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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 JuneSeptember 30, 2016
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
Newark, New Jersey 07102
973 430-7000
http://www.pseg.com
  22-2625848
001-00973  
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(A New Jersey Corporation)
80 Park Plaza
Newark, New Jersey 07102
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
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
     
Public Service Electric and Gas Company
Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o
     
PSEG 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 July 19,October 18, 2016, Public Service Enterprise Group Incorporated had outstanding 505,916,520505,896,218 shares of its sole class of Common Stock, without par value.
As of July 19,October 18, 2016, 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.
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
FILING FORMAT
iii
PART I. FINANCIAL INFORMATION 
Item 1.Financial Statements 
 
Public Service Enterprise Group Incorporated
1
 
Public Service Electric and Gas Company
6
 
PSEG Power LLC
11
 Notes to Condensed Consolidated Financial Statements 
 
Note 1. Organization and Basis of Presentation
16
 
Note 2. Recent Accounting Standards
16
 
Note 3. Variable Interest Entities (VIEs)
Early Plant Retirements
18
 
Note 4. Rate Filings
18
Note 5. Financing Receivables
Variable Interest Entities (VIEs)
19
 Note 5. Rate Filings
20
Note 6. Available-for-Sale SecuritiesFinancing Receivables
21
 
Note 7. Available-for-Sale Securities
23
Note 8. Pension and Other Postretirement Benefits (OPEB)
26
Note 8. Commitments and Contingent Liabilities
28
 
Note 9. DebtCommitments and Credit Facilities
Contingent Liabilities
3530
 
Note 10. Financial Risk Management Activities
Debt and Credit Facilities
3637
 
Note 11. Fair Value Measurements
Financial Risk Management Activities
4339
 
Note 12. Other Income and Deductions
Fair Value Measurements
5145
 
Note 13. Other Income Taxes
and Deductions
5253
 
Note 14. Income Taxes
54
Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax
5355
 
Note 15.16. Earnings Per Share (EPS) and Dividends
57
Note 16. Financial Information by Business Segments
58
Note 17. Related-Party Transactions
59
 Note 17. Financial Information by Business Segments
60
Note 18. Related-Party Transactions
61
Note 19. Guarantees of Debt
6163
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
6466
 Executive Overview of 2016 and Future Outlook
6466
 
Results of Operations
7074
 
Liquidity and Capital Resources
7579
 
Capital Requirements
7781
 
Accounting Matters
7782
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
7882
Item 4.
Controls and Procedures
7983
  
PART II. OTHER INFORMATION 
Item 1.
Legal Proceedings
7983
Item 1A.
Risk Factors
7983
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
7984
Item 5.
Other Information
7984
Item 6.
Exhibits
8386
 
Signatures
8487


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FORWARD-LOOKING STATEMENTS
Certain of the matters discussed in this report about our and our subsidiaries'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'smanagement’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 ongoing low pricing of the capacity and energy that we sell into wholesale electricity markets,
adverse changes in energy industry law, policies and regulations, including market structures and transmission planning,
any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators, including prudency reviews, disallowances and changes in authorized returns,
any deterioration in our credit quality or the credit quality of our counterparties,
changes in federal and state environmental regulations and enforcement that could increase our costs or limit our operations,
adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry,
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 or increase the cost 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,
delays or unforeseen cost escalations in our construction and development activities, or the inability to recover the carrying amount of our assets,
availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs,
increases in competition in energy supply markets as well as for transmission projects,
changes in technology, such as distributed generation, storage and micro grids, and greater reliance on these technologies,
changes in customer behaviors, including increases in energy efficiency, net-metering and demand response,
adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in funding requirements,
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 insurance proceeds of insurance with respect to such events,
acts of terrorism, cybersecurity attacks or intrusions that could adversely impact our businesses,
delays in receipt of necessary permits and approvals for our construction and development activities,
any inability to achieve, or continue to sustain, our expected levels of operating performance,
changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units,
an extended economic recession,recessions,
an inability to realize anticipated tax benefits or retain tax credits,
challenges associated with recruitment and/or retention of a qualified workforce, and
changes in the credit quality and the ability of lessees to meet their obligations under our domestic leveraged leases.
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

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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.

FILING FORMAT
This combined Quarterly Report on Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), 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. PSE&G and Power are each only responsible for information about itself and its subsidiaries.
Discussions throughout the document refer to PSEG and its direct operating subsidiaries, PSE&G and Power. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions, except per share data
(Unaudited)

          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
 OPERATING REVENUES$1,905
 $2,314
 $4,521
 $5,449
 
 OPERATING EXPENSES        
 Energy Costs624
 668
 1,460
 1,762
 
 Operation and Maintenance710
 761
 1,439
 1,424
 
 Depreciation and Amortization224
 317
 448
 647
 
 Total Operating Expenses1,558
 1,746
 3,347
 3,833
 
 OPERATING INCOME347
 568
 1,174
 1,616
 
 Income from Equity Method Investments4
 4
 6
 7
 
 Other Income44
 76
 92
 124
 
 Other Deductions(10) (10) (31) (22) 
 Other-Than-Temporary Impairments(10) (10) (20) (15) 
 Interest Expense(97) (97) (189) (195) 
 INCOME BEFORE INCOME TAXES278
 531
 1,032
 1,515
 
 Income Tax Expense(91) (186) (374) (584) 
 NET INCOME$187
 $345
 $658
 $931
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:        
 BASIC505
 506
 505
 506
 
 DILUTED508
 508
 508
 508
 
 NET INCOME PER SHARE:        
 BASIC$0.37
 $0.68
 $1.30
 $1.84
 
 DILUTED$0.37
 $0.68
 $1.30
 $1.83
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.41
 $0.39
 $0.82
 $0.78
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
 OPERATING REVENUES$2,450
 $2,688
 $6,971
 $8,137
 
 OPERATING EXPENSES        
 Energy Costs866
 815
 2,326
 2,577
 
 Operation and Maintenance776
 746
 2,215
 2,170
 
 Depreciation and Amortization231
 313
 679
 960
 
 Total Operating Expenses1,873
 1,874
 5,220
 5,707
 
 OPERATING INCOME577
 814
 1,751
 2,430
 
 Income from Equity Method Investments3
 3
 9
 10
 
 Other Income47
 47
 139
 171
 
 Other Deductions(8) (14) (39) (36) 
 Other-Than-Temporary Impairments(5) (30) (25) (45) 
 Interest Expense(99) (96) (288) (291) 
 INCOME BEFORE INCOME TAXES515
 724
 1,547
 2,239
 
 Income Tax Expense(188) (285) (562) (869) 
 NET INCOME$327
 $439
 $985
 $1,370
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:        
 BASIC505
 505
 505
 505
 
 DILUTED508
 508
 508
 508
 
 NET INCOME PER SHARE:        
 BASIC$0.65
 $0.87
 $1.95
 $2.71
 
 DILUTED$0.64
 $0.87
 $1.94
 $2.70
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.41
 $0.39
 $1.23
 $1.17
 
          
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 Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
 NET INCOME$187
 $345
 $658
 $931
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(10), $15, $(26) and $2 for the three and six months ended 2016 and 2015, respectively10
 (15) 26
 (1) 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $(1) and $7 for the three and six months ended 2016 and 2015, respectively(1) —
 1
 (9) 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(6), $(6), $(12) and $(12) for the three and six months ended 2016 and 2015, respectively8
 8
 16
 16
 
 Other Comprehensive Income (Loss), net of tax17
 (7) 43
 6
 
 COMPREHENSIVE INCOME$204
 $338
 $701
 $937
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
 NET INCOME$327
 $439
 $985
 $1,370
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(24), $33, $(50) and $35 for the three and nine months ended 2016 and 2015, respectively24
 (31) 50
 (32) 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $(1), $(1) and $6 for the three and nine months ended 2016 and 2015, respectively1
 —
 2
 (9) 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(5), $(5), $(17) and $(17) for the three and nine months ended 2016 and 2015, respectively9
 9
 25
 25
 
 Other Comprehensive Income (Loss), net of tax34
 (22) 77
 (16) 
 COMPREHENSIVE INCOME$361
 $417
 $1,062
 $1,354
 
          
See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  June 30,
2016		 December 31,
2015		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$648
 $394
 
 Accounts Receivable, net of allowances of $65 and $67 in 2016 and 2015, respectively988
 1,068
 
 Tax Receivable4
 305
 
 Unbilled Revenues202
 197
 
 Fuel351
 463
 
 Materials and Supplies, net554
 513
 
 Prepayments271
 135
 
 Derivative Contracts152
 242
 
 Regulatory Assets310
 164
 
 Other9
 13
 
 Total Current Assets3,489
 3,494
 
 PROPERTY, PLANT AND EQUIPMENT37,285
 35,494
 
      Less: Accumulated Depreciation and Amortization(9,271) (8,955) 
 Net Property, Plant and Equipment28,014
 26,539
 
 NONCURRENT ASSETS    
 Regulatory Assets3,120
 3,196
 
 Long-Term Investments1,218
 1,233
 
 Nuclear Decommissioning Trust (NDT) Fund1,797
 1,754
 
 Long-Term Tax Receivable183
 171
 
 Long-Term Receivable of Variable Interest Entity (VIE)513
 495
 
 Other Special Funds246
 227
 
 Goodwill16
 16
 
 Other Intangibles131
 102
 
 Derivative Contracts76
 77
 
 Other242
 231
 
 Total Noncurrent Assets7,542
 7,502
 
 TOTAL ASSETS$39,045
 $37,535
 
      
      
  September 30,
2016		 December 31,
2015		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$450
 $394
 
 Accounts Receivable, net of allowances of $67 in 2016 and 20151,031
 1,068
 
 Tax Receivable23
 305
 
 Unbilled Revenues180
 197
 
 Fuel366
 463
 
 Materials and Supplies, net591
 513
 
 Prepayments145
 135
 
 Derivative Contracts149
 242
 
 Regulatory Assets253
 164
 
 Other21
 13
 
 Total Current Assets3,209
 3,494
 
 PROPERTY, PLANT AND EQUIPMENT38,225
 35,494
 
      Less: Accumulated Depreciation and Amortization(9,421) (8,955) 
 Net Property, Plant and Equipment28,804
 26,539
 
 NONCURRENT ASSETS    
 Regulatory Assets3,124
 3,196
 
 Long-Term Investments1,066
 1,233
 
 Nuclear Decommissioning Trust (NDT) Fund1,857
 1,754
 
 Long-Term Tax Receivable177
 171
 
 Long-Term Receivable of Variable Interest Entity (VIE)509
 495
 
 Other Special Funds243
 227
 
 Goodwill16
 16
 
 Other Intangibles154
 102
 
 Derivative Contracts86
 77
 
 Other243
 231
 
 Total Noncurrent Assets7,475
 7,502
 
 TOTAL ASSETS$39,488
 $37,535
 
      
See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

 
      
  June 30,
2016		 December 31,
2015		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$662
 $734
 
 Commercial Paper and Loans—
 364
 
 Accounts Payable1,308
 1,369
 
 Derivative Contracts20
 76
 
 Accrued Interest103
 96
 
 Accrued Taxes107
 42
 
 Clean Energy Program200
 142
 
 Obligation to Return Cash Collateral128
 128
 
 Regulatory Liabilities74
 123
 
 Regulatory Liabilities of VIEs22
 42
 
 Other496
 459
 
 Total Current Liabilities3,120
 3,575
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)8,545
 8,166
 
 Regulatory Liabilities165
 175
 
 Asset Retirement Obligations693
 679
 
 OPEB Costs1,199
 1,228
 
 OPEB Costs of Servco389
 375
 
 Accrued Pension Costs429
 487
 
 Accrued Pension Costs of Servco118
 114
 
 Clean Energy Program27
 —
 
 Environmental Costs402
 415
 
 Derivative Contracts14
 27
 
 Long-Term Accrued Taxes171
 212
 
 Other181
 181
 
 Total Noncurrent Liabilities12,333
 12,059
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 CAPITALIZATION
   
 LONG-TERM DEBT10,273
 8,834
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000 shares; issued, 2016 and 2015—534 shares4,919
 4,915
 
 Treasury Stock, at cost, 2016—29 shares; 2015—28 shares(709) (671) 
 Retained Earnings9,360
 9,117
 
 Accumulated Other Comprehensive Loss(252) (295) 
 Total Common Stockholders’ Equity13,318
 13,066
 
 Noncontrolling Interest1
 1
 
 Total Stockholders’ Equity13,319
 13,067
 
 Total Capitalization23,592
 21,901
 
 TOTAL LIABILITIES AND CAPITALIZATION$39,045
 $37,535
 
  

   
      
  September 30,
2016		 December 31,
2015		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$—
 $734
 
 Commercial Paper and Loans255
 364
 
 Accounts Payable1,363
 1,369
 
 Derivative Contracts40
 76
 
 Accrued Interest127
 96
 
 Accrued Taxes214
 42
 
 Clean Energy Program185
 142
 
 Obligation to Return Cash Collateral132
 128
 
 Regulatory Liabilities96
 123
 
 Regulatory Liabilities of VIEs9
 42
 
 Other383
 459
 
 Total Current Liabilities2,804
 3,575
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)8,661
 8,166
 
 Regulatory Liabilities151
 175
 
 Asset Retirement Obligations708
 679
 
 OPEB Costs1,207
 1,228
 
 OPEB Costs of Servco395
 375
 
 Accrued Pension Costs400
 487
 
 Accrued Pension Costs of Servco108
 114
 
 Environmental Costs430
 415
 
 Derivative Contracts13
 27
 
 Long-Term Accrued Taxes197
 212
 
 Other241
 181
 
 Total Noncurrent Liabilities12,511
 12,059
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 CAPITALIZATION
   
 LONG-TERM DEBT10,697
 8,834
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000 shares; issued, 2016 and 2015—534 shares4,928
 4,915
 
 Treasury Stock, at cost, 2016—29 shares; 2015—28 shares(714) (671) 
 Retained Earnings9,480
 9,117
 
 Accumulated Other Comprehensive Loss(218) (295) 
 Total Common Stockholders’ Equity13,476
 13,066
 
 Noncontrolling Interest—
 1
 
 Total Stockholders’ Equity13,476
 13,067
 
 Total Capitalization24,173
 21,901
 
 TOTAL LIABILITIES AND CAPITALIZATION$39,488
 $37,535
 
  

   
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, 
  2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$985
 $1,370
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization679
 960
 
 Amortization of Nuclear Fuel154
 162
 
  Impairment Costs102
 —
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC445
 230
 
 Non-Cash Employee Benefit Plan Costs95
 121
 
 Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes(12) 6
 
 Loss on Leases, Net of Tax86
 —
 
 Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives96
 (87) 
 Change in Accrued Storm Costs(6) 15
 
 Net Change in Other Regulatory Assets and Liabilities(66) 26
 
 Cost of Removal(109) (82) 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(12) (2) 
 Net Change in Certain Current Assets and Liabilities:    
           Tax Receivable282
 206
 
           Accrued Taxes202
 127
 
           Margin Deposit(4) 142
 
           Other Current Assets and Liabilities(229) 15
 
 Employee Benefit Plan Funding and Related Payments(81) (87) 
 Other154
 106
 
 Net Cash Provided By (Used In) Operating Activities2,761
 3,228
 
 CASH FLOWS FROM INVESTING ACTIVITIES

   
 Additions to Property, Plant and Equipment(2,985) (2,782) 
 Proceeds from Sales of Capital Leases and Investments—
 12
 
 Proceeds from Sales of Available-for-Sale Securities551
 1,120
 
 Investments in Available-for-Sale Securities(576) (1,163) 
 Other(44) (28) 
 Net Cash Provided By (Used In) Investing Activities(3,054) (2,841) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans(109) 20
 
 Issuance of Long-Term Debt1,975
 600
 
 Redemption of Long-Term Debt(824) (300) 
 Redemption of Securitization Debt—
 (191) 
 Cash Dividends Paid on Common Stock(622) (592) 
 Other(71) (55) 
 Net Cash Provided By (Used In) Financing Activities349
 (518) 
 Net Increase (Decrease) in Cash and Cash Equivalents56
 (131) 
 Cash and Cash Equivalents at Beginning of Period394
 402
 
 Cash and Cash Equivalents at End of Period$450
 $271
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(274) $292
 
 Interest Paid, Net of Amounts Capitalized$252
 $265
 
 Accrued Property, Plant and Equipment Expenditures$579
 $321
 
      
      
  Six Months Ended 
  June 30, 
  2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$658
 $931
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization448
 647
 
 Amortization of Nuclear Fuel105
 106
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC334
 170
 
 Non-Cash Employee Benefit Plan Costs63
 81
 
 Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes(30) (22) 
 Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives153
 (9) 
 Change in Accrued Storm Costs(1) 15
 
 Net Change in Other Regulatory Assets and Liabilities(124) (53) 
 Cost of Removal(74) (58) 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(2) (21) 
 Net Change in Certain Current Assets and Liabilities:    
           Tax Receivable301
 188
 
           Accrued Taxes94
 71
 
           Margin Deposit(46) 69
 
           Other Current Assets and Liabilities(120) 98
 
 Employee Benefit Plan Funding and Related Payments(78) (67) 
 Other41
 88
 
 Net Cash Provided By (Used In) Operating Activities1,722
 2,234
 
 CASH FLOWS FROM INVESTING ACTIVITIES

   
 Additions to Property, Plant and Equipment(1,971) (1,743) 
 Proceeds from Sales of Available-for-Sale Securities392
 885
 
 Investments in Available-for-Sale Securities(407) (918) 
 Other(18) 3
 
 Net Cash Provided By (Used In) Investing Activities(2,004) (1,773) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans(364) —
 
 Issuance of Long-Term Debt1,550
 600
 
 Redemption of Long-Term Debt(171) (300) 
 Redemption of Securitization Debt—
 (125) 
 Cash Dividends Paid on Common Stock(415) (394) 
 Other(64) (47) 
 Net Cash Provided By (Used In) Financing Activities536
 (266) 
 Net Increase (Decrease) in Cash and Cash Equivalents254
 195
 
 Cash and Cash Equivalents at Beginning of Period394
 402
 
 Cash and Cash Equivalents at End of Period$648
 $597
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(276) $184
 
 Interest Paid, Net of Amounts Capitalized$176
 $195
 
 Accrued Property, Plant and Equipment Expenditures$513
 $324
 
      
See Notes to Condensed Consolidated Financial Statements.

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

          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
 OPERATING REVENUES$1,350
 $1,466
 $3,062
 $3,468
 
 OPERATING EXPENSES        
 Energy Costs529
 544
 1,258
 1,436
 
 Operation and Maintenance352
 368
 734
 780
 
 Depreciation and Amortization136
 234
 275
 481
 
 Total Operating Expenses1,017
 1,146
 2,267
 2,697
 
 OPERATING INCOME333
 320
 795
 771
 
 Other Income19
 19
 39
 37
 
 Other Deductions(1) (1) (2) (2) 
 Interest Expense(74) (67) (142) (136) 
 INCOME BEFORE INCOME TAXES277
 271
 690
 670
 
 Income Tax Expense(98) (104) (249) (261) 
 NET INCOME$179
 $167
 $441
 $409
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
 OPERATING REVENUES$1,684
 $1,766
 $4,746
 $5,234
 
 OPERATING EXPENSES        
 Energy Costs721
 740
 1,979
 2,176
 
 Operation and Maintenance376
 391
 1,110
 1,171
 
 Depreciation and Amortization137
 231
 412
 712
 
 Total Operating Expenses1,234
 1,362
 3,501
 4,059
 
 OPERATING INCOME450
 404
 1,245
 1,175
 
 Other Income22
 22
 61
 59
 
 Other Deductions(1) —
 (3) (2) 
 Interest Expense(72) (67) (214) (203) 
 INCOME BEFORE INCOME TAXES399
 359
 1,089
 1,029
 
 Income Tax Expense(144) (137) (393) (398) 
 NET INCOME$255
 $222
 $696
 $631
 
          
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 Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
 NET INCOME$179
 $167
 $441
 $409
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 and $0 for the three and six months ended 2016 and 2015, respectively1
 (1) 1
 (1) 
 COMPREHENSIVE INCOME$180
 $166
 $442
 $408
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
 NET INCOME$255
 $222
 $696
 $631
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 and $0 for the three and nine months ended 2016 and 2015, respectively—
 —
 1
 (1) 
 COMPREHENSIVE INCOME$255
 $222
 $697
 $630
 
          
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)

      
  June 30,
2016		 December 31,
2015		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$168
 $198
 
 Accounts Receivable, net of allowances of $65 and $67 in 2016 and 2015, respectively736
 787
 
 Accounts Receivable—Affiliated Companies—
 222
 
 Unbilled Revenues202
 197
 
 Materials and Supplies162
 148
 
 Prepayments196
 31
 
 Regulatory Assets310
 164
 
 Derivative Contracts—
 13
 
 Other8
 9
 
 Total Current Assets1,782
 1,769
 
 PROPERTY, PLANT AND EQUIPMENT24,976
 23,732
 
 Less: Accumulated Depreciation and Amortization(5,627) (5,504) 
 Net Property, Plant and Equipment19,349
 18,228
 
 NONCURRENT ASSETS    
 Regulatory Assets3,120
 3,196
 
 Long-Term Investments316
 330
 
 Other Special Funds57
 49
 
 Other113
 105
 
 Total Noncurrent Assets3,606
 3,680
 
 TOTAL ASSETS$24,737
 $23,677
 
      
      
  September 30,
2016		 December 31,
2015		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$406
 $198
 
 Accounts Receivable, net of allowances of $67 in 2016 and 2015806
 787
 
 Accounts Receivable—Affiliated Companies28
 222
 
 Unbilled Revenues180
 197
 
 Materials and Supplies190
 148
 
 Prepayments94
 31
 
 Regulatory Assets253
 164
 
 Derivative Contracts—
 13
 
 Other20
 9
 
 Total Current Assets1,977
 1,769
 
 PROPERTY, PLANT AND EQUIPMENT25,617
 23,732
 
 Less: Accumulated Depreciation and Amortization(5,701) (5,504) 
 Net Property, Plant and Equipment19,916
 18,228
 
 NONCURRENT ASSETS    
 Regulatory Assets3,124
 3,196
 
 Long-Term Investments305
 330
 
 Other Special Funds54
 49
 
 Other110
 105
 
 Total Noncurrent Assets3,593
 3,680
 
 TOTAL ASSETS$25,486
 $23,677
 
      
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)

      
  June 30,
2016		 December 31,
2015		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$100
 $171
 
 Commercial Paper and Loans—
 153
 
 Accounts Payable680
 724
 
 Accounts Payable—Affiliated Companies179
 292
 
 Accrued Interest73
 70
 
 Clean Energy Program200
 142
 
 Derivative Contracts2
 —
 
 Obligation to Return Cash Collateral127
 128
 
 Regulatory Liabilities74
 123
 
 Regulatory Liabilities of VIEs22
 42
 
 Other339
 297
 
 Total Current Liabilities1,796
 2,142
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC5,503
 5,181
 
 OPEB Costs904
 937
 
 Accrued Pension Costs165
 202
 
 Regulatory Liabilities165
 175
 
 Clean Energy Program27
 —
 
 Environmental Costs336
 365
 
 Asset Retirement Obligations220
 218
 
 Derivative Contracts—
 11
 
 Long-Term Accrued Taxes99
 109
 
 Other113
 114
 
 Total Noncurrent Liabilities7,532
 7,312
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT7,394
 6,650
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150 shares authorized; issued and outstanding, 2016 and 2015—132 shares892
 892
 
 Contributed Capital695
 695
 
 Basis Adjustment986
 986
 
 Retained Earnings5,440
 4,999
 
 Accumulated Other Comprehensive Income2
 1
 
 Total Stockholder’s Equity8,015
 7,573
 
 Total Capitalization15,409
 14,223
 
 TOTAL LIABILITIES AND CAPITALIZATION$24,737
 $23,677
 
      
      
  September 30,
2016		 December 31,
2015		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$—
 $171
 
 Commercial Paper and Loans—
 153
 
 Accounts Payable702
 724
 
 Accounts Payable—Affiliated Companies214
 292
 
 Accrued Interest83
 70
 
 Clean Energy Program185
 142
 
 Derivative Contracts4
 —
 
 Obligation to Return Cash Collateral132
 128
 
 Regulatory Liabilities96
 123
 
 Regulatory Liabilities of VIEs9
 42
 
 Other276
 297
 
 Total Current Liabilities1,701
 2,142
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC5,703
 5,181
 
 OPEB Costs908
 937
 
 Accrued Pension Costs147
 202
 
 Regulatory Liabilities151
 175
 
 Environmental Costs364
 365
 
 Asset Retirement Obligations220
 218
 
 Derivative Contracts—
 11
 
 Long-Term Accrued Taxes92
 109
 
 Other114
 114
 
 Total Noncurrent Liabilities7,699
 7,312
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT7,816
 6,650
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150 shares authorized; issued and outstanding, 2016 and 2015—132 shares892
 892
 
 Contributed Capital695
 695
 
 Basis Adjustment986
 986
 
 Retained Earnings5,695
 4,999
 
 Accumulated Other Comprehensive Income2
 1
 
 Total Stockholder’s Equity8,270
 7,573
 
 Total Capitalization16,086
 14,223
 
 TOTAL LIABILITIES AND CAPITALIZATION$25,486
 $23,677
 
      
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)
      
  Six Months Ended 
  June 30, 
  2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$441
 $409
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization275
 481
 
 Provision for Deferred Income Taxes and ITC290
 79
 
 Non-Cash Employee Benefit Plan Costs36
 48
 
 Cost of Removal(74) (58) 
 Change in Accrued Storm Costs(1) 15
 
 Net Change in Other Regulatory Assets and Liabilities(124) (53) 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues50
 53
 
 Materials and Supplies(14) (10) 
 Prepayments(165) (162) 
 Accounts Payable(29) 48
 
 Accounts Receivable/Payable—Affiliated Companies, net181
 154
 
 Other Current Assets and Liabilities17
 (27) 
 Employee Benefit Plan Funding and Related Payments(62) (55) 
 Other(13) (13) 
 Net Cash Provided By (Used In) Operating Activities808
 909
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(1,355) (1,230) 
 Proceeds from Sales of Available-for-Sale Securities12
 12
 
 Investments in Available-for-Sale Securities(13) (14) 
 Other2
 12
 
 Net Cash Provided By (Used In) Investing Activities(1,354) (1,220) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt(153) —
 
 Issuance of Long-Term Debt850
 600
 
 Redemption of Long-Term Debt(171) (300) 
 Redemption of Securitization Debt—
 (125) 
 Other(10) (8) 
 Net Cash Provided By (Used In) Financing Activities516
 167
 
 Net Increase (Decrease) In Cash and Cash Equivalents(30) (144) 
 Cash and Cash Equivalents at Beginning of Period198
 310
 
 Cash and Cash Equivalents at End of Period$168
 $166
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(255) $(74) 
 Interest Paid, Net of Amounts Capitalized$134
 $131
 
 Accrued Property, Plant and Equipment Expenditures$381
 $282
 
      
      
  Nine Months Ended 
  September 30, 
  2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$696
 $631
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization412
 712
 
 Provision for Deferred Income Taxes and ITC482
 96
 
 Non-Cash Employee Benefit Plan Costs55
 71
 
 Cost of Removal(109) (82) 
 Change in Accrued Storm Costs(6) 15
 
 Net Change in Other Regulatory Assets and Liabilities(66) 26
 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues2
 30
 
 Materials and Supplies(42) (13) 
 Prepayments(63) (67) 
 Accounts Payable(30) 34
 
 Accounts Receivable/Payable—Affiliated Companies, net154
 190
 
 Other Current Assets and Liabilities(6) (18) 
 Employee Benefit Plan Funding and Related Payments(64) (72) 
 Other(14) (35) 
 Net Cash Provided By (Used In) Operating Activities1,401
 1,518
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(2,035) (1,946) 
 Proceeds from Sales of Available-for-Sale Securities16
 16
 
 Investments in Available-for-Sale Securities(17) (18) 
 Other6
 13
 
 Net Cash Provided By (Used In) Investing Activities(2,030) (1,935) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt(153) 20
 
 Issuance of Long-Term Debt1,275
 600
 
 Redemption of Long-Term Debt(271) (300) 
 Redemption of Securitization Debt—
 (191) 
 Other(14) (8) 
 Net Cash Provided By (Used In) Financing Activities837
 121
 
 Net Increase (Decrease) In Cash and Cash Equivalents208
 (296) 
 Cash and Cash Equivalents at Beginning of Period198
 310
 
 Cash and Cash Equivalents at End of Period$406
 $14
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(279) $(29) 
 Interest Paid, Net of Amounts Capitalized$194
 $186
 
 Accrued Property, Plant and Equipment Expenditures$404
 $251
 
      
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 Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
 OPERATING REVENUES$714
 $1,025
 $2,027
 $2,750
 
 OPERATING EXPENSES        
 Energy Costs381
 409
 1,019
 1,302
 
 Operation and Maintenance265
 313
 518
 485
 
 Depreciation and Amortization80
 75
 159
 151
 
 Total Operating Expenses726
 797
 1,696
 1,938
 
 OPERATING INCOME (LOSS)(12) 228
 331
 812
 
 Income from Equity Method Investments4
 5
 6
 8
 
 Other Income25
 55
 51
 84
 
 Other Deductions(9) (7) (27) (18) 
 Other-Than-Temporary Impairments(10) (10) (20) (15) 
 Interest Expense(20) (33) (42) (64) 
 INCOME (LOSS) BEFORE INCOME TAXES(22) 238
 299
 807
 
 Income Tax Benefit (Expense)11
 (72) (118) (306) 
 NET INCOME (LOSS)$(11) $166
 $181
 $501
 
      

   
          
 
Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
 OPERATING REVENUES$1,075
 $1,096
 $3,102
 $3,846
 
 OPERATING EXPENSES        
 Energy Costs462
 367
 1,481
 1,669
 
 Operation and Maintenance289
 263
 807
 748
 
 Depreciation and Amortization86
 75
 245
 226
 
 Total Operating Expenses837
 705
 2,533
 2,643
 
 OPERATING INCOME238
 391
 569
 1,203
 
 Income from Equity Method Investments3
 3
 9
 11
 
 Other Income23
 25
 74
 109
 
 Other Deductions(6) (14) (33) (32) 
 Other-Than-Temporary Impairments(5) (30) (25) (45) 
 Interest Expense(24) (30) (66) (94) 
 INCOME BEFORE INCOME TAXES229
 345
 528
 1,152
 
 Income Tax Benefit (Expense)(90) (139) (208) (445) 
 NET INCOME$139
 $206
 $320
 $707
 
      

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


11

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

          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
 NET INCOME (LOSS)$(11) $166
 $181
 $501
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(9), $14, $(25) and $1 for the three and six months ended 2016 and 2015, respectively9
 (14) 25
 —
 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $0 and $7 for the three and six months ended 2016 and 2015, respectively—
 —
 —
 (9) 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(5), $(10) and $(10) for the three and six months ended 2016 and 2015, respectively7
 7
 14
 14
 
 Other Comprehensive Income (Loss), net of tax16
 (7) 39
 5
 
 COMPREHENSIVE INCOME$5
 $159
 $220
 $506
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
 NET INCOME$139
 $206
 $320
 $707
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(23), $32, $(48) and $33 for the three and nine months ended 2016 and 2015, respectively22
 (29) 47
 (29) 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $(1), $0 and $6 for the three and nine months ended 2016 and 2015, respectively—
 —
 —
 (9) 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(5), $(15) and $(15) for the three and nine months ended 2016 and 2015, respectively7
 7
 21
 21
 
 Other Comprehensive Income (Loss), net of tax29
 (22) 68
 (17) 
 COMPREHENSIVE INCOME$168
 $184
 $388
 $690
 
          
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.


12

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PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  June 30,
2016		 December 31,
2015		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$16
 $12
 
 Accounts Receivable202
 217
 
 Accounts Receivable—Affiliated Companies94
 276
 
 Short-Term Loan to Affiliate1,335
 363
 
 Fuel351
 463
 
 Materials and Supplies, net389
 363
 
 Derivative Contracts150
 223
 
 Prepayments7
 25
 
 Other4
 7
 
 Total Current Assets2,548
 1,949
 
 PROPERTY, PLANT AND EQUIPMENT11,969
 11,354
 
 Less: Accumulated Depreciation and Amortization(3,491) (3,227) 
 Net Property, Plant and Equipment8,478
 8,127
 
 NONCURRENT ASSETS    
 NDT Fund1,797
 1,754
 
 Long-Term Investments112
 119
 
 Goodwill16
 16
 
 Other Intangibles131
 102
 
 Other Special Funds60
 55
 
 Derivative Contracts76
 77
 
 Other60
 51
 
 Total Noncurrent Assets2,252
 2,174
 
 TOTAL ASSETS$13,278
 $12,250
 
      
      
  September 30,
2016		 December 31,
2015		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$12
 $12
 
 Accounts Receivable174
 217
 
 Accounts Receivable—Affiliated Companies126
 276
 
 Short-Term Loan to Affiliate514
 363
 
 Fuel366
 463
 
 Materials and Supplies, net399
 363
 
 Derivative Contracts149
 223
 
 Prepayments16
 25
 
 Other3
 7
 
 Total Current Assets1,759
 1,949
 
 PROPERTY, PLANT AND EQUIPMENT12,271
 11,354
 
 Less: Accumulated Depreciation and Amortization(3,564) (3,227) 
 Net Property, Plant and Equipment8,707
 8,127
 
 NONCURRENT ASSETS    
 NDT Fund1,857
 1,754
 
 Long-Term Investments106
 119
 
 Goodwill16
 16
 
 Other Intangibles154
 102
 
 Other Special Funds60
 55
 
 Derivative Contracts86
 77
 
 Other65
 51
 
 Total Noncurrent Assets2,344
 2,174
 
 TOTAL ASSETS$12,810
 $12,250
 
      
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)

      
  June 30,
2016		 December 31,
2015		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$553
 $553
 
 Accounts Payable466
 432
 
 Accounts Payable—Affiliated Companies102
 33
 
 Derivative Contracts17
 76
 
 Accrued Interest29
 25
 
 Other96
 107
 
 Total Current Liabilities1,263
 1,226
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC2,418
 2,347
 
 Asset Retirement Obligations470
 457
 
 OPEB Costs234
 230
 
 Derivative Contracts14
 16
 
 Accrued Pension Costs151
 166
 
 Long-Term Accrued Taxes22
 35
 
 Other104
 87
 
 Total Noncurrent Liabilities3,413
 3,338
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

 

 
 LONG-TERM DEBT2,380
 1,684
 
 MEMBER’S EQUITY
   
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings5,195
 5,014
 
 Accumulated Other Comprehensive Loss(201) (240) 
 Total Member’s Equity6,222
 6,002
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$13,278
 $12,250
 
      
      
  September 30,
2016		 December 31,
2015		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$—
 $553
 
 Accounts Payable477
 432
 
 Accounts Payable—Affiliated Companies156
 33
 
 Derivative Contracts36
 76
 
 Accrued Interest43
 25
 
 Other82
 107
 
 Total Current Liabilities794
 1,226
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC2,375
 2,347
 
 Asset Retirement Obligations485
 457
 
 OPEB Costs238
 230
 
 Derivative Contracts13
 16
 
 Accrued Pension Costs143
 166
 
 Long-Term Accrued Taxes79
 35
 
 Other162
 87
 
 Total Noncurrent Liabilities3,495
 3,338
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 LONG-TERM DEBT2,381
 1,684
 
 MEMBER’S EQUITY
   
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings5,084
 5,014
 
 Accumulated Other Comprehensive Loss(172) (240) 
 Total Member’s Equity6,140
 6,002
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$12,810
 $12,250
 
      
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)

      
  Six Months Ended 
  June 30, 
  2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$181
 $501
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization159
 151
 
 Amortization of Nuclear Fuel105
 106
 
 Provision for Deferred Income Taxes and ITC37
 64
 
 Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives153
 (9) 
 Non-Cash Employee Benefit Plan Costs19
 24
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(2) (21) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies86
 209
 
 Margin Deposit(46) 69

 Accounts Receivable(12) 76
 
 Accounts Payable(10) (62) 
 Accounts Receivable/Payable—Affiliated Companies, net179
 123
 
 Other Current Assets and Liabilities11
 (21) 
 Employee Benefit Plan Funding and Related Payments(10) (7) 
 Other67
 89
 
 Net Cash Provided By (Used In) Operating Activities917
 1,292
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(598) (487) 
 Proceeds from Sales of Available-for-Sale Securities346
 837
 
 Investments in Available-for-Sale Securities(359) (854) 
 Short-Term Loan—Affiliated Company, net(972) (366) 
 Other(24) (17) 
 Net Cash Provided By (Used In) Investing Activities(1,607) (887) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Issuance of Long-Term Debt700
 —
 
 Cash Dividend Paid—
 (400) 
 Other(6) (2) 
 Net Cash Provided By (Used In) Financing Activities694
 (402) 
 Net Increase (Decrease) in Cash and Cash Equivalents4
 3
 
 Cash and Cash Equivalents at Beginning of Period12
 9
 
 Cash and Cash Equivalents at End of Period$16
 $12
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(53) $218
 
 Interest Paid, Net of Amounts Capitalized$38
 $62
 
 Accrued Property, Plant and Equipment Expenditures$132
 $42
 
      
      
  Nine Months Ended 
  September 30, 
  2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$320
 $707
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization245
 226
 
 Amortization of Nuclear Fuel154
 162
 
 Provision for Deferred Income Taxes and ITC(34) 109
 
 Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives96
 (87) 
 Impairment Costs102
 —
 
 Non-Cash Employee Benefit Plan Costs28
 36
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(12) (2) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies(27) 113
 
 Margin Deposit(4) 142

 Accounts Receivable(11) 54
 
 Accounts Payable(29) (99) 
 Accounts Receivable/Payable—Affiliated Companies, net235
 115
 
 Other Current Assets and Liabilities20
 (26) 
 Employee Benefit Plan Funding and Related Payments(10) (9) 
 Other187
 117
 
 Net Cash Provided By (Used In) Operating Activities1,260
 1,558
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(923) (797) 
 Proceeds from Sales of Available-for-Sale Securities490
 1,057
 
 Investments in Available-for-Sale Securities(512) (1,083) 
 Short-Term Loan—Affiliated Company, net(151) (281) 
 Other(55) (46) 
 Net Cash Provided By (Used In) Investing Activities(1,151) (1,150) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Issuance of Long-Term Debt700
 —
 
 Cash Dividend Paid(250) (400) 
 Redemption of Long-Term Debt(553) —
 
 Other(6) (2) 
 Net Cash Provided By (Used In) Financing Activities(109) (402) 
 Net Increase (Decrease) in Cash and Cash Equivalents—
 6
 
 Cash and Cash Equivalents at Beginning of Period12
 9
 
 Cash and Cash Equivalents at End of Period$12
 $15
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(7) $284
 
 Interest Paid, Net of Amounts Capitalized$51
 $76
 
 Accrued Property, Plant and Equipment Expenditures$175
 $70
 
      
See disclosures regarding PSEG Power LLC included in the Notes to the Condensed Consolidated Financial Statements.


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Note 1. Organization and Basis of Presentation
Organization
PSEGPublic Service Enterprise Group (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&GPublic Service Electric and Gas Company (PSE&G)—which is a 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 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.
PSEG Power LLC (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 transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
PSEG'sPSEG’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 operates the Long Island Power Authority'sAuthority’s (LIPA) transmission and distribution (T&D) system under an 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 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, 2015.
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 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, 2015.

Note 2. Recent Accounting Standards
New Standards Issued But Not Yet Adopted
Revenue from Contracts with Customers
This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides 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 standard was originally to be effective for annual and interim reporting periods beginning after December 15, 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 will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements.statementsand disclosures as well as the transition method to use to adopt the guidance. PSEG is considering the impacts of outstanding industry related issues currently being addressed by the AICPA’s Revenue Recognition Working Group and the FASB’s Transition Resource Group, including its ability to recognize revenue for

16

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certain contracts where there is uncertainty regarding collection, bundled price sales contracts and accounting for contributions in aid of construction.
Recognition and Measurement of Financial Assets and Financial Liabilities
This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures.
The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (NDT) and Rabbi Trust Funds.
Leases
This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.
The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements.
Stock Compensation-Improvements to Employee Share-Based Payment Accounting
This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.
Under the new guidance, all excess tax benefits and tax deficiencies will be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award.
The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. PSEG is currently analyzingevaluating early adoption of the impactstandard in the fourth quarter of this standard on2016; however, PSEG does not expect adoption to materially affect its financial statements.
Measurement of Credit Losses on Financial Instruments
This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination.
The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements.


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Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments
This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows.
The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements.

Note 3. Early Plant Retirements
On October 3, 2016, Power determined that it will cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Power expects the units to continue to be available to generate electricity and receive previously cleared capacity payments through the date the units cease operations. The exact timing of the early retirement of these units will be reviewed for reliability impacts by PJM, the regional transmission organization that controls the area where these units are located, and may be impacted by operational and other conditions that could subsequently arise. 
PSEG and Power undertake their annual five year strategic planning process primarily during the third and fourth quarters of each year. The primary factors considered during this process that contributed to the decision to retire these units early include significant declines in revenues and margin caused by a sustained period of depressed wholesale power prices and reduced capacity factors caused by lower natural gas prices making coal generation less economically competitive than natural gas-fired generation. Despite experiencing recent warmer than normal weather in PJM this summer, Power did not experience the usual increase in electricity prices in PJM as it had in past hot summers. This trend has a further adverse economic impact to these units because they generally dispatch and earn energy margin on peak hot and cold days. In addition, the upcoming PJM capacity auction in May 2017 for the capacity period from June 2020 to May 2021 will be the first to require all generating units to meet the increased operating performance standards of PJM’s new capacity performance regulations. During the current annual five-year strategic planning process, Power determined, on October 3, 2016, that the costs to upgrade the existing units at the Hudson and Mercer stations to comply with these higher reliability standards to be too significant and not economic given current market conditions, including anticipated future capacity prices, current forward energy prices and past operational performance results of the units. While these units have the capability to run on both coal and natural gas, they have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units.
The decision to retire the Hudson and Mercer units early will have a material effect on PSEG’s and Power’s results of operations. In the third quarter of 2016, PSEG and Power recognized the following one-time pre-tax charges in Energy Costs, Operation and Maintenance and Depreciation expense:
    
  Three Months Ended September 30, 
  2016 
  Millions 
 Statement of Operations Expense (pre-tax)  
 Energy Costs  
 Coal Inventory Lower of Cost or Market Adjustments and Capacity Penalties$62
 
 Operation and Maintenance  
     Materials and Supplies Obsolescence31
 
     Write-down of Construction Work in Progress14
 
     Other (A)3
 
 Depreciation and Amortization  
 Accelerated Depreciation including Asset Retirement Costs4
 
 Total Pre-Tax Expense$114
 
    
(A)Includes severance and miscellaneous costs.
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In addition to these one-time charges, Power will recognize incremental Depreciation and Amortization during the remainder of 2016 of $568 million and $946 million into 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. Additional employee-related salary continuance and severance costs and various miscellaneous costs may also be incurred during the period prior to retirement. Finally, Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at these sites would trigger investigation and possible remediation of identified environmental contamination. The amounts for any such environmental investigation or remediation are neither currently probable nor estimable but may be material.
PSEG and Power evaluate long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, including a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. As disclosed for Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives or that meet the normal purchases and normal sales exemption. An impairment would result in a reduction of the value of the long-lived asset/asset group through a noncash charge to earnings.
Because the Hudson and Mercer generating units will cease operations significantly before the end of their previously estimated useful lives, Power performed a recoverability test for its portfolio of generating assets in the PJM region to determine if an impairment exists. As of September 30, 2016, the estimated undiscounted future cash flows of the PJM asset group exceeded the carrying amount and no impairment was identified.
In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone, Conemaugh and Bridgeport Harbor generating stations, to ensure their economic viability through the end of their designated useful lives. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement of our other coal units before the end of their current estimated useful lives may have a material adverse impact on PSEG’s and Power’s future financial results.

Note 4. Variable Interest Entities (VIEs)
VIEs 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 was pledged as collateral to a trustee. PSE&G acted as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds were remitted to Transition Funding and Transition Funding II and were used for interest and principal payments on the transition bonds and related costs. During 2015, Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained with these VIEs. Effective January 1, 2016, PSE&G commenced refunding the overcollections from customers associated with these VIEs and expects to fully refund these liabilities in 2016.
VIE 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'sLIPA’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'sServco’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'sServco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI'sLI’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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents

fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco'sServco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.
For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operation and Maintenance (O&M) Expense, respectively. Servco recorded $101$116 million and $84$96 million for the three months and $199$315 million and $166$262 million for the sixnine months ended JuneSeptember 30, 2016 and 2015, 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'sPSEG’s Condensed Consolidated Statement of Operations.

Note 4.5. Rate Filings
This Note should be read in conjunction with Note 5. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.
In addition to items previously reported in the Annual Report on Form 10-K, significant regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:
Remediation Adjustment Charge (RAC)—In April 2016, the BPU approved PSE&G's filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015.
Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June 2016, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million, respectively. The petition requests rates to be effective September 1, 2016, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.
Basic Gas Supply Service (BGSS)—In June 2016, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $87 million in annual BGSS revenues. If approved, the BGSS rate would be reduced from approximately 40 cents to 34 cents per therm effective October 1, 2016. This matter is pending.

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Transmission Formula Rate Filings—In June 2016, PSE&G filed its 2015 true-up adjustment pertaining to its transmission formula rates in effect for 2015. This resulted in an adjustment of $34 million less than the 2015 originally filed revenues primarily due to the impact of bonus depreciation legislation enacted after PSE&G filed its 2015 formula rate requirement in October 2014. PSE&G had recognized the majority of this adjustment in its Consolidated Statement of Operations for the year ended December 31, 2015.
In October 2016, the 2017 Annual Formula Rate Update was filed with FERC and requests approximately $121 million in increased annual transmission revenues effective January 1, 2017, subject to true-up.
Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June 2016, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million, respectively. In August 2016, the BPU approved these rate increases effective September 1, 2016.
In September 2016, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2016 through November 30, 2016. The petition requests rates to be effective March 1, 2017, consistent with the BPU Order of approval of the Energy Strong Program. The annualized requested increase in electric revenue requirement is approximately $15 million. This matter is pending.
Basic Gas Supply Service (BGSS)—In June 2016, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $87 million in annual BGSS revenues. In September 2016, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 40 cents to 34 cents per therm effective October 1, 2016. The rate is subject to final settlement.
Weather Normalization Clause—On July 1, 2016, PSE&G filed a petition requesting approval to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period. The deficiency gas revenues would be collected from customers over the 2016-2017 and 2017-2018 Winter Periods (October 1 through May 31). This matter is pending.In September 2016, the BPU approved PSE&G’s filing on a provisional basis with respect to the $54 million in deficiency revenues to be collected from customers effective October 1, 2016.
Solar and Energy Efficiency - Green Program Recovery Charges (GPRC)—Each year PSE&G files with the BPU for annual recovery of its Green Program investments which include a return on its investment and recovery of expenses. On July 1, 2016, PSE&G filed its 2016 GPRC cost recovery petition requesting recovery for the nine combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2016 through September 30, 2017 designed to recover approximately $44 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's&G’s implementation of these BPU approved programs. This matter is pending.In September 2016, the BPU approved the July 2016 filing on a provisional basis, with new rates effective October 1, 2016.
Gas System Modernization Program (GSMP)—On July 29,In October 2016, PSE&G filedupdated its initial annual GSMP cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $13$10 million effective
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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January 1, 2017. This increase represents the return of and on investment for GSMP investments expected to be in service through September 30, 2016. This request will be updatedmatter is pending.  
Universal Service Fund (USF)/Lifeline—In September 2016, the BPU approved rates set to recover state-wide costs incurred by New Jersey electric and gas distribution companies under the State’s USF/Lifeline energy assistance programs effective October 1, 2016. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in Octoberno impact on its Consolidated Statement of Operations.
Remediation Adjustment Charge (RAC)—In April 2016, for actual costs.  the BPU approved PSE&G’s filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015.
        
Note 5.6. 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'sPSEG’s and PSE&G's&G’s Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”
       
 Outstanding Loans by Class of Customer 
   As of As of 
 Consumer Loans June 30,
2016		 December 31,
2015		 
   Millions 
 Commercial/Industrial $174
 $177
 
 Residential 12
 12
 
 Total $186
 $189
 
       
       
 Outstanding Loans by Class of Customer 
   As of As of 
 Consumer Loans September 30,
2016		 December 31,
2015		 
   Millions 
 Commercial/Industrial $165
 $177
 
 Residential 11
 12
 
 Total $176
 $189
 
       
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. 
During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016, calculated by comparing the gross investment in the leases before and after the revised residual estimates.

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The following table shows Energy Holdings’ gross and net lease investment as of JuneSeptember 30, 2016 and December 31, 2015, respectively.
      
  As of As of 
  June 30,
2016		 December 31,
2015		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$630
 $631
 
 Estimated Residual Value of Leased Assets519
 519
 
 Total Investment in Rental Receivables1,149
 1,150
 
 Unearned and Deferred Income(359) (366) 
 Gross Investment in Leases790
 784
 
 Deferred Tax Liabilities(694) (724) 
 Net Investment in Leases$96
 $60
 
      
      
  As of As of 
  September 30,
2016		 December 31,
2015		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$630
 $631
 
 Estimated Residual Value of Leased Assets346
 519
 
 Total Investment in Rental Receivables976
 1,150
 
 Unearned and Deferred Income(320) (366) 
 Gross Investment in Leases656
 784
 
 Deferred Tax Liabilities(661) (724) 
 Net Investment in Leases$(5) $60
 
      
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.
     
   
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating Standard & Poor's (S&P) as of June 30, 2016   
  As of June 30, 2016 
   Millions 
 AA $16
 
 BBB+ — BBB- 316
 
 BB- 134
 
 CCC 164
 
 Total $630
 
     
     
   
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating Standard & Poor’s (S&P) as of September 30, 2016   
  As of September 30, 2016 
   Millions 
 AA $16
 
 BBB+ — BBB- 316
 
 BB- 134
 
 CCC 164
 
 Total $630
 
     
The “BB-” and the "CCC"“CCC” ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of JuneSeptember 30, 2016, the gross investment in the leases of such assets, net of non-recourse debt, was $573436 million ($(5)(108) million, net of deferred taxes). A more detailed description of such assets under lease, as of JuneSeptember 30, 2016, is presented in the following table.
                 
 Asset Location 
Gross
Investment
 
%
Owned
 Total MW 
Fuel
Type
 
Counterparties’
S&P Credit
Ratings
 Counterparty 
     Millions           
 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 (A) BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $121
 17% 1,711
 Coal CCC (C) NRG REMA, LLC 
 Conemaugh Station Units 1 and 2 PA $121
 17% 1,711
 Coal CCC (C) NRG REMA, LLC 
 Shawville Station Units 1, 2, 3 and 4 PA $113
 100% 603
 Coal (B) CCC (C) NRG REMA, LLC 
                 
                 
 Asset Location 
Gross
Investment
 
%
Owned
 Total MW 
Fuel
Type
 
Counterparties’
S&P Credit
Ratings
 Counterparty 
     Millions           
 Powerton Station Units 5 and 6 IL $134
 64% 1,538
 Coal BB- NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $83
 64% 1,044
 Gas BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $55
 17% 1,711
 Coal CCC (B) REMA 
 Conemaugh Station Units 1 and 2 PA $55
 17% 1,711
 Coal CCC (B) REMA 
 Shawville Station Units 1, 2, 3 and 4 PA $109
 100% 603
 Coal (A) CCC (B) REMA 
                 
(A)The Joliet facility is currently in the process of converting to natural gas.

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(B)NRG REMA LLC (NRG REMA) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the late fall of 2016 with the ability to use natural gas.
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(C)(B)On May 24, 2016, S&P lowered its corporate credit rating on REMA’s parent company, GenOn Energy Inc. (GenOn) and affiliates (including NRG REMA) to "CCC"“CCC” from "CCC+"“CCC+” due to a weaker forward power curve, milder weather patterns and weakening financial measures. PSEG continuesOn October 7, 2016, Moody’s downgraded the GenOn Corporate Family Rating to monitor any changesCaa3 to GenOn's status and potential impacts on Energy Holdings' lease investments.reflect its high debt burden relative to cash flow. GenOn reported in August 2016 that it did not expect to have sufficient liquidity to repay the senior unsecured notes due in June 2017.
The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and attempt to seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital investments and trigger certain material tax obligations which could be mitigated by tax indemnification claims with the counterparty. A bankruptcy of a lessee would likely delay and potentially limit 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. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. 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.
Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.

Note 6.7. Available-for-Sale Securities
NDT Fund
Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisers who operate under investment guidelines developed by Power.
Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.
          
  As of June 30, 2016 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$679
 $198
 $(12) $865
 
 Debt Securities        
 Government Obligations503
 23
 —
 526
 
 Other348
 12
 (3) 357
 
 Total Debt Securities851
 35
 (3) 883
 
 Other Securities49
 —
 —
 49
 
 Total NDT Available-for-Sale Securities$1,579
 $233
 $(15) $1,797
 
          
          
  As of September 30, 2016 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$691
 $238
 $(7) $922
 
 Debt Securities        
 Government Obligations509
 21
 —
 530
 
 Other349
 13
 (2) 360
 
 Total Debt Securities858
 34
 (2) 890
 
 Other Securities45
 —
 —
 45
 
 Total NDT Available-for-Sale Securities$1,594
 $272
 $(9) $1,857
 
          

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  As of December 31, 2015 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$693
 $185
 $(13) $865
 
 Debt Securities        
 Government Obligations483
 8
 (3) 488
 
 Other366
 3
 (10) 359
 
 Total Debt Securities849
 11
 (13) 847
 
 Other Securities42
 —
 —
 42
 
 Total NDT Available-for-Sale Securities$1,584
 $196
 $(26) $1,754
 
          
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 
  June 30,
2016		 December 31,
2015		 
  Millions 
 Accounts Receivable$18
 $17
 
 Accounts Payable$10
 $10
 
      
      
  As of As of 
  September 30,
2016		 December 31,
2015		 
  Millions 
 Accounts Receivable$9
 $17
 
 Accounts Payable$7
 $10
 
      

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 June 30, 2016 As of December 31, 2015 
  
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)$108
 $(12) $5
 $—
 $151
 $(13) $1
 $—
 
 Debt Securities                
 Government Obligations (B)12
 —
 6
 —
 245
 (2) 19
 (1) 
 Other (C)12
 —
 43
 (3) 222
 (7) 36
 (3) 
 Total Debt Securities24
 —
 49
 (3) 467
 (9) 55
 (4) 
 NDT Available-for-Sale Securities$132
 $(12) $54
 $(3) $618
 $(22) $56
 $(4) 
                  
                  
  As of September 30, 2016 As of December 31, 2015 
  
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)$101
 $(6) $4
 $(1) $151
 $(13) $1
 $—
 
 Debt Securities                
 Government Obligations (B)41
 —
 4
 —
 245
 (2) 19
 (1) 
 Other (C)34
 —
 25
 (2) 222
 (7) 36
 (3) 
 Total Debt Securities75
 —
 29
 (2) 467
 (9) 55
 (4) 
 NDT Available-for-Sale Securities$176
 $(6) $33
 $(3) $618
 $(22) $56
 $(4) 
                  
(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 JuneSeptember 30, 2016.
(B)Debt Securities (Government Obligations)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. 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

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more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of JuneSeptember 30, 2016.
(C)Debt Securities (Other)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of JuneSeptember 30, 2016.
The proceeds from the sales of and the net realized gains on securities in the NDT Fund were:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
  Millions 
 Proceeds from NDT Fund Sales (A)$154
 $232
 $331
 $822
 
 Net Realized Gains (Losses) on NDT Fund:        
 Gross Realized Gains10
 14
 25
 33
 
 Gross Realized Losses(6) (4) (22) (13) 
 Net Realized Gains (Losses) on NDT Fund$4
 $10
 $3
 $20
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
  Millions 
 Proceeds from NDT Fund Sales (A)$139
 $215
 $470
 $1,037
 
 Net Realized Gains (Losses) on NDT Fund:        
 Gross Realized Gains$11
 $14
 $36
 $47
 
 Gross Realized Losses(3) (11) (25) (24) 
 Net Realized Gains (Losses) on NDT Fund$8
 $3
 $11
 $23
 
          
(A)2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers.
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 $110131 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG'sPSEG’s and Power’s Condensed Consolidated Balance Sheets as of JuneSeptember 30, 2016.

The NDT available-for-sale debt securities held as of JuneSeptember 30, 2016 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $19
 
 1 - 5 years 216
 
 6 - 10 years 220
 
 11 - 15 years 54
 
 16 - 20 years 61
 
 Over 20 years 313
 
 Total NDT Available-for-Sale Debt Securities$883
 
     
     
 Time Frame Fair Value 
   Millions 
 Less than one year $22
 
 1 - 5 years 233
 
 6 - 10 years 214
 
 11 - 15 years 56
 
 16 - 20 years 62
 
 Over 20 years 303
 
 Total NDT Available-for-Sale Debt Securities$890
 
     
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 sixnine months ended JuneSeptember 30, 2016, other-than-temporary impairments of $2025 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.

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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 June 30, 2016 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$11
 $10
 $—
 $21
 
 Debt Securities        
 Government Obligations104
 2
 —
 106
 
 Other90
 1
 (1) 90
 
 Total Debt Securities194
 3
 (1) 196
 
 Other Securities5
 —
 —
 5
 
 Total Rabbi Trust Available-for-Sale Securities$210
 $13
 $(1) $222
 
          
          
  As of September 30, 2016 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$11
 $11
 $—
 $22
 
 Debt Securities        
 Government Obligations104
 3
 —
 107
 
 Other91
 3
 —
 94
 
 Total Debt Securities195
 6
 —
 201
 
 Other Securities1
 —
 —
 1
 
 Total Rabbi Trust Available-for-Sale Securities$207
 $17
 $—
 $224
 
          
          
  As of December 31, 2015 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$12
 $10
 $—
 $22
 
 Debt Securities        
 Government Obligations108
 1
 (1) 108
 
 Other82
 —
 (1) 81
 
 Total Debt Securities190
 1
 (2) 189
 
 Other Securities2
 —
 —
 2
 
 Total Rabbi Trust Available-for-Sale Securities$204
 $11
 $(2) $213
 
          
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 
  June 30,
2016		 December 31,
2015		 
  Millions 
 Accounts Receivable$2
 $1
 
 Accounts Payable$4
 $—
 
      
      
  As of As of 
  September 30,
2016		 December 31,
2015		 
  Millions 
 Accounts Receivable$1
 $1
 
 Accounts Payable$—
 $—
 
      

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The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than and greater than 12 months.
                  
  As of June 30, 2016 As of December 31, 2015 
  
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)14
 —
 3
 —
 53
 (1) 2
 —
 
 Other (C)14
 —
 11
 (1) 46
 (1) 9
 —
 
 Total Debt Securities28
 —
 14
 (1) 99
 (2) 11
 —
 
 Rabbi Trust Available-for-Sale Securities$28
 $—
 $14
 $(1) $99
 $(2) $11
 $—
 
                  
                  
  As of September 30, 2016 As of December 31, 2015 
  
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)4
 —
 1
 —
 53
 (1) 2
 —
 
 Other (C)9
 —
 5
 —
 46
 (1) 9
 —
 
 Total Debt Securities13
 —
 6
 —
 99
 (2) 11
 —
 
 Rabbi Trust Available-for-Sale Securities$13
 $—
 $6
 $—
 $99
 $(2) $11
 $—
 
                  
(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 Obligations)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. 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 JuneSeptember 30, 2016.
(C)Debt Securities (Other)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of JuneSeptember 30, 2016.
The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
  Millions 
 Proceeds from Rabbi Trust Sales (A)$36
 $44
 $61
 $63
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$2
 $2
 $3
 $2
 
 Gross Realized Losses(1) —
 (2) —
 
 Net Realized Gains (Losses) on Rabbi Trust$1
 $2
 $1
 $2
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
  Millions 
 Proceeds from Rabbi Trust Sales$20
 $20
 $81
 $83
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$2
 $—
 $5
 $2
 
 Gross Realized Losses(2) (1) (4) (1) 
 Net Realized Gains (Losses) on Rabbi Trust$—
 $(1) $1
 $1
 
          
(A)2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers.
Gross realized gains disclosed in the preceding table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of $710 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of JuneSeptember 30, 2016.

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The Rabbi Trust available-for-sale debt securities held as of JuneSeptember 30, 2016 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $8
 
 1 - 5 years 45
 
 6 - 10 years 48
 
 11 - 15 years 6
 
 16 - 20 years 7
 
 Over 20 years 82
 
 Total Rabbi Trust Available-for-Sale Debt Securities$196
 
     
     
 Time Frame Fair Value 
   Millions 
 Less than one year $9
 
 1 - 5 years 42
 
 6 - 10 years 48
 
 11 - 15 years 9
 
 16 - 20 years 9
 
 Over 20 years 84
 
 Total Rabbi Trust Available-for-Sale Debt Securities$201
 
     
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). For the nine months ended September 30, 2016, no other-than-temporary impairments were recognized on securities in the Rabbi Trust. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
The fair value of assets in the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:
      
  As of As of 
  June 30,
2016		 December 31,
2015		 
  Millions 
 PSE&G$44
 $42
 
 Power54
 52
 
 Other124
 119
 
 Total Rabbi Trust Available-for-Sale Securities$222
 $213
 
      
      
  As of As of 
  September 30,
2016		 December 31,
2015		 
  Millions 
 PSE&G$44
 $42
 
 Power55
 52
 
 Other125
 119
 
 Total Rabbi Trust Available-for-Sale Securities$224
 $213
 
      

Note 7.8. 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.
Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change is being reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $8$9 million and $3 million, for the three months ended JuneSeptember 30, 2016, respectively, and $17$26 million and $6$9 million for the sixnine months ended JuneSeptember 30, 2016, respectively, as compared to the 2016 amounts that would have been derived from applying PSEG'sPSEG’s 2015 and prior years'years’ methodology.
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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.

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Pension and OPEB costsbasis for PSEG, except for Servco, are detailed as follows:Servco.
                  
  Pension Benefits OPEB Pension Benefits OPEB 
  Three Months Ended Three Months Ended Six Months Ended Six Months Ended 
  June 30, June 30, June 30, June 30, 
  2016
 2015 2016
 2015 2016 2015 2016 2015 
  Millions 
 Components of Net Periodic Benefit Costs                
 Service Cost$27
 $31
 $4
 $6
 $54
 $62
 $8
 $11
 
 Interest Cost51
 58
 14
 17
 101
 117
 29
 34
 
 Expected Return on Plan Assets(99) (104) (7) (8) (197) (207) (15) (15) 
 Amortization of Net                
 Prior Service Cost (Credit)(5) (4) (4) (4) (9) (9) (7) (7) 
 Actuarial Loss40
 37
 10
 11
 79
 74
 20
 21
 
 Total Benefit Costs$14
 $18
 $17
 $22
 $28
 $37
 $35
 $44
 
                  
                  
  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, 
  2016
 2015 2016
 2015 2016 2015 2016 2015 
  Millions 
 Components of Net Periodic Benefit Costs                
 Service Cost$28
 $30
 $5
 $5
 $82
 $92
 $13
 $16
 
 Interest Cost50
 59
 15
 16
 151
 176
 44
 50
 
 Expected Return on Plan Assets(98) (103) (8) (7) (295) (310) (23) (22) 
 Amortization of Net                
 Prior Service Cost (Credit)(5) (5) (4) (4) (14) (14) (11) (11) 
 Actuarial Loss39
 38
 10
 11
 118
 112
 30
 32
 
 Total Benefit Costs$14
 $19
 $18
 $21
 $42
 $56
 $53
 $65
 
                  
 
Pension and OPEB costs for 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 Six Months Ended Six Months Ended 
  June 30, June 30, June 30, June 30, 
  2016 2015 2016 2015 2016 2015 2016 2015 
  Millions 
 PSE&G$7
 $10
 $11
 $14
 $14
 $20
 $22
 $28
 
 Power4
 5
 5
 6
 8
 11
 11
 13
 
 Other3
 3
 1
 2
 6
 6
 2
 3
 
 Total Benefit Costs$14
 $18
 $17
 $22
 $28
 $37
 $35
 $44
 
                  
                  
  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, 
  2016 2015 2016 2015 2016 2015 2016 2015 
  Millions 
 PSE&G$8
 $10
 $11
 $13
 $22
 $30
 $33
 $41
 
 Power3
 5
 6
 7
 11
 16
 17
 20
 
 Other3
 4
 1
 1
 9
 10
 3
 4
 
 Total Benefit Costs$14
 $19
 $18
 $21
 $42
 $56
 $53
 $65
 
                  
During the three months ended March 31, 2016, PSEG contributed its entire planned contributions for the year 2016 of $21 million into its pension plans and $14 million into its OPEB plan.plan during 2016.
Servco Pension and OPEB
At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 3.4. Variable Interest 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. Servco plans to contributehas contributed its entire planned contribution of $28 million into its pension plan trusts during 2016. Servco'sServco’s pension-related revenues and costs were $6$16 million and $7$17 million for the three months ended JuneSeptember 30, 2016 and 2015, respectively, and $12$28 million and $13$30 million for the sixnine months ended JuneSeptember 30, 2016 and 2015, respectively. The OPEB-related revenues earned and costs incurred for each of the three months and sixnine months ended JuneSeptember 30, 2016 and 2015 were immaterial.


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Note 8.9. Commitments and Contingent Liabilities
Guaranteed Obligations
Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.
Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to
support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
obtain credit.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to
fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and
all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).
Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This currentCurrent exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Power is subject to
counterparty collateral calls related to commodity contracts, and
certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.

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The following table shows the face value of Power'sPower’s outstanding guarantees, current exposure and margin positions as of JuneSeptember 30, 2016 and December 31, 2015.
      
  As of As of 
  June 30,
2016		 December 31,
2015		 
  Millions 
 Face Value of Outstanding Guarantees$1,809
 $1,734
 
 Exposure under Current Guarantees$136
 $172
 
      
 Letters of Credit Margin Posted$160
 $122
 
 Letters of Credit Margin Received$130
 $192
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(4) $(15) 
    Net Broker Balance Deposited (Received)$30
 $(5) 
      
 Additional Amounts Posted:    
 Other Letters of Credit$51
 $51
 
      
      
  As of As of 
  September 30,
2016		 December 31,
2015		 
  Millions 
 Face Value of Outstanding Guarantees$1,797
 $1,734
 
 Exposure under Current Guarantees$143
 $172
 
      
 Letters of Credit Margin Posted$164
 $122
 
 Letters of Credit Margin Received$136
 $192
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(4) $(15) 
    Net Broker Balance Deposited (Received)$(12) $(5) 
      
 Additional Amounts Posted:    
 Other Letters of Credit$51
 $51
 
      
As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10.11. Financial Risk Management Activities for further discussion. In accordance with PSEG'sPSEG’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 addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power had posted letters of credit to support Power'sPower’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power'sPower’s payment obligations related to its equity interest in the PennEast natural gas pipeline and a $21 million guarantee to support Power'sPower’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.
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 “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 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 PSE&G and 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
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(UNAUDITED)
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miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the

29

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RI/FS among its members 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 are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is 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. PSEG has provided notice to insurers concerning this potential claim.
In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby 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 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.
In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than with respect to 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. Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power'sPower’s combined 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 contemplated the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS set forth various alternatives for remediating this portion of the Passaic River.
The CPG, which consisted of 5352 members as of JuneSeptember 30, 2016, 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 for the preparation of the RI/FS is approximately $163$167 million, which the CPG continues to incur. Of the estimated $163$167 million, as of JuneSeptember 30, 2016, the CPG had spent approximately $150$156 million, of which PSE&G's&G’s and Power'sPower’s combined share was approximately $11$10 million.
The CPG'sCPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set 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 on an undiscounted basis. 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 ranged from approximately $518 million to $772 million. Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G's&G’s and Power'sPower’s estimated 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.
In March 2016, the EPA released its Record of Decision (ROD) for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7 and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation.
Based upon the estimated cost of the ROD Remedy, PSEG'sPSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of JuneSeptember 30, 2016, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.
Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental ChemicalsChemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond
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Shamrock, willwould voluntarily perform the remedial design for the ROD Remedy. IfOn September 30, 2016, OCC and the EPA secures aexecuted an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the

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Remedial Design from OCC, remedial design, it is anticipated that the EPA plans towill begin negotiation of a remedial action consent decree, under which OCC and the other “major” PRPs“major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. "Major PRP" is undefined in the letter.The EPA has not defined “major PRP.”
On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG'sPSEG’s share of the costs.
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 PSE&G's&G’s and Power'sPower’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G's&G’s and Power’s respective shares 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 PSEG'sPSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs. 
Natural Resource Damage Claims
In 2003, the New 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 U.S. Department of Commerce and the U.S. 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. PSE&G and Power are unable to estimate their 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. PSE&G and Power are unable to estimate their respective 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 $426$424 million and $491$481 million through 2021, including its $46 million share for the Passaic River accrued as of JuneSeptember 30, 2016, as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $426$424 million as of JuneSeptember 30, 2016. Of this amount, $99$70 million was recorded in Other Current Liabilities and $327$354 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $426$424 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. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy. 

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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.
Clean Water Act Permit Renewals
Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.
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. Second 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.
On June 10, 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. On July 8, 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP'sNJDEP’s issuance of the final permit for Salem. The Riverkeeper'sRiverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the Clean Water Act. Such service water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants including 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, and could result in acceleration of decommissioning activities. 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 $1.0 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'sPower’s future capital requirements, financial condition or results of operations.
Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing

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intake structure and retire BH3 in 2021, which is four years earlier than the current estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in late 2016.
Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt
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(UNAUDITED)
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of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power will seek to operate BH3 through the current estimated useful life.
In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. Operations are expected to begin in mid-2019.
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'sstation’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter.
Jersey City, New Jersey Subsurface Feeder Cable Matter
In early October 2016, a discharge of mineral oil dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the New Jersey Department of Environmental Protection (NJDEP). The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order; and to restore the property. The U.S. Coast Guard has issued Notices of Federal Interest for an Oil Pollution Incident, to the property owners, PSE&G and Con Edison, and the NJDEP has issued a Field Directive to both PSE&G and Con Edison. The investigation and response actions related to the fluid discharge are ongoing. The investigation of the discharge and its potential cause is in the preliminary stages, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC; however, based on currently available information and the potential scope of the necessary repair and remediation work, the costs could be material.   
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 andPower’s Bridgeport Harbor stationsstation and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and 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'sPower’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 choose not to purchase electric supply from third party suppliers. The first category, which represents about 80% of PSE&G's&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy 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 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
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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, 2016 is $335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

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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  
  2013 2014 2015 2016  
 36-Month Terms EndingMay 2016
 May 2017
 May 2018
 May 2019
(A)  
 Load (MW)2,800
 2,800
 2,900
 2,800
   
 $ per MWh$92.18 $97.39 $99.54 $96.38   
           
(A)Prices set in the 2016 BGS auction year became effective on June 1, 2016 when the 2013 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 a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 17.18. 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, enrichment and fabrication requirements through 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom.
Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G's&G’s customers, Power can use the gas to supply its fossil generating stations.
Power also has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations.
As of JuneSeptember 30, 2016,, the total minimum purchase requirements included in these commitments were as follows:
     
 Fuel Type Power's Share of Commitments through 2020 
   Millions 
 Nuclear Fuel   
 Uranium $454
 
 Enrichment $358
 
 Fabrication $180
 
 Natural Gas $972
 
 Coal $265
 
     
     
 Fuel Type Power's Share of Commitments through 2020 
   Millions 
 Nuclear Fuel   
 Uranium $338
 
 Enrichment $307
 
 Fabrication $179
 
 Natural Gas $904
 
 Coal $235
 
     
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(UNAUDITED)
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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. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional

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pricing errors in the bids were identified. 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 FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power continues to implement procedures to help mitigate the risk of similar issues occurring in the future.
During the three month period 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. No additional charges to income have been recorded for this matter since that time.
Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has responded to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC'sFERC’s response to PSEG'sPSEG’s legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.
PSEG is unable to reasonably estimate the range of possible loss for this matter; however, the amounts of potential disgorgement and other potential penalties that Power may incur span a wide range depending on the success of PSEG'sPSEG’s legal arguments. These arguments include that Power’s energy market bids in a substantial majority of the hours were below the allowed rate under the Tariff and therefore any errors in those hours were immaterial and that it is unclear whether the quantity of the bids violated any legal requirement. If PSEG'sPSEG’s legal arguments do not prevail in whole or in part with FERC or in a judicial challenge that PSEG may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to PSEG’s and Power’s Consolidated Statements of Operations in the quarterly and annual periods in which they are recorded.
Nuclear Insurance Coverages
The following should be read in conjunction with Note 12. Commitments and Contingent Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.
Based upon a review of its nuclear insurance, Power made changes to its Nuclear Electric Insurance Limited (NEIL) insurance coverage of the excess layer for property damage which became effective on April 1, 2016. The excess layer provides coverage above the primary layer of NEIL insurance coverage for property damage of $1.5 billion. For the excess layer at the Salem/Hope Creek site, Power purchased coverage for property damage of $300 million due to a nuclear event and $300 million due to a non-nuclear event. For the excess layer at the Peach Bottom site, Power purchased coverage for its ownership interest for property damage of $300 million due to a nuclear event. For the excess layer at the Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ownership interest of Power. 

Note 9.10. Debt and Credit Facilities
Long-Term Debt Financing Transactions
The following long-term debt transactions occurred in the sixnine months ended JuneSeptember 30, 2016:
PSE&G
issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021,
issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046, and
issued $425 million of 2.25% Secured Medium-Term Notes, Series L due September 2026,
retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds, Series VV at maturity.maturity, and
Power
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
issued $700 million(UNAUDITED)
Table of 3.00% Senior Notes due June 2021.Contents
PSE&G
On July 1, 2016, PSE&G
repurchased at par $100$100 million aggregate principal amount of Pollution Control Financing Authority of Salem County Bonds (Salem Bonds) and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds.

Power
issued $700 million of 3.00% Senior Notes due June 2021,
35retired $303 million of 5.32% Senior Notes due September 2016 and

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Tableretired $250 million of Contents (UNAUDITED)2.75% Senior Notes due September 2016.

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 PSEG'sPSEG’s $4.2 billion credit facilities are provided by a diverse bank group with no single institution representing more than 7% of the total commitments in PSEG'sPSEG’s credit facilities. As of JuneSeptember 30, 2016, PSEG'sPSEG’s total available credit capacity of $3.9$3.7 billion was in excess of its anticipated maximum liquidity requirements.
Each of PSEG'sPSEG’s 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 its subsidiaries'subsidiaries’ liquidity needs. PSEG'sPSEG’s total credit facilities and available liquidity as of JuneSeptember 30, 2016 were as follows:
             
   As of June 30, 2016     
 Company/Facility 
Total
Facility
 Usage (D) 
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
 $14
 $586
 Apr 2020 CP Support/Funding/Letters of Credit 
 Total PSE&G $600
 $14
 $586
     
 Power           
   5-year Credit Facility $1,600
 $189
 $1,411
 Apr 2019 Funding/Letters of Credit 
   5-year Credit Facility (C) 953
 13
 940
 Apr 2020 Funding/Letters of Credit 
 Total Power $2,553
 $202
 $2,351
     
 Total $4,153
 $226
 $3,927
     
             
             
   As of September 30, 2016     
 Company/Facility 
Total
Facility
 Usage (D) 
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
 255
 245
 Apr 2020 CP Support/Funding/Letters of Credit 
 Total PSEG $1,000
 $265
 $735
     
 PSE&G           
  5-year Credit Facility (B) $600
 $14
 $586
 Apr 2020 CP Support/Funding/Letters of Credit 
 Total PSE&G $600
 $14
 $586
     
 Power           
   5-year Credit Facility $1,600
 $194
 $1,406
 Apr 2019 Funding/Letters of Credit 
   5-year Credit Facility (C) 953
 11
 942
 Apr 2020 Funding/Letters of Credit 
 Total Power $2,553
 $205
 $2,348
     
 Total $4,153
 $484
 $3,669
     
             
(A)PSEG facility will be reduced by $12 million in March 2018.
(B)PSE&G facility will be reduced by $14 million in March 2018.
(C)Power facility will be reduced by $24 million in March 2018.
(C)Power facility will be reduced by $24 million in March 2018.
(D)The primary use of PSEG'sPSEG’s and PSE&G's&G’s credit facilities is to support their respective CP Programs. As of September 30, 2016, PSEG andhad $255 million outstanding under its CP Program at a weighted average interest rate of 0.79%. As of September 30, 2016, PSE&G had no amounts outstanding under their respectiveits CP Programs as of June 30, 2016.Program.

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(UNAUDITED)
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Note 10.11. 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

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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 are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value.
Commodity Prices
Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to price risk primarily relating to changes in the market price of 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, environmental policies, transmission availability and 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. 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. PSEG had no commodity derivative transactions designated as cash flow or fair value hedges as of JuneSeptember 30, 2016 and December 31, 2015.
Economic Hedges
Power enters into derivative contracts that 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 Power'sPower’s expected generation. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract to optimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities.
Interest Rates
PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.
Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of June 30, 2016, PSEG had interest rate swaps outstanding totaling $550 million. These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective asThe changes in 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. Interest rate swaps totaling $550 million that converted the retired Power’s Senior Notes due September 2016 into variable-rate debt matured in the third quarter. There were no outstanding interest rate swaps as of September 30, 2016. As of June 30, 2016 and December 31, 2015, the fair value of all the underlying hedges was $2 million and $6 million, respectively.million. The effect of these hedges reduced interest expense by $2 million and $5 million for the three months ended JuneSeptember 30, 2016 and 2015, respectively, and $4$6 million and $10$15 million for the sixnine months ended JuneSeptember 30, 2016 and 2015, respectively.
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(UNAUDITED)
Table of Contents

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. As of JuneSeptember 30, 2016, PSEG had interest rate hedges outstanding totaling $500 million. The hedge ineffectiveness associated with theseThese hedges was immaterial. convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. The total fair value of these interest rate hedges was $(1) millionand the related ineffectiveness were immaterial as of JuneSeptember 30, 2016. PSEG interest rate hedges totaling $400 million were terminated during the second quarter and a gain of $2 million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power'sPower’s $700 million of 3% Senior Notes due June 2021. For additional information see Note 9.10. Debt and Credit Facilities. There were no outstanding interest rate cash flow hedges as of December 31, 2015. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $1$2 million as of JuneSeptember 30, 2016 and was immaterial as of December 31, 2015. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months are immaterial. The expiration date of the longest-dated interest rate hedge is in May 2021.
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

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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 PSEG'sPSEG’s accounting policy, these positions have been offset on the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables.
               
   As of June 30, 2016 (A) 
   Power PSE&G PSEG Consolidated 
   Not Designated     Not Designated Designated as Hedges   
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
   Millions 
 Derivative Contracts             
 Current Assets $460
 $(310) $150
 $—
 $2
 $152
 
 Noncurrent Assets 264
 (188) 76
 —
 —
 76
 
 Total Mark-to-Market Derivative Assets $724
 $(498) $226
 $—
 $2
 $228
 
 Derivative Contracts             
 Current Liabilities $(334) $317
 $(17) $(2) $(1) $(20) 
 Noncurrent Liabilities (203) 189
 (14) —
 —
 (14) 
 Total Mark-to-Market Derivative (Liabilities) $(537) $506
 $(31) $(2) $(1) $(34) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $187
 $8
 $195
 $(2) $1
 $194
 
               
               
   As of September 30, 2016 (A) 
   Power PSE&G PSEG Consolidated 
   Not Designated     Not Designated Designated as Hedges   
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
   Millions 
 Derivative Contracts             
 Current Assets $432
 $(283) $149
 $—
 $—
 $149
 
 Noncurrent Assets 305
 (219) 86
 —
 —
 86
 
 Total Mark-to-Market Derivative Assets $737
 $(502) $235
 $—
 $—
 $235
 
 Derivative Contracts             
 Current Liabilities $(314) $278
 $(36) $(4) $—
 $(40) 
 Noncurrent Liabilities (219) 206
 (13) —
 —
 (13) 
 Total Mark-to-Market Derivative (Liabilities) $(533) $484
 $(49) $(4) $—
 $(53) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $204
 $(18) $186
 $(4) $—
 $182
 
               
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents

               
   As of December 31, 2015 (A) 
   Power PSE&G PSEG Consolidated 
   Not Designated     Not Designated Designated as Hedges   
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
   Millions 
 Derivative Contracts             
 Current Assets $700
 $(477) $223
 $13
 $6
 $242
 
 Noncurrent Assets 208
 (131) 77
 —
 —
 77
 
 Total Mark-to-Market Derivative Assets $908
 $(608) $300
 $13
 $6
 $319
 
 Derivative Contracts             
 Current Liabilities $(513) $437
 $(76) $—
 $—
 $(76) 
 Noncurrent Liabilities (132) 116
 (16) (11) —
 (27) 
 Total Mark-to-Market Derivative (Liabilities) $(645) $553
 $(92) $(11) $—
 $(103) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $263
 $(55) $208
 $2
 $6
 $216
 
               
(A)Substantially all of Power'sPower’s and PSEG'sPSEG’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 JuneSeptember 30, 2016 and December 31, 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

38

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

(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 on the Condensed Consolidated Balance Sheets. As of JuneSeptember 30, 2016 and December 31, 2015, net cash collateral (received) paid of $8$(18) million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $8$(18) million as of JuneSeptember 30, 2016, $(2)$(13) million and $(14) million of cash collateral waswere netted against current assets and $10noncurrent assets, respectively, and $9 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2$2 million were netted against current liabilities and noncurrent liabilities, respectively.
Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P and Moody’s ratings. 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, and contracts designated as NPNS) was $26$42 million and $78 million as of JuneSeptember 30, 2016 and December 31, 2015, respectively. As of JuneSeptember 30, 2016 and December 31, 2015, Power had the contractual right of offset of $18$11 million and $12 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 to a below investment grade rating, it would have had additional collateral obligations of $8$31 million and $66 million as of JuneSeptember 30, 2016 and December 31, 2015, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents

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 JuneSeptember 30, 2016 and 2015.
                   
 
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 
  June 30,   June 30,   June 30, 
  2016 2015   2016 2015   2016 2015 
   Millions 
 PSEG                 
 Energy-Related Contracts $—
 $—
 Operating Revenues $—
 $—
 Operating Revenues $—
 $—
 
 Interest Rate Swaps (1) —
 Interest Expense —
 —
 Interest Expense —
 —
 
 Total PSEG $(1) $—
   $—
 $—
   $—
 $—
 
 Power                 
 Energy-Related Contracts $—
 $—
 Operating Revenues $—
 $—
 Operating Revenues $—
 $—
 
 Total Power $—
 $—
   $—
 $—
   $—
 $—
 
                   

39

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

                   
 
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, 
  2016 2015   2016 2015   2016 2015 
   Millions 
 PSEG                 
 Energy-Related Contracts $—
 $1
 Operating Revenues $—
 $—
 Operating Revenues $—
 $—
 
 Interest Rate Swaps 1
 —
 Interest Expense —
 —
 Interest Expense —
 —
 
 Total PSEG $1
 $1
   $—
 $—
   $—
 $—
 
 Power                 
 Energy-Related Contracts $—
 $1
 Operating Revenues $—
 $—
 Operating Revenues $—
 $—
 
 Total Power $—
 $1
   $—
 $—
   $—
 $—
 
                   
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 sixnine months ended JuneSeptember 30, 2016 and 2015.
                   
 
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)
 
  Six Months Ended   Six Months Ended   Six Months Ended 
  June 30,   June 30,   June 30, 
  2016 2015                                2016 2015   2016 2015 
   Millions 
 PSEG                 
 Energy-Related Contracts $—
 $1
 Operating Revenues $—
 $17
 Operating Revenues $—
 $—
 
 Interest Rate Swaps 2
 —
 Interest Expense —
 —
 Interest Expense —
 —
 
 Total PSEG $2
 $1
   $—
 $17
   $—
 $—
 
 Power                 
 Energy-Related Contracts $—
 $1
 Operating Revenues $—
 $17
 Operating Revenues $—
 $—
 
 Total Power $—
 $1
   $—
 $17
   $—
 $—
 
                   
                   
 
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, 
  2016 2015                                2016 2015   2016 2015 
   Millions 
 PSEG                 
 Energy-Related Contracts $—
 $2
 Operating Revenues $—
 $17
 Operating Revenues $—
 $—
 
 Interest Rate Swaps 3
 —
 Interest Expense —
 —
 Interest Expense —
 —
 
 Total PSEG $3
 $2
   $—
 $17
   $—
 $—
 
 Power                 
 Energy-Related Contracts $—
 $2
 Operating Revenues $—
 $17
 Operating Revenues $—
 $—
 
 Total Power $—
 $2
   $—
 $17
   $—
 $—
 
                   
    
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents

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, 2014 $17
 $10

 Gain Recognized in AOCI 3
 2
 
 Less: Gain Reclassified into Income (20) (12) 
 Balance as of December 31, 2015 $—
 $—
 
 Gain Recognized in AOCI 3
—
2
 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of March 31, 2016 $3
 $2
 
 Loss Recognized in AOCI (1) (1) 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of June 30, 2016 $2
 $1
 
       

40

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

       
 Accumulated Other Comprehensive Income Pre-Tax After-Tax 
   Millions 
 Balance as of December 31, 2015 $—
 $—
 
 Gain Recognized in AOCI 2
—
1
 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of June 30, 2016 $2
 $1
 
 Gain Recognized in AOCI 1
 1
 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of September 30, 2016 $3
 $2
 
       
The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS, such as its BGS contracts and certain other energy supply contracts, for the three months and sixnine months ended JuneSeptember 30, 2016 and 2015. Power'sPower’s derivative contracts reflected in these tables include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel.
             
 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 Six Months Ended 
     June 30, June 30, 
     2016 2015 2016 2015 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $(86) $124
 $130
 $48
 
 Energy-Related Contracts Energy Costs 6
 (10) 8
 —
 
 Total PSEG and Power   $(80) $114
 $138
 $48
 
             
             
 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, 
     2016 2015 2016 2015 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $125
 $154
 $255
 $202
 
 Energy-Related Contracts Energy Costs (11) (4) (3) (4) 
 Total PSEG and Power   $114
 $150
 $252
 $198
 
             
The following reflects the gross volume, on an absolute value basis, of derivatives as of JuneSeptember 30, 2016 and December 31, 2015.
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of June 30, 2016           
 Natural Gas Dekatherm (Dth) 347
 —
 327
 20
 
 Electricity MWh 326
 —
 326
 —
 
 Financial Transmission Rights (FTRs) MWh 21
 —
 21
 —
 
 Interest Rate Swaps U.S. Dollars 1,050
 1,050
 —
 —
 
 As of December 31, 2015           
 Natural Gas Dth 201
 —
 168
 33
 
 Electricity MWh 299
 —
 299
 —
 
 FTRs MWh 23
 —
 23
 —
 
 Interest Rate Swaps U.S. Dollars 550
 550
 —
 —
 
             
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of September 30, 2016           
 Natural Gas Dekatherm (Dth) 315
 —
 300
 15
 
 Electricity MWh 349
 —
 349
 —
 
 Financial Transmission Rights (FTRs) MWh 14
 —
 14
 —
 
 Interest Rate Swaps U.S. Dollars 500
 500
 —
 —
 
 As of December 31, 2015           
 Natural Gas Dth 201
 —
 168
 33
 
 Electricity MWh 299
 —
 299
 —
 
 FTRs MWh 23
 —
 23
 —
 
 Interest Rate Swaps U.S. Dollars 550
 550
 —
 —
 
             

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

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 JuneSeptember 30, 2016, 90%92% of the net 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).

41

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

The following table provides information on Power’s credit risk from others, net of collateral, as of JuneSeptember 30, 2016. 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 $334
 $129
 $205
 2
 $125
(A)  
 Non-Investment Grade—External Rating 20
 —
 20
 —
 —
   
 Investment Grade—No External Rating 8
 1
 7
 —
 —
   
 Non-Investment Grade—No External Rating 3
 —
 3
 —
 —
   
 Total $365
 $130
 $235
 2
 $125
   
              
              
 Rating 
Current
Exposure
 
Securities
Held as
Collateral
 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
   Millions   Millions  
 Investment Grade—External Rating $384
 $135
 $249
 2
 $147
(A)  
 Non-Investment Grade—External Rating 24
 —
 24
 —
 —
   
 Investment Grade—No External Rating 9
 —
 9
 —
 —
   
 Non-Investment Grade—No External Rating 1
 1
 —
 —
 —
   
 Total $418
 $136
 $282
 2
 $147
   
              
(A)Represents net exposure of $94$114 million with PSE&G. The remaining net exposure of $31$33 million is with a non-affiliated power purchaser which is an investment grade counterparty.
As of JuneSeptember 30, 2016, collateral held from counterparties where Power had credit exposure included $3 million in cash collateral and $127$133 million in letters of credit.
As of JuneSeptember 30, 2016, Power had 140135 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 is greater than the supplier’s unsecured credit limit. As of JuneSeptember 30, 2016, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G's&G’s suppliers’ credit exposure is calculated each business day. As of JuneSeptember 30, 2016, PSE&G had no net credit exposure with suppliers, including Power.
PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.


42

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

Note 11.12. 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, PSE&G and Power have the ability to access. These consist primarily of listed equity 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 JuneSeptember 30, 2016, these consisted primarily of long-term gas supply contracts and certain electric load contracts.
The following tables present information about PSEG’s, PSE&G’s and Power'sPower’s respective assets and (liabilities) measured at fair value on a recurring basis as of JuneSeptember 30, 2016 and December 31, 2015, 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 PSE&G and Power.

43

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

             
   Recurring Fair Value Measurements as of June 30, 2016 
 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) $570
 $—
 $570
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $226
 $(498) $—
 $717
 $7
 
 Interest Rate Swaps (C) $2
 $—
 $—
 $2
 $—
 
 NDT Fund (D)           
 Equity Securities $865
 $—
 $865
 $—
 $—
 
 Debt Securities—Govt Obligations $526
 $—
 $—
 $526
 $—
 
 Debt Securities—Other $357
 $—
 $—
 $357
 $—
 
 Other Securities $49
 $—
 $49
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $21
 $—
 $21
 $—
 $—
 
 Debt Securities—Govt Obligations $106
 $—
 $—
 $106
 $—
 
 Debt Securities—Other $90
 $—
 $—
 $90
 $—
 
 Other Securities $5
 $—
 $5
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(33) $506
 $—
 $(537) $(2) 
 Interest Rate Swaps (C) $(1) $—
 $—
 $(1) $—
 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $125
 $—
 $125
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $—
 $—
 $—
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $4
 $—
 $4
 $—
 $—
 
 Debt Securities—Govt Obligations $21
 $—
 $—
 $21
 $—
 
 Debt Securities—Other $18
 $—
 $—
 $18
 $—
 
 Other Securities $1
 $—
 $1
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(2) $—
 $—
 $—
 $(2) 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $226
 $(498) $—
 $717
 $7
 
 NDT Fund (D)           
 Equity Securities $865
 $—
 $865
 $—
 $—
 
 Debt Securities—Govt Obligations $526
 $—
 $—
 $526
 $—
 
 Debt Securities—Other $357
 $—
 $—
 $357
 $—
 
 Other Securities $49
 $—
 $49
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $26
 $—
 $—
 $26
 $—
 
 Debt Securities—Other $22
 $—
 $—
 $22
 $—
 
 Other Securities $1
 $—
 $1
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(31) $506
 $—
 $(537) $—
 
             
             
   Recurring Fair Value Measurements as of September 30, 2016 
 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) $357
 $—
 $357
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $235
 $(502) $—
 $722
 $15
 
 Interest Rate Swaps (C) $—
 $—
 $—
 $—
 $—
 
 NDT Fund (D)           
 Equity Securities $922
 $—
 $922
 $—
 $—
 
 Debt Securities—Govt Obligations $530
 $—
 $—
 $530
 $—
 
 Debt Securities—Other $360
 $—
 $—
 $360
 $—
 
 Other Securities $45
 $—
 $45
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $22
 $—
 $22
 $—
 $—
 
 Debt Securities—Govt Obligations $107
 $—
 $—
 $107
 $—
 
 Debt Securities—Other $94
 $—
 $—
 $94
 $—
 
 Other Securities $1
 $—
 $1
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(53) $484
 $—
 $(533) $(4) 
 Interest Rate Swaps (C) $—
 $—
 $—
 $—
 $—
 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $357
 $—
 $357
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $—
 $—
 $—
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $4
 $—
 $4
 $—
 $—
 
 Debt Securities—Govt Obligations $22
 $—
 $—
 $22
 $—
 
 Debt Securities—Other $18
 $—
 $—
 $18
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(4) $—
 $—
 $—
 $(4) 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $235
 $(502) $—
 $722
 $15
 
 NDT Fund (D)           
 Equity Securities $922
 $—
 $922
 $—
 $—
 
 Debt Securities—Govt Obligations $530
 $—
 $—
 $530
 $—
 
 Debt Securities—Other $360
 $—
 $—
 $360
 $—
 
 Other Securities $45
 $—
 $45
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $6
 $—
 $6
 $—
 $—
 
 Debt Securities—Govt Obligations $26
 $—
 $—
 $26
 $—
 
 Debt Securities—Other $23
 $—
 $—
 $23
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(49) $484
 $—
 $(533) $—
 
             

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   Recurring Fair Value Measurements as of December 31, 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) $326
 $—
 $326
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $313
 $(608) $—
 $896
 $25
 
 Interest Rate Swaps (C) $6
 $—
 $—
 $6
 $—
 
 NDT Fund (D)           
 Equity Securities $865
 $—
 $865
 $—
 $—
 
 Debt Securities—Govt Obligations $488
 $—
 $—
 $488
 $—
 
 Debt Securities—Other $359
 $—
 $—
 $359
 $—
 
 Other Securities $42
 $—
 $42
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $22
 $—
 $22
 $—
 $—
 
 Debt Securities—Govt Obligations $108
 $—
 $—
 $108
 $—
 
 Debt Securities—Other $81
 $—
 $—
 $81
 $—
 
 Other Securities $2
 $—
 $2
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(103) $553
 $—
 $(644) $(12) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $160
 $—
 $160
 $—
 $—
 
 Derivative Contracts:           
 Energy Related Contracts (B) $13
 $—
 $—
 $—
 $13
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $21
 $—
 $—
 $21
 $—
 
 Debt Securities—Other $16
 $—
 $—
 $16
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(11) $—
 $—
 $—
 $(11) 
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $300
 $(608) $—
 $896
 $12
 
 NDT Fund (D)           
 Equity Securities $865
 $—
 $865
 $—
 $—
 
 Debt Securities—Govt Obligations $488
 $—
 $—
 $488
 $—
 
 Debt Securities—Other $359
 $—
 $—
 $359
 $—
 
 Other Securities $42
 $—
 $42
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—Govt Obligations $26
 $—
 $—
 $26
 $—
 
 Debt Securities—Other $20
 $—
 $—
 $20
 $—
 
 Other Securities $1
 $—
 $1
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(92) $553
 $—
 $(644) $(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

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midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.
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 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 government 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 JuneSeptember 30, 2016, net cash collateral (received) paid of $8$(18) million was netted against the corresponding net derivative contract positions. Of the $8$(18) million as of JuneSeptember 30, 2016, $(2)$(27) million of cash collateral was netted against assets, and $10$9 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets, and $14 million was netted against liabilities.
Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

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For 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 fair value of Power'sPower’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. The following tables provide details surrounding significant Level 3 valuations as of JuneSeptember 30, 2016 and December 31, 2015.
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position June 30, 2016 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 PSE&G             
 Gas Natural Gas Supply Contracts  $—
 $(2) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth 
 Total PSE&G   $—
 $(2)       
 Power             
                  Electricity Electric Load Contracts $7
 $—
 Discounted Cash flow Historic Load Variability 0% to +10% 
 Total Power   $7
 $—
       
 Total PSEG   $7
 $(2)       
               
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position September 30, 2016 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 PSE&G             
 Gas Natural Gas Supply Contracts  $—
 $(4) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth 
 Total PSE&G   $—
 $(4)       
 Power             
 Electricity Electric Load Contracts $12
 $—
 Discounted Cash flow Historic Load Variability 0% to +10% 
 Gas (A) Other 3
 —
       
 Total Power   $15
 $—
       
 Total PSEG   $15
 $(4)       
               
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position December 31, 2015 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 PSE&G             
 Gas Natural Gas Supply Contracts  $13
 $(11) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth 
 Total PSE&G   $13
 $(11)       
 Power             
 Electricity Electric Load Contracts $11
 $(1) Discounted Cash Flow Historic Load Variability 0% to +10% 
 Electricity Other 1
 —
       
 Total Power   $12
 $(1)       
 Total PSEG   $25
 $(12)       
               
(A) Includes gas supply positions that are immaterial.
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 the load variability would decrease the fair value.

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A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and sixnine months ended JuneSeptember 30, 2016 and JuneSeptember 30, 2015, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months and SixNine Months Ended JuneSeptember 30, 2016
                 
   Three Months Ended June 30, 2016   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of April 1, 2016 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2016 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $21
 $1
 $(12) $—
 $(5) $—
 $5
 
 PSE&G               
 Net Derivative Assets (Liabilities) $10
 $—
 $(12) $—
 $—
 $—
 $(2) 
 Power               
 Net Derivative Assets (Liabilities) $11
 $1
 $—
 $—
 $(5) $—
 $7
 
                 
   Six Months Ended June 30, 2016   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2016 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2016 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $13
 $16
 $(4) $—
 $(20) $—
 $5
 
 PSE&G               
 Net Derivative Assets (Liabilities) $2
 $—
 $(4) $—
 $—
 $—
 $(2) 
 Power               
 Net Derivative Assets (Liabilities) $11
 $16
 $—
 $—
 $(20) $—
 $7
 
                 

                 
   Three Months Ended September 30, 2016   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2016 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2016 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $5
 $8
 $(2) $4
 $(4) $—
 $11
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(2) $—
 $(2) $—
 $—
 $—
 $(4) 
 Power               
 Net Derivative Assets (Liabilities) $7
 $8
 $—
 $4
 $(4) $—
 $15
 
                 
   Nine Months Ended September 30, 2016   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2016 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2016 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $13
 $24
 $(6) $4
 $(24) $—
 $11
 
 PSE&G               
 Net Derivative Assets (Liabilities) $2
 $—
 $(6) $—
 $—
 $—
 $(4) 
 Power               
 Net Derivative Assets (Liabilities) $11
 $24
 $—
 $4
 $(24) $—
 $15
 
                 







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Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months and SixNine Months Ended JuneSeptember 30, 2015
                 
   Three Months Ended June 30, 2015   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of April 1, 2015 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of June 30, 2015 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $9
 $5
 $(2) $—
 $(4) $—
 $8
 
 PSE&G               
 Net Derivative Assets (Liabilities) $7
 $—
 $(2) $—
 $—
 $—
 $5
 
 Power               
 Net Derivative Assets (Liabilities) $2
 $5
 $—
 $—
 $(4) $—
 $3
 
                 
   Six Months Ended June 30, 2015   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2015 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2015 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $37
 $8
 $(21) $—
 $(16) $—
 $8
 
 PSE&G               
 Net Derivative Assets (Liabilities) $26
 $—
 $(21) $—
 $—
 $—
 $5
 
 Power               
 Net Derivative Assets (Liabilities) $11
 $8
 $—
 $—
 $(16) $—
 $3
 
                 
                 
   Three Months Ended September 30, 2015   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2015 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 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 (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 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
 
                 
(A)PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1$8 million and $16$24 million in Operating Income for the three months and sixnine months ended JuneSeptember 30, 2016, respectively. Of the $1$8 million in Operating Income, $(4)$4 million is unrealized. Of the $16The $24 million in Operating Income $(4) million is unrealized.realized.
(B)Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated 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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Table of Contents (UNAUDITED)

(C)Represents $(5)$(4) million and $(20)$(24) million in settlements for the three months and sixnine months ended JuneSeptember 30, 2016, respectively. Represents $(4)$(2) million and $(16)$(18) million in settlements for the three months and sixnine months ended JuneSeptember 30, 2015, respectively.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents

(D)
There were no transfers among levels during the three months and sixnine months ended JuneSeptember 30, 2016 and 2015.
(E)PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $5$4 million and $8$12 million in Operating Income for the three months and sixnine months ended JuneSeptember 30, 2015, respectively. The $5Of the $4 million in Operating Income, $3 million is realized.unrealized. Of the $8$12 million in Operating Income, $(9)$(6) million is unrealized.
As of JuneSeptember 30, 2016, PSEG carried $2.8$2.6 billion of net assets that are measured at fair value on a recurring basis, of which $5$11 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of JuneSeptember 30, 2015, PSEG carried $2.72.3 billion of net assets that are measured at fair value on a recurring basis, of which $82 million of net liabilitiesassets 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 JuneSeptember 30, 2016 and December 31, 2015.
          
  As of As of 
  June 30, 2016 December 31, 2015 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (Parent) (A)$501
 $502
 $503
 $506
 
 PSE&G (B)7,494
 8,624
 6,821
 7,235
 
 Power - Recourse Debt (B)2,933
 3,274
 2,237
 2,508
 
 Energy Holdings:        
   Project Level, Non-Recourse Debt (C)7
 7
 7
 7
 
 Total Long-Term Debt$10,935
 $12,407
 $9,568
 $10,256
 
          
          
  As of As of 
  September 30, 2016 December 31, 2015 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (Parent) (A)$500
 $500
 $503
 $506
 
 PSE&G (B)7,816
 8,996
 6,821
 7,235
 
 Power - Recourse Debt (B)2,381
 2,788
 2,237
 2,508
 
 Energy Holdings:        
   Project Level, Non-Recourse Debt (C)—
 —
 7
 7
 
 Total Long-Term Debt$10,697
 $12,284
 $9,568
 $10,256
 
          
(A)Fair value includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.
(B)Given that most bonds do not trade, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
(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 12.13. Other Income and Deductions
          
 Other IncomePSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended June 30, 2016        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $23
 $—
 $23
 
 Allowance for Funds Used During Construction10
 —
 —
 10
 
 Solar Loan Interest5
 —
 —
 5
 
 Other4
 2
 —
 6
 
 Total Other Income$19
 $25
 $—
 $44
 
 Six Months Ended June 30, 2016        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $48
 $—
 $48
 
 Allowance for Funds Used During Construction21
 —
 —
 21
 
 Solar Loan Interest11
 —
 —
 11
 
 Other7
 3
 2
 12
 
   Total Other Income$39
 $51
 $2
 $92
 
 Three Months Ended June 30, 2015        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $25
 $—
 $25
 
 Allowance for Funds Used During Construction12
 —
 —
 12
 
 Solar Loan Interest6
 —
 —
 6
 
      Gain on Insurance Recovery—
 28
 —
 28
 
 Other1
 2
 2
 5
 
 Total Other Income$19
 $55
 $2
 $76
 
 Six Months Ended June 30, 2015        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $54
 $—
 $54
 
 Allowance for Funds Used During Construction22
 —
 —
 22
 
 Solar Loan Interest12
 —
 —
 12
 
      Gain on Insurance Recovery—
 28
 —
 28
 
 Other3
 2
 3
 8
 
 Total Other Income$37
 $84
 $3
 $124
 
          
          
 Other IncomePSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2016        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $21
 $—
 $21
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Solar Loan Interest6
 —
 —
 6
 
 Other2
 2
 2
 6
 
 Total Other Income$22
 $23
 $2
 $47
 
 Nine Months Ended September 30, 2016        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $69
 $—
 $69
 
 Allowance for Funds Used During Construction35
 —
 —
 35
 
 Solar Loan Interest17
 —
 —
 17
 
 Other9
 5
 4
 18
 
   Total Other Income$61
 $74
 $4
 $139
 
 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
 
          
          
 Other DeductionsPSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended June 30, 2016        
   NDT Fund Realized Losses and Expenses$—
 $8
 $—
 $8
 
   Other1
 1
 —
 2
 
     Total Other Deductions$1
 $9
 $—
 $10
 
 Six Months Ended June 30, 2016        
   NDT Fund Realized Losses and Expenses$—
 $26
 $—
 $26
 
   Other2
 1
 2
 5
 
     Total Other Deductions$2
 $27
 $2
 $31
 
 Three Months Ended June 30, 2015        
   NDT Fund Realized Losses and Expenses$—
 $6
 $—
 $6
 
   Other1
 1
 2
 4
 
   Total Other Deductions$1
 $7
 $2
 $10
 
 Six Months Ended June 30, 2015        
   NDT Fund Realized Losses and Expenses$—
 $17
 $—
 $17
 
   Other2
 1
 2
 5
 
   Total Other Deductions$2
 $18
 $2
 $22
 
          
          
 Other DeductionsPSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2016        
   NDT Fund Realized Losses and Expenses$—
 $5
 $—
 $5
 
   Other1
 1
 1
 3
 
     Total Other Deductions$1
 $6
 $1
 $8
 
 Nine Months Ended September 30, 2016        
   NDT Fund Realized Losses and Expenses$—
 $31
 $—
 $31
 
   Other3
 2
 3
 8
 
     Total Other Deductions$3
 $33
 $3
 $39
 
 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
 
          
(A)Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

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(UNAUDITED)
Table of Contents (UNAUDITED)


Note 13.14. Income Taxes
PSEG’s, PSE&G’s and Power'sPower’s effective tax rates for the three months and sixnine months ended JuneSeptember 30, 2016 and 2015 were as follows:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
 PSEG32.7% 35.0% 36.2% 38.5% 
 PSE&G35.4% 38.4% 36.1% 39.0% 
 Power50.0% 30.3% 39.5% 37.9% 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
 PSEG36.5% 39.4% 36.3% 38.8% 
 PSE&G36.1% 38.2% 36.1% 38.7% 
 Power39.3% 40.3% 39.4% 38.6% 
          
For the three months and sixnine months ended JuneSeptember 30, 2016, the overall decreases in PSEG'sPSEG’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions and plant and other flow through items, offset by the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.related items.
For the three months and sixnine months ended JuneSeptember 30, 2016, the overall decreases in PSE&G's&G’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions and plant and other flow through items.
For the three months ended June 30, 2016, the increase in Power's effective tax rate as compared to the same period in the prior year as well as to the statutory tax rate of 40.85%, was due primarily to the absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.
The Tax Increase Prevention Act of 2014 extended the 50% bonus depreciation rules for qualified property placed in service before January 1, 2015 and for long production property placed in service in 2015.
The Protecting Americans from Tax Hikes Act of 2015 (Tax Act) extended the 50% bonus depreciation rules for qualified property placed in service from January 1, 2015 through December 31, 2017. The rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. The Tax Act also extended the 30% ITC for qualified property placed in service starting January 1, 2016 through December 31, 2019 but reduces the ITC rate to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions.
These provisions have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs.


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Note 14.15. Accumulated Other Comprehensive Income (Loss), Net of Tax
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2016 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2016 $2
 $(378) $107
 $(269) 
 Other Comprehensive Income before Reclassifications (1) —
 8
 7
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 8
 2
 10
 
 Net Current Period Other Comprehensive Income (Loss) (1) 8
 10
 17
 
 Balance as of June 30, 2016 $1
 $(370) $117
 $(252) 
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2015 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2015 $1
 $(403) $132
 $(270) 
 Other Comprehensive Income before Reclassifications —
 —
 (14) (14) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 8
 (1) 7
 
 Net Current Period Other Comprehensive Income (Loss) —
 8
 (15) (7) 
 Balance as of June 30, 2015 $1
 $(395) $117
 $(277) 
     
 PSEG Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2016 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2015 $—
 $(386) $91
 $(295) 
 Other Comprehensive Income before Reclassifications 1
 —
 18
 19
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 16
 8
 24
 
 Net Current Period Other Comprehensive Income (Loss) 1
 16
 26
 43
 
 Balance as of June 30, 2016 $1
 $(370) $117
 $(252) 
           
 PSEG Other Comprehensive Income (Loss) 
   Six Months Ended June 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
 —
 2
 3
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (10) 16
 (3) 3
 
 Net Current Period Other Comprehensive Income (Loss) (9) 16
 (1) 6
 
 Balance as of June 30, 2015 $1
 $(395) $117
 $(277) 
           
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2016 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2016 $1
 $(370) $117
 $(252) 
 Other Comprehensive Income before Reclassifications 1
 —
 26
 27
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 9
 (2) 7
 
 Net Current Period Other Comprehensive Income (Loss) 1
 9
 24
 34
 
 Balance as of September 30, 2016 $2
 $(361) $141
 $(218) 
           
 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) 
     
 PSEG Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2016 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2015 $—
 $(386) $91
 $(295) 
 Other Comprehensive Income before Reclassifications 2
 —
 44
 46
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 25
 6
 31
 
 Net Current Period Other Comprehensive Income (Loss) 2
 25
 50
 77
 
 Balance as of September 30, 2016 $2
 $(361) $141
 $(218) 
           
 PSEG 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) 
           

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 Power Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2016 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2016 $—
 $(320) $103
 $(217) 
 Other Comprehensive Income before Reclassifications —
 —
 6
 6
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 3
 10
 
 Net Current Period Other Comprehensive Income (Loss) —
 7
 9
 16
 
 Balance as of June 30, 2016 $—
 $(313) $112
 $(201) 
     
 Power Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2015 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2015 $2
 $(344) $126
 $(216) 
 Other Comprehensive Income before Reclassifications —
 —
 (14) (14) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 —
 7
 
 Net Current Period Other Comprehensive Income (Loss) —
 7
 (14) (7) 
 Balance as of June 30, 2015 $2
 $(337) $112
 $(223) 
           
 Power Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2016 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2015 $—
 $(327) $87
 $(240) 
 Other Comprehensive Income before Reclassifications —
 —
 16
 16
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 14
 9
 23
 
 Net Current Period Other Comprehensive Income (Loss) —
 14
 25
 39
 
 Balance as of June 30, 2016 $—
 $(313) $112
 $(201) 
  ��        
 Power Other Comprehensive Income (Loss) 
   Six Months Ended June 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
 —
 2
 3
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (10) 14
 (2) 2
 
 Net Current Period Other Comprehensive Income (Loss) (9) 14
 —
 5
 
 Balance as of June 30, 2015 $2
 $(337) $112
 $(223) 
           
           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2016 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2016 $—
 $(313) $112
 $(201) 
 Other Comprehensive Income before Reclassifications —
 —
 24
 24
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 (2) 5
 
 Net Current Period Other Comprehensive Income (Loss) —
 7
 22
 29
 
 Balance as of September 30, 2016 $—
 $(306) $134
 $(172) 
     
 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) 
           
 Power Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2016 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2015 $—
 $(327) $87
 $(240) 
 Other Comprehensive Income before Reclassifications —
 —
 40
 40
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 21
 7
 28
 
 Net Current Period Other Comprehensive Income (Loss) —
 21
 47
 68
 
 Balance as of September 30, 2016 $—
 $(306) $134
 $(172) 
           
 Power 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) 
           

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 PSEG   Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
    Three Months Ended Six Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of OperationsJune 30, 2016 June 30, 2016 
  Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
    Millions 
 Pension and OPEB Plans            
 Amortization of Prior Service (Cost) Credit O&M Expense3
 (1) 2
 6
 (2) 4
 
    Amortization of Actuarial Loss O&M Expense(17) 7
 (10) (34) 14
 (20) 
 Total Pension and OPEB Plans(14) 6
 (8) (28) 12
 (16) 
 Available-for-Sale Securities            
 Realized Gains Other Income12
 (6) 6
 28
 (14) 14
 
 Realized Losses Other Deductions(7) 4
 (3) (24) 12
 (12) 
 Other-Than-Temporary Impairments (OTTI) OTTI(10) 5
 (5) (20) 10
 (10) 
 Total Available-for-Sale Securities(5) 3
 (2) (16) 8
 (8) 
 Total  $(19) $9
 $(10) $(44) $20
 $(24) 
                
                
 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 OperationsSeptember 30, 2016 September 30, 2016 
  Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
    Millions 
 Pension and OPEB Plans            
 Amortization of Prior Service (Cost) Credit O&M Expense$3
 $(2) $1
 $9
 $(4) $5
 
    Amortization of Actuarial Loss O&M Expense(17) 7
 (10) (51) 21
 (30) 
 Total Pension and OPEB Plans(14) 5
 (9) (42) 17
 (25) 
 Available-for-Sale Securities            
 Realized Gains Other Income13
 (6) 7
 41
 (20) 21
 
 Realized Losses Other Deductions(5) 3
 (2) (29) 15
 (14) 
 Other-Than-Temporary Impairments (OTTI) OTTI(5) 2
 (3) (25) 12
 (13) 
 Total Available-for-Sale Securities3
 (1) 2
 (13) 7
 (6) 
 Total  $(11) $4
 $(7) $(55) $24
 $(31) 
                
                 
 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Six Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations June 30, 2015 June 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
 6
 (2) 4
 
    Amortization of Actuarial Loss O&M Expense (17) 7
 (10) (34) 14
 (20) 
 Total Pension and OPEB Plans (14) 6
 (8) (28) 12
 (16) 
 Available-for-Sale Securities             
 Realized Gains Other Income 16
 (8) 8
 35
 (18) 17
 
 Realized Losses Other Deductions (4) 2
 (2) (13) 7
 (6) 
 OTTI OTTI (10) 5
 (5) (15) 7
 (8) 
 Total Available-for-Sale Securities 2
 (1) 1
 7
 (4) 3
 
 Total   $(12) $5
 $(7) $(4) $1
 $(3) 
                 
                 
 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) 
 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) 
                 

55

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

                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Six Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations June 30, 2016 June 30, 2016 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Pension and OPEB Plans               
 Amortization of Prior Service (Cost) Credit O&M Expense $2
 $(1) $1
 $5
 $(2) $3
 
    Amortization of Actuarial Loss O&M Expense (14) 6
 (8) (29) 12
 (17) 
 Total Pension and OPEB Plans (12) 5
 (7) (24) 10
 (14) 
 Available-for-Sale Securities             
 Realized Gains Other Income 10
 (5) 5
 25
 (13) 12
 
 Realized Losses Other Deductions (6) 3
 (3) (22) 11
 (11) 
 OTTI OTTI (10) 5
 (5) (20) 10
 (10) 
 Total Available-for-Sale Securities (6) 3
 (3) (17) 8
 (9) 
 Total   $(18) $8
 $(10) $(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, 2016 September 30, 2016 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 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 (15) 6
 (9) (44) 18
 (26) 
 Total Pension and OPEB Plans (12) 5
 (7) (36) 15
 (21) 
 Available-for-Sale Securities             
 Realized Gains Other Income 12
 (5) 7
 37
 (18) 19
 
 Realized Losses Other Deductions (4) 2
 (2) (26) 13
 (13) 
 OTTI OTTI (5) 2
 (3) (25) 12
 (13) 
 Total Available-for-Sale Securities 3
 (1) 2
 (14) 7
 (7) 
 Total   $(9) $4
 $(5) $(50) $22
 $(28) 
                 
                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Six Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations June 30, 2015 June 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
 6
 (2) 4
 
    Amortization of Actuarial Loss O&M Expense (15) 6
 (9) (30) 12
 (18) 
 Total Pension and OPEB Plans (12) 5
 (7) (24) 10
 (14) 
 Available-for-Sale Securities             
 Realized Gains Other Income 14
 (7) 7
 33
 (17) 16
 
 Realized Losses Other Deductions (4) 2
 (2) (13) 7
 (6) 
 OTTI OTTI (10) 5
 (5) (15) 7
 (8) 
 Total Available-for-Sale Securities —
 —
 —
 5
 (3) 2
 
 Total   $(12) $5
 $(7) $(2) $—
 $(2) 
                 
                 
 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) 
                 


56

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

Note 15.16. Earnings Per Share (EPS) and Dividends
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG'sPSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:
                  
  Three Months Ended June 30, Six Months Ended June 30, 
  2016 2015 2016 2015 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator (Millions):
                
 Net Income$187
 $187
 $345
 $345
 $658
 $658
 $931
 $931
 
 
EPS Denominator (Millions):
                
 Weighted Average Common Shares Outstanding505
 505
 506
 506
 505
 505
 506
 506
 
 Effect of Stock Based Compensation Awards—
 3
 —
 2
 —
 3
 —
 2
 
 Total Shares505
 508
 506
 508
 505
 508
 506
 508
 
                  
 EPS                
 Net Income$0.37
 $0.37
 $0.68
 $0.68
 $1.30
 $1.30
 $1.84
 $1.83
 
                  
                  
  Three Months Ended September 30, Nine Months Ended September 30, 
  2016 2015 2016 2015 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator (Millions):
                
 Net Income$327
 $327
 $439
 $439
 $985
 $985
 $1,370
 $1,370
 
 
EPS Denominator (Millions):
                
 Weighted Average Common Shares Outstanding505
 505
 505
 505
 505
 505
 505
 505
 
 Effect of Stock Based Compensation Awards—
 3
 —
 3
 —
 3
 —
 3
 
 Total Shares505
 508
 505
 508
 505
 508
 505
 508
 
                  
 EPS                
 Net Income$0.65
 $0.64
 $0.87
 $0.87
 $1.95
 $1.94
 $2.71
 $2.70
 
                  
There were approximately 0.3 million and 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months and sixnine months ended JuneSeptember 30, 2016 and 2015, respectively.2015.
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Dividend Payments on Common Stock2016 2015 2016 2015 
 Per Share$0.41
 $0.39
 $0.82
 $0.78
 
 In Millions$208
 $197
 $415
 $394
 
          

On July 19, 2016, PSEG's Board of Directors approved a $0.41 per share common stock dividend for the third quarter of 2016.
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Dividend Payments on Common Stock2016 2015 2016 2015 
 Per Share$0.41
 $0.39
 $1.23
 $1.17
 
 In Millions$207
 $198
 $622
 $592
 
          


57

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

Note 16.17. Financial Information by Business Segment
            
  PSE&G Power Other (A) Eliminations (B) Consolidated 
  Millions 
 Three Months Ended June 30, 2016          
 Total Operating Revenues$1,350
 $714
 $127
 $(286) $1,905
 
 Net Income (Loss)179
 (11) 19
 —
 187
 
 Gross Additions to Long-Lived Assets631
 265
 10
 —
 906
 
 Six Months Ended June 30, 2016          
 Operating Revenues$3,062
 $2,027
 $249
 $(817) $4,521
 
 Net Income (Loss)441
 181
 36
 —
 658
 
 Gross Additions to Long-Lived Assets1,355
 598
 18
 —
 1,971
 
 Three Months Ended June 30, 2015          
 Total Operating Revenues$1,466
 $1,025
 $108
 $(285) $2,314
 
 Net Income (Loss)167
 166
 12
 —
 345
 
 Gross Additions to Long-Lived Assets631
 348
 17
 —
 996
 
 Six Months Ended June 30, 2015          
 Operating Revenues$3,468
 $2,750
 $206
 $(975) $5,449
 
 Net Income (Loss)409
 501
 21
 —
 931
 
 Gross Additions to Long-Lived Assets1,230
 487
 26
 —
 1,743
 
 As of June 30, 2016          
 Total Assets$24,737
 $13,278
 $2,873
 $(1,843) $39,045
 
 Investments in Equity Method Subsidiaries$—
 $112
 $—
 $—
 $112
 
 As of December 31, 2015          
 Total Assets$23,677
 $12,250
 $2,810
 $(1,202) $37,535
 
 Investments in Equity Method Subsidiaries$—
 $119
 $—
 $—
 $119
 
            
            
  PSE&G Power Other (A) Eliminations (B) Consolidated 
  Millions 
 Three Months Ended September 30, 2016          
 Total Operating Revenues$1,684
 $1,075
 $7
 $(316) $2,450
 
 Net Income (Loss)255
 139
 (67) —
 327
 
 Gross Additions to Long-Lived Assets680
 325
 9
 —
 1,014
 
 Nine Months Ended September 30, 2016          
 Operating Revenues$4,746
 $3,102
 $256
 $(1,133) $6,971
 
 Net Income (Loss)696
 320
 (31) —
 985
 
 Gross Additions to Long-Lived Assets2,035
 923
 27
 —
 2,985
 
 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          
 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
 
 As of September 30, 2016          
 Total Assets$25,486
 $12,810
 $2,385
 $(1,193) $39,488
 
 Investments in Equity Method Subsidiaries$—
 $106
 $—
 $—
 $106
 
 As of December 31, 2015          
 Total Assets$23,677
 $12,250
 $2,810
 $(1,202) $37,535
 
 Investments in Equity Method Subsidiaries$—
 $119
 $—
 $—
 $119
 
            
(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 relate to intercompany transactions between PSE&G and 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 PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 17.18. Related-Party Transactions.


58

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

Note 17.18. Related-Party Transactions
The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

PSE&G
The financial statements for PSE&G include transactions with related parties as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2016 2015 2016 2015 
  Millions 
 Billings from Affiliates:        
 Net Billings from Power primarily through BGS and BGSS (A)$320
 $294
 $1,162
 $1,287
 
 Administrative Billings from Services (B)73
 66
 224
 197
 
 Total Billings from Affiliates$393
 $360
 $1,386
 $1,484
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Related-Party Transactions2016 2015 2016 2015 
  Millions 
 Billings from Affiliates:        
 Net Billings from Power primarily through BGS and BGSS (A)$297
 $297
 $842
 $993
 
 Administrative Billings from Services (B)82
 65
 151
 131
 
 Total Billings from Affiliates$379
 $362
 $993
 $1,124
 
          
      
  As of As of 
 Related-Party TransactionsJune 30, 2016 December 31, 2015 
  Millions 
 Receivables from PSEG (C)$—
 $222
 
 Payable to Power (A)$94
 $212
 
 Payable to Services (B)79
 80
 
 Payable to PSEG (C)6
 —
 
 Accounts Payable—Affiliated Companies$179
 $292
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$99
 $109
 
      
      
  As of As of 
 Related-Party TransactionsSeptember 30, 2016 December 31, 2015 
  Millions 
 Receivables from PSEG (C)$28
 $222
 
 Payable to Power (A)$126
 $212
 
 Payable to Services (B)88
 80
 
 Accounts Payable—Affiliated Companies$214
 $292
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$92
 $109
 
      
Power
The financial statements for Power include transactions with related parties as follows:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Related-Party Transactions2016 2015 2016 2015 
  Millions 
 Billings to Affiliates:        
 Net Billings to PSE&G primarily through BGS and BGSS (A)$297
 $297
 $842
 $993
 
 Billings from Affiliates:        
 Administrative Billings from Services (B)$45
 $46
 $90
 $91
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2016 2015 2016 2015 
  Millions 
 Billings to Affiliates:        
 Net Billings to PSE&G primarily through BGS and BGSS (A)$320
 $294
 $1,162
 $1,287
 
 Billings from Affiliates:        
 Administrative Billings from Services (B)$44
 $44
 $134
 $135
 
          

59

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

      
  As of As of 
 Related-Party TransactionsJune 30, 2016 December 31, 2015 
  Millions 
 Receivables from PSE&G (A)$94
 $212
 
 Receivables from PSEG (C)—
 64
 
 Accounts Receivable—Affiliated Companies$94
 $276
 
 Payable to Services (B)$28
 $33
 
 Payable to PSEG (C)74
 —
 
 Accounts Payable—Affiliated Companies$102
 $33
 
 Short-Term Loan Due (to) from Affiliate (E)$1,335
 $363
 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$22
 $35
 
      
      
  As of As of 
 Related-Party TransactionsSeptember 30, 2016 December 31, 2015 
  Millions 
 Receivables from PSE&G (A)$126
 $212
 
 Receivables from PSEG (C)—
 64
 
 Accounts Receivable—Affiliated Companies$126
 $276
 
 Payable to Services (B)$27
 $33
 
 Payable to PSEG (C)129
 —
 
 Accounts Payable—Affiliated Companies$156
 $33
 
 Short-Term Loan Due (to) from Affiliate (E)$514
 $363
 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$79
 $35
 
      
(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. In addition, Power and PSE&G provide certain technical services for each other in compliance with FERC and BPU affiliate rules.
(B)Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power 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.



60

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

Note 18.19. 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, as of JuneSeptember 30, 2016 and December 31, 2015 and for the three months and sixnine months ended JuneSeptember 30, 2016 and 2015.
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended June 30, 2016          
 Operating Revenues$—
 $700
 $46
 $(32) $714
 
 Operating Expenses2
 716
 40
 (32) 726
 
 Operating Income (Loss)(2) (16) 6
 —
 (12) 
 Equity Earnings (Losses) of Subsidiaries(1) 1
 4
 —
 4
 
 Other Income17
 30
 —
 (22) 25
 
 Other Deductions—
 (9) —
 —
 (9) 
 Other-Than-Temporary Impairments—
 (10) —
 —
 (10) 
 Interest Expense(31) (7) (4) 22
 (20) 
 Income Tax Benefit (Expense)6
 3
 2
 —
 11
 
 Net Income (Loss)$(11) $(8) $8
 $—
 $(11) 
 Comprehensive Income (Loss)$5
 $1
 $8
 $(9) $5
 
 Six Months Ended June 30, 2016          
 Operating Revenues$—
 $2,002
 $88
 $(63) $2,027
 
 Operating Expenses12
 1,668
 79
 (63) 1,696
 
 Operating Income (Loss)(12) 334
 9
 —
 331
 
 Equity Earnings (Losses) of Subsidiaries204
 —
 6
 (204) 6
 
 Other Income34
 62
 —
 (45) 51
 
 Other Deductions—
 (27) —
 —
 (27) 
 Other-Than-Temporary Impairments—
 (20) —
 —
 (20) 
 Interest Expense(61) (17) (9) 45
 (42) 
 Income Tax Benefit (Expense)16
 (137) 3
 —
 (118) 
 Net Income (Loss)$181
 $195
 $9
 $(204) $181
 
 Comprehensive Income (Loss)$220
 $220
 $9
 $(229) $220
 
 Six Months Ended June 30, 2016          
 
Net Cash Provided By (Used In)
   Operating Activities
$337
 $777
 $159
 $(356) $917
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(1,287) $(504) $(395) $579
 $(1,607) 
 
Net Cash Provided By (Used In)
   Financing Activities
$951
 $(273) $239
 $(223) $694
 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended September 30, 2016          
 Operating Revenues$—
 $1,059
 $43
 $(27) $1,075
 
 Operating Expenses(2) 826
 40
 (27) 837
 
 Operating Income (Loss)2
 233
 3
 —
 238
 
 Equity Earnings (Losses) of Subsidiaries143
 (1) 3
 (142) 3
 
 Other Income18
 26
 —
 (21) 23
 
 Other Deductions(2) (4) —
 —
 (6) 
 Other-Than-Temporary Impairments—
 (5) —
 —
 (5) 
 Interest Expense(30) (12) (3) 21
 (24) 
 Income Tax Benefit (Expense)8
 (97) (1) —
 (90) 
 Net Income (Loss)$139
 $140
 $2
 $(142) $139
 
 Comprehensive Income (Loss)$168
 $161
 $2
 $(163) $168
 
 Nine Months Ended September 30, 2016          
 Operating Revenues$—
 $3,061
 $131
 $(90) $3,102
 
 Operating Expenses10
 2,494
 119
 (90) 2,533
 
 Operating Income (Loss)(10) 567
 12
 —
 569
 
 Equity Earnings (Losses) of Subsidiaries347
 (1) 9
 (346) 9
 
 Other Income52
 88
 —
 (66) 74
 
 Other Deductions(2) (31) —
 —
 (33) 
 Other-Than-Temporary Impairments—
 (25) —
 —
 (25) 
 Interest Expense(91) (29) (12) 66
 (66) 
 Income Tax Benefit (Expense)24
 (234) 2
 —
 (208) 
 Net Income (Loss)$320
 $335
 $11
 $(346) $320
 
 Comprehensive Income (Loss)$388
 $381
 $11
 $(392) $388
 
 Nine Months Ended September 30, 2016          
 
Net Cash Provided By (Used In)
   Operating Activities
$175
 $1,261
 $234
 $(410) $1,260
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(588) $(1,166) $(549) $1,152
 $(1,151) 
 
Net Cash Provided By (Used In)
   Financing Activities
$413
 $(95) $315
 $(742) $(109) 
            

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  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended June 30, 2015          
 Operating Revenues$—
 $1,012
 $39
 $(26) $1,025
 
 Operating Expenses(1) 787
 37
 (26) 797
 
 Operating Income (Loss)1
 225
 2
 —
 228
 
 Equity Earnings (Losses) of Subsidiaries186
 (1) 5
 (185) 5
 
 Other Income12
 55
 —
 (12) 55
 
 Other Deductions(1) (6) —
 —
 (7) 
 
Other-Than-Temporary
   Impairments
—
 (10) —
 —
 (10) 
 Interest Expense(33) (7) (5) 12
 (33) 
 Income Tax Benefit (Expense)1
 (73) —
 —
 (72) 
 Net Income (Loss)$166
 $183
 $2
 $(185) $166
 
 Comprehensive Income (Loss)$159
 $169
 $2
 $(171) $159
 
 Six Months Ended June 30, 2015          
 Operating Revenues$—
 $2,727
 $107
 $(84) $2,750
 
 Operating Expenses4
 1,918
 100
 (84) 1,938
 
 Operating Income (Loss)(4) 809
 7
 —
 812
 
 Equity Earnings (Losses) of Subsidiaries535
 (2) 8
 (533) 8
 
 Other Income23
 85
 —
 (24) 84
 
 Other Deductions(1) (17) —
 —
 (18) 
 Other-Than-Temporary Impairments—
 (15) —
 —
 (15) 
 Interest Expense(62) (16) (10) 24
 (64) 
 Income Tax Benefit (Expense)10
 (315) (1) —
 (306) 
 Net Income (Loss)$501
 $529
 $4
 $(533) $501
 
 Comprehensive Income (Loss)$506
 $520
 $4
 $(524) $506
 
 Six Months Ended June 30, 2015          
 
Net Cash Provided By (Used In)
   Operating Activities
$410
 $1,508
 $61
 $(687) $1,292
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(480) $(963) $(210) $766
 $(887) 
 
Net Cash Provided By (Used In)
   Financing Activities
$70
 $(543) $150
 $(79) $(402) 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  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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  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 As of June 30, 2016          
 Current Assets$5,490
 $1,655
 $231
 $(4,828) $2,548
 
 Property, Plant and Equipment, net58
 6,476
 1,944
 —
 8,478
 
 Investment in Subsidiaries4,419
 345
 —
 (4,764) —
 
 Noncurrent Assets134
 2,041
 128
 (51) 2,252
 
 Total Assets$10,101
 $10,517
 $2,303
 $(9,643) $13,278
 
 Current Liabilities$1,079
 $3,719
 $1,293
 $(4,828) $1,263
 
 Noncurrent Liabilities420
 2,652
 392
 (51) 3,413
 
 Long-Term Debt2,380
 —
 —
 —
 2,380
 
 Member's Equity6,222
 4,146
 618
 (4,764) 6,222
 
 Total Liabilities and Member's Equity$10,101
 $10,517
 $2,303
 $(9,643) $13,278
 
 As of December 31, 2015          
 Current Assets$4,501
 $1,912
 $364
 $(4,828) $1,949
 
 Property, Plant and Equipment, net83
 6,502
 1,542
 —
 8,127
 
 Investment in Subsidiaries4,501
 346
 —
 (4,847) —
 
 Noncurrent Assets155
 1,959
 136
 (76) 2,174
 
 Total Assets$9,240
 $10,719
 $2,042
 $(9,751) $12,250
 
 Current Liabilities$1,112
 $3,866
 $1,076
 $(4,828) $1,226
 
 Noncurrent Liabilities442
 2,597
 375
 (76) 3,338
 
 Long-Term Debt1,684
 —
 —
 —
 1,684
 
 Member's Equity6,002
 4,256
 591
 (4,847) 6,002
 
 Total Liabilities and Member's Equity$9,240
 $10,719
 $2,042
 $(9,751) $12,250
 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 As of September 30, 2016          
 Current Assets$4,889
 $1,845
 $287
 $(5,262) $1,759
 
 Property, Plant and Equipment, net57
 6,570
 2,080
 —
 8,707
 
 Investment in Subsidiaries4,709
 483
 —
 (5,192) —
 
 Noncurrent Assets157
 2,140
 123
 (76) 2,344
 
 Total Assets$9,812
 $11,038
 $2,490
 $(10,530) $12,810
 
 Current Liabilities$818
 $3,888
 $1,350
 $(5,262) $794
 
 Noncurrent Liabilities473
 2,704
 394
 (76) 3,495
 
 Long-Term Debt2,381
 —
 —
 —
 2,381
 
 Member’s Equity6,140
 4,446
 746
 (5,192) 6,140
 
 Total Liabilities and Member’s Equity$9,812
 $11,038
 $2,490
 $(10,530) $12,810
 
 As of December 31, 2015          
 Current Assets$4,501
 $1,912
 $364
 $(4,828) $1,949
 
 Property, Plant and Equipment, net83
 6,502
 1,542
 —
 8,127
 
 Investment in Subsidiaries4,501
 346
 —
 (4,847) —
 
 Noncurrent Assets155
 1,959
 136
 (76) 2,174
 
 Total Assets$9,240
 $10,719
 $2,042
 $(9,751) $12,250
 
 Current Liabilities$1,112
 $3,866
 $1,076
 $(4,828) $1,226
 
 Noncurrent Liabilities442
 2,597
 375
 (76) 3,338
 
 Long-Term Debt1,684
 —
 —
 —
 1,684
 
 Member’s Equity6,002
 4,256
 591
 (4,847) 6,002
 
 Total Liabilities and Member’s Equity$9,240
 $10,719
 $2,042
 $(9,751) $12,250
 
            

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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), 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. PSE&G and Power each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG'sPSEG’s business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:
PSE&G, our public utility company which is 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 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, and
Power, our multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA), and the states in which they operate.
PSEG'sPSEG’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 operates the Long Island Power Authority'sAuthority’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 2015 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 2015 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2016 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 2015 Form 10-K.

EXECUTIVE OVERVIEW OF 2016 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:
improving utility operations through growth in investment in T&D and other infrastructure projects designed to enhance resiliency, and
maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.




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Financial Results
The results for PSEG, PSE&G and Power for the three months and sixnine months ended JuneSeptember 30, 2016 and 2015 are presented as follows:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Earnings2016 2015 2016 2015 
  Millions 
 PSE&G$179
 $167
 $441
 $409
 
 Power (A)(11) 166
 181
 501
 
 Other (B)19
 12
 36
 21
 
 PSEG Net Income$187
 $345
 $658
 $931
 
          
 PSEG Net Income Per Share (Diluted)$0.37
 $0.68
 $1.30
 $1.83
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Earnings2016 2015 2016 2015 
  Millions 
 PSE&G$255
 $222
 $696
 $631
 
 Power (A) (B)139
 206
 320
 707
 
 Other (C)(67) 11
 (31) 32
 
 PSEG Net Income$327
 $439
 $985
 $1,370
 
          
 PSEG Net Income Per Share (Diluted)$0.64
 $0.87
 $1.94
 $2.70
 
          
(A)Includes after-tax expenses of $67 million related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants in the three months and nine months ended September 30, 2016. See Item 1. Note 3. Early Plant Retirements for additional information.
(B)Includes an after-tax insurance recovery for Superstorm Sandy of $27 million and $102 million in the three months and sixnine months ended JuneSeptember 30, 2015, respectively.2015.
(B)(C)Other includes activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded an after-tax impairment of $86 million related to its investments in NRG REMA, LLC’s leveraged leases in the three months and nine months ended September 30, 2016. See Item 1. Note 6. Financing Receivables for further information.
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 future delivery dates.
The variances in our Net Income include the changes related to NDT and MTM shown in the following table:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2016 2015 2016 2015 
  Millions, after tax 
 NDT Fund Income (Expense) (A) (B)$(1) $1
 $(6) $3
 
 Non-Trading MTM Gains (Losses) (C)$(101) $28
 $(88) 8
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2016 2015 2016 2015 
  Millions, after tax 
 NDT Fund Income (Expense) (A) (B)$2
 $(14) $(4) $(11) 
 Non-Trading MTM Gains (Losses) (C)$34
 $50
 $(54) $58
 
          
(A)NDT Fund Income (Expense) includes the 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.
(B)Net of tax (expense) benefit of $(1) million, $(2) million, $2$10 million, $0 million and $(7)$3 million for the three and sixnine months ended JuneSeptember 30, 2016 and 2015, respectively.
(C)Net of tax (expense) benefit of $70$(24) million, $(20)$(34) million, $61$37 million and $(6)$(40) million for the three and sixnine months ended JuneSeptember 30, 2016 and 2015, respectively.
Our $158$112 million decrease in Net Income for the three months ended JuneSeptember 30, 2016 was driven primarily by
MTM lossesan impairment related to investments in 2016 as comparedcertain leveraged leases at Energy Holdings (See Item 1. Note 6. Financing Receivables),
charges related to MTM gains in 2015,the early retirement of two coal/gas generation units at Power (See Item 1. Note 3. Early Plant Retirements), and

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lower volumes of energy sold at lower average realized prices and lower capacity revenues, primarily in the PJM Interconnection, L.L.C. (PJM) region,
higher congestion costs in PJM resulting from credits received in 2015 due to the colder than normal weather, and
insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy.region.
These decreases were partially offset by
higher revenues due to increased investments in transmission projects,
lower generation costs driven by lower natural gashigher electricity sales under non-BGS wholesale load contracts in PJM and New England (NE) and higher volumes of electricity sold at higher prices and reduced generation output,under our Basic Generation Service (BGS) contracts, and

lower other-than-temporary impairments of the NDT Fund.
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lower O&M expense at Power due to higher costs incurred in 2015 for planned major outages.
Our $273$385 million decrease in Net Income for the sixnine months ended JuneSeptember 30, 2016 was driven primarily by
the aforementioned charges in the 2016 third quarter for the early retirement of the two coal/gas generation units at Power,
MTM losses in 2016 as compared to MTM gains in 2015,
lower volumes of energy sold at lower average realized sales primarily in the PJM region and lower volumes of energy sold under wholesale load contracts,prices,
lower capacity and operating reserve revenues and capacity revenues in PJM,
higher 2016 congestion costs in PJM as a result of credits received in 2015 due to extremely colder weather,
lower volumes of gas sold at lower average prices under the Basic Gas Supply Service (BGSS) contract, and
insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy.Sandy, and

the aforementioned third quarter 2016 impairment on leveraged leases at Energy Holdings.
These decreases were partially offset by
•lower generation costs driven by lower fuel costs, particularly for natural gas, and reduced generation output at Power,
•a decrease in O&M expense at Power due to higher costs incurred at Power for planned outages in 2015, and
higher revenues due to increased investments in transmission projects.
During the first halfnine months of 2016, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results and allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our multi-year, long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, our merchant generator, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.
At PSE&G, in 2016 we continuedcontinue to make investments and seek recovery on such investments made to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014.2014 and to seek recovery on such investments. We also commenced modernizing PSE&G's&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. In 2017, as a result of our Energy Strong Order from the BPU, we will be required to file a Distribution rate case proceeding. We cannot predict the impact such proceeding will have on our distribution business.
Despite the unseasonable warm winter weather patterns during the first six months ofin 2016, Power’s results benefited from access to natural gas supplies through its existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the BGSS arrangement. The contracts are sized to provide for 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. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s strategic hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business.
Our recent investments in the latter half of 2015 and early 2016 in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These additions to

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our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.
Since 2013, eight nuclear generating stations in the United States totaling over 8,300 MW of capacity have closed or announced early retirement due to economic reasons. Fourreasons, and four additional stations totaling nearly 5,300 MW of capacity have been announced as being at risk for early retirement. This situation is generally due to low natural gas prices resulting from the growth of shale gas production since 2007, the continuing cost of regulatory compliance for nuclear facilities and both federal and state-level policies that provide credits to renewable energy such as wind and solar, but do not apply to nuclear generating stations. These trends have significantly reduced the revenues to nuclear generating stations while simultaneously raising the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating greater reliance on natural gas pipelines for delivery and less diversity of the generation fleet. Additionally, we believe that the early retirement of nuclear plants will lead to an increase in replacement energy and environmental costs.
WhileIf trends noted above continue or worsen, our nuclear generating units are not currently at riskcould cease being economically competitive which may cause us to retire such units prior to the end of earlytheir useful lives. The costs associated with any such retirement, wewhich may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs and environmental remediation costs, could be material. We continue to advocate for sound policies that recognize nuclear power as a source of clean energy and an important part of a diverse and reliable energy portfolio.

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Regulatory, Legislative and Other Developments
In our pursuit 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
In April 2013, PJM 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 in New Jersey. In February 2016, FERC issued an order granting PSE&G’s request that it be permitted to seek recovery of 100% of its portion of prudently incurred Artificial Island project costs if the project is cancelled for reasons beyond PSE&G’s control. In April 2016, PSE&G accepted construction responsibility for the three components of the Artificial Island project that PJM assigned to us. On August 5, 2016, PJM announced that it based on having reached agreement with PJM regarding an estimate forhas suspended the Artificial Island transmission project base costand is performing a comprehensive analysis to determine a future course of $273 million, plus risk and contingency for a totalaction, which is expected to be completed by February 2017. We may also from time to time have opportunities to submit transmission project cost of up to $340 million. PSE&G continues to work with PJM to optimizeproposals in regions where we are not the scope and cost of the project.incumbent. However, there can be no assurance that any such proposals would be successful.
In April 2016, PJM filed at FERC to incorporate a voltage threshold into PJM’s Regional Transmission Expansion Plan (RTEP) process to exempt, except under certain circumstances, reliability violations on facilities below 200 kV from PJM’s proposal window process. We generally support this reform as a measure to improve the efficiency of the open window procedure that will permit transmission developers to focus on the projects most likely to benefit from a competitive process. 
There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G's&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey and may cause increased scrutiny regarding PSE&G's&G’s future capital investments. In addition, as a basic generation service (BGS) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to an adjustment, subject to BPU approval. We do not believe that these matters will have a material effect on Power'sPower’s business or results of operations.
Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners'owners’ base ROEs. While we are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, the results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

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Wholesale Power Market Design
In an important development in the proceedings concerning the actions that had been taken by the states of New Jersey and Maryland to subsidize new generation that is above market cost, in April 2016, the United States Supreme Court affirmed the decision of the lower courts that had held the action in Maryland to be unconstitutional. The Supreme Court’s ruling upholds FERC’s authority to foster competitive wholesale electricity markets and provides guidance to states in balancing their interests to encourage and support the development of renewables and other generating facilities. 
Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. In June 2015, FERC conditionally accepted a proposal from PJM for a capacity performance (CP) product to include generators, Demand Response and energy efficiency providers, which will be required to perform during emergency conditions, as a supplement to the base capacity product. The proposal included enhanced performance-based incentives and penalties. We believe that the auction pricing adequately reflects the increased costs that could result from operating under more stringent rules for generation availability. Based on the auction results, the CPcapacity performance 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 and financial risks. Appeals of FERC's CPFERC’s capacity performance orders are pending.
In May 2016, PJM announced the results of the RPM capacity auction for the 2019-2020 delivery year. Power cleared 8,895 MW of its generating capacity at an average price of $116 per MW-day for the 2019-2020 delivery period. Of the cleared capacity, Power believes that nearly all is compliant with PJM's CPPJM’s capacity performance requirements. In the two prior capacity auctions covering the 2017-2018 and 2018-2019 delivery years, Power cleared approximately 8,700 MW at average prices of $177 per MW-day and $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the emergency transfer limits due to transmission expansion and the effects of both the new generation and uncleared generation from the prior year’s auction.
An emerging issueAs a result of the efforts of certain entities in PJM involvesto obtain financial support arrangements from their state commission, a group of suppliers requested that FERC direct PJM to expand the impact ofcurrently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized existing generation on RPM market outcomes. These subsidiesgenerators would likely enable the affected generators to submit bids into the PJM capacity marketsmarket that aredid not reflective ofreflect their actual costs of operation and may prevent uneconomic generating facilities from retiring. Either of these conditions could artificially

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suppress capacity market prices, especially given that PJM’sprices. We are currently effective “minimum offer price rule” (MOPR) which applies only to new gas-fired units, would not apply to these plants. Givenawaiting FERC action on the uncertainty surrounding these possible subsidies, wesuppliers’ request and cannot predict the effects this might have on capacity prices andoutcome of the corresponding impact on our business.proceeding. See Part II, Item 5. Other Information—Federal Regulation—Capacity Market Issues—PJM for additional information.
Environmental Regulation
We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act (FWPCA) requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs. See Item 1. Note 8.9. Commitments and Contingent Liabilities for further information.
In October 2015, the EPA published the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act (CAA) for existing power plants. The regulation establishes state-specific emission targets based on implementation of the best systems of emission reduction. We continue to work with FERC and other federal and state regulators, as well as industry partners, to determine the potential impact of these regulations.
The U.S. Supreme Court’s February 2016 decision to stay the implementation of the CPP will delay deadlines for submission of state requests for extensions and final plans. If the CPP is upheld, new deadlines will need to be established and the effective date of the compliance period may be impacted.
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous 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. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs of any such remediation efforts could be material.
For further information regarding the matters described above as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 8.9. Commitments and Contingent Liabilities.
FERC Compliance
Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power'sPower’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. This investigation is ongoing. The amounts of potential disgorgement and other potential penalties that we may incur span a wide range depending on the success of our legal arguments. If our legal arguments do not prevail, in whole or in part with FERC or in a judicial challenge that we may

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choose to pursue, it is likely that Power would record losses that would be material to PSEG'sPSEG’s and Power'sPower’s results of operations in the quarterly and annual periods in which they are recorded. For additional information, see Item 1. Note 8.9. Commitments and Contingent Liabilities.
Early Retirement of Hudson and Mercer Units
In October 2016, Power determined it will cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. The exact timing of the early retirement of these units will be reviewed for reliability impacts by PJM, and may be impacted by operational and other conditions that could subsequently arise. The decision to retire the Hudson and Mercer units will have a material effect on PSEG’s and Power’s results of operations. In the third quarter of 2016, PSEG and Power recognized one-time pre-tax charges in Energy Costs, Operation and Maintenance and Depreciation and Amortization of $62 million, $48 million and $4 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs, construction work in progress impairments, and asset retirement obligation (ARO) adjustments, among other shut down items. In addition to these one-time charges, Power will recognize incremental Depreciation and Amortization during the remainder of 2016 of $568 million and $946 million into 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. Additional employee-related salary continuance and severance costs and various miscellaneous costs may also be incurred during the period prior to retirement. Finally, Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger investigation and possible remediation of identified environmental contamination. The amounts for any such environmental investigation or remediation are not currently probable or estimable but may be material. For additional information, including our estimated costs through 2017, see Item 1. Note 3. Early Plant Retirements.
The primary factors considered during our annual five-year strategic planning process that contributed to the decision to retire these units early include significant declines in revenues and margin caused by a sustained period of depressed wholesale power prices and reduced capacity factors caused by lower natural gas prices making coal generation less economically competitive than natural gas-fired generation. Despite experiencing recent warmer than normal weather in PJM this summer, Power did not experience the usual increase in electricity prices in PJM as it had in past hot summers. This trend has a further adverse economic impact to these units because they generally dispatch and earn energy margin on peak hot and cold days. In addition, the upcoming PJM capacity auction in May 2017 will be the first to require all generating units to meet the increased operating performance standards of PJM’s new capacity performance construct. Power determined that the costs to upgrade the existing units at the Hudson and Mercer stations to be able to comply with these higher reliability standards are too significant and not economic given current market conditions. 
In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone, Conemaugh and Bridgeport Harbor generating stations, to ensure their economic viability through the end of their designated useful lives. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact our ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement of our other coal units before the end of their current estimated useful lives may have a material adverse impact on PSEG’s and Power’s future financial results.
Leveraged Lease Impairments
During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016, calculated by comparing the gross investment in the leases before and after the revised residual estimates. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.
Additional facilities in our leveraged lease portfolio include the Joliet facility, which has converted to natural gas. The coal-fired units at the Shawville generating facility are expected to return to service in the fall of 2016 with the ability to use natural gas. However, these units may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. As a result, these facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged leases associated with these facilities.  

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REMA’s parent company, GenOn Energy, Inc. (GenOn), reported in August 2016 that it did not expect to have sufficient liquidity to repay their senior unsecured notes due in June 2017. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged leases.
Salem Operations
In April 2016, during a scheduled refueling outageThe previously announced bolt replacement at Salem Unit 1 a visual inspection revealed degradation to a number of bolts inside the reactor vessel. The bolt replacement has beenwas completed and the unit is in the process of returningreturned to service.service on July 30, 2016. We expect to continue to inspect and replace degraded bolts at both Salem units over the next several refueling outage cyclescycles. We are participating with the Electric Power Research Institute, the Nuclear Energy Institute and other operators of similarly-designed pressurized water reactors in developing a strategic solutionstrategy to maintain the long-term health of boththe reactor vessel internals is under review. Production and margin effects for the second quarter of 2016 were largely offset by the increased production at Peach Bottom as a result of the Extended Power Uprates made in 2015 being fully operational. internals. 
Extension of the Salem Unit 1 outage into July and an unplanned outage at Salem Unit 2 will have a continuing effect ondue to transformer issues reduced output from the Salem units in the third quarter, performance.which was partially offset by increased production at our Hope Creek and Peach Bottom units. As a result, our nuclear capacity factor for the nine months ended September 30, 2016 was 88%.

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 yearin a rapidly evolving market as we remain diligent in managing costs. For the first sixnine months of 2016, our
total nuclear fleet achieved an average capacity factor of 91.2%, and
diverse fuel mix and dispatch flexibility allowed us to generate approximately 2640 terra-watt hours while addressing unit outages and balancing fuel availability and price volatility.volatility and compensating for the extended outages at our Salem units, and

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63%.
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 sixnine months of 2016 as we
had cash on hand of $648$450 million as of JuneSeptember 30, 2016,
maintained solid investment grade credit ratings, and
increased our indicative annual dividend for 2016 to $1.64 per share.
We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, without the issuance of new equity.
Disciplined Investment
We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first halfnine months of 2016, we
made additional investments in transmission infrastructure projects,
began executing our GSMP and continued executing Energy Strong and other existing BPU-approved utility programs,
commenced construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and announced our plan to construct BH5 and commence operations in mid-2019, and
acquired three solar energy projects totaling 100 MW-direct currentcurrent. Two of these projects are already in service in North Carolina and Colorado. The third project is in Colorado and expected to go intobe in service during 2016.by year end.
Future Outlook    
Our future success will depend on our ability to continue to maintain strong operational and financial performance in a slow-growing economy and a cost-constrained environment with low gas prices, 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,

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successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,
execute our utility capital investment program, including our Energy Strong program, 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, Sewaren 7, BH5 and other generation projects,
advocate for measures to ensure the implementation by PJM and 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 and manage LIPA'sLIPA’s fuel supply and generation dispatch obligations.
For 2016 and beyond, the key issues and challenges we expect our business to confront include:
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,
fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our base rate case which must be filed with the BPU no later than November 1, 2017,
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,

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the potential for continued reductions in demand and sustained lower natural gas and electricity prices, both at market hubs and the locations where we operate,
the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,
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,
maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and
FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.
Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:
the acquisition, construction or disposition of transmission and distribution facilities and/or generation units,
the disposition or reorganization of our merchant generation business or other existing businesses or the acquisition or development of new businesses, such as retail energy marketing,
the expansion of our geographic footprint,
continued or expanded participation in solar, demand response and energy efficiency programs, and
investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, and modernizing existing infrastructure.infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.
We continue to actively explore opportunities in the retail energy marketing business, which we believe would complement our existing wholesale marketing business. Our entry into the retail energy marketing business is subject to market conditions and regulatory approval, among other things.

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There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.


RESULTS OF OPERATIONS
PSEG
Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PSE&G and Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note 17.18. Related-Party Transactions.
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2016 2015 2016 vs. 2015 2016 2015 2016 vs. 2015 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,905
 $2,314
 $(409) (18) $4,521
 $5,449
 $(928) (17) 
 Energy Costs624
 668
 (44) (7) 1,460
 1,762
 (302) (17) 
 Operation and Maintenance710
 761
 (51) (7) 1,439
 1,424
 15
 1
 
 Depreciation and Amortization224
 317
 (93) (29) 448
 647
 (199) (31) 
 Income from Equity Method Investments4
 4
 —
 —
 6
 7
 (1) (14) 
 Other Income (Deductions)34
 66
 (32) (48) 61
 102
 (41) (40) 
 Other-Than-Temporary Impairments10
 10
 —
 —
 20
 15
 5
 33
 
 Interest Expense97
 97
 —
 —
 189
 195
 (6) (3) 
 Income Tax Expense91
 186
 (95) (51) 374
 584
 (210) (36) 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2016 2015 2016 vs. 2015 2016 2015 2016 vs. 2015 
  Millions Millions % Millions Millions % 
 Operating Revenues$2,450
 $2,688
 $(238) (9) $6,971
 $8,137
 $(1,166) (14) 
 Energy Costs866
 815
 51
 6
 2,326
 2,577
 (251) (10) 
 Operation and Maintenance776
 746
 30
 4
 2,215
 2,170
 45
 2
 
 Depreciation and Amortization231
 313
 (82) (26) 679
 960
 (281) (29) 
 Income from Equity Method Investments3
 3
 —
 —
 9
 10
 (1) (10) 
 Other Income (Deductions)39
 33
 6
 18
 100
 135
 (35) (26) 
 Other-Than-Temporary Impairments5
 30
 (25) (83) 25
 45
 (20) (44) 
 Interest Expense99
 96
 3
 3
 288
 291
 (3) (1) 
 Income Tax Expense188
 285
 (97) (34) 562
 869
 (307) (35) 
                  
The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.


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PSE&G
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2016 2015 2016 vs. 2015 2016 2015 2016 vs. 2015 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,350
 $1,466
 $(116) (8) $3,062
 $3,468
 $(406) (12) 
 Energy Costs529
 544
 (15) (3) 1,258
 1,436
 (178) (12) 
 Operation and Maintenance352
 368
 (16) (4) 734
 780
 (46) (6) 
 Depreciation and Amortization136
 234
 (98) (42) 275
 481
 (206) (43) 
 Other Income (Deductions)18
 18
 —
 —
 37
 35
 2
 6
 
 Interest Expense74
 67
 7
 10
 142
 136
 6
 4
 
 Income Tax Expense98
 104
 (6) (6) 249
 261
 (12) (5) 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2016 2015 2016 vs. 2015 2016 2015 2016 vs. 2015 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,684
 $1,766
 $(82) (5) $4,746
 $5,234
 $(488) (9) 
 Energy Costs721
 740
 (19) (3) 1,979
 2,176
 (197) (9) 
 Operation and Maintenance376
 391
 (15) (4) 1,110
 1,171
 (61) (5) 
 Depreciation and Amortization137
 231
 (94) (41) 412
 712
 (300) (42) 
 Other Income (Deductions)21
 22
 (1) (5) 58
 57
 1
 2
 
 Interest Expense72
 67
 5
 7
 214
 203
 11
 5
 
 Income Tax Expense144
 137
 7
 5
 393
 398
 (5) (1) 
                  
Three Months Ended JuneSeptember 30, 2016 as Compared to 2015
Operating Revenues decreased $116$82 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues increased $28$57 million due primarily to an increase in transmission revenues.
Transmission revenues were $48$50 million higher due to increased capital investments.
Electric distribution revenues decreased $19increased $8 million due primarily to $12 million in higher sales volumes and $12 million due to the inclusion of Energy Strong in base rates, partially offset by lower Green Program Recovery Charges (GPRC) of $14 million and $5 million in lower sales volumes.$16 million.

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Commodity Revenue decreased $15$19 million as a result of $30$14 million of lower ElectricGas revenues partially offset by $15and $5 million in higher Gasof lower Electric revenues. Commodity revenue for both electricgas and gaselectric is entirely offset with the change in Energy Costs. PSE&G earns no margin on the provision of BGSBGSS and BGSSBGS to retail customers.
Gas revenues decreased $14 million due to $25 million of lower BGSS sales volumes, partially offset by $11 million in higher prices.
Electric revenues decreased $30$5 million due primarily to $15$17 million of lower revenues from collections of Non-Utility Generation Charges (NGC), a $7 million or 2% decrease in BGS revenues due to lower sales volumes, and a decrease of $8$14 million due to lower volumes of Non-Utility Generation (NUG) energy sold.
Gassold at lower prices. These decreases were partially offset by a $26 million increase in BGS revenues increased $15 million due to higher BGSS sales volumes.
Clause Revenues decreased $128$121 million due primarily to lower Securitization Transition Charges (STC) of $122 million and lower Societal Benefit Charges (SBC) of $5$118 million. The STC reduction iswas a result of rate reductions due to the completion of securitization collections in 2015. The changes in the STC and SBC amounts are entirely offset by decreases in 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 or SBC collections.
Operating Expenses
Energy Costs decreased $15$19 million. This is entirely offset by the change in Commodity Revenue.
Operation and Maintenance decreased $16$15 million, of which the most significant components were
a $28$23 million net reduction in costs related to various clause mechanisms, including SBC and STC, and GPRC, and
a $2 million decreasein pension and OPEB costs, net of capitalized amounts,
partially offset by a $7net increase of $10 million increase in operating expenses, including increases in appliance service costs, gas distribution maintenance, due to increases of $4 million for vegetation managementcosts and $3 million forelectric distribution corrective maintenance.
Depreciation and Amortization decreased $98$94 million due to a decrease of $116$114 million in amortization of Regulatory Assets primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by a $17an $18 million increase in depreciation due to additional plant in service.
Interest Expense increased $7$5 million due primarily to an increase of $8$7 million due to net debt issuances in 2015 and 2016.2016, partially offset by a $2 million decrease due to the redemption of securitization debt in 2015.
Income Tax Expense decreased $6increased $7 million due primarily to plant and other flow throughhigher pre-tax income, partially offset by plant-related items and uncertain tax positions, partially offset by higher pre-tax income.positions.

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SixNine Months Ended JuneSeptember 30, 2016 as Compared to 2015
Operating Revenues decreased $406$488 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues increased $57$116 million due primarily to an increase in transmission revenues.
Transmission revenues were $102$152 million higher due to increased capital investments.
Electric distribution revenues decreased $42$30 million due primarily to lower GPRC of $26$42 million and a $4 million decrease due to lower sales volumes partially offset by $16 million increase due to the inclusion of Energy Strong in lower sales volumes.base rates.
Gas distribution revenues decreased $3$6 million due primarily to $68$75 million of lower delivery volumes and lower GPRC of $7 million due to lower sales volumes from warmer winter weather. These decreases were almost entirely offset by $62$64 million in higher Weather Normalization Clause revenue and $10a $12 million increase due to the roll ininclusion of Energy Strong intoin base rates effective September 1, 2015.
Commodity Revenue decreased $178$197 million as a result of lower Gas and Electric revenues. Commodity revenue for both gas and electric is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGSS and BGS to retail customers.
Gas revenues decreased $94$108 million due primarily to lower BGSS sales volumes.
Electric revenues decreased $84$89 million due primarily to a $42 million or 5% decrease in BGS revenues due to lower sales volumes, $26$43 million of lower revenues from collections of NGC, and a decrease of $16$31 million due to lower volumes of NUG energy sold atand a $15 million or 1% decrease in BGS revenues due primarily to lower prices.sales volumes.

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Clause Revenues decreased $282$402 million due primarily to lower STC of $251$370 million, and lower SBC of $38 million and $9 million of lower SPRC, partially offset by higher Margin Adjustment Clause (MAC) revenue of $14$15 million. The STC reduction is a result of rate reductions due to the completion of securitization collections in 2015. The changes in the STC, SBC, SPRC and MAC amounts are entirely offset by decreases in the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SBC, SPRC or MAC collections.
Operating Expenses
Energy Costs decreased $178$197 million. This is entirely offset by the change in Commodity Revenue.
Operation and Maintenance decreased $46$61 million, of which the most significant components were
a $72$95 million net reduction in costs related to various clause mechanisms, including SBC, SPRC, STC and MAC, and GPRC, and
a $10 million decrease in pension and OPEB costs, net of capitalized amounts,
partially offset by an $11 million increase in distribution maintenance, due to increases of $6 million for corrective maintenance and $5 million for vegetation management and
$10$10 million of storm insurance recovery proceeds received in 2015.2015,
an $8 million increase in electric distribution corrective maintenance,
a $5 million increase in vegetation management,
a $5 million increase in transmission related maintenance and
a $16 million increase in operating expenses, including $3 million increases related to both appliance service costs and gas distribution costs.
Depreciation and Amortization decreased $206$300 million due to a decrease of $239$353 million in amortization of Regulatory Assets primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by a $32$49 million increase in depreciation due to additional plant in service.
Interest Expense increased $6$11 million due primarily to an increase of $13$20 million due to net debt issuances in 2015 and 2016, partially offset by an $8a $10 million decrease due to the redemption of securitization debt in 2015.
Income Tax Expense decreased $12$5 million due primarily to plantuncertain tax positions, plant-related and other flow through items, and uncertain tax positionspartially offset by higher pre-tax income.

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Power
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2016 2015
 2016 vs. 2015 2016 2015 2016 vs. 2015 
  Millions Millions % Millions Millions % 
 Operating Revenues$714
 $1,025
 $(311) (30) $2,027
 $2,750
 $(723) (26) 
 Energy Costs381
 409
 (28) (7) 1,019
 1,302
 (283) (22) 
 Operation and Maintenance265
 313
 (48) (15) 518
 485
 33
 7
 
 Depreciation and Amortization80
 75
 5
 7
 159
 151
 8
 5
 
 Income from Equity Method Investments4
 5
 (1) (20) 6
 8
 (2) (25) 
 Other Income (Deductions)16
 48
 (32) (67) 24
 66
 (42) (64) 
 Other-Than-Temporary Impairments10
 10
 —
 —
 20
 15
 5
 33
 
 Interest Expense20
 33
 (13) (39) 42
 64
 (22) (34) 
 Income Tax Expense(11) 72
 (83) N/A
 118
 306
 (188) (61) 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2016 2015
 2016 vs. 2015 2016 2015 2016 vs. 2015 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,075
 $1,096
 $(21) (2) $3,102
 $3,846
 $(744) (19) 
 Energy Costs462
 367
 95
 26
 1,481
 1,669
 (188) (11) 
 Operation and Maintenance289
 263
 26
 10
 807
 748
 59
 8
 
 Depreciation and Amortization86
 75
 11
 15
 245
 226
 19
 8
 
 Income from Equity Method Investments3
 3
 —
 —
 9
 11
 (2) (18) 
 Other Income (Deductions)17
 11
 6
 55
 41
 77
 (36) (47) 
 Other-Than-Temporary Impairments5
 30
 (25) (83) 25
 45
 (20) (44) 
 Interest Expense24
 30
 (6) (20) 66
 94
 (28) (30) 
 Income Tax Expense90
 139
 (49) (35) 208
 445
 (237) (53) 
                  
Three Months Ended JuneSeptember 30, 2016 as Compared to 2015
Operating Revenues decreased $311$21 million due to changes in generation, gas supply and other revenues.
Generation Revenues decreased $300$23 million due primarily to
a decrease of $212 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $187 million was due to changes in forward power prices, which increased in the current period and decreased during the comparable period in 2015. Also contributing to the decrease was $25 million from higher gains on positions reclassified to realized upon settlement this year compared to last year, 
a decrease of $66$73 million in energy sales volumes and lower average realized prices, primarily in the PJM region, due to lower volumes and lower average realized prices,
a decrease of $14$24 million in capacity revenue, primarily in the PJM region,
partially offset by a net increase of $44 million in electricity sold under non-BGS wholesale load contracts in the PJM and NE regions due to the retirementhigher volumes sold partially offset by lower average prices, and
an increase of older peaking units in June 2015, and
a net decrease of $8$24 million in electricity sold under our BGS contracts due primarily to lower volumes.

Gas Supply Revenues decreased $11 million due primarily to
a net decrease of $15 million in sales under the BGSS contract primarily due to lower average sales prices and MTM losses, and
a net increase of $4 million on sales to third party customers, of which $8 million was due to higher volumes sold partially offset by $4 millionas a result of lowerwarmer weather, coupled with higher average sales prices.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $28 million due to
Generation costs decreased $37 million due primarily to lower natural gas and coal fuel costs of $30 million reflecting lower average realized prices and the utilization of lower volumes.
Gas costsincreased $9 million mainly related to higher volumes sold to third parties.
Operation and Maintenance decreased $48$95 million due primarily to

a net decrease of $35Generation costs increased $93 millionrelated to our fossil plants, primarily due to higher costs incurred in 2015 for the installation of upgraded technology at our combined cycle Bergen generating plant, and

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a net decrease$62 million charge associated with the announced early retirement of $33 million related to our nuclear facilities, largely due to a planned outage at our 100%-owned Hope Creek plant in 2015, partly offset in 2016 by an extended refueling outage at our 57%-owned Salem Unit 1 plant,
partially offset by $17 million of insurance recoveries received in 2015 related to Superstorm Sandy,
Depreciationthe coal/gas Mercer and Amortization increased $5 million dueHudson generation units, primarily to a higher depreciable nuclear asset base.
Other Income (Deductions) decreased $32 million due primarily to $28 million of insurance recoveries received in 2015 related to Superstorm Sandy and higher net realized gains from the NDT Fund in 2015.
Interest Expense decreased $13 million due primarily to the maturity of $300 million of 5.50% Senior Notes in December 2015 and higher capitalized interest in 2016.
Income Tax Expense decreased $83 million in 2016 due primarily to lower pre-tax income, partially offset by a benefit related to a Nuclear Decommissioning Tax Carryback transaction that was recorded in 2015.coal inventory write-down of $57 million,
Six Months Ended June 30, 2016 as Compared to 2015
Operating Revenuesdecreased$723 million due to changes in generation and gas supply revenues.
Generation Revenues decreased $474 million due primarily to
a decreasean increase of $173$32 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $103$25 million was due to lower gains on positions reclassified to realized upon settlement this year compared to last year, and
an increase of $13 million due to increases in purchases of renewable energy credits and energy to serve load contracts,
partially offset by a decrease of $20 million due primarily to lower natural gas costs reflecting lower average realized prices.
Operation and Maintenance increased $26 million due primarily to
$48 million of charges related to the early retirement of the Hudson and Mercer units,
partially offset by a net decrease of $18 million due to the timing of a planned outage at our 50%-owned Peach Bottom nuclear plant.

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Depreciation and Amortization increased $11 million due primarily to
a $7 million increase due primarily to a higher nuclear asset base, and
$4 million of accelerated depreciation on asset retirement costs from previously retired assets at the Hudson and Mercer plants.
Other Income (Deductions) increased $6 million due primarily to lower net realized losses from the NDT Fund in 2016.
Other-Than-Temporary Impairments decreased $25 million due to lower impairments of equity securities in the NDT Fund in 2016.
Interest Expense decreased $6 million due primarily to higher capitalized interest in 2016.
Income Tax Expense decreased $49 million in 2016 due primarily to lower pre-tax income.
Nine Months Ended September 30, 2016 as Compared to 2015
Operating Revenuesdecreased$744 million due to changes in generation, gas supply and other revenues.
Generation Revenues decreased $497 million due primarily to
a decrease of $213 million in energy sales volumes in the PJM, NE and New York (NY) regions due primarily to milder weather and lower average realized prices,
a decrease of $166 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $127 million was due to higher gains on positions reclassified to realized upon settlement this year compared to last year. Also contributing to the decrease was $70were lower MTM gains of $39 million from a decreasedue to minor changes in forward power prices in 2015,
a decrease of $140 million in energy sales volumes in the PJM and New England (NE) regions due primarilythis year compared to milder weather and lower average realized prices in the PJM and New York regions,last year,
a net decrease of $87$113 million primarily in the PJM region due to lower operating reserve revenues coupled with lower capacity revenuesrevenue resulting from the retirement of older peaking units in June 2015, coupled with lower operating reserve revenue, and
a net decrease of $40$10 million in electricity sold under wholesale loadour BGS contracts in the PJM and NE regions due primarily to lower volumes and loweras a result of milder weather, partially offset by higher average prices.

Gas Supply Revenues decreased $249$248 million due primarily to
a net decrease of $234$241 million in sales under the BGSS contract, substantially comprised of lower sales volumes due to warmer average temperatures in the 2016 winter heating season, coupled with lower average sales prices, and
a net decrease of $15$7 million onin sales to third party customers, of which $47$45 million was due to lower average sales prices, partially offset by $32$38 million of higher volumes sold.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $283188 million due to

Generation costs decreased $160$67 million due primarily to
lower fuel costs of $267$287 million reflecting lower average realized prices for natural gas and the utilization of lower volumes of fuel, and
a decrease of $18 million due to MTM gains in 2016 as compared to MTM losses in 2015. The 2016 MTM gains were primarily due to favorable forward price movements on natural gas, while the 2015 MTM losses were primarily due to higher gains on positions reclassified to realized upon settlement on transmission products, 
partially offset by higher congestion costs in PJM of $142$137 million, mainly as a result of credits received in the prior year due to extremely cold weather.winter weather,
a $62 million charge associated with the announced early retirement of the Mercer and Hudson units, primarily related to a coal inventory write-down of $57 million, and
a net increase of $15 million due to lower MTM gains in 2016 as compared to 2015. Of this amount, $10 million was due to lower gains on positions reclassified to realized upon settlement this year compared to last year.

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Gas costs decreased $123$121 million mainly related to
a decrease of $136$142 million related to sales under the BGSS contract due primarily to lower volumes sold due to warmer average temperatures during the 2016 winter heating season and lower average gas costs,
partially offset by a net increase of $13$21 million related to sales to third parties due primarily to an increase in volumes sold.

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Operation and Maintenance increased $33$59 million due primarily to
$145 million of insurance recoveries received in 2015 related to Superstorm Sandy,
$48 million of charges related to early retirement of the Hudson and Mercer units,
partially offset by a net decrease of $85$75 million related to our fossil plants, largely due to higher costs incurred in 2015 for our planned major outages at the Bethlehem Energy Center and Bergen generating plants, and
a net decrease of $38$58 million related to our nuclear plants due primarily to the aforementioned reasons provided for the second quarter variance.a planned outage at our 100%-owned Hope Creek plant and our 50%-owned Peach Bottom plant in 2015, partly offset in 2016 by an extended refueling outage at our 57%-owned Salem Unit 1 plant.
Depreciation and Amortization increased $819 million due primarily to
a $12 million increase due primarily to a higher depreciable nuclear asset base.base,
$4 million of accelerated depreciation on asset retirement costs from previously retired assets at the Hudson and Mercer plants, and
$3 million of higher depreciation due to new solar projects.
Other Income (Deductions) decreased $42$36 million due primarily to $28 million of insurance recoveries received in 2015 related to Superstorm Sandy and higherlower net realized gains from the NDT Fund in 2015.2016.
Other-Than-Temporary Impairments increased $5decreased $20 million due to an increase inlower impairments of equity securities in the NDT Fund in 2016.
Interest Expense decreased $22$28 million due primarily to higher capitalized interest in 2016 and the maturity of $300 million of 5.50% Senior Notes in December 2015, and higher capitalized interestpartially offset by the issuance of $700 million of 3.00% Senior Notes in June 2016.
Income Tax Expense decreased $188$237 million in 2016 due primarily to lower 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
We expect operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder dividend payments.
For the sixnine months ended JuneSeptember 30, 2016, our operating cash flow decreased $512467 million as compared to the same period in 2015. The net change was due primarily to the net changes from PSE&G and Power as discussed below.
PSE&G
PSE&G’s operating cash flow decreased $101117 million from $9091,518 million to $8081,401 million for the sixnine months ended JuneSeptember 30, 2016, as compared to the same period in 2015, due primarily to a decrease of $87$113 million due to a change in regulatory deferrals, primarily driven by lower volumes due to warmer weather impacting our Gas Weather Normalization, SBC, GPRC and BGSS clauses and a $77$64 million decrease due to higher vendor payments.payments and a decrease due to the completion of securitization collections in 2015. These amounts were partially offset by higher earnings and higher tax refunds in 2016.
Power
Power’s operating cash flow decreased $375298 million from $1,2921,558 million to $9171,260 million for the sixnine months ended JuneSeptember 30, 2016, as compared to the same period in 2015, primarily due to lower earnings, a $123$140 million decrease from fuels, materials and supplies, and a $115$146 million increase in margin deposit requirements, partially offset by a reduction in 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.

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We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of JuneSeptember 30, 2016 were as follows:
         
 Company/Facility As of June 30, 2016 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,000
 $10
 $990
 
 PSE&G 600
 14
 586
 
 Power 2,553
 202
 2,351
 
 Total $4,153
 $226
 $3,927
 
         
         
 Company/Facility As of September 30, 2016 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,000
 $265
 $735
 
 PSE&G 600
 14
 586
 
 Power 2,553
 205
 2,348
 
 Total $4,153
 $484
 $3,669
 
         
As of JuneSeptember 30, 2016, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power losing its investment grade credit rating, which would represent a three level downgrade from its current S&P and Moody’s ratings. In the event of a deterioration of Power’s credit rating certain of Power'sPower’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if Power were to lose its investment grade credit rating was approximately $748$807 million and $864 million as of JuneSeptember 30, 2016 and December 31, 2015, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units is not expected to have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 1. Note 3. Early Plant Retirements.
As of JuneSeptember 30, 2016, PSEG’s credit facilities are primarily available to back-stop its Commercial Paper Program and issue letters of credit. As of June 30, 2016, no Commercial Paper wasunder which PSEG had $255 million outstanding. PSE&G's&G’s credit facility primary use is to support its Commercial Paper Program under which as of JuneSeptember 30, 2016, no amounts were outstanding. Most of our credit facilities expire in 2019 and 2020.
For additional information, see Item 1.Note 9.10. Debt and Credit Facilities.
Long-Term Debt Financing
Power has $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 2016, see Item 1. Note 9.10. Debt and Credit Facilities.
Common Stock Dividends
On AprilJuly 19, 2016, our Board of Directors approved a $0.41 per share of common stock dividend for the second quarter of 2016. On July 19, 2016, our Board of Directors declared a quarterly dividend of $0.41 per share of common stock for the third quarter of 2016. This reflects an indicative annual dividend rate of $1.64 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 15.16. Earnings Per Share (EPS) and Dividends.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or 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'agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
In January 2016, S&P published updated research reports on PSEG and PSE&G and the existing ratings and outlooks were unchanged. In June 2016, Moody'sMoody’s published credit opinions on Power and PSE&G and the existing ratings and outlooks were

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unchanged. In June 2016, S&P published an updated research report on Power and the existing rating and outlook were unchanged.

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In September 2016, Moody’s published an updated research report on PSEG and the existing rating and outlook were unchanged.
       
   Moody’s (A) S&P (B) 
 PSEG     
 Outlook Positive Stable 
 Commercial Paper P2 A2 
 PSE&G     
 Outlook Stable Stable 
 Mortgage Bonds Aa3 A 
 Commercial Paper P1 A2 
 Power     
 Outlook Stable Stable 
 Senior Notes Baa1 BBB+ 
       
(A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.
(B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. The Corporate Credit Rating outlook does not apply to PSEG'sPSEG’s or PSE&G's&G’s Commercial Paper Rating or PSE&G's&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. There were no material changes to our projected capital expenditures at Power and Services as compared to amounts disclosed in our 2015 Form 10-K.
PSEG
In July 2016, PSEG partnered with Vectren Corporation on a FERC 1000 proposal to construct, own and operate a twenty mile, 345 kilovolt transmission line in the midwest region served by the Midcontinent Independent System Operator (MISO). MISO estimated the project would cost approximately $60 million and would go in service in 2021. MISO is expected to select a proposal in December 2016. This project is not included in PSEG'sPSEG’s projected capital expenditures.    
PSE&G
PSE&G increased its estimate of its capital expenditure program as reported in our 2015 Form 10-K by approximately $300 million from $8.3 billion to $8.6 billion primarily to address new business requests and to replace aging equipment and infrastructure.   
In MayAugust 2016, PSE&G filed a petition with the BPU requesting approval of the $268 million investment and an associated cost recovery mechanism to develop a project where PSE&G would rebuild New Jersey Transit’s Mason substation and related facilities in Kearny, NJ. This is not included in PSE&G’s projected capital expenditures.
On October 20, 2016, PSE&G submitted a settlement agreement to the BPU providing for an extension of itsthe existing landfill/brownfield solar program to construct 100up to 33 MW of grid-connected solargrid connected facilities with projected capital expenditures of up to $240approximately $80 million through approximately 2021.May 2020. This extension is pending approval by the BPU. This is not included in PSE&G's&G’s projected capital expenditures.
During the sixnine months ended JuneSeptember 30, 2016, PSE&G made capital expenditures of $1,355$2,035 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of $74$109 million, which are included in operating cash flows.
Power
During the sixnine months ended JuneSeptember 30, 2016, Power made capital expenditures of $505$767 million, excluding $93156 million for nuclear fuel, primarily related to our Keys, Sewaren 7, BH5 and other generation projects.


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 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 AprilJuly through JuneSeptember 2016, MTM VaR remained relatively stable between low of $10$11 million to high of $18$16 million at 95% confidence level. The range of VaR was narrower for the three months ended JuneSeptember 30, 2016 as compared with the year ended December 31, 2015.
       
   MTM VaR 
   Three Months Ended June 30, 2016 Year Ended December 31, 2015 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $16
 $24
 
 Average for the Period $15
 $17
 
 High $18
 $40
 
 Low $10
 $8
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $25
 $38
 
 Average for the Period $23
 $26
 
 High $27
 $63
 
 Low $16
 $12
 
       
       
   MTM VaR 
   Three Months Ended September 30, 2016 Year Ended December 31, 2015 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $11
 $24
 
 Average for the Period $13
 $17
 
 High $16
 $40
 
 Low $11
 $8
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $17
 $38
 
 Average for the Period $21
 $26
 
 High $25
 $63
 
 Low $17
 $12
 
       
See Item 1. Note 10.11. 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, Public Service Electric and Gas 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, 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
There have been no changes in internal control over financial reporting that occurred during the secondthird quarter of 2016 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

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 of Part I of the 2015 Annual Report on Form 10-K, see Part I, Item 1. Note 8.9. Commitments and Contingent Liabilities and Item 5. Other Information.
Ewing Explosion
In February 2014, pursuant to an existing contract, PSE&G assigned Henkels and McCoy (Henkels) to replace the electrical service at a home in the South Fork Townhouse Community in Ewing Township, Mercer County, New Jersey. In March 2014, after Henkels began work to install new electric service, a gas explosion occurred in the townhouse community resulting in damage to numerous properties, personal injuries and one fatality.
Twenty-two lawsuits have been filed to date relating to the gas explosion, of which PSE&G was named as a defendant in nineteen cases. To date, six of these cases have resolved through private negotiations and/or mediation. In one of the remaining pending matters, plaintiffs representing the estate of the decedent are seeking damages under the New Jersey Wrongful Death Act and the New Jersey Survivors Act as well as punitive damages. PSE&G has denied all allegations of liability. We intend to continue to vigorously defend these lawsuits. At this stage of the litigation, we are unable to determine or predict the ultimate outcome of any of the remaining lawsuits.

ITEM 1A.RISK FACTORS
There are no additional Risk Factors to be added to those disclosed in Part I, Item 1A of our 2015 Annual Report on Form 10-K.


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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 secondthird quarter of 2016.
      
 Three Months Ended June 30, 2016
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 April 1 - April 30—
 $—
 
 May 1 - May 31228,639
 $46.23
 
 June 1- June 3050,000
 $44.50
 
      
      
 Three Months Ended September 30, 2016
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 July 1 - July 31—
 $—
 
 August 1 - August 31167,430
 $45.21
 
 September 1- September 3043,000
 $42.85
 
      

ITEM 5. OTHER INFORMATION
Certain information reported in the 2015 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2015 Annual Report on Form 10-K and the Quarterly ReportReports on Form 10-Q for the quarterquarters ended March 31, 2016 and June 30, 2016. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.
Employee Relations
December 31, 2015 Form 10-K page 16 and March 31, 2016 Form 10-Q page 70. Since the beginning of 2016, six of our eight labor unions ratified extensions of their collective bargaining agreements with us, with expiration dates from 2019 to

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2021. The collective bargaining agreements for the remaining two unions expire in 2017 and 2018. We believe we maintain satisfactory relationships with our employees.
Federal Regulation
FERC
Capacity Market Issues—PJMIssues-PJM
December 31, 2015 Form 10-K page 17, and March 31, 2016 Form 10-Q page 70.70 and June 30, 2016 Form 10-Q page 80. An emerging issueOver the past several years, certain entities in PJM, involves the impact of subsidized generation on RPM market outcomes. In particular,namely, FirstEnergy Corp. (FE) and American Electric Power (AEP) have been looking to the Ohio Public Utility Commission (PUCO) to provide financial support arrangements for their coal plants and a nuclear plant (FE). FE and AEP originally proposed to enter into power purchase agreements (PPAs) with their non-utility generation affiliates providing for above-market purchases from certain coal plants and a nuclear plant (in FE's case). The Ohio Public Utility Commission (PUCO) approvedPUCO Staff proposed a payment to support modernization of the PPAs on terms similar todistribution system (distribution modernization rider) in the terms soughtFE case which was ultimately accepted by those companies.the PUCO. The Dayton Power and Light Company hasalso recently also filed for comparable arrangements coveringa distribution modernization rider for the generating plants that it owns.  On April 27, 2016, FERC issued orders finding
The PUCO proceedings created a concern that subsidized units within the PPAs should be reviewed to determine whether they comport withPJM footprint would submit bids in the Commission’s standards for contracts. FE subsequently submittedcapacity market that are not reflective of their actual operating costs and would, in turn, artificially suppress capacity prices. As a modified arrangement to PUCO arguing that it is within PUCO’s exclusive jurisdiction. This modified proposal is currently the subject of contested proceedings at both the PUCO and at FERC. In another proceeding at FERC,result, certain parties are claimingrequested that PJMFERC should be directeddirect PJM to expand the MOPR“minimum offer price rule” to apply to existing contracts, including the FE and AEP PPAs.units.   
We are unable to predict the results of these pending proceedings or any future related proceedings or to calculate the potential impacts on our business.
Capacity Market Issues—ISO-New England
December 31, 2015 Form 10-K page 18 and March 31, 2016 Form 10-Q page 71. In March 2015, in conjunction with other companies, we filed a petition for review with the D.C. Circuit Court of Appeals (D.C. Court) of FERC's ruling accepting the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources. On December 1, 2015, following a request by FERC for a voluntary remand of the order, the D.C. Court remanded the case to FERC for additional consideration. However, on April 8, 2016, FERC issued an order upholding the exemption. We and other companies continue to contest the reasonableness of the exemption.
Reactive Power RatesTransmission Regulation
December 31, 2015 Form 10-K page 19 and March 31,June 30, 2016 Form 10-Q page 71.80. 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. Following settlement discussions with FERC Trial Staff, Power agreed to accept an overall rate of $34 million per year on the condition that we will refile in six years, which FERC approved in February 2016. FERC had earlier referred the filing to the FERC Office of Enforcement for its evaluation, which remains pending. More broadly, FERC has begun to review regulations relating to reactive power compensation. We cannot predict the impact of potential changes to reactive power compensation regulations on our business and results of operations.October 2016,
Transmission Regulation
December 31, 2015 Form 10-K page 19. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. In June 2016, PSE&G filed its 2015 true-up adjustment pertaining2017 Annual Formula Rate Update with FERC which requests approximately $121 million in increased annual transmission revenues effective January 1, 2017, subject to its transmission formula rates in effect for 2015, which resulted in an adjustment of $34 million less than the 2015 originally filed revenues.true-up. For additional information about our transmission formula rate, see Part I,1, Item 1. Financial Information—Note 4.5. Recent Rate Filings.
Transmission Regulation—Transmission Policy Developments
December 31, 2015 Form 10-K page 19, and March 31, 2016 Form 10-Q page 71.71 and June 30, 2016 Form 10-Q page 80. FERC concluded in Order 1000 that 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 and other companies appealed Order 1000 but this appeal was denied in 2014 by the D.C. Court. The current PJM rules retain carve-outs for projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing rights-of-way and whose construction would interfere with incumbents’ use of their rights-of-way. While these carve-outs ameliorate the impacts of the Order 1000 ruling on incumbents, we and several other companies appealed various aspects of the FERC order approving PJM’s implementation of Order 1000, including the elimination of the ROFR from the PJM Tariff. OnIn July 1, 2016, the D.C. Court dismissed the case, thus upholding FERC’s determination. We are currently analyzinghave decided not to pursue further action on this decision.
In April 2016, PSE&G accepted construction responsibility for the impactthree components of the D.C. Court’s decision on our operationstransmission project involving upgrades at Artificial Island in New Jersey. On August 5, 2016, PJM announced that it has suspended the Artificial Island transmission project and whether furtheris performing a comprehensive analysis to determine a future course of action, which is appropriate.expected to be completed by February 2017. 

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There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G contending that insufficient levels of costs are being allocated to PSE&G. Projects involved include the Artificial Island project, the Bergen-Linden project in New Jersey and a smaller project in Sewaren, New Jersey. On April 22,In August 2016, FERC issued orders denyingan order to PJM and the complaintsPJM Transmission Owners with respect to their compliance with a previous FERC order (Order 890) that requires transparency in the transmission planning process. The order directs PJM and leaving the current cost allocation in effect asPJM Transmission Owners to propose revisions to the Artificial Island and Bergen-Linden projects. DuePJM governing documents to an intervening FERC order concerning the allocation of costsensure compliance with Order 890 or show cause why they should not do so. The PJM Transmission Owners jointly filed for projects constructed to meet local reliability requirements, FERC directed that allrehearing of the Sewaren costs be allocatedorder to PSE&G. Itshow cause and jointly responded to FERC’s directives. FERC is anticipated that additional proceedings are likelyalso evaluating issues related to occur. It is anticipated that these various proceedings will not be resolved for several years.
Another proceeding is a matter remanded from a federal appellate court concerningcompetitive transmission development processes, including the appropriateuse of cost allocation for certain 500 kV projects in PJM that either have been built or arecontainment provisions. PSE&G has argued against the use of cost caps in the processassessment of being built, includingOrder 1000 open window project bids. We are unable to predict at this time the Susquehanna-Roseland project. A proposedresults of these proceedings and the impact they will have on our business.
State Regulation
Solar 4 All Program Extension II
On October 20, 2016, PSE&G submitted a settlement was filed with FERC on June 15, 2016. The settlement, if adopted by FERC, will result in increased annual cost allocationsagreement to customers in the PSE&G Transmission Zone. Under this settlement, Power, as a BGS supplier could become obligatedBPU providing for an extension of the existing landfill/brownfield solar program to pay amounts previously paid by other PJM transmission customers. However, we do not believe that the anticipated level of any such potential payments would have a material effect on Power’s financial statements.
Con Edison Wheeling Agreement
In April 2016, Con Edison informed PJM that it would allow its Wheeling Agreementconstruct up to expire effective as of May 1, 2017. The Wheeling Agreement enables Con Edison to move 1,00033 MW of energy from southeast New York acrossgrid connected facilities with projected capital expenditures of approximately $80 million through May 2020. This matter is pending approval by the PSE&G system for delivery into New York City. Discussions are currently ongoing among PJM and NYISO stakeholders regarding future operational procedures and transmission planning assumptions associated with the affected transmission lines. Depending on the outcome of these discussions, which may require FERC to approve tariff revisions, there could be impacts on capacity and energy prices in the region as well as impacts on transmission planning. In addition, Regional Transmission Expansion Plan costs that would have been allocated to Con Edison under the Wheeling Agreement will be reallocated elsewhere, which will include some reallocations to the customers within the PSE&G Transmission Zone.   BPU.
Nuclear Regulatory Commission (NRC)
Environmental Matters
Air Pollution Control
Cross-State Air Pollution Rule (CSAPR)    
December 31, 2015 Form 10-K page 21. 24.As a result of events at In September 2016, the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in 2011, the NRC began performing additional operational and safety reviews of nuclear facilities in the United States. We believe that our nuclear plants currently meet the stringent applicable design and safety specifications of the NRC.
Among other things, the NRC advised the staff to give the highest priority to those activities that can achieve the greatest safety benefit and/or have the broadest applicability (Tier 1).
The NRC issued letters and orders to licensees implementing the Tier 1 recommendations in March 2012. In June 2013, the NRC issued an order requiring Mark I and Mark II licensees to upgrade or replace their reliable hardened vents with containment venting systems designed and installed to remain functional during severe accident conditions. We are implementing the diverse and flexible strategies and spent fuel pool level indication modifications in accordance with the regulatory requirements at the Salem, Hope Creek and Peach Bottom nuclear units. For our Hope Creek and Peach Bottom units, final installation of the required modifications is expected to be completed by 2018.
In March 2013, the NRC initiated a rulemaking process for filtering strategies with drywell filtration and severe accident management for U.S. Boiling Water Reactors with Mark I and Mark II containments. The NRC subsequently disapproved the staff plan to pursue rulemaking, based in part on the upgrades required by the June 2013 order. The NRC continues to evaluate potential revisions to its requirements in connection with its operational and safety reviews of nuclear facilities in the United States as a result of the Fukushima Daiichi incident.
We are unable to predictEPA published the final outcome of these reviewsCSAPR Updating Rule to address the 2008 National Ambient Air Quality Standards for ground-level ozone. The rule establishes more stringent annual ozone season (May 1 through September 30) caps beginning in May 2017. We do not anticipate any material impact on our business or financial condition due to the cost of any actions we would need to take to comply with any new regulations, including possible modifications to our Salem, Hope Creek and Peach Bottom facilities, but such cost could be material.
State Regulation
Connecticut Rate Filing
December 31, 2015 Form 10-K page 23. On June 30, 2016, Power’s subsidiary, PSEG New Haven LLC, filed a mandatory annual rate case with the Connecticut Public Utilities Regulatory Authority for recovery of its costs and investment in its Connecticut-based peaking unit. Power requested 2017 revenues of $20 million. This matter is pending.CSAPR.

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Solar 4 All Program Extension II
In May 2016, PSE&G filed a petition with the BPU requesting an extension of its existing landfill/brownfield solar program to construct 100 MW of grid-connected solar facilities with projected capital expenses of up to $240 million, through approximately 2021. This matter is pending.  

Environmental Matters
Air Pollution Control
Hazardous Air Pollutants Regulation
December 31, 2015 Form 10-K page 24 and March 31, 2016 Form 10-Q page 72. In February 2012, the(EPA) published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources under the National Emission Standard for Hazardous Air Pollutants (NESHAP) provisions of the CAA. The MATS established allowable levels for mercury as well as other hazardous air pollutants and went into effect in April 2015. In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plants. On April 15, 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to the U.S. Supreme Court's ruling. Industry participants and various state authorities have filed petitions with the D.C. Court challenging the EPA’s Supplemental Finding. We do not expect this Supplemental Finding to impact operation of our facilities.
Demand Response (DR) Reciprocating Internal Combustion Engines (RICE) Litigation
December 31, 2015 Form 10-K page 24. In March 2013, Power filed a petition at the EPA challenging the National Emission Standards for Hazardous Air Pollutants (NESHAP) for RICE issued in January 2013. Among other things, the NESHAP include two exemptions that allow owners and operators of stationery emergency RICE to operate their engines 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 (2) as part of a financial arrangement with another entity per specified restrictions in non-emergency situations for 50 hours per year (50 hour exemption). We believe this waiver of NESHAP standards results in disparate treatment of different generation technology types. In its appeal, Power sought more stringent emission control standards for RICE to support more competitive markets, particularly the PJM capacity market. In August 2014, the EPA denied the March 2013 petition and in October 2014, Power appealed the EPA's denial to the D.C. Court. 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. On May 4, 2016, the D.C. Court vacated the 100 hour exemption which removes that provision from the rule. 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.
Cooling Water Intake Structure Regulation    
December 31, 2015 Form10-K page 26. On June 10, 2016, the New Jersey Department of Environmental Protection (NJDEP) issued the final New Jersey Pollutant Discharge Elimination System (NJPDES) permit for Salem, with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. On July 8, 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP's issuance of a final NJPDES renewal permit for Salem. The Riverkeeper's filing does not change the effective date of the permit. For additional information, see Part I, Item 1. Note 8. Commitments and Contingent Liabilities.

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ITEM 6.EXHIBITS
A listing of exhibits being filed with this document is as follows:
a. PSEG:  
Exhibit 10a(10):Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016
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 Daniel 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 Daniel 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. PSE&G:  
Exhibit 10a(9):
Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016 (1)
Exhibit 12.1: 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 Daniel 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 Daniel 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. Power:  
Exhibit 10a(8):
Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016 (1)
Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.4: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5: Certification by Daniel 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 Daniel 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

(1) Filed as Exhibit 10a(10) by PSEG with this Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, File No. 001-09120 on July 29, 2026 and incorporated herein by this reference.

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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: July 29,October 31, 2016

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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: July 29,October 31, 2016


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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: July 29,October 31, 2016


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