Quarterly Reports on Form 10-Q for the quarters ended June 30, 2014 and March 31, 2014.10-K.

EXECUTIVE OVERVIEW OF 20142015 AND FUTURE OUTLOOK
Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:
Growing our utility operations through continued investment in T&D and other infrastructure projects, with greater diversity of regulatory oversight, and
Maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels to allowwhich allows us to respond to market volatility and capitalize on opportunities as they arise in the locations in which we operate.arise.



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Financial Results
The results for PSEG, PSE&G and Power for the three months and nine months ended September 30, 20142015 and 20132014 are presented as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Earnings (Losses)2014 2013 2014 2013 
  Millions 
 Power$222
 $226
 $440
 $577
 
 PSE&G200
 168
 565
 468
 
 Other (A)22
 (4) 37
 (2) 
 PSEG Net Income$444
 $390
 $1,042
 $1,043
 
          
 PSEG Net Income Per Share (Diluted)$0.87
 $0.77
 $2.05
 $2.06
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Earnings2015 2014 2015 2014 
  Millions 
 PSE&G$222
 $200
 $631
 $565
 
 Power (A)206
 222
 707
 440
 
 Other (B)11
 22
 32
 37
 
 PSEG Net Income$439
 $444
 $1,370
 $1,042
 
          
 PSEG Net Income Per Share (Diluted)$0.87
 $0.87
 $2.70
 $2.05
 
          
(A)Includes an after-tax insurance recovery for Superstorm Sandy of $102 million in the nine months ended September 30, 2015. See Item 1. Note 8. Commitments and Contingent Liabilities.
(B)Other includes activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations.
Power’s results above include the realized gains, losses and earnings on the Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity and the impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with forward delivery dates.
The variances in our Net Income include the changes related to NDT and MTM shown in the following table:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2014 2013 2014 2013 
  Millions, after tax 
 NDT Fund Income (Expense) (A)$17
 $12
 $40
 $29
 
 Non-Trading MTM Gains (Losses)$36
 $3
 $(138) $(22) 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2015 2014 2015 2014 
  Millions, after tax 
 NDT Fund Income (Expense) (A)$(14) $17
 $(11) $40
 
 Non-Trading MTM Gains (Losses)$50
 $36
 $58
 $(138) 
          
(A)NDT Fund Income (Expense) includes the net realized gains and losses, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions, and impairments on certain NDT securities recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization Expense.
Our $54$5 million increasedecrease in Net Income for the three months ended September 30, 20142015 was driven byprimarily by:
lower net realized gains and higher other-than-temporary impairments related to the NDT Fund, and
higher maintenance costs related to the earlier start in 2015 of the planned annual outage of our Peach Bottom Unit 3 nuclear facility and higher pension and other postretirement (OPEB) costs and lower maintenance costs due to a planned outage at our combined cycle Bethlehem Energy Center (BEC) fossil plant in 2013,OPEB costs.
These decreases were largely offset by
higher revenues due to increased investments in transmission projects, and
lower income tax expense due to tax benefits related to the settlement of the Internal Revenue Service audits for the years 2007-2010.

These increases were partially offset by lower capacity revenues resulting from lower average auction prices in PJM.higher MTM gains.
Our $328 million increase in Net Income for the nine months ended September 30, 2014 remained nearly level with Net Income for the comparable prior year period. While we experienced2015 was driven primarily by:
higher sales volumes under the basic gas supply service (BGSS) contract dueMTM gains in 2015 as compared to colder average temperaturesMTM losses in the 2014, winter heating season,
higher volumes of gaselectricity sold under wholesale load contracts and under the BGS contract, the latter at higher average prices,
lower generation costs due to third party customers,lower fuel costs,

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higher revenues due to increased investments in transmission projects, and
insurance recoveries of Superstorm Sandy costs, primarily at Power.
These year-to date increases were partially offset by
lower realized gains and higher other-than-temporary impairments related to the NDT Fund,
higher planned outage costs at our nuclear plants and higher pension and OPEB costs, and lower storm costs
higher Depreciation Expense largely related to Superstorm Sandy,increased investments in transmission and distribution projects and a higher depreciable nuclear and fossil asset base.

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TableAt PSE&G, our regulated utility, we continued to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers. Effective January 1, 2015, PSE&G's formula rate increased our annual transmission revenues by approximately $182 million. Each year, transmission revenues are filed based on estimated data and subject to true up with actual current year data. The true-up adjustment for 2015, which will be filed in the Spring of Contents



such increases were completely offset by
higher MTM losses in 2014 resulting from an increase in prices2016, will primarily include the impact on forward positions,
lower volumes of electricity sold under our basic generation service (BGS) contracts resulting from serving fewer tranches in 2014, and
higher generation costsrate base due to the extension of bonus depreciation, which was enacted after the filing was made, and is estimated to reduce our 2015 annual revenue increase by approximately $21 million. In October 2015, we filed our 2016 Annual Formula Rate Update with the Federal Energy Regulatory Commission (FERC), which will provide $146 million in increased annual transmission revenues effective January 1, 2016.
Over the past few years, these types of investments have altered the business mix of our overall results of operations to reflect a higher fuel costs and higher gas costs related to the BGSS contract.percentage contribution by PSE&G.
Power’s results benefited from access to natural gas supplies through its existing firm pipeline transportation contracts during the cold weather experienced in the first quarter of 2014.2015. Power manages these contracts for the benefit of PSE&G’s customers through the BGSSbasic gas supply service (BGSS) arrangement. The contracts are sized to ensure delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third party sales and supply gas to its generating units in New Jersey and to make third party sales.Jersey.
UnderGas prices have remained relatively low this year as a result of the PJM capacity auction conducted in May 2014, Power cleared 8,693 MWexpansion of its generating capacity at an average price of $164.61 MW-day for the 2017-2018 delivery period, a price consistent with what has been realizedshale gas production, primarily in the past three auctions. ForMarcellus/Utica regions. These low prices benefit PSE&G’s gas customers and provide a more detailed discussionlow cost fuel supply for Power’s combined cycle units. However, they have also resulted in a decline in power prices. Our contractual hedges currently in place have helped mitigate some of the effects of low prices this year and for 2016. However, as these arrangements expire and new hedges are set at lower price levels, our margins will be impacted. A sustained continuation of low prices could have an adverse impact on the Reliability Pricing Model (RPM) capacity auction, refer to Part II, Item 5. Other Information—Federal Regulation—Capacity Market Issues—PJM.
Power’s 2014 results were unfavorably impacted by an extended refueling outage at Salem Unit 2. A planned refueling outage began on April 12, 2014 but was extended due to repairs to the Reactor Coolant Pump Turning Vanes. Salem Unit 2 returned to service on July 14, 2014.
At PSE&G,earnings from our regulated utility, we continued to invest capital in T&D infrastructure projects aimed at maintaining the reliability of our service to our customers. PSE&G’s results for the first half of 2014 reflect the favorable impacts from these investments as well as a slowly improving economy. Effective January 1, 2014, PSE&G's annual formula rate increased our annual transmission revenues by approximately $171 million. In October 2014, we filed our 2015 Annual Formula Rate Update with the Federal Energy Regulatory Commission (FERC), which would provide $182 million in increased annual transmission revenues effective January 1, 2015. Over the past few years, these types of investments have altered the business mix of our overall results of operations to reflect a higher percentage contribution by PSE&G.nuclear and coal-fired units. 
Regulatory, Legislative and Other Developments
In developing and implementing our strategypursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.
Transmission Planning
FERC’s rule under Order 1000 altered the right of first refusal (ROFR) previously held by incumbent utilities to build transmission within their respective service territories, creating the potential that new transmission projects in our service territory could be assigned to third parties rather than PSE&G. Order 1000 also presents opportunities for us to construct transmission outside of our service territory. In April 2013, PJM Interconnection, L.L.C. (PJM) initiated a solicitation process in which we participated to review technical solutions to improve the operational performance in the Artificial Island area, consisting of our Salem and Hope Creek nuclear generation facilities. In April 2015, the PJM staff advised stakeholders that it intended to recommend a transmission project that would primarily be awarded to another entity, but that a portion would be assigned to PSE&G. We subsequently filed comments with the PJM Board of Managers (PJM Board) identifying what we believed were deficiencies in the PJM staff recommendation. In July 2015, the PJM Board approved the PJM staff's recommendation and in August 2015, PJM provided notice to PSE&G of its designation for construction responsibility with respect to three components of the project, estimated by PJM to cost approximately $126 million. PSE&G is currently in discussions with PJM regarding the accuracy of this estimate given the complexities associated with construction work at Artificial Island. See Part II. Item 5. Other Information—Transmission Regulation—Transmission Policy Developments for additional information.


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Wholesale Power Market Design
Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. In May 2014, a federal court issued a rule that vacated a FERC Order in which FERC had determined that demand response (DR) providers should receive full market compensation for power and held that FERC has no jurisdiction over DR. In October 2015, the U.S. Supreme Court heard oral arguments on this case. Although a reversal by the U.S. Supreme Court of the federal court's decision regarding FERC's lack of jurisdiction is not expected to have significant impacts on capacity markets, a decision that upholds such decision could have a material impact on capacity market outcomes.
In a separate development of significance to the wholesale capacity market, in December 2014 PJM filed at FERC its proposal for a capacity performance product to include generators, DR and energy efficiency providers who would need to certify their availability during emergency conditions, as a supplement to base capacity. The proposal included enhanced performance-based incentives and penalties. In June 2015, FERC conditionally accepted the proposal. PJM commenced the auction on August 10, 2015 and announced the auction results on August 21, 2015. Power cleared 8,634 MW of its generating capacity at an average price of $214.72 MW-day for the 2018-2019 delivery period. Of the cleared capacity, Power believes that nearly all is compliant with PJM's CP requirements. In the two prior capacity auctions covering the 2016-2017 and 2017-2018 delivery years, Power cleared approximately 8,700 MW at average prices of $172 MW-day and $177 MW-day, respectively. The capacity that Power cleared for the 2018-2019 delivery year included Sewaren 7 and Keys Energy Center generation plants. See Other Developments below for additional details about our construction of these two new projects. We believe that this pricing adequately reflects the increased costs that could result from operating under more stringent rules for generation availability. No assurances can be given that similar pricing will continue in future auctions.
Applications for rehearing of FERC's capacity performance order are pending. See Part II, Item 5. Other Information—Capacity Market Issues—PJM for additional information.
We have also been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for setting prices for energy in the day-ahead and real-time markets administered by PJM and other system operators. A recent development which we view as positive involves a September 2015 FERC notice of proposed rulemaking on two issues: aligning settlements with dispatch intervals (more granular “5-minute pricing” in real-time markets) and improving real-time scarcity pricing. Comments made by FERC commissioners stressed these two items are intended to be the first of a series of steps FERC will take on energy price formation in the future. See Part II, Item 5. Other Information—Price Formation Initiatives for additional information.
Environmental Regulation
We continue to advocate for the development and implementation of fair and reasonable rules by the U.S. Environmental Protection Agency (EPA) and state environmental regulators. On May 19, 2014,In particular, the EPA released the final Clean Water Act SectionEPA’s 316(b) rule on cooling water intake that establishes new requirements for the regulation of cooling water intakes at existing power plantscould adversely impact future nuclear and industrial facilities with a design flow of more than two million gallons of water per day. Eight of Power’s generating facilitiesfossil operations and three of its jointly-owned generating facilities are subject to the rule.costs. As adopted by the EPA, the rule requires that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts, primarily by reducing the amount of fish and shellfish that are impinged or entrained at a cooling water intake structure.impacts. Under this standard, power facilities have the flexibility to select one of several options as their method of compliance. However, the EPA has structured the rule so that each state will continue to consider renewal permits for existing power facilities on a case by case basis,basis. In June 2015, the New Jersey Department of Environmental Protection (NJDEP) issued a draft New Jersey Pollutant Discharge Elimination Systems (NJPDES) permit governing cooling water intake structures for Salem. The draft permit does not require installation of cooling towers and will require facilitiesallows Salem to conductcontinue to operate utilizing the existing once-through cooling water system with required system modifications. The draft permit was subject to a wide rangesixty-day public notice and comment period. The NJDEP may make revisions before issuing the final permit expected during the first half of studies related to impingement mortality2016. We participated in the NJDEP’s August 2015 public hearing and entrainment and submitsubmitted comments on the results with theirdraft permit applications. A federal court challenge to the EPA rule is pending. We are unable to predict the outcome that these permitting decisions may take and the effect, if any, that they may have on us although such impacts could be material.in September 2015. See Item 1. Note 8. Commitments and Contingent Liabilities and Part II, Item 5. Other Information—Environmental Matters—Water Pollution Control for additionalfurther information.
On June 18, 2014,The EPA’s greenhouse gas (GHG) emissions regulations are also of potential consequence to our results. In October 2015, the EPA issuedpublished the Clean Power Plan (CPP), a proposed greenhouse gasGHG emissions regulation under the Clean Air Act (CAA) for existing power plants. The regulation establishes state-specific emission rate targets based on implementation of the best systemsystems of emission reduction. States may choose theseEach state must submit a compliance plan to the EPA by September 6, 2016 or other methodologiesseek a two-year extension to achieve the necessary reductions of carbon dioxide emissions. The EPA is requesting comment on many aspects of the proposal and therefore, the final rule may look considerably different than the proposal.September 6, 2018. We continue to work with stateFERC and other federal and state regulators, as well as industry partners, to determine the potential impact of these regulations. The EPA, FERC and the regulation.U.S. Department of Energy have announced that they plan to meet at least quarterly to evaluate states' plans and identify reliability concerns so adjustments can be made before the final plans are submitted. The agencies are engaging various stakeholders, including the Regional Transmission Operators/Independent System Operators. The agencies will continue to meet after the states' plans are in effect to assess if revisions are required. See Part II, Item 5. Other Information—Environmental Matters—Climate Change for additional information.
In addition,CO2 Regulation Under the Clean Air Act (CAA)Act.
CAA regulations governing hazardous air pollutants under the EPA's Maximum Achievable Control Technology rules are also of significance; however, we believe our generation business remains well-positioned for such air pollution control regulations if and when they are implemented. In addition, state environmental regulations governing emissions from power plants also have a significant

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The FERC’s rule under Order 1000 alteredimpact on our operations. In the rightsecond quarter of first refusal previously held by incumbent utilities2015, we retired 1,545 MW of fully depreciated combustion turbine capacity that would not be able to build all transmission within their respective service territories. Our challenge to the rule itself was rejected by the federal court. However, PJM’s implementation of the rule has minimized the risk associatedcomply with the FERC’s changesmore stringent emission standards for high electric demand day units (HEDD) under the New Jersey HEDD regulations for nitrous oxide, which will reduce capacity revenues for this year.
Other Developments
In the first nine months of 2015, we continued to the right of first refusal by carving out categories of projects that will continue to default to incumbent transmission owners. Further, the FERC's action presents opportunities for us to construct transmission outside of our service territory. In April 2013, PJM initiated a solicitation process pursuant to Order 1000 to review technical solutionsmake investments and seek recovery on such investments made to improve the operational performance in the Artificial Island area, consistingresiliency of our Salem Units 1 and 2 and Hope Creek nuclear generation facilities. In June 2014, PJM’s management recommended approval by its Board of a 500 kV project to be constructed by PSE&G to address performance issues at Artificial Island. In July 2014, the PJM Board announced that it was deferring the selection of a project to enable four developers, including PSE&G, to supplement their project proposals by, among other things, re-evaluating the costs of their respective proposals. In September 2014, PSE&G and three other finalists submitted supplemental proposals. PJM currently expects to select a project in the first quarter of 2015.
PJM has filed with the FERC to add a new “multi-driver” category of transmission projects, which projects may include a combination of reliability, economic and public policy elements. Changes to the factors used in making determinations in the PJM project planning and cost-allocation processes could have significant implications for the types of projects selected and the utility customers ultimately charged for the costs of such new transmission facilities.
Capacity market design, including the RPM, remains an important focus for us. In May 2014, a federal court issued a rule that vacated a FERC Order in which the FERC had determined that demand response (DR) providers should receive full market compensation for power and held that the FERC has no jurisdiction over DR. A subsequent challenge to the participation of DR as a resource in the PJM capacity market is pending at the FERC. In addition, PJM has filed at the FERC to reset the demand curve for the RPM, as is done every three years. We are working to assure that the demand curve is set at a level that accurately reflects the cost of building a new generating unit in New Jersey. Further, in response to last winter’s polar vortex, PJM is developing a proposal to be filed with the FERC for a capacity performance product to include generators, DR and energy efficiency providers who would guarantee availability during peak winter and summer conditions, as a supplement to base capacity and with enhanced performance-based incentives and penalties. The implications of these developments could be significant for the capacity market. See Part II, Item 5. Other Information—Federal Regulation—Capacity Market Issues—PJM for additional information.
In 2014, appeals to challenge the federal court rulings that the New Jersey Long-Term Capacity Agreement Pilot Program Act to subsidize above-market new generation and a similar action taken by Maryland were unconstitutional and null and void were each denied. For additional information, refer to Part II, Item 5. Other Information—Federal Regulation—Capacity Market Issues—Long-Term Capacity Agreement Pilot Program Act.
A critical aspect of our wholesale energy marketing business is the continued retention of market-based rate (MBR) authority from the FERC for our operating subsidiaries that engage in such activities. On October 14, 2014, the FERC issued an Order that accepted our triennial market power update, concluding that our submission satisfied its requirements for retention of MBR authority.
In recent years we have been impacted by severe weather conditions, including Hurricane Irene in 2011 and Superstorm Sandy in 2012, the latter storm resulting in the highest level of customer outages in our history. For more detailed information, refer to Item 1—Note 8. Commitments and Contingent Liabilities—Superstorm Sandy. We have begun work in our gas and electric distribution systems to improve resiliency. Thesystem as part of our Energy Strong program that was approved by the New Jersey Board of Public Utilities (BPU) in 2014. As approved, the settlement of our Energy Strong Proposal in a total amountprogram provides for $1.2 billion of $1.22 billion. The settlement provides forinvestment, with cost recovery at a 9.75% rate of return on equity on the first $1.0 billion of the investment, plus associated allowance for funds used during construction, through an accelerated recovery mechanism. We will seek recovery of the remainingup to $220 million of investment in PSE&G's next base rate case, which is to be filed no later than November 1, 2017.
In September 2015, we reached a settlement in principle with the BPU Staff and the New Jersey Division of Rate Counsel regarding PSE&G’s Gas System Modernization Program (GSMP) through which, if approved, we will invest $905 million over the next three years to modernize PSE&G's gas systems. The settlement in principle provides for cost recovery at a 9.75% rate of return on equity on the first $650 million of the investment through an accelerated recovery mechanism. Under the settlement in principle, PSE&G will seek recovery of the remaining $255 million of investment in its next base rate case, which is to be filed no later than November 1, 2017. For additional information, refer tosee Part II, Item 5. Other Information—State Regulation—Energy StrongGas System Modernization Program.
In September 2014, the BPU approved substantiallyAugust 2015, we announced our entire request forplan to construct Sewaren 7, a determination that our storm related costs,new 540 MW duel-fueled combined cycle generating plant in the total amount of $366 million, were prudently incurred and recoverable in a future base rate proceeding, subjectWoodbridge, New Jersey scheduled to offsetbe in-service for the amountsummer of insurance proceeds received. For additional information, refer to Item 1. Note2018 at an estimated investment of $625 million - $675 million. The Sewaren 7 plant will replace Sewaren Units 1, 2, 3 and 4. Rate Filings.
On January 1, 2014, we commenced operation of the LIPA T&D system under a twelve-year contract with opportunity to extend for an additional eight years. Also, beginning in January 2015, Power will provide fuel procurement and power management services to LIPA under separate agreements.
In the first quarterJune 2015, we acquired a development project to construct a 755 MW gas-fired combined cycle generating station (Keys Energy Center) in Maryland with completion expected in 2018 at an estimated investment of 2014, Power discovered that it incorrectly calculated$825 million - $875 million.
The preliminary non-public staff investigation initiated by FERC into Power's discovery and investigation of (i) incorrect calculations for certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. We notified the FERC, PJMmarket and the PJM Independent Market Monitor (IMM) of this issue. Upon discovery of the errors, we retained outside counsel to assist(ii) differences in the conduct of an investigation into the matter. As the investigation proceeded, additional pricing errors in the bids were identified and it was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed

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from the amount for which Power was compensated in the capacity market for those units. We informed the FERC, PJM and the IMM of these additional issues, and have corrected these errors.units continues. Power is also in thehas an ongoing process of implementing improved procedures to help mitigate the risk of similar issues occurring in the future. On September 2, 2014, the FERC Staff verbally informed us that they have initiated a preliminary, non-public staff investigation into the matter. This investigation could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies. It is not possible at this time to reasonably estimate the ultimate impact or predict any resulting penalties, other costs associated with this matter, or the applicability of mitigating factors. For more detailed information, regarding this matter, refer to Item 1. Note 8. Commitments and Contingent Liabilities—FERC Compliance.
Operational Excellence
We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of market opportunities presented during the year as we remain diligent in managing costs. In the first nine months of 2014,2015, our
total nuclear fleet achieved an average capacity factor of 91%92%, while also completing an extended outage at Salem Unit 2,
nuclear output increased by 2.7% and combined cycle output by 14.9% as compared to the same period in 2014, and
diverse fuel mix and dispatch flexibility allowed us to generate approximately 41,300 GWh,42.5 TWh while addressing unit outages and balancing fuel availability and price volatility, and
construction of transmission and solar projects proceeded on schedule and within budget.volatility.
Financial Strength
Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first nine months of 20142015 as we
had cash on handflow from operations of $703 million$3.2 billion as of September 30, 2014,
extended the expiration dates of PSEG's $500 million and Power's $1.6 billion five-year credit facilities from 2017 to 2019, and maintained substantial liquidity,2015,
maintained solid investment grade credit ratings,
extended the expiration dates for approximately $2.0 billion of five-year credit facilities for PSEG, PSE&G and Power from 2018 to 2020, and
increased our indicated annual dividend for 20142015 to $1.48$1.56 per share.
We expect to be able to fund our transmission projects required under PJM's reliability program, our Energy Strong distribution program, Keys Energy Center and other planned projects, with internally generated cash and external debt financing.as well as our GSMP, without the issuance of new equity.

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Disciplined Investment
We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In 2015, in addition to our acquisition of the first nine monthsKeys Energy Center and clearance of 2014Sewaren 7 in the 2018/2019 capacity auction, each of which is under construction, we
placed into service the final phase of our 230500 kV Burlington-CamdenSusquehanna-Roseland and 230 kV North Central ReliabilityMickleton-Gloucester-Camden transmission projects,
made additional investments in transmission infrastructure projects,
secured approval to extend three Energy Efficiency Economic Stimulus subprograms to allow for additional capital expenditures and administrative expenses to provide energy efficiency assistance to hospitals, healthcare facilities and residential multi-family housing units,
continued to execute our existing BPU-approved utility programs,
completed the power ascension for the extended power uprate at our co-owned Peach Bottom 2 nuclear station,
completed installation of equipment to increase output and improve efficiency at our LindenBergen 2 combined cycle gas generatingunit similar to our 2014 installation at our Linden plant, and continue to plan for the installation of such equipment at our other combined cycle gas units,
acquired an equity interest with an expected investment of $100-$120 million in the 105.5 mile
PennEast pipeline to transport natural gas from eastern Pennsylvania to New Jersey, and
acquired rights toplaced into service a 13 MWdc solar energy facilities locatedfacility near El Paso, TexasWaldorf, Maryland and Burlington, Vermont, totaling 16.6 MW which are expected to be operational in the fourth quarter of 2014.acquired and placed into service a 25 MWdc solar energy facility near San Francisco, California.


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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 difficultslow-moving economy and a cost-constrained environment, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to
focus on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,
successfully manage our energy obligations and re-contract our open supply positions,
execute our capital investment program, including our Energy Strong program, proposed GSMP and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,
effectively manage construction of our Keys Energy Center, Sewaren 7 and other generation projects,
advocate for measures to ensure the implementation by PJM and the FERC of market design and transmission planning rules that continue to promote fair and efficient electricity markets,
engage multiple stakeholders, including regulators, government officials, customers and investors, and
successfully operate the LIPA T&D system.system and manage LIPA's fuel supply and generation dispatch obligations.
For the remainder of 20142015 and beyond, the key issues and challenges we expect our business to confront includeinclude:
regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,
uncertainty in the slowly improving national and regional economic recovery, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,
the continuing potential for continued reductions in demand and sustained lower natural gas and electricity prices, both at market hubs and atthe locationswhere we operate, and
delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory approvals.

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RESULTS OF OPERATIONS
PSEG
Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PowerPSE&G and PSE&G,Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note 17. Related-Party Transactions.
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2014 2013 2014 vs. 2013 2014 2013 2014 vs. 2013 
  Millions Millions % Millions Millions % 
 Operating Revenues$2,641
 $2,554
 $87
 3
 $8,113
 $7,650
 $463
 6
 
 Energy Costs863
 801
 62
 8
 3,008
 2,711
 297
 11
 
 Operation and Maintenance714
 713
 1
 —
 2,370
 2,069
 301
 15
 
 Depreciation and Amortization318
 313
 5
 2
 919
 886
 33
 4
 
 Taxes Other than Income Taxes—
 15
 (15) (100) —
 50
 (50) (100) 
 Income from Equity Method Investments3
 4
 (1) (25) 10
 9
 1
 11
 
 Other Income and (Deductions)66
 47
 19
 40
 154
 118
 36
 31
 
 Other-Than-Temporary Impairments10
 3
 7
 N/A
 14
 7
 7
 100
 
 Interest Expense100
 100
 —
 —
 291
 303
 (12) (4) 
 Income Tax Expense261
 270
 (9) (3) 633
 708
 (75) (11) 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2015 2014 2015 vs. 2014 2015 2014 2015 vs. 2014 
  Millions Millions % Millions Millions % 
 Operating Revenues$2,688
 $2,641
 $47
 2
 $8,137
 $8,113
 $24
 —
 
 Energy Costs815
 863
 (48) (6) 2,577
 3,008
 (431) (14) 
 Operation and Maintenance746
 714
 32
 4
 2,170
 2,370
 (200) (8) 
 Depreciation and Amortization313
 318
 (5) (2) 960
 919
 41
 4
 
 Income from Equity Method Investments3
 3
 —
 —
 10
 10
 —
 —
 
 Other Income and (Deductions)33
 66
 (33) (50) 135
 154
 (19) (12) 
 Other-Than-Temporary Impairments30
 10
 20
 N/A
 45
 14
 31
 N/A
 
 Interest Expense96
 100
 (4) (4) 291
 291
 —
 —
 
 Income Tax Expense285
 261
 24
 9
 869
 633
 236
 37
 
                  
The 2014 amounts in the preceding table for Operating Revenues and O&M Costs each include $107 million and $307 million for the three months and nine months ended September 30, 2014, respectively, for Long Island Electric Utility Servco, LLC, a wholly owned subsidiary of PSEG LI. These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Note 3. Variable Interest Entities for further explanation. The following discussions for PowerPSE&G and PSE&GPower provide a detailed explanation of their respective variances.

PowerPSE&G
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2014 2013
 2014 vs. 2013 2014 2013 2014 vs. 2013 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,138
 $1,174
 $(36) (3) $3,824
 $3,818
 $6
 —
 
 Energy Costs472
 430
 42
 10
 2,036
 1,785
 251
 14
 
 Operation and Maintenance242
 305
 (63) (21) 871
 868
 3
 —
 
 Depreciation and Amortization71
 69
 2
 3
 215
 202
 13
 6
 
 Income from Equity Method Investments4
 4
 —
 —
 11
 12
 (1) (8) 
 Other Income (Deductions)50
 34
 16
 47
 110
 78
 32
 41
 
 Other-Than-Temporary Impairments10
 3
 7
 N/A
 14
 7
 7
 100
 
 Interest Expense31
 26
 5
 19
 92
 85
 7
 8
 
 Income Tax Expense144
 153
 (9) (6) 277
 384
 (107) (28) 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2015 2014 2015 vs. 2014 2015 2014 2015 vs. 2014 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,766
 $1,655
 $111
 7
 $5,234
 $5,235
 $(1) —
 
 Energy Costs740
 668
 72
 11
 2,176
 2,278
 (102) (4) 
 Operation and Maintenance391
 366
 25
 7
 1,171
 1,190
 (19) (2) 
 Depreciation and Amortization231
 238
 (7) (3) 712
 682
 30
 4
 
 Other Income (Deductions)22
 14
 8
 57
 57
 41
 16
 39
 
 Interest Expense67
 71
 (4) (6) 203
 206
 (3) (1) 
 Income Tax Expense137
 126
 11
 9
 398
 355
 43
 12
 
                  


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Three Months Ended September 30, 20142015 as Compared to 20132014
Operating Revenues increased $111 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues increased $67 million due primarily to increases in transmission and electric distribution revenues.
Transmission revenues were $41 million higher due to increases resulting primarily from increased capital investments.
Electric distribution revenues increased $29 million due primarily to higher sales volumes of $24 million, higher Green Program Recovery Charges (GPRC) of $3 million and $2 million due to the roll in of Energy Strong into base rates effective September 1, 2015.

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Gas distribution revenues decreased $3 million due primarily to lower delivery volume.
Commodity Revenue increased $72 million as a result of higher Electric revenues partially offset by lower Gas revenues. Commodity revenue for both electric and gas is entirely offset with increased Energy Costs. PSE&G earns no margin on the provision of basic generation service (BGS) and Basic Gas Supply Service (BGSS) to retail customers.
Electric revenues increased $81 million due primarily to an $83 million or 16% increase in BGS revenues due to higher sales volumes and $2 million of higher revenues from collections of Non-Utility Generation Charges (NGC). These increases were partially offset by a $4 million reduction in revenues due to lower volumes on Non-Utility Generation (NUG) energy sold at lower prices.
Gas revenues decreased $9 million due primarily to $11 million in lower BGSS prices, partially offset by $2 million in higher prices.
Clause Revenues decreased $28 million due primarily to lower Securitization Transition Charges (STC) of $28 million, lower Solar Pilot Recovery Charges (SPRC) of $3 million, and lower Margin Adjustment Clause Revenue of $1 million, partially offset by higher Societal Benefit Charges (SBC) of $4 million. The changes in the STC, SPRC, MAC and SBC amounts are entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SPRC, MAC or SBC collections.
Other Operating Revenues experienced no material change.
Operating Expenses
Energy Costs increased $72 million due to higher Electric costs partially offset by lower Gas costs. This is entirely offset by decreased Commodity Revenue.
Electric costs increased $81 million or 14% due to $45 million of higher BGS and NUG prices and $68 million in higher BGS volumes. BGS volumes increased due to higher sales volumes due to warmer weather and reverse customer migration. These increases were partially offset by $19 million of decreased deferred cost recovery and $13 million of lower NUG volumes.
Gas costs decreased $9 million or 11% due to $11 million in lower prices, partially offset by $2 million in higher volumes.
Operation and Maintenance increased $25 million, of which the most significant components were
$10 million increase in pension and OPEB expenses,
$7 millionincrease in transmission operating expenses,
$8 million increase in other operating expenses, including $4 million in appliance service costs, $3 million in higher preventive maintenance and tree trimming and $1 million increase in general operating expenses,
partially offset by a $3 million decrease in costs related to a net decrease in SBC, MAC, GPRC, SPRC and STC. Due to the nature of the SBC, MAC, SPRC and STC clause mechanisms, these are entirely offset in revenue.
Depreciation and Amortization decreased $7 million due primarily to a decrease of $22 million in amortization of Regulatory Assets, partially offset by a $13 million increase in depreciation of additional plant in service related to increased investments in various transmission and distribution projects.
Other Income and (Deductions) increased $8 million due primarily to an increase in Allowance for Funds used During Construction (AFUDC).
Interest Expense decreased $4 million due primarily to partial redemption of securitization debt and clause interest, partially offset by net issuances of Medium Term Notes during 2015 and the latter half of 2014.
Income Tax Expense increased $11 million due primarily to higher pre-tax income.

Nine Months Ended September 30, 2015 as Compared to 2014
Operating Revenues decreased $1 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues increased $178 million due primarily to increases in transmission and electric distribution revenues.
Transmission revenues were $124 million higher due to increases resulting primarily from increased capital investments.

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Electric distribution revenues increased $45 million due primarily to higher sales volumes of $37 million, an
increase in Capital Stimulus Infrastructure Program (CIP) revenues of $5 million due to the inclusion of CIP II in base rates beginning in July 2014 and $3 million of higher revenues from GPRC.
Gas distribution revenues increased $9 million due primarily to $16 million from higher sales volumes and an increase in CIP revenues of $2 million, partially offset by lower Weather Normalization Charges (WNC) revenue of $9 million due to colder weather in 2015 compared to 2014.
Commodity Revenue decreased $102 million due to lower Gas revenues offset partially by higher Electric revenues. Commodity revenue for both electric and gas is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
Gas revenues decreased $209 million due primarily to lower BGSS prices of $290 million, of which $215 million was due to lower residential rates resulting from $133 million in residential bill credits and $82 million of lower commodity prices, partially offset by higher BGSS volumes of $81 million due to colder weather in 2015.
Electric revenues increased $107 million due primarily to $140 million of higher net BGS revenues. BGS revenues increased $171 million or 13%, due to higher sales volumes, which were partially offset by $31 million due to lower BGS rates. The increase from BGS was partially offset by $33 million in lower revenues from lower collection of NGC and lower sales prices and volumes of NUG energy.
Clause Revenues decreased $75 million due primarily to lower MAC revenue of $24 million, lower STC of $24 million, lower SBC of $23 million and lower SPRC of $4 million. The changes in the MAC, STC, SBC and SPRC amounts were entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on MAC, STC, SBC or SPRC collections.
Other Operating Revenues experienced no material change.
Operating Expenses
Energy Costs decreased $102 million due to lower Gas costs partially offset by higher Electric costs. This is entirely offset by decreased Commodity Revenue.
Gas costs decreased $209 million or 27% due to a $290 million or 37% decline in prices, partially offset by $81 million or 10% in higher sales volumes due to colder than normal weather.
Electric costs increased $107 million or 7% due to a $140 million or 11% increase in BGS volumes, due to reverse customer migration and higher sales volumes due to warmer weather and a $57 million increase due to higher BGS and NUG prices, partially offset by $69 million of decreased deferred cost recovery and $21 million in lower NUG sales volumes.
Operation and Maintenance decreased $19 million, of which the most significant components were
a $63 million decrease in costs related primarily to a net decrease in SBC, MAC, GPRC, CIP, SPRC and STC. Due to the nature of the SBC, MAC, SPRC and STC clause mechanisms, these are entirely offset in revenues,
storm insurance recovery proceeds of $10 million, and
decreased injuries and damages of $6 million,
•partially offset by a $28 million increase in pension and OPEB expenses,
•increased transmission operating expenses of $10 million,
•$8 million of higher appliance service costs,
increased bad debt expense of $6 million, and
an $8 million increase in other general operating expenses.
Depreciation and Amortizationincreased$30 million due primarily to a $42 millionincrease in depreciation of additional plant in service related to increased investments in various transmission and distribution projects, offset by a decrease of $13 million in amortization of Regulatory Assets which is fully offset in Clause Revenues.
Other Income and (Deductions) increased $16 million due primarily to an increase in AFUDC.
Interest Expense decreased $3 million due primarily to partial redemption of securitization debt partially offset by net issuances of Medium Term Notes in 2015 and the latter half of 2014.

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Income Tax Expenseincreased$43 million due primarily to higher pre-tax income.

Power
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2015 2014
 2015 vs. 2014 2015 2014 2015 vs. 2014 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,096
 $1,138
 $(42) (4) $3,846
 $3,824
 $22
 1
 
 Energy Costs367
 472
 (105) (22) 1,669
 2,036
 (367) (18) 
 Operation and Maintenance263
 242
 21
 9
 748
 871
 (123) (14) 
 Depreciation and Amortization75
 71
 4
 6
 226
 215
 11
 5
 
 Income from Equity Method Investments3
 4
 (1) (25) 11
 11
 —
 —
 
 Other Income (Deductions)11
 50
 (39) (78) 77
 110
 (33) (30) 
 Other-Than-Temporary Impairments30
 10
 20
 N/A
 45
 14
 31
 N/A
 
 Interest Expense30
 31
 (1) (3) 94
 92
 2
 2
 
 Income Tax Expense139
 144
 (5) (3) 445
 277
 168
 61
 
                  

Three Months Ended September 30, 2015 as Compared to 2014
Operating Revenues decreased $36$42 million due to changes in generation, gas supply and other operating revenues.

GenerationGas Supply Revenues decreased $55$44 million due primarily to
a decrease of $71$14 million in sales under the BGSS contract substantially comprised of lower average sales prices, and
a decrease of $30 million due to lower capacity revenues resulting from lower average auctionsales prices and volumes to third party customers.
Generation Revenues increased $3 million due primarily to
an increase of $39 million due to higher volumes of electricity sold under our BGS contract at higher average prices,
partially coupled with a decrease in operating reserve revenue in PJM in 2014, and
offset by a decrease of $27 million due primarily to lower volumes of electricity sold under our BGSthe wholesale load contracts as a result of serving fewer tranches in 2014,
partially offset by higher net revenues of $23 million due primarily to higher generation volumes at higher average realized prices in the New York (NY) region and higher MTM gains in 2014 which were partially offset by lower average realized prices in the PJM and New England (NE) regions, andregions.
an increase of $20 million due to higher volumes on wholesale load contracts in the PJM region.
Gas Supply Revenues increased $15 million due primarily to higher sales volumes at lower average natural gas prices to third party customers.
Other Operating Revenuesincreased $4decreased$1 milliondue to transitionlower fees related to thereceived from fuel management and power supply management contracts with LIPA.

Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $42decreased $105 million due to
Generation costs increased $32decreased $59 million due primarily to lower fuel costs, reflecting lower average realized natural gas prices and the utilization of lower coal volumes at lower average realized prices, coupled with higher MTM gains in 2015. These decreased costs were partially offset by higher congestion costs and renewable energy credits, partially offset byin the favorable MTM impact from lower average unrealized prices on forward positions.PJM region.
Gas costs increased $10decreased $46 million reflecting higher sales volumesrelated to third party customers, partially offset by lower average gas inventory costs on both obligations under the BGSS contract.contract and sales to third parties, coupled with lower volumes sold to third parties.
Operation and Maintenance decreased $63increased $21 million due primarily to
lower planned outage costsa net increase of $39$24 million at our fossil stations,nuclear facilities, primarily due to the start of the 2015 fall outage one month sooner than in 2014 at our BEC combined cycle gas generating plant due to maintenance on the low pressure turbine in 2013 and lower outage costs at our nuclear50%-owned Peach Bottom facility,nuclear unit 3,

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partially offset by a decrease of $13$5 million related to our fossil plants, largely due to lower stormhigher costs related to Superstorm Sandy,incurred in 2014 for planned outages and
lower pension and OPEB expense of $14 million. maintenance.
Depreciation and Amortization experienced no material change.increased $4 million due primarily to a higher depreciable fossil and nuclear asset base.
Income from Equity Method Investments experienced no material change.
Other Income and (Deductions) increased $16decreased $39 million due primarily due to higherlower net realized gains related tofrom the NDT Fund restructuring in May 2014.Fund.
Other-Than-Temporary Impairments increased $7$20 million due to an increase in impairments onof the NDT Fund.
Interest Expense increased $5 million due primarily to the issuance of $500 million of Senior Notes in November 2013.experienced no material change.
Income Tax Expense decreased $9$5 million in 20142015 due primarily to lower pre-tax income.

Nine Months Ended September 30, 20142015 as Compared to 20132014
Operating Revenues increased $622 million due to changes in generation, gas supply and other operating revenues.
Generation Revenuesdecreased$128 increased $203 million due primarily to
lowerhigher net revenues of $72$232 million due primarily to higherMTM gains in 2015 compared to MTM losses in 2014, resulting from an increase in prices on forward positions, partially offset by higherlower energy volumes sold in the NY and NE regions, and
a decrease of $70 million due to lower volumes of electricity sold under our BGS contracts as a result of serving fewer tranches in 2014region and lower average pricing,

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partially offset by a netan increase of $12 million due primarily to higher capacity revenues resulting from higher average auction prices and higher ancillary revenue in the PJM region, and
a net increase of $2$78 million due primarily to higher volumes onof electricity sold under wholesale load contracts in the PJM and NE regions, and
an increase of $48 million due primarily to higher volumes of electricity sold under the BGS contract at higher average prices,
partially offset by a decrease of $155 million due primarily to lower capacity revenues resulting from lower average auction prices coupled with lower ancillary and operating reserve revenues in the PJM region.

Gas Supply Revenues increased$123 milliondecreased $182 million due primarily to
a net increasedecrease of $74$86 million in sales under the BGSS contract, substantially comprised of lower average sales prices, partially offset by higher sales volumevolumes due to colder average temperatures duringin the 20142015 winter heating season, and
a net increasedecrease of $49$96 million due primarily to higher sales volumes at lower average sales prices and volumes to third party customers.

Other Operating Revenues increased $11$1 million due to transitionhigher fees related to thereceived from fuel management and power supply management contracts with LIPA.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increaseddecreased $251367 million due to
Generation costs increased$200 milliondecreased $149 million due primarily to higherlower fuel costs, reflecting higherlower average realized natural gas and oil prices and the unfavorableutilization of lower volumes of coal, coupled with MTM impact from lower average unrealized natural gas prices on forward positions andgains in 2015 as compared to MTM losses in 2014. These decreased costs were partially offset by the utilization of higher volumes of coal and oil.natural gas, coupled with higher congestion costs in the PJM region.
Gas costs increased$51 milliondecreased, principally $218 million related to lower average gas inventory costs on both obligations under the BGSS contract and sales to third parties, coupled with lower volumes sold to third parties. This was partially offset by higher volumes sold under the BGSS contract and to third parties due to colder average temperatures during the 20142015 winter heating season, partially offset by lower average gas inventory costs.season.
Operation and Maintenance increaseddecreased $3123 million due primarily to
an increasea decrease of $62$145 million due to insurance recoveries related to Superstorm Sandy, and
a net decrease of $48 million related primarilyto our fossil plants, largely due to higher costs incurred in 2014 for planned outage and maintenance costs, at our fossil plants, including maintenance and installation of upgraded technology at our Linden combined cycle gas generating plant, partially offset by lowerplanned outage costs in 2015 at our BEC fossil station as well as lowerBethlehem Energy Center generating plant and installation of upgraded technology at our combined cycle Bergen plant,

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partially offset by an increase of $48 million at our nuclear facilities, primarily due to higher planned outage costs at our nuclear100%-owned Hope Creek and 50%-owned Peach Bottom facility, partially offset by3 nuclear plants in 2015 as compared to our 57%-owned Salem nuclear unit 2 in 2014, and
lowera $22 million increase due to higher pension and OPEB costs of $40 million, and
a decrease of $19 million due to lower storm costs related to Superstorm Sandy.costs.
Depreciation and Amortization increased $1311 million due primarily to a higher depreciable fossil and nuclear asset base.
Income from Equity Method Investments experienced no material change.
Other Income and (Deductions) increased $32decreased $33 million due primarily to lower net losses that were incurred in March 2013 as a result of rebalancingrealized gains from the NDT portfolio.Fund partially offset by a $28 million insurance recovery related to Superstorm Sandy.
Other-Than-Temporary Impairments increased $7$31 million due to an increase in impairments onof the NDT Fund.
Interest Expense increased $7 million due primarily to the issuance of $500 million of Senior Notes in November 2013, partially offset by the maturity of $300 million of Senior Notes in April 2013.
Income Tax Expensedecreased$107 million in 2014 due primarily to lower pre-tax income.


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PSE&G
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2014 2013 2014 vs. 2013 2014 2013 2014 vs. 2013 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,655
 $1,666
 $(11) (1) $5,235
 $5,084
 $151
 3
 
 Energy Costs668
 661
 7
 1
 2,278
 2,208
 70
 3
 
 Operation and Maintenance366
 408
 (42) (10) 1,190
 1,204
 (14) (1) 
 Depreciation and Amortization238
 236
 2
 1
 682
 658
 24
 4
 
 Taxes Other Than Income Taxes—
 15
 (15) (100) —
 50
 (50) (100) 
 Other Income (Deductions)14
 12
 2
 17
 41
 38
 3
 8
 
 Interest Expense71
 75
 (4) (5) 206
 223
 (17) (8) 
 Income Tax Expense126
 115
 11
 10
 355
 311
 44
 14
 
                  
Three Months Ended September 30, 2014 as Compared to 2013
Operating Revenues decreased $11 million due to changes in delivery, commodity, clause, and other operating revenues.
Delivery Revenues increased $15 million due primarily to an increase in transmission revenues. The Transitional Energy Facilities Assessment (TEFA) reductions in electric and gas distribution revenues are entirely offset by the decrease in Taxes Other Than Income Taxes.
Transmission revenues were $38 million higher due to net rate increases resulting primarily from increased capital investments.
Electric distribution revenues decreased $22 million due primarily to lower TEFA revenue of $13 million due to elimination of the TEFA rate effective January 1, 2014 and lower sales volumes of $5 million, $3 million of lower Capital Infrastructure Program (CIP) related revenue due to the 2014 reduction in the Capital Adjustment Charge (CAC) tariff and lower revenue from Green Program Recovery Charges (GPRC) of $1 million.
Gas distribution revenues decreased $1 million due primarily to lower TEFA revenue of $2 million due to elimination of the TEFA rate in 2014 and lower CIP related revenue of $2 million due to the 2014 reduction in the CAC tariff, partially offset by an increase of $3 million from higher sales volumes.
Commodity Revenue increased $7 million due to higher Gas revenues, partially offset by lower Electric revenues. This is entirely offset with increased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
Electric revenues decreased $3 million due primarily to $17 million in lower revenues from collection of Non-Utility Generation Charges (NGC) and lower sales volumes of Non-Utility generation (NUG) energy, partially offset by $14 million in higher BGS revenues. BGS sales volumes decreased 1% due primarily to weather.
Gas revenues increased $10 million due primarily to higher BGSS volumes of $5 million and higher BGSS prices of $5 million.
Clause Revenues decreased $32 million due primarily to lower Societal Benefit Charges (SBC) of $19 million, lower Securitization Transition Charge (STC) revenues of $9 million and lower Margin Adjustment Clause (MAC) of $4 million. The change in the SBC, STC and MAC amounts were entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, STC or MAC collections.
Other Operating Revenues remained level with the prior period.

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Operating Expenses
Energy Costs increased $7 million. This is entirely offset by Commodity Revenue.
Electric costs decreased $3 million or 1% due primarily to $9 million of lower BGS and NUG prices and $15 million in lower BGS and NUG volumes, partially offset by $21 million of increased deferred cost recovery. BGS and NUG volumes decreased 3% due primarily to customer migration to third party suppliers (TPS) and weather.
Gas costs increased $10 million or 14% due to $5 million or 7% in higher sales volumes and $5 million or 7% in higher prices.
Operation and Maintenance decreased $42 million, of which the most significant components were
a $28 million decrease in costs related to clauses due primarily to lower SBC, MAC, CIP and GPRC. Due to the nature of the SBC, MAC, CIP and GPRC clause mechanisms, these are entirely offset in revenues,
an $18 million decrease in pension and OPEB expenses and partially offset by
an increase in other operating expenses of $4 million.
Depreciation and Amortization increased $2 million due primarily to
a $12 million increase in depreciation of additional plant in service related to increased investments in various transmission and distribution projects,
partially offset by a $10 million decrease in amortization of Regulatory Assets.
Taxes Other Than Income Taxes decreased $15 million due to elimination of the TEFA rate in 2014. This is entirely offset by the reduction in electric and gas distribution revenues.
Other Income and (Deductions)experienced no material change.
Interest Expense decreased $4 million due primarily to a partial redemption of securitization debt.
Income Tax Expense increased $11 million due primarily to higher pre-tax income.

Nine Months EndedSeptember 30, 2014 as Compared to 2013
Operating Revenuesincreased$151 million due to changes in delivery, commodity, clause, and other operating revenues.
Delivery Revenuesincreased$93 million due primarily to an increase in transmission revenues. The TEFA reductions in electric and gas distribution revenues are entirely offset by the decrease in Taxes Other Than Income Taxes.
Transmission revenues were $115 millionhigher due to net rate increases resulting primarily from increased capital investments.
Gas distribution revenues were flat due primarily to $53 million from higher sales volumes and higher revenue from GPRC of $6 million, offset by lower Weather Normalization Clause (WNC) revenue of $36 million due to colder than normal weather, lower TEFA revenue of $15 million due to elimination of the TEFA rate in 2014 and lower CIP related revenues of $8 million partially due to the 2014 reduction in the CAC tariff.
Electric distribution revenues decreased$22 million due primarily to lower TEFA revenue of $35 million due to elimination of the TEFA rate in 2014, lower sales volumes of $7 million and lower CIP related revenues of $3 million due to the 2014 reduction in the CAC tariff, partially offset by higher revenue from the GPRC of $23 million.
Commodity Revenueincreased$70 million due to higher Electric and Gas revenues. This is entirely offset with increased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
Electric revenues increased$15 million due primarily to $48 million in higher volumes and prices of BGS sales, partially offset by $33 million in lower revenues from collection of NGC and lower sales volumes of NUG energy. BGS sales volumes increased2% due primarily to weather.
Gas revenues increased$55 million due primarily to higher BGSS volumes of $106 million, partially offset by lower BGSS prices of $51 million. The average price of natural gas was 7%lower in 2014.
Clause Revenuesdecreased$20 million due primarily to lower STC of $12 million, lower SBC of $7 million and lower MAC of $7 million partially offset by higher Solar Pilot Recovery Charge (SPRC). The change in the STC, SBC MAC and SPRC

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amounts were entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SBC, MAC or SPRC collections.
Other Operating Revenuesincreased$8 million due primarily to increased revenues from our appliance repair business and miscellaneous electric operating revenues.
Operating Expenses
Energy Costsincreased$70 million. This is entirely offset by Commodity Revenue.
Electric costs increased$15 million or 1% due to $72 million of increased deferred cost recovery and $2 million of higher BGS and NUG prices, partially offset by $59 million in lower BGS and NUG volumes. BGS and NUG volumes decreased 4% due primarily to customer migration to TPS.
Gas costs increased$55 million or 8% due to $106 million or 14% in higher sales volumes, partially offset by $51 million or 6% in lower prices.
Operation and Maintenance decreased $14 million, of which the most significant components were
a $55 million decrease in pension and OPEB expenses, partially offset by,
an $11 million increase in costs related primarily to a net increase in SBC, MAC, CIP and GPRC. Due to the nature of the SBC, MAC, CIP and GPRC clause mechanisms, these are entirely offset in revenues, and
a $30 million increase in operational expenses due primarily to storm-related costs of $7 million, damage claims of $8 million, transmission related costs of $3 million, general wage increases of $2 million, tree trimming of $2 million and general operating expenses of $8 million.
Depreciation and Amortizationincreased$24 million due primarily to a $33 millionincrease in depreciation of additional plant in service related to increased investments in various transmission and distribution projects, partially offset by a decrease of $11 million in amortization of Regulatory Assets.
Taxes Other Than Income Taxesdecreased$50 million due to elimination of the TEFA rate in 2014. This is entirely offset by the reduction in electric and gas distribution revenues.
Other Income and (Deductions) experienced no material change.
Interest Expense decreased $17 million due primarily to a partial redemption of securitization debt and maturity of Medium Term Notes (MTNs) in the second half of 2013, partially offset by the issuance of MTNs in the latter part of 2013 and 2014.
Income Tax Expense increased $44168 million in 2015 due primarily to higher pre-tax income.

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 two direct major operating subsidiaries.
Operating Cash Flows
Our operating cash flows combined with cash on hand and financing activities are expected to be sufficient to fund planned capital expenditures and shareholder dividend payments.
For the nine months ended September 30, 20142015, our operating cash flow increased $101692 million as compared to the same period in 2013.2014. The net change was due primarily to the net changes from PowerPSE&G and PSE&GPower as discussed below and higher federal tax payments made by the parent company in 2014.below.
PowerPSE&G
Power’sPSE&G’s operating cash flow decreasedincreased $204175 million from $1,3141,343 million to $1,1101,518 million for the nine months ended September 30, 20142015, as compared to the same period in 2013,2014, due primarily resulting from an increase in working capital needs, largely due to higher margin deposit requirements,earnings, a $203 million reduction in tax payments, $37 million reduction in vendor payments and a $25 million decrease in prepayments. These amounts were partially offset by a $40decrease of $232 million decreasedue to a change in employee benefit plan funding.regulatory deferrals primarily driven by the return of prior year overcollections to customers for BGSS gas costs, Gas Weather Normalization charges and Non-Utility Generation charges.
PSE&GPower
PSE&G’sPower’s operating cash flow increased $294448 million from $1,0491,110 million to $1,3431,558 million for the nine months ended September 30, 20142015, as compared to the same period in 2013,2014, primarily due primarily to higher earnings and a reduction in margin deposit requirements, partially offset by an increase of $197 million in net regulatory liabilities related to BGS and NUG costs and overcollections in Gas Weather Normalization Charges partly offset by GPRC rate recoveries and an $80 million decrease in employee benefit plan funding.tax payments.

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Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
The commitments under our $4.3$4.2 billion credit facilities are provided by a diverse bank group. As of September 30, 20142015, our total available credit capacity was $4.1$3.9 billion.
As of September 30, 20142015, no single institution represented more than 8%7% of the total commitments in our credit facilities.
As of September 30, 20142015, 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 in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’subsidiaries' liquidity needs. In April 2014, PSEG and Power amended their 2012 credit agreements ending in 2017, extending the expiration date from March 2017 to April 2019. PSEG's $500 million and Power's $1.6 billion facility amendments, resulting in total commitments of $2.1 billion, will mature in 2019.
Our total credit facilities and available liquidity as of September 30, 20142015 were as follows:

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   As of September 30, 2014     
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
   5-year Credit Facility $500
 $8
 $492
 Apr 2019 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
 $8
 $992
     
 Power           
   5-year Credit Facility $1,600
 $76
 $1,524
 Apr 2019 Funding/Letters of Credit 
   5-year Credit Facility (B) 1,000
 —
 1,000
 Mar 2018 Funding/Letters of Credit 
   Bilateral Credit Facility 100
 100
 —
  Sept 2015 Letters of Credit 
 Total Power $2,700
 $176
 $2,524
     
 PSE&G           
  5-year Credit Facility (C) $600
 $14
 $586
 Mar 2018 CP Support/Funding/Letters of Credit 
 Total PSE&G $600
 $14
 $586
     
 Total $4,300
 $198
 $4,102
     
             
             
   As of September 30, 2015     
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
   5-year Credit Facility $500
 $10
 $490
 Apr 2019 Commercial Paper (CP) Support/Funding/Letters of Credit 
   5-year Credit Facility (A) 500
 —
 500
 Apr 2020 CP Support/Funding/Letters of Credit 
 Total PSEG $1,000
 $10
 $990
     
 PSE&G           
  5-year Credit Facility (B) $600
 $34
 $566
 Apr 2020 CP Support/Funding/Letters of Credit 
 Total PSE&G $600
 $34
 $566
     
 Power           
   5-year Credit Facility $1,600
 $201
 $1,399
 Apr 2019 Funding/Letters of Credit 
   5-year Credit Facility (C) 1,000
 14
 986
 Apr 2020 Funding/Letters of Credit 
 Total Power $2,600
 $215
 $2,385
     
 Total $4,200
 $259
 $3,941
     
             
(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.
(A)PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018.
(B)PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018.
(C)Power facility will be reduced by $48 million in April 2016 and $24 million in March 2018.
Long-Term Debt Financing
PSE&G has $171 million of 6.75% Mortgage Bonds maturing in January 2016. Power has $300 million of 2.70%, Series G, Medium Term5.50% Senior Notes maturing in May 2015.December 2015 and $303 million of 5.32% Senior Notes and $250 million of 2.75% Senior Notes maturing in September 2016.
For a discussion of our long-term debt transactions during 2014,2015, see Item 1. Note 9. Changes in Capitalization.
Common Stock Dividends
On July 15, 2014,21, 2015, our Board of Directors approved a $0.37$0.39 per share common stock dividend for the third quarter of 2014.2015. This reflects an indicated annual dividend rate of $1.48$1.56 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. Note 15. Earnings Per Share (EPS) and Dividends.

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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. Credit Ratings shown are for securities that we typically issue. Outlooks assigned to ratings are as follows: stable, negative (Neg)shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or positive (Pos).Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies' ratings. The ratings should not be construed as an indication to buy, hold or sell any security. In January 2014, Moody's upgraded PSE&G's Mortgage Bond Rating from A1 to Aa3 and its commercial paper rating from P2 to P1. PSE&G's outlook is stable.
In May 2014,2015, Moody’s published updated research reports on PSEG, PSE&G and Power and the existing ratings and outlooks were unchanged.
In May 2014,2015, S&P published updated research reports and revised the outlook to stable from positive from stable for Power.PSEG’s Corporate Credit Rating and Power’s Senior Notes. S&P also affirmed the senior unsecured rating of BBB+ at Power and the mortgage bond rating of A at PSE&G. In September 2015, Moody's published an updated research report on PSEG and revised the outlook to positive from stable. In September and October 2014,2015, Fitch affirmed thepublished full rating reports on PSEG and Power leaving ratings and outlooks unchanged. As of October 2015, PSEG has ended a contractual agreement with Fitch to provide credit rating services for PSEG, PSE&G and Power.


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   Moody’s (A) S&P (B)Fitch (C) 
 PSEG    
OutlookPositiveStable
Commercial PaperP2A2
PSE&G     
 Outlook Stable Stable 
 StableMortgage BondsAa3A 
 Commercial Paper P2P1 A2F2 
 Power     
 Outlook Stable PositiveStable 
 Senior Notes Baa1 BBB+BBB+ 
PSE&G
OutlookStableStableStable
Mortgage BondsAa3AA+
Commercial PaperP1A2F2
       
(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+A1 (highest) to D (lowest) for short-term securities.
(C)Fitch ratings range from AAA (highest) The Corporate Credit Rating outlook does not apply to D (lowest) for long-term securities and F1+ (highest) to D (lowest) for short-term securities.PSEG's or PSE&G's Commercial Paper Rating or PSE&G's Mortgage Bond rating.

CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing.
In September 2015, we reached a settlement in principle with the BPU Staff and the New Jersey Division of Rate Counsel regarding our GSMP, through which, if approved, we will invest $905 million over the next three years to modernize PSE&G’s gas systems.
In June 2015, we acquired a development project to construct a 755 MW gas-fired combined cycle generating station in Maryland (Keys Energy Center). We plan to start constructing this year with expected completion in 2018 at an estimated investment of $825 million - $875 million.
In August 2015, we announced our plan to construct Sewaren 7, a new 540 MW duel-fueled combined cycle generating plant in Woodbridge, New Jersey scheduled to be in-service for the summer of 2018 at an estimated investment of $625 million - $675 million.
The aforementioned estimated project expenditures related to the GSMP at PSE&G and the Maryland and Woodbridge, New Jersey projects at Power are not included in the $8.7 billion three-year capital forecast table in our 2014 Form 10-K. There were no material changes to our projected capital expenditures at Power and Services as compared to amounts disclosed in our 20132014 Form 10-K.
PSE&G
During the nine months ended September 30, 2015, PSE&G has increased its total projectedmade capital expenditures through 2016 by $295of $1,946 million, including $145 millionprimarily for additional transmission reliability enhancements in 2015 and $50 million and $100 million in 2015 and 2016, respectively, related to additional distribution system reliability. This does not include expenditures for reliability enhancements and facility replacement.
On May 21, 2014, the BPU issued an Order approving our Energy Strong program, agreeing that PSE&G would spend $1.22 billion to protect and strengthen PSE&G's electric and gas systems against severe weather conditions over primarily a three-year period with some projects extending over five years. This amount is notcost of removal, net of salvage, of $82 million, which are included in the projected capital expenditures disclosed in our 2013 Form 10-K or in the increases reported above. See Item 5. Other Information—Energy Strong Program for additional information.operating cash flows.
Power
During the nine months ended September 30, 2014,2015, Power made capital expenditures of $298$597 million, excluding $116200 million for nuclear fuel, primarily related to various projects at its fossil and nuclear generation stations.stations, including the new Maryland generating station noted above.
PSE&G
During the nine months ended September 30, 2014, PSE&G made capital expenditures of $1.49 billion, primarily for transmission and distribution system reliability. This does not include expenditures for certain energy efficiency and renewable programs of $13 million or cost of removal, net of salvage, of $68 million, which are included in operating cash flows.

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ACCOUNTING MATTERS
For information related to recent accounting matters, see Item 1. 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.
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.
From July through September 2014,2015, MTM VaR remained relatively stable.stable between low of $8 million to high of $14 million at 95% confidence level. The range of VaR was narrower for the three months ended September 30, 20142015 as compared with the year ended December 31, 2013.2014.
       
   MTM VaR 
   Three Months Ended September 30, 2014 Year Ended December 31, 2013 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $20
 $12
 
 Average for the Period $20
 $15
 
 High $26
 $29
 
 Low $15
 $8
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $32
 $18
 
 Average for the Period $31
 $23
 
 High $40
 $46
 
 Low $24
 $13
 
       
       
   MTM VaR 
   Three Months Ended September 30, 2015 Year Ended December 31, 2014 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $10
 $36
 
 Average for the Period $10
 $30
 
 High $14
 $195
 
 Low $8
 $14
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $16
 $56
 
 Average for the Period $15
 $46
 
 High $23
 $306
 
 Low $12
 $22
 
       
See Item 1. 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 CFO and CEO of each of Public Service Enterprise Group Incorporated, PSEG Power LLC, and Public Service Electric and Gas Company.Company and PSEG Power LLC. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of Public Service Enterprise Group Incorporated, PSEG Power LLC, and Public Service Electric and Gas Company and PSEG Power LLC have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.
Internal Controls
We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the third quarter of 20142015 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 additional information regarding material legal proceedings, including updates to information reported in Item 3.3 of Part I of the 20132014 Annual Report on Form 10-K, see see Part I, Item 1. Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.

ITEM 1A.RISK FACTORS
There are no additional Risk Factors to be added to those disclosed in Part I Item 1A of our 20132014 Annual Report on Form 10-K.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the third quarter of 20142015.
      
 Three Months Ended September 30, 2014
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 July 1 - July 31—
 $—
 
 August 1- August 3146,894
 $34.98
 
 September 1 - September 30—
 $—
 
      
      
 Three Months Ended September 30, 2015
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 July 1 - July 31—
 $—
 
 August 1- August 31189,018
 $42.23
 
 September 1- September 3020,000
 $38.97
 
      


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ITEM 5.OTHER INFORMATION
ITEM 5. OTHER INFORMATION
Certain information reported in the 20132014 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014 and June 30, 2014 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 20132014 Annual Report on Form 10-K and the Quarterly ReportsReport on Form 10-Q for the quarters ended March 31, 20142015 and June 30, 2014.2015. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.
Business Operations and Strategy
Other
December 31, 2013 Form 10-K page 13 and June 30, 2014 Form 10-Q page 80. On July 1, 2014, PSEG LI submitted a proposal to LIPA to invest up to $200 million of capital in equipment at customer facilities that would improve energy efficiency and reduce peak load. PSEG LI proposed to make the investments from 2015 through 2018 and recover its investment and earn a return over approximately ten years. On October 6, 2014, PSEG LI filed an interim update which increased the size of the proposed program to approximately $345 million, reaffirmed its original investment proposal to fund up to $200 million of the program and also offered an alternate economic structure which included a performance incentive mechanism rather than utilizing PSEG LI’s capital. The New York State Department of Public Service will review the proposal and make a recommendation to LIPA which is expected to take action on the proposal at its December 2014 meeting.    
Federal Regulation
FERC
Regulation of Wholesale Sales—Generation/Market Issues
Capacity Market Power
Under FERC regulations, public utilities must receive FERC authorization to sell power in interstate commerce. They can sell power at cost-based rates or apply to the FERC for authority to make market-based rate (MBR) sales. For a requesting company to receive MBR authority, the FERC must first make a determination that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. The FERC requires that holders of MBR tariffs file an update every three years demonstrating that they continue to lack market power and/or that

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market power has been sufficiently mitigated and report in the interim to the FERC any material change in facts from those the FERC relied on in granting MBR authority. Retention of MBR authority is important to the maintenance of our generation business’ revenues.
PSE&G, PSEG Energy Resources & Trade LLC, PSEG Power Connecticut, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG New Haven LLC all have been granted MBR authority from the FERC. Each of these companies, except PSEG New Haven LLC (which received MBR authority in May 2012), filed a market power update with the FERC at the end of 2013. In an order issued on October 14, 2014, the FERC accepted our filing as having satisfied the requirements for retention of MBR authority.
Energy Clearing PricesIssues—PJM
December 31, 20132014 Form 10-K page 16, March 31, 20142015 Form 10-Q page 69 and June 30, 20142015 Form 10-Q page 80. As a result of the polar vortex and related cold weather events in January 2014, there were both gas and electric price spikes in the Northeast markets, including in PJM. The FERC has examined the facts surrounding these price spikes, as well as “lessons learned” from the various Regional Transmission Operators/Independent System Operators (RTO/ISO) and potential changes in market rules intended to encourage dual fuel capability of generating units, the purchase of firm fuel to fire these units and the construction of additional natural gas pipeline capacity. As discussed below, PJM has proposed changes to its capacity market construct to develop a new capacity product that would be compensated for availability during peak winter periods. The FERC is also examining price formation issues, focusing on levels of compensation to generators in the energy and ancillary services markets. We cannot predict what action the FERC might take, but such an examination could lead to future rule changes.
Capacity Market Issues
December 31, 2013 Form 10-K page 16, March 31, 2014 Form 10-Q page 69 and June 30, 2014 Form 10-Q page 81. PJM, the New York ISO (NYISO), and the ISO-New England (ISO-NE) each have capacity markets that have been approved by the FERC. The FERC regulates these markets and continues to examine whether the market design for these three capacity markets is working optimally. Specific issues being considered by the FERC are whether capacity market rules properly address and foster the development of state public policies, demand response (DR) and emerging technologies, and whether generators are being sufficiently compensated in the capacity market. We cannot predict what action, if any, the FERC might take with regard to capacity market design.
Capacity Market Issues—PJM
December 31, 2013 Form 10-K page 16, March 31, 2014 Form 10-Q page 70 and June 30, 2014 Form 10-Q page 8178. The Reliability Pricing Model (RPM)RPM is the locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under the RPM, generators located in constrained areas within
On December 12, 2014, PJM are paid more for their capacity as an incentivefiled a proposal at FERC to ensure adequate supply where generation capacity is most needed. The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active. There is currently significant activity concerning three topics: (i) the future role of DR in the RPM market in light of a decision by the D.C. Circuit Court of Appeals (D.C. Court) holding that DR is not a FERC-jurisdictional product, (ii) PJM’s development of a new capacity product calledimplement a Capacity Performance (CP) product, and (iii) the setting of the Cost of New Entry (CONE) value for the RPM demand curve for the next three years.
On May 23, 2014, in a case involving the proper level of compensation for DR resources in the energy markets, the D.C. Court held that DR is not a FERC-jurisdictional product, thereby calling into question DR resources’ ability to participate in either the energy or capacity markets in the future. The FERC and other parties to the case subsequently submitted petitions for rehearing before the entire court of judges, which petitions were denied on September 17, 2014. The FERC has obtained a stay of the court’s decision until at least December 16, 2014, the due date for the FERC to file a petition for certiorari to the U.S. Supreme Court. Should the FERC file such a petition, the stay will remain in effect until such time as the Supreme Court disposes of the case. Upon lifting of the stay, the issue of the proper treatment of DR resources will be addressed by the FERC and the RTOs/ISOs. First Energy Corp. has filed a complaint at the FERC which argues that DR resources should no longer participate in the PJM capacity market and seeks to invalidate the results of the last RPM Base Residual Auction. PJM has also signaled that it may in the future only allow DR to participate in the capacity market through adjustment of the demand curve rather than as a capacity resource that receives a revenue stream, although PJM has not yet taken any formal action to effectuate this. Elimination of DR as a capacity resource would have a significant effect on future auction clearing prices should this actually occur.
PJM is currently developing a CP construct which it has stated it intends to file with the FERC by the beginning of December 2014.mechanism. Under this construct, the details of which remain under development,mechanism, PJM is creatingcreated a more robust capacity product definition with enhanced incentives for winter peak performance during emergency conditions and significant penalties for non-performance. TheOn June 9, 2015, FERC conditionally accepted the CP product would be expected to be capable of providing energy when needed during both summer and winter peak-load conditions and extreme weather events and satisfying certain operational requirements. CP resources would be subject to a maximum penalty of 1.5

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times annual capacity revenues, with articulated penalty exceptions. This new product wouldmechanism which will be phased in over the next few years, with full implementationthe participation of both the CP product and a base product that has less rigorous performance obligations. The CP mechanism was implemented for the delivery year 2018-2019.2015 base residual auction (covering the 2018-2019 Delivery Year) which concluded on August 21, 2015. The CP product will be implemented fully for the 2020-2021 Delivery Year. Based upon the August 2015 base residual auction results, the CP mechanism appears to have provided the opportunity for enhanced capacity market revenue streams for Power but future impacts cannot be assured. Further, there may be requirements for additional investment and there are additional performance risks.
On June 30, 2015, a consumer coalition filed a complaint requesting that the load forecast that PJM was currently analyzing and updating to determine the amount of capacity it would procure in the 2016 base residual auction be implemented immediately for the upcoming 2015 transition auctions and base residual auction. FERC did not address the complaint prior to the auctions, effectively denying it.
Price Formation Initiatives
Power has been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for setting prices for energy in the day-ahead and real-time markets administered by PJM and other system operators. A recent development which we consider positive involves a September 25, 2014, PJM filed at17, 2015 FERC notice of proposed rulemaking on two issues: aligning settlements with dispatch intervals (more granular “5-minute pricing” in real-time markets) and improving real-time scarcity pricing. Comments made by FERC commissioners stressed these two items are intended to be the first of a series of steps FERC will take on energy price formation in the future.
Reactive Power Rates
In June 2015, Power submitted a tariff filing with FERC to increase Power’s rates for reactive supply and voltage control service from approximately $27 million per year to about $39 million per year. The rates were last adjusted in 2008 and since that time various generating units have been de-activated, activated or improved with the net impact supportive of an upward rate adjustment. FERC accepted Power’s rate filing increase to become effective in January 2016, subject to refund, hearing and settlement procedures. FERC also referred the filing to the FERC Office of Enforcement for its evaluation. Power has participated in two settlement conferences to re-set the Variable Resource Requirement (VRR) curve for the RPM, as is done every three years. Establishment of the VRR curve is a critical component in determining how generators are paid in the capacity auction. We and other generators have challenged certain elements of this filing, including how PJM has calculated the cost of capital and labor costs that form the basis for the CONE component of the demand curve, which we believe have been set too low and do not accurately reflect the costs of building a new generating unit in PJM. This matter is currently pending at the FERC.
Capacity Market Issues—ISO-New England (ISO-NE)
December 31, 2013 Form 10-K page 16 and June 30, 2014 Form 10-Q page 81. ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and DR. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of resources on the system and contains incentive mechanisms to encourage availability during stressed system conditions. In June 2014, the FERC issued an order requiring the implementation of a downward sloping demand curve, similar to the design in place in PJM, for use in ISO-NE's ninth capacity market auction to be held in February 2015 and effective in the 2018-2019 planning year. This action is expected to result in greater stability of capacity prices in New England and is also expected to send more appropriate price signals that will incent the development of new generation. One aspect of this order that we did not support was the exemption from the Minimum Offer Price Rule afforded annually up to 600 MW of renewable resources. We challenged this portion of the order on rehearing on the grounds that we believe that it is unduly discriminatory and will suppress capacity prices. The rehearing request remains pending.
In addition, in the FERC order referenced above, the FERC directed the ISO-NE to develop demand curves for each capacity zone in the market. The ISO-NE is currently conducting a stakeholder proceeding and expects to make a filingdate with the FERC by January 2015. The shape of the demand curve in the zones will have a significant impact upon the revenues our generation receives in the capacity market in New England.trial staff.
Capacity Market Issues—Long-Term Capacity Agreement Pilot Program Act (LCAPP)
December 31, 20132014 Form 10-K page 17.18. In 2011, the State of New Jersey enacted the LCAPP to subsidize approximately 2,000 MW of new natural gas-fired generation. The LCAPP provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey EDCs. The SOCA required 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 three SOCAs as directed by the State, but did so under protest reserving their rights.
In 2013, the U.S. District Court in New Jersey found that the LCAPP was unconstitutional and declared the LCAPP null and void. This federal court decision was subsequently challenged on appeal in the U.S. Third Circuit Court of Appeals. The State of Maryland also took similar action to subsidize above-market new generation. This action was also determined to be unconstitutional in 2013 in the U.S. District Court in Maryland and such decision was challenged in the U.S. Fourth Circuit Court of Appeals. Both appeals were denied, with the U.S. Fourth Circuit Court of Appeals (Fourth Circuit) denying the appeal regarding the State of Maryland’s action in June 2014 and the U.S. Third Circuit Court of Appeals denying the LCAPP appeal in September 2014.
Transmission Regulation—Transmission Policy Developments
December 31, 2013 Form 10-K page 17 and June 30, 2014 Form 10-Q page 82. The FERC concluded in Order 1000 These denials have been challenged on appeal to the U.S. Supreme Court. In October 2015, the U.S. Supreme Court announced that it would consider the incumbent transmission owner should not always have a “right of first refusal” (ROFR) to construct and own transmission projects in its service territory. We had challenged the FERC's eliminationappeal of the ROFRFourth Circuit's decision involving Maryland. The U.S. Supreme Court is expected to consider this case in federal court. In August 2014, our challenge was rejected by the D.C. Court. PJM is currently implementing its rules under which the construction of certain types of transmission projects is no longer subject to a ROFR for incumbents. In May 2014, the FERC approved PJM’s rules, which retain carve-outs for projects that will continue to default to incumbents for construction responsibility, including projects being built on existing right-of-way and whose construction would interfere with incumbents’ use of their right-of-way. Several companies, including PSE&G, have appealed various aspects of this approval order. The FERC has also approved the “state agreement approach” to cost allocation under which transmission projects being built to address public policy concerns may be placed into PJM's planning process if the state sponsoring the project agrees to pay the costs of the project. To date, no such projects have been placed into the planning process but this mechanism could potentially facilitate transmission projects that are not needed for reliability or market efficiency under PJM standards for transmission, including potential offshore wind projects proposed by third parties, should a state or states agree to fund the costs of such projects.
In addition, in September 2014, PJM filed at the FERC to add another category of project - the “multi-driver” project - to its planning process. This type of project would contain reliability, economic and/or public policy elements. Projects falling within this category would be required to independently satisfy all of the different drivers in order to be approved. However,

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this category could also serve as a vehicle for projects that may not be needed but are being supported for public policy purposes.
2016. We cannot predict the final outcome or impact of these matters on us; however, specific implementationthis appeal. 

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table of Order 1000 in the various regions, including within our service territory, may expose us to competition from third party construction of certain transmission projects within our service territory while at the same time providing opportunities to build transmission outside of our service territory.contents

Transmission Regulation—Transmission Policy Developments
PJM’s first action toward complying with Order 1000 commenced inDecember 31, 2014 Form 10-K page 18, March 31, 2015 Form 10-Q page 70 and June 30, 2015 Form 10-Q page 78.
In April 2013, when it implementedPJM initiated its first “open window”"open window" solicitation process to allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues at Artificial Island.Island off the shore of New Jersey. In June 2014, PJM’s management recommended approval by itsApril 2015, the PJM staff advised stakeholders that it intended to recommend a transmission project to the PJM Board of a 500 kV projectManagers consisting of various components to be constructed by LS Power, PSE&G to address these performance issues. However, inand Potomac Holding Company.  On July 2014,29, 2015, the PJM Board announced that it was deferring selection ofapproved the PJM staff's recommendation. In August 2015, PJM sent PSE&G a project to enable four developers, includingConstruction Responsibility Letter (to which PSE&G to supplement their proposals by, among other things, re-evaluating the costs of their respective proposals. In September 2014,will be responding on November 9) awarding PSE&G and the three other finalists submitted supplemental proposals. All of the finalists will meet with PJM in the presence of a FERC Administrative Law Judge to answer questions about the components of the supplemental proposals.project, estimated by PJM to cost approximately $126 million. PSE&G is also meetingcurrently in discussions with relevant environmental permitting agencies andPJM regarding the Nuclear Regulatory Commission to gauge constructabilityaccuracy of this estimate given the proposed projects. PJM has indicated that it expects to selectcomplexities associated with construction work at Artificial Island. In a project in the first quarter of 2015.
Transmission Regulation—Transmission Rate Proceedings
December 31, 2013 Form 10-K page 18, March 31, 2014 Form 10-Q page 70 and June 30, 2014 Form 10-Q page 82. In September 2011,related matter, FERC denied a complaint was filed by several state utility commissionsPSE&G contending that PJM had failed to follow its rules during the Artificial Island solicitation process.     PSE&G, however, continues to work with both PJM and consumer advocatesits stakeholders to improve the rules governing open window processes in PJM. 
In November 2014, Con Edison had brought a complaint against transmission ownersPJM at FERC challenging PJM's allocation of costs for two PSE&G projects in northern New England challenging their base return on equity (ROE)Jersey, including the Bergen-Linden Corridor Project (BLC). In June 2014, the2015, FERC issued an order dismissing the complaint. Con Edison and a merchant generator have sought judicial review of certain aspects of FERC’s order and Con Edison has filed a rehearing request with FERC.
There have been developments on several additional matters involving cost allocation issues. In May 2015 and as amended in this proceedingJuly 2015, a merchant transmission operator filed a complaint against PJM challenging PJM’s allocation of costs for four PSE&G projects, including BLC. PSE&G filed opposition to the complaint and the matter is currently pending at FERC. In August 2015, the Delaware Public Service Commission and the Maryland Public Service Commission filed a complaint against PJM and certain transmission owners that providedhave voting rights over cost allocation and rate design, including PSE&G, alleging that PJM tariff provisions allocate an excessive share of the Artificial Island project costs to them relative to the actual benefits of the project to residents of Delaware and Maryland. PSE&G intends to participate in a group filing of transmission owners that will oppose the complaint.
In June 2015, a transmission developer filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for a new approach to determining the ROE for public utilities that, among other things, is intended to narrow the parameters set in calculating the ROE. In applying the new methodology to this case, the FERC tentatively foundevaluating transmission network upgrade requests that the New England transmission owners’ base ROE should be reduced by 57 basis points,developer had submitted to PJM. According to the complaint, PJM and institutedcertain transmission owners wrongfully inflated the scope and associated costs of mitigation work needed to accommodate the developer’s proposal in order to prevent it from pursuing its projects. Although not named as a hearing to allow the participantsrespondent in the proceeding an opportunity to submit evidence in writing solely concerning the applicationcomplaint, PSE&G is identified as one of the new approach. In addition, the FERC directed that the approachcompanies claimed to determine ROE set forth in the New England transmission owners' order should apply to all currently pending ROE-related complaint cases in which the FERC has not issued a final order.have been involved. In July 2014,2015, PJM filed a response, which included a supporting affidavit from PSE&G, contesting the parties filed motions for reconsideration and rehearing regarding the June 2014 order, and also in July 2014, the complaining parties filed another complaint at the FERC challenging the New England transmission owners’ ROE.
On October 16, 2014, the FERC issued an order regarding the application of its new approach, setting the New England transmission owners’ base ROE at 10.57%, the rate indicated in its June 2014 order, with a total or maximum ROE not exceeding the top of the range of reasonable returns, i.e., 11.74%, inclusive of transmission incentive ROE adders (the base ROE does not include basis point adders for participation in an ISO or other incentive adders). The motions for reconsideration/rehearing and the new complaint filed in July 2014 remain pending.
Compliance—FERC
March 31, 2014 Form 10-Q page 70 and June 30, 2014 Form 10-Q page 83. In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, we retained outside counsel to assist in the conduct of an investigation into the matter. As the investigation proceeded, additional pricing errors in the bids were identified and it was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. On September 2, 2014, the FERC staff verbally informed us that they have initiated a preliminary, non-public staff investigation into the matter. This investigation could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies. It is not possible at this time to reasonably estimate the ultimate impact or predict any resulting penalties, other costs associated with this matter, or the applicability of mitigating factors. See Part I, Item 1. Note 8. Commitments and Contingent Liabilities—FERC Compliance for further discussion of this matter.
Compliance—FERC Audit
December 31, 2013 Form 10-K page 18. In November 2012, the FERC commenced an audit of each of the PSEG companies that have MBR authority from the FERC. The companies were audited by the FERC for compliance with its rules for (i) receiving and retaining MBR authority, (ii) the filing of electric quarterly reports (EQRs), and (iii) our generating units' receipt of payments from the RTO/ISO when they are required to run for reliability reasons when it is not economical for them to do so. On October 16, 2014, the FERC issued a final, public audit report that contained two findings and recommendations for enhanced review and reporting of our EQRs. As required, we intend to submit a compliance plan within 30 days.

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State Regulation
Energy Strong Program
December 31, 2013 Form 10-K page 20, March 31, 2014 Form 10-Q page 71 and June 30, 2014 Form 10-Q page 83. On May 21, 2014, the BPU issued an Order approving the settlement of our Energy Strong program. This program encompasses infrastructure investments of $1.22 billion that we will make to our BPU jurisdictional electric and gas system to improve resiliency for the future. For additional information, see Part I, Item 1. MD&A—Overview of 2014 and Future Outlook—Regulatory, Legislative and Other Developments. On September 30, 2014, PSE&G filed its initial Energy Strong cost recovery petition, seeking BPU approval to recover in base rates an estimated annual revenue increase of $1.6 million effective March 1, 2015. This increase represents capitalized Energy Strong electric investment costs expected to be in service through November 30, 2014. This request will be updated in December 2014 for actual costs.
Storm Proceedings
December 31, 2013 Form 10-K page 20. In December 2012, the BPU issued an order allowing PSE&G to defer on its books actually incurred, prudent, incremental storm restoration costs associated with extraordinary storms, including Superstorm Sandy and Hurricane Irene, and not otherwise recoverable through base rates or insurance. In March 2013, the BPU initiated a proceeding to evaluate the prudency of storm costs incurred by New Jersey utilities. On September 30, 2014, the BPU approved a Stipulation of Settlement finding that $366 million, consisting of all of PSE&G's 2010 through 2012 major storm capital expenditures of $126 million, and virtually all of PSE&G’s 2010 through 2012 major storm incremental O&M costs ($240.1 million of the $240.5 million identified) were prudent and recoverable in a future base rate proceeding, subject to offset for the amount of insurance proceeds received. See Part I, Item 1. Note 4. Rate Filings.
Energy Efficiency Economic Stimulus Extension II (EEE Ext II)
In August 2014, we filed for approval from the BPU of an EEE Ext II Program to extend three EEE subprograms (multi-family, direct install and hospital efficiency). We proposed to extend the subprograms’ offerings under the same clause recovery process as currently approved while seeking additional capital expenditures of approximately $96 million and additional administrative costs of $14 million.allegations. The matter is pending.
Consolidated Tax Adjustments (CTA)State Regulation
Gas System Modernization Program (GSMP)
March 31, 2015 Form 10-Q page 71. In September 2015, PSE&G reached a settlement in principle with the BPU Staff and the New Jersey is oneDivision of onlyRate Counsel regarding PSE&G’s GSMP through which, if approved, PSE&G will invest $905 million over the next three years to modernize its gas system. The settlement in principle will enable the utility to replace up to 510 miles of gas mains and 38,000 service lines over a few states that make CTA in setting rates for regulated utilities. These adjustments tothree-year period, with cost recovery at a 9.75% rate base are madeduringof return on equity on the rate setting process andare intended to allocate to utility customers a portionfirst $650 million of the tax benefits realized frominvestment through an accelerated recovery mechanism. Under the filing of a consolidated federal tax return bythe utility’s parent corporation. The BPU has been considering the appropriatenesssettlement in principle, PSE&G will seek recovery of the adjustmentremaining $255 million of investment in its next base rate case, which is to be filed no later than November 1, 2017.
Connecticut Rate Filing
June 30, 2015 Form 10-Q page 79. In June 2015, Power’s subsidiary PSEG New Haven LLC, filed a mandatory annual rate case with the Connecticut Public Utilities Regulatory Authority (PURA) for recovery of its costs and the methodology and mechanicsinvestment in its Connecticut-based peaking unit. Power requested 2016 revenues of the calculation for some time.$22 million. On October 22, 2014,2015, PURA issued a Proposed Final Decision to approve the BPU approved a proposal by its Staff that limits the tax benefit periodentirety of Power’s request. A Final Decision is expected to be considered in the calculation to five years, sets the rate base adjustment at 25%issued on November 4, 2015.

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table of any such tax benefit, and eliminates from the process any tax benefits tied to transmission earnings. In accordance with this October action, this CTA policy will be applied only with respect to future rate cases. The adoption of these modifications by the BPU is not expected to have a material impact on PSE&G’s current earnings nor in its next rate case filing.contents

Environmental Matters
Air Pollution Control
Demand Response (DR) and Reciprocating Internal Combustion Engines (RICE) Litigation
December 31, 20132014 Form 10-K page 21.23 and June 30, 2015 Form 10-Q page 79. In March 2013, wePower filed a petition at the EPA challenging the National Emission Standards for Hazardous Air Pollutants (NESHAP) for RICE issued onin January 30, 2013. Among other things, the final EPA rule allowsincludes two exemptions that allow owners and operators of stationarystationery emergency RICE to operate their engines as part of an emergency DR program without the installation and operation of emission controls (1) as part of an emergency DR program for 100 hours per year (100 hour exemption) or compliance(2) as part of a financial arrangement with emission limits otherwise applicable toanother entity per specified restrictions in non-emergency counterparts.situations for 50 hours per year (50 hour exemption). This waiver of NESHAP standards results in disparate treatment of different generation technology types. In ourits appeal, wePower sought more stringent emission control standards for RICE to support more competitive markets, particularly the PJM capacity market. OnIn August 15, 2014, the EPA denied the March 2013 petition for reconsideration. We and other petitioners are considering whether to take further legal action.
Cross-State Air Pollution Rule (CSAPR)
December 31, 2013 Form 10-K page 21, March 31,in October 2014, Form 10-Q page 71 and June 30, 2014 Form 10-Q page 84. In July 2011,Power appealed the EPA issued the final CSAPR, which limited power plant emissions of Sulfur Dioxide (SO2) and annual and ozone season NOx in 28 states that contributeEPA's denial to the ability of downwind states to attain and/or maintain current particulate matter and ozone National Ambient Air Quality Standards. In August 2012,D.C. Court. On May 1, 2015, the D.C. Court vacated CSAPR and ordered that the existing Clean Air Interstate Rule requirements100 hour exemption but thereafter granted a stay until May 1, 2016. On September 23, 2015, the D.C. Court granted the EPA's motion for voluntary remand of the 50 hour exemption provision to the EPA. While both provisions remain in effect until an appropriate substitute rule has been promulgated. On April 29, 2014,place, the Supreme Court overturnedEPA will undergo proceedings to address the D.C. Court's ruling. On June 26,orders. We believe that the impact of the D.C. Court's rulings would likely benefit Power's and its competitors' operations of their power generation peaking units.
Ozone Standard
March 31, 2015 Form 10-Q page 71. In December 2014, the EPA proposed a rule to lower the ambient air quality standard for the level of ozone in the atmosphere from 75 parts per billion (ppb) to a level in the range of 65-70 ppb. On October 1, 2015, the EPA finalized a standard of 70 ppb. To meet the new standard, the EPA and the states have to implement additional emission reduction strategies for NOX and volatile organic compounds. Some portions of the Mid-Atlantic and New England states are not expected to be able to meet the new standard. Although the majority of our fossil generating units employ state-of-the-art NOX emission controls, we cannot predict the outcome of this matter since new requirements of the EPA and the states are unknown at this time. A coal mining company has filed a motionpetition for review with the D.C. Court to liftchallenge the rule.

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Table of ContentsClimate Change

CO2 Regulation Under the Clean Air Act (CAA)

stay on CSAPRDecember 31, 2014 Form 10-K page 23, March 31, 2015 Form 10-Q page 72 and allow for implementation of Phase I to begin on January 1, 2015.June 30, 2015 Form 10-Q page 80. On October 23, 2014, the D.C. Court lifted the stay on CSAPR and we anticipate implementation effective January 2015, per the EPA's motion. We do not anticipate any material impact on our earnings or financial condition due to the CSAPR.
Climate Change
CO2 Regulation Under the CAA
December 31, 2013 Form 10-K page 22 and June 30, 2014 Form 10-Q page 84. On June 18, 2014, the EPA issuedpublished the Clean Power Plan (CPP), a proposed greenhouse gas (GHG) emissions regulation under the CAA for existing power plants. The regulation establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In September 2014,reduction (BSER). The BSER consists of three components: (i) heat rate improvements at existing coal-fired power plants, (ii) increased use of existing natural gas combined cycle capacity, and (iii) operation of incremental zero-emitting generation (renewables and nuclear). States may choose these or other methodologies to achieve the necessary reductions of CO2 emissions.
Each state must submit a compliance plan to the EPA extended the comment period from October 16, 2014by September 6, 2016 or seek a two-year extension to December 1, 2014. The EPA is requesting comments on many aspects of the proposal and therefore,September 6, 2018. States can comply using an emission rate-based plan (pounds CO2/MWh) or a mass-based plan (tons). Compliance with the final rule may look considerably different thanis effective January 1, 2022.
The EPA, FERC and the proposal. WeU.S. Department of Energy announced that they plan to meet at least quarterly to evaluate states' plans and identify reliability concerns so adjustments can be made before the final plans are submitted. The agencies are engaging various stakeholders, including the Regional Transmission Operators/Independent System Operators. The agencies will continue to workmeet after the states' plans are in effect to assess if revisions are required.
On October 23, 2015, the EPA also published proposed federal implementation requirements for states that do not submit an EPA-approved compliance plan. Comments are due by January 21, 2016.
Numerous states, including New Jersey, and several industry groups have filed petitions for review with state and federal regulators, as well as industry partners,the D.C. Court to determine challenge the potential impact.CPP.
If relevant federal or state common law were to impose liability upon those that emit GHGs for alleged impacts In addition, the petitioners are seeking a stay of GHGs emissions, such potential liability to our fossil generation operations could be material. However, approximately 60% of our generation output comes from nuclear facilities which are GHG-free and would not be impacted.the rule. 
Water Pollution Control
Steam Electric Effluent Guidelines
December 31, 2014 Form 10-K page 24. On September 30, 2015, the EPA issued a new Effluent Guidelines Limitation Rule for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power has two electric generation facilities, its dual-

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fuel (gas/coal) Mercer station in New Jersey and coal-fired Bridgeport Harbor station in Connecticut, that have bottom ash transport water discharges that are regulated under this rule. We are unable to predict if these new standards will have a material impact on Power's future capital requirements, financial condition or results of operations.
Cooling Water Intake Structure Regulation
December 31, 20132014 Form 10-K page 23, March 31, 201425 and June 30, 2015 Form 10-Q page 72 and80. On June 30, 2014 Form 10-Q page 85. On May 19, 2014,2015, the EPANJDEP issued a finaldraft permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water intake rule under Section 316(b)system with certain required system modifications. The draft permit is subject to a sixty-day public notice and comment period. We participated in the NJDEP’s August 5, 2015 public hearing and submitted comments on the draft permit on September 18, 2015.The NJDEP may make revisions before issuing the final permit expected in the first half of the Clean Water Act that establishes new requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. 
On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Fourth Circuit Court of Appeals.
We are assessing the potential impact of the rule on each of our affected facilities and are unable to predict the outcome of permitting decisions and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material. See2016. For additional information, see Part I, Item 1. Note 8. Commitments and Contingent Liabilities—Liabilities.
Waters of the United States
December 31, 2014 Form 10-K page 25 and June 30, 2015 Form 10-Q page 80. In April 2014, the EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published a proposed rule to clarify the definition of waters of the U.S. under the Clean Water Act Permit Renewals for additional information.  (CWA) programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. The final rule was published on June 29, 2015 and we are reviewing it to determine the materiality of the impacts that might result from the final rule. Some states, including New Jersey, are subject to state requirements beyond those imposed under federal law. While we do not anticipate material impacts to projects in New Jersey, the new definition could impose requirements in other states and regions that could impact the development of renewables.
Various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the final rule. On October 9, 2015, the Sixth Circuit Court of Appeals issued a stay of the rule pending further court action.




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

a. PSEG:  
Exhibit 10Employment Agreement with Daniel J. Cregg. dated September 22, 2015
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 DorsaDaniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1: Certification by Caroline DorsaDaniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS: XBRL Instance Document
Exhibit 101.SCH: XBRL Taxonomy Extension Schema
Exhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF: XBRL Taxonomy Extension Definition Document
   
b. Power:PSE&G:  
Exhibit 10Employment Agreement with Daniel J. Cregg, dated September 22, 2015
Exhibit 12.1: Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.2:Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
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 DorsaDaniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3: Certification by Caroline DorsaDaniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS: XBRL Instance Document
Exhibit 101.SCH: XBRL Taxonomy Extension Schema
Exhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF: XBRL Taxonomy Extension Definition Document
   
c. PSE&G:Power:  
Exhibit 4 (a) (22):10 Supplemental IndentureEmployment Agreement with Daniel J. Cregg, dated August 1, 2014
Exhibit 12.2:Computation of Ratios of Earnings to Fixed ChargesSeptember 22, 2015
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 DorsaDaniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.4: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.5: Certification by Caroline DorsaDaniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS: XBRL Instance Document
Exhibit 101.SCH: XBRL Taxonomy Extension Schema
Exhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF: XBRL Taxonomy Extension Definition Document



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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/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: October 30, 20142015

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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/ STUART J. BLACK
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: October 30, 2014


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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/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: October 30, 20142015


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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/ STUART J. BLACK
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: October 30, 2015


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