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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 SeptemberJune 30, 20172018
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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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
Emerging growth company  o
      
Public Service Electric and Gas Company
Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o
Emerging growth company  o
      
PSEG Power LLC
Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o
Emerging growth company  o
If any of the registrants is an emerging growth company, indicate by check mark if such registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ 
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 OctoberJuly 17, 2017,2018, Public Service Enterprise Group Incorporated had outstanding 506,038,791505,323,326 shares of its sole class of Common Stock, without par value.
As of OctoberJuly 17, 2017,2018, 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 and Significant Accounting StandardsPolicies
16
 Note 3. Early Plant Retirements2. Recent Accounting Standards
1917
Note 3. Revenues
20
 Note 4. Variable Interest Entity (VIE)Early Plant Retirements
2124
 Note 5. Rate FilingsVariable Interest Entity (VIE)
2126
 Note 6. Financing ReceivablesRate Filings
2227
 Note 7. Available-for-Sale SecuritiesFinancing Receivables
2528
 Note 8. Trust Investments
31
Note 9. Pension and Other Postretirement Benefits (OPEB)
30
Note 9. Commitments and Contingent Liabilities
3236
 Note 10. DebtCommitments and Credit FacilitiesContingent Liabilities
4038
 Note 11. Financial Risk Management ActivitiesDebt and Credit Facilities
4145
 Note 12. Fair Value MeasurementsFinancial Risk Management Activities
46
 Note 13. Other Income and DeductionsFair Value Measurements
5450
 Note 14. Other Income Taxes(Deductions)
5558
 Note 15. Income Taxes
58
Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax
5660
 Note 16.17. Earnings Per Share (EPS) and Dividends
60
Note 17. Financial Information by Business Segments
6164
 Note 18. Related-Party TransactionsFinancial Information by Business Segment
6265
 Note 19. Related-Party Transactions
65
Note 20. Guarantees of Debt
6467
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
6770
 Executive Overview of 20172018 and Future Outlook
6770
 
Results of Operations
7579
 
Liquidity and Capital Resources
8084
 
Capital Requirements
8286
 
Accounting Matters
8286
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
8286
Item 4.
Controls and Procedures
8387
  
PART II. OTHER INFORMATION 
Item 1.
Legal Proceedings
8387
Item 1A.
Risk Factors
8387
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
8488
Item 5.
Other Information
8588
Item 6.
Exhibits
8990
 
Signatures
9091


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FORWARD-LOOKING STATEMENTS
Certain of the matters discussed in this report about our and our subsidiaries’ future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in filings we make with the United States Securities and Exchange Commission (SEC), including our Annual Report on Form 10-K and subsequent reports on Form 10-Q and Form 8-K. These factors include, but are not limited to:
fluctuations in wholesale power and natural gas markets, including the potential impacts on the economic viability of our generation units;
our ability to obtain adequate fuel supply;
any inability to manage our energy obligations with available supply;
increases in competition in wholesale energy and capacity markets;
changes in technology related to energy generation, distribution and consumption and customer usage patterns;
economic downturns;
third-party credit risk relating to our sale of generation output and purchase of fuel;
adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in funding requirements;
changes in state and federal legislation and regulations;regulations, and PSE&G’s ability to recover costs and earn returns on authorized investments;
the impact of pending and any future rate case proceedings;
regulatory, financial, environmental, health and safety risks associated with our ownership and operation of nuclear facilities;
adverse changes in energy industry laws, policies and regulations, including market structures and transmission planning;
changes in federal and state environmental regulations and enforcement;
delays in receipt of, or an inability to receive, necessary licenses and permits;
adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry;
changes in tax laws and regulations;
the impact of our holding company structure on our ability to meet our corporate funding needs, service debt and pay dividends;
lack of growth or slower growth in the number of customers or changes in customer demand;
any inability of Power to meet its commitments under forward sale obligations;
reliance on transmission facilities that we do not own or control and the impact on our ability to maintain adequate transmission capacity;
any inability to successfully develop or construct generation, transmission and distribution projects;
any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers;

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our inability to exercise control over the operations of generation facilities in which we do not maintain a controlling interest;

ii

Tableany inability to recover the carrying amount of Contents


our long-lived assets and leveraged leases;
any inability to maintain sufficient liquidity;
any inability to realize anticipated tax benefits or retain tax credits;
challenges associated with recruitment and/or retention of key executives and a qualified workforce;
the impact of our covenants in our debt instruments on our operations; and
the impact of acts of terrorism, cybersecurity attacks or intrusions.

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business, prospects, financial condition, results of operations or cash flows. 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 in light of new information or future events, 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 Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
 OPERATING REVENUES$2,263
 $2,450
 $6,988
 $6,971
 
 OPERATING EXPENSES        
 Energy Costs638
 866
 2,100
 2,326
 
 Operation and Maintenance680
 776
 2,100
 2,215
 
 Depreciation and Amortization252
 231
 1,721
 679
 
 Total Operating Expenses1,570
 1,873
 5,921
 5,220
 
 OPERATING INCOME693
 577
 1,067
 1,751
 
 Income from Equity Method Investments3
 3
 11
 9
 
 Other Income66
 47
 208
 139
 
 Other Deductions(10) (8) (30) (39) 
 Other-Than-Temporary Impairments(5) (5) (9) (25) 
 Interest Expense(100) (99) (289) (288) 
 INCOME BEFORE INCOME TAXES647
 515
 958
 1,547
 
 Income Tax Expense(252) (188) (340) (562) 
 NET INCOME$395
 $327
 $618
 $985
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:        
 BASIC505
 505
 505
 505
 
 DILUTED507
 508
 507
 508
 
 NET INCOME PER SHARE:        
 BASIC$0.78
 $0.65
 $1.22
 $1.95
 
 DILUTED$0.78
 $0.64
 $1.22
 $1.94
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.43
 $0.41
 $1.29
 $1.23
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$2,016
 $2,142
 $4,834
 $4,733
 
 OPERATING EXPENSES        
 Energy Costs600
 588
 1,552
 1,456
 
 Operation and Maintenance725
 718
 1,479
 1,435
 
 Depreciation and Amortization280
 641
 560
 1,469
 
 Total Operating Expenses1,605
 1,947
 3,591
 4,360
 
 OPERATING INCOME411
 195
 1,243
 373
 
 Income from Equity Method Investments5
 5
 7
 8
 
 Net Gains (Losses) on Trust Investments8
 25
 (14) 53
 
 Other Income (Deductions)34
 33
 66
 65
 
 Non-Operating Pension and OPEB Credits (Costs)19
 1
 38
 1
 
 Interest Expense(111) (91) (214) (189) 
 INCOME BEFORE INCOME TAXES366
 168
 1,126
 311
 
 Income Tax Expense(97) (59) (299) (88) 
 NET INCOME$269
 $109
 $827
 $223
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:        
 BASIC504
 505
 504
 505
 
 DILUTED507
 507
 507
 507
 
 NET INCOME PER SHARE:        
 BASIC$0.53
 $0.22
 $1.64
 $0.44
 
 DILUTED$0.53
 $0.22
 $1.63
 $0.44
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.45
 $0.43
 $0.90
 $0.86
 
          
See Notes to Condensed Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
(Unaudited)
 
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
 NET INCOME$395
 $327
 $618
 $985
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(15), $(24), $(40) and $(50) for the three and nine months ended 2017 and 2016, respectively17
 24
 42
 50
 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $0 and $(1) for the three and nine months ended 2017 and 2016, respectively(1) 1
 (1) 2
 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(4), $(5), $(12) and $(17) for the three and nine months ended 2017 and 2016, respectively6
 9
 18
 25
 
 Other Comprehensive Income (Loss), net of tax22
 34
 59
 77
 
 COMPREHENSIVE INCOME$417
 $361
 $677
 $1,062
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 NET INCOME$269
 $109
 $827
 $223
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $4, $(9), $13 and $(25) for the three and six months ended 2018 and 2017, respectively(5) 10
 (19) 25
 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $0, $1 and $0 for the three and six months ended 2018 and 2017, respectively(1) —
 (1) —
 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(3), $(4), $(6) and $(8) for the three and six months ended 2018 and 2017, respectively7
 6
 15
 12
 
 Other Comprehensive Income (Loss), net of tax1
 16
 (5) 37
 
 COMPREHENSIVE INCOME$270
 $125
 $822
 $260
 
          
See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  September 30,
2017		 December 31,
2016		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$278
 $423
 
 Accounts Receivable, net of allowances of $59 in 2017 and $68 in 20161,022
 1,161
 
 Tax Receivable127
 78
 
 Unbilled Revenues176
 260
 
 Fuel348
 326
 
 Materials and Supplies, net588
 561
 
 Prepayments200
 76
 
 Derivative Contracts84
 163
 
 Regulatory Assets239
 199
 
 Other19
 7
 
 Total Current Assets3,081
 3,254
 
 PROPERTY, PLANT AND EQUIPMENT39,916
 39,337
 
      Less: Accumulated Depreciation and Amortization(9,383) (10,051) 
 Net Property, Plant and Equipment30,533
 29,286
 
 NONCURRENT ASSETS    
 Regulatory Assets3,336
 3,319
 
 Long-Term Investments936
 1,050
 
 Nuclear Decommissioning Trust (NDT) Fund2,012
 1,859
 
 Long-Term Tax Receivable—
 104
 
 Long-Term Receivable of Variable Interest Entity (VIE)599
 589
 
 Other Special Funds229
 217
 
 Goodwill16
 16
 
 Other Intangibles88
 98
 
 Derivative Contracts62
 24
 
 Other265
 254
 
 Total Noncurrent Assets7,543
 7,530
 
 TOTAL ASSETS$41,157
 $40,070
 
      
      
  June 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$95
 $313
 
 Accounts Receivable, net of allowances of $59 in 2018 and 20171,163
 1,348
 
 Tax Receivable111
 127
 
 Unbilled Revenues189
 296
 
 Fuel218
 289
 
 Materials and Supplies, net574
 577
 
 Prepayments324
 118
 
 Derivative Contracts24
 29
 
 Regulatory Assets296
 211
 
 Other11
 4
 
 Total Current Assets3,005
 3,312
 
 PROPERTY, PLANT AND EQUIPMENT42,809
 41,231
 
      Less: Accumulated Depreciation and Amortization(9,658) (9,434) 
 Net Property, Plant and Equipment33,151
 31,797
 
 NONCURRENT ASSETS    
 Regulatory Assets3,225
 3,222
 
 Long-Term Investments924
 932
 
 Nuclear Decommissioning Trust (NDT) Fund2,049
 2,133
 
 Long-Term Receivable of Variable Interest Entity (VIE)688
 686
 
 Rabbi Trust Fund224
 231
 
 Goodwill16
 16
 
 Other Intangibles127
 114
 
 Derivative Contracts21
 7
 
 Other277
 266
 
 Total Noncurrent Assets7,551
 7,607
 
 TOTAL ASSETS$43,707
 $42,716
 
      
See Notes to Condensed Consolidated Financial Statements.


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

 
      
  September 30,
2017		 December 31,
2016		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$1,250
 $500
 
 Commercial Paper and Loans202
 388
 
 Accounts Payable1,305
 1,459
 
 Derivative Contracts7
 13
 
 Accrued Interest136
 97
 
 Accrued Taxes146
 31
 
 Clean Energy Program184
 142
 
 Obligation to Return Cash Collateral132
 132
 
 Regulatory Liabilities44
 88
 
 Other425
 426
 
 Total Current Liabilities3,831
 3,276
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)8,931
 8,658
 
 Regulatory Liabilities89
 118
 
 Asset Retirement Obligations748
 726
 
 OPEB Costs1,301
 1,324
 
 OPEB Costs of Servco474
 452
 
 Accrued Pension Costs504
 568
 
 Accrued Pension Costs of Servco113
 128
 
 Environmental Costs399
 401
 
 Derivative Contracts1
 3
 
 Long-Term Accrued Taxes173
 180
 
 Other195
 211
 
 Total Noncurrent Liabilities12,928
 12,769
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 CAPITALIZATION
   
 LONG-TERM DEBT11,274
 10,895
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016—534 shares4,938
 4,936
 
 Treasury Stock, at cost, 2017 and 2016—29 shares(750) (717) 
 Retained Earnings9,140
 9,174
 
 Accumulated Other Comprehensive Loss(204) (263) 
 Total Stockholders’ Equity13,124
 13,130
 
 Total Capitalization24,398
 24,025
 
 TOTAL LIABILITIES AND CAPITALIZATION$41,157
 $40,070
 
  

   
      
  June 30,
2018		 December 31,
2017		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$1,550
 $1,000
 
 Commercial Paper and Loans270
 542
 
 Accounts Payable1,348
 1,694
 
 Derivative Contracts23
 16
 
 Accrued Interest105
 103
 
 Accrued Taxes104
 48
 
 Clean Energy Program203
 128
 
 Obligation to Return Cash Collateral131
 129
 
 Regulatory Liabilities32
 47
 
 Other478
 461
 
 Total Current Liabilities4,244
 4,168
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)5,475
 5,240
 
 Regulatory Liabilities2,937
 2,948
 
 Clean Energy Program27
 —
 
 Asset Retirement Obligations1,047
 1,024
 
 OPEB Costs1,423
 1,455
 
 OPEB Costs of Servco551
 542
 
 Accrued Pension Costs480
 537
 
 Accrued Pension Costs of Servco122
 129
 
 Environmental Costs332
 357
 
 Derivative Contracts1
 5
 
 Long-Term Accrued Taxes177
 175
 
 Other223
 221
 
 Total Noncurrent Liabilities12,795
 12,633
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 CAPITALIZATION
   
 LONG-TERM DEBT12,510
 12,068
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000 shares; issued, 2018 and 2017—534 shares4,955
 4,961
 
 Treasury Stock, at cost, 2018—30 shares; 2017—29 shares(813) (763) 
 Retained Earnings10,426
 9,878
 
 Accumulated Other Comprehensive Loss(410) (229) 
 Total Stockholders’ Equity14,158
 13,847
 
 Total Capitalization26,668
 25,915
 
 TOTAL LIABILITIES AND CAPITALIZATION$43,707
 $42,716
 
  

   
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, 
  2017 2016 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$618
 $985
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization1,721
 679
 
 Amortization of Nuclear Fuel152
 154
 
 Renewable Energy Credit (REC) Compliance Accrual79
 87
 
 Impairment Costs for Early Plant Retirements—
 102
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC227
 445
 
 Non-Cash Employee Benefit Plan Costs67
 95
 
 Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes(7) (12) 
 Net (Gain) Loss on Lease Investments48
 86
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives8
 96
 
 Net Change in Regulatory Assets and Liabilities(121) (72) 
 Cost of Removal(72) (109) 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(86) (12) 
 Net Change in Certain Current Assets and Liabilities:    
           Tax Receivable64
 282
 
           Accrued Taxes115
 202
 
           Margin Deposit64
 (4) 
           Other Current Assets and Liabilities(69) (229) 
 Employee Benefit Plan Funding and Related Payments(64) (81) 
 Other(10) 67
 
 Net Cash Provided By (Used In) Operating Activities2,734
 2,761
 
 CASH FLOWS FROM INVESTING ACTIVITIES

   
 Additions to Property, Plant and Equipment(3,046) (2,985) 
 Purchase of Emissions Allowances and RECs(90) (77) 
 Proceeds from Sales of Available-for-Sale Securities1,013
 551
 
 Investments in Available-for-Sale Securities(1,029) (576) 
 Other48
 33
 
 Net Cash Provided By (Used In) Investing Activities(3,104) (3,054) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans(186) (109) 
 Issuance of Long-Term Debt1,125
 1,975
 
 Redemption of Long-Term Debt—
 (824) 
 Cash Dividends Paid on Common Stock(652) (622) 
 Other(62) (71) 
 Net Cash Provided By (Used In) Financing Activities225
 349
 
 Net Increase (Decrease) in Cash and Cash Equivalents(145) 56
 
 Cash and Cash Equivalents at Beginning of Period423
 394
 
 Cash and Cash Equivalents at End of Period$278
 $450
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(16) $(274) 
 Interest Paid, Net of Amounts Capitalized$261
 $252
 
 Accrued Property, Plant and Equipment Expenditures$604
 $579
 
      
      
  Six Months Ended 
  June 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$827
 $223
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization560
 1,469
 
 Amortization of Nuclear Fuel95
 101
 
 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual

46
 51
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC213
 91
 
 Non-Cash Employee Benefit Plan Costs35
 45
 
 Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes8
 (30) 
 Net (Gain) Loss on Lease Investments14
 45
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(54) (42) 
 Net Change in Regulatory Assets and Liabilities(58) (124) 
 Cost of Removal(84) (47) 
 Net (Gains) Losses and (Income) Expense from NDT Fund(8) (58) 
 Net Change in Certain Current Assets and Liabilities:    
           Tax Receivable16
 69
 
           Accrued Taxes57
 15
 
           Margin Deposit24
 59
 
           Other Current Assets and Liabilities2
 (58) 
 Employee Benefit Plan Funding and Related Payments(58) (49) 
 Other(2) (5) 
 Net Cash Provided By (Used In) Operating Activities1,633
 1,755
 
 CASH FLOWS FROM INVESTING ACTIVITIES

   
 Additions to Property, Plant and Equipment(2,005) (1,981) 
 Purchase of Emissions Allowances and RECs(44) (29) 
 Proceeds from Sales of Trust Investments821
 711
 
 Purchases of Trust Investments(829) (726) 
 Other30
 36
 
 Net Cash Provided By (Used In) Investing Activities(2,027) (1,989) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans(272) (388) 
 Issuance of Long-Term Debt1,400
 1,125
 
 Redemption of Long-Term Debt(400) —
 
 Cash Dividends Paid on Common Stock(455) (435) 
 Other(83) (62) 
 Net Cash Provided By (Used In) Financing Activities190
 240
 
 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash(204) 6
 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period315
 426
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$111
 $432
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$52
 $(30) 
 Interest Paid, Net of Amounts Capitalized$205
 $189
 
 Accrued Property, Plant and Equipment Expenditures$625
 $513
 
      

See Notes to Condensed Consolidated Financial Statements.

Table of Contents



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

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
 OPERATING REVENUES$1,509
 $1,684
 $4,689
 $4,746
 
 OPERATING EXPENSES        
 Energy Costs535
 721
 1,760
 1,979
 
 Operation and Maintenance346
 376
 1,064
 1,110
 
 Depreciation and Amortization169
 137
 506
 412
 
 Total Operating Expenses1,050
 1,234
 3,330
 3,501
 
 OPERATING INCOME459
 450
 1,359
 1,245
 
 Other Income23
 22
 70
 61
 
 Other Deductions(1) (1) (3) (3) 
 Interest Expense(79) (72) (223) (214) 
 INCOME BEFORE INCOME TAXES402
 399
 1,203
 1,089
 
 Income Tax Expense(156) (144) (450) (393) 
 NET INCOME$246
 $255
 $753
 $696
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$1,386
 $1,393
 $3,231
 $3,219
 
 OPERATING EXPENSES        
 Energy Costs488
 488
 1,270
 1,250
 
 Operation and Maintenance353
 359
 744
 729
 
 Depreciation and Amortization187
 166
 377
 337
 
 Total Operating Expenses1,028
 1,013
 2,391
 2,316
 
 OPERATING INCOME358
 380
 840
 903
 
 Net Gains (Losses) on Trust Investments—
 —
 —
 2
 
 Other Income (Deductions)20
 21
 40
 43
 
 Non-Operating Pension and OPEB Credits (Costs)15
 (1) 30
 (3) 
 Interest Expense(82) (69) (163) (144) 
 INCOME BEFORE INCOME TAXES311
 331
 747
 801
 
 Income Tax Expense(80) (123) (197) (294) 
 NET INCOME$231
 $208
 $550
 $507
 
          
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.


Table of Contents


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


          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
 NET INCOME$246
 $255
 $753
 $696
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0, $1 and $0 for the three and nine months ended 2017 and 2016, respectively—
 —
 (1) 1
 
 COMPREHENSIVE INCOME$246
 $255
 $752
 $697
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 NET INCOME$231
 $208
 $550
 $507
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0, $0 and $1 for the three and six months ended 2018 and 2017, respectively1
 —
 —
 (1) 
 COMPREHENSIVE INCOME$232
 $208
 $550
 $506
 
          
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.


Table of Contents


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

      
  September 30,
2017		 December 31,
2016		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$239
 $390
 
 Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016762
 810
 
 Accounts Receivable—Affiliated Companies—
 76
 
 Unbilled Revenues176
 260
 
 Materials and Supplies196
 180
 
 Prepayments115
 9
 
 Regulatory Assets239
 199
 
 Other18
 6
 
 Total Current Assets1,745
 1,930
 
 PROPERTY, PLANT AND EQUIPMENT28,301
 26,347
 
 Less: Accumulated Depreciation and Amortization(6,019) (5,760) 
 Net Property, Plant and Equipment22,282
 20,587
 
 NONCURRENT ASSETS    
 Regulatory Assets3,336
 3,319
 
 Long-Term Investments283
 299
 
 Other Special Funds46
 43
 
 Other110
 110
 
 Total Noncurrent Assets3,775
 3,771
 
 TOTAL ASSETS$27,802
 $26,288
 
      
      
  June 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$20
 $242
 
 Accounts Receivable, net of allowances of $59 in 2018 and 2017796
 882
 
 Accounts Receivable—Affiliated Companies18
 —
 
 Unbilled Revenues189
 296
 
 Materials and Supplies195
 197
 
 Prepayments205
 44
 
 Regulatory Assets296
 211
 
 Other10
 4
 
 Total Current Assets1,729
 1,876
 
 PROPERTY, PLANT AND EQUIPMENT30,396
 29,117
 
 Less: Accumulated Depreciation and Amortization(6,200) (6,101) 
 Net Property, Plant and Equipment24,196
 23,016
 
 NONCURRENT ASSETS    
 Regulatory Assets3,225
 3,222
 
 Long-Term Investments285
 280
 
 Rabbi Trust Fund45
 46
 
 Other123
 114
 
 Total Noncurrent Assets3,678
 3,662
 
 TOTAL ASSETS$29,603
 $28,554
 
      
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.


Table of Contents


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

      
  September 30,
2017		 December 31,
2016		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$750
 $—
 
 Accounts Payable624
 718
 
 Accounts Payable—Affiliated Companies178
 260
 
 Accrued Interest89
 76
 
 Clean Energy Program184
 142
 
 Derivative Contracts—
 5
 
 Obligation to Return Cash Collateral132
 132
 
 Regulatory Liabilities44
 88
 
 Other278
 296
 
 Total Current Liabilities2,279
 1,717
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC6,408
 5,873
 
 OPEB Costs977
 1,009
 
 Accrued Pension Costs209
 250
 
��Regulatory Liabilities89
 118
 
 Environmental Costs325
 332
 
 Asset Retirement Obligations216
 213
 
 Long-Term Accrued Taxes83
 130
 
 Other109
 116
 
 Total Noncurrent Liabilities8,416
 8,041
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT7,493
 7,818
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150 shares authorized; issued and outstanding, 2017 and 2016—132 shares892
 892
 
 Contributed Capital1,095
 945
 
 Basis Adjustment986
 986
 
 Retained Earnings6,641
 5,888
 
 Accumulated Other Comprehensive Income—
 1
 
 Total Stockholder’s Equity9,614
 8,712
 
 Total Capitalization17,107
 16,530
 
 TOTAL LIABILITIES AND CAPITALIZATION$27,802
 $26,288
 
      
      
  June 30,
2018		 December 31,
2017		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$600
 $750
 
 Commercial Paper and Loans195
 —
 
 Accounts Payable704
 728
 
 Accounts Payable—Affiliated Companies150
 340
 
 Accrued Interest79
 78
 
 Clean Energy Program203
 128
 
 Obligation to Return Cash Collateral131
 129
 
 Regulatory Liabilities32
 47
 
 Other376
 311
 
 Total Current Liabilities2,470
 2,511
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC3,570
 3,391
 
 OPEB Costs1,066
 1,103
 
 Accrued Pension Costs189
 226
 
 Regulatory Liabilities2,937
 2,948
 
 Clean Energy Program27
 —
 
 Environmental Costs255
 283
 
 Asset Retirement Obligations214
 212
 
 Long-Term Accrued Taxes94
 91
 
 Other111
 114
 
 Total Noncurrent Liabilities8,463
 8,368
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT8,286
 7,841
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150 shares authorized; issued and outstanding, 2018 and 2017—132 shares892
 892
 
 Contributed Capital1,095
 1,095
 
 Basis Adjustment986
 986
 
 Retained Earnings7,411
 6,861
 
 Total Stockholder’s Equity10,384
 9,834
 
 Total Capitalization18,670
 17,675
 
 TOTAL LIABILITIES AND CAPITALIZATION$29,603
 $28,554
 
      
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.


Table of Contents


PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
      
  Nine Months Ended 
  September 30, 
  2017 2016 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$753
 $696
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization506
 412
 
 Provision for Deferred Income Taxes and ITC497
 482
 
 Non-Cash Employee Benefit Plan Costs37
 55
 
 Cost of Removal(72) (109) 
 Net Change in Other Regulatory Assets and Liabilities(121) (72) 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues136
 2
 
 Materials and Supplies(13) (42) 
 Prepayments(106) (63) 
 Accounts Payable(37) (30) 
 Accounts Receivable/Payable—Affiliated Companies, net(61) 154
 
 Other Current Assets and Liabilities(12) (6) 
 Employee Benefit Plan Funding and Related Payments(55) (64) 
 Other(59) (14) 
 Net Cash Provided By (Used In) Operating Activities1,393
 1,401
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(2,118) (2,035) 
 Proceeds from Sales of Available-for-Sale Securities33
 16
 
 Investments in Available-for-Sale Securities(34) (17) 
 Solar Loan Investments(2) —
 
 Other7
 6
 
 Net Cash Provided By (Used In) Investing Activities(2,114) (2,030) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt—
 (153) 
 Issuance of Long-Term Debt425
 1,275
 
 Redemption of Long-Term Debt—
 (271) 
 Contributed Capital150
 —
 
 Other(5) (14) 
 Net Cash Provided By (Used In) Financing Activities570
 837
 
 Net Increase (Decrease) In Cash and Cash Equivalents(151) 208
 
 Cash and Cash Equivalents at Beginning of Period390
 198
 
 Cash and Cash Equivalents at End of Period$239
 $406
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(107) $(279) 
 Interest Paid, Net of Amounts Capitalized$208
 $194
 
 Accrued Property, Plant and Equipment Expenditures$363
 $404
 
      
      
  Six Months Ended 
  June 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$550
 $507
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization377
 337
 
 Provision for Deferred Income Taxes and ITC160
 330
 
 Non-Cash Employee Benefit Plan Costs19
 25
 
 Cost of Removal(84) (47) 
 Net Change in Regulatory Assets and Liabilities(58) (124) 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues195
 108
 
 Materials and Supplies2
 (15) 
 Prepayments(161) (184) 
 Accounts Payable(30) (30) 
 Accounts Receivable/Payable—Affiliated Companies, net(204) (72) 
 Other Current Assets and Liabilities66
 14
 
 Employee Benefit Plan Funding and Related Payments(50) (42) 
 Other(20) (38) 
 Net Cash Provided By (Used In) Operating Activities762
 769
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(1,447) (1,389) 
 Proceeds from Sales of Trust Investments9
 28
 
 Purchases of Trust Investments(10) (29) 
 Solar Loan Investments(11) (3) 
 Other3
 5
 
 Net Cash Provided By (Used In) Investing Activities(1,456) (1,388) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt195
 —
 
 Issuance of Long-Term Debt700
 425
 
 Redemption of Long-Term Debt(400) —
 
 Other(9) (5) 
 Net Cash Provided By (Used In) Financing Activities486
 420
 
 Net Increase (Decrease) In Cash, Cash Equivalents and Restricted Cash(208) (199) 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period244
 393
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$36
 $194
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$97
 $(75) 
 Interest Paid, Net of Amounts Capitalized$157
 $144
 
 Accrued Property, Plant and Equipment Expenditures$436
 $319
 
      
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.

Table of Contents



PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
(Unaudited)

          
 
Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
 OPERATING REVENUES$873
 $1,075
 $3,086
 $3,102
 
 OPERATING EXPENSES        
 Energy Costs357
 462
 1,461
 1,481
 
 Operation and Maintenance227
 289
 711
 807
 
 Depreciation and Amortization76
 86
 1,191
 245
 
 Total Operating Expenses660
 837
 3,363
 2,533
 
 OPERATING INCOME (LOSS)213
 238
 (277) 569
 
 Income from Equity Method Investments3
 3
 11
 9
 
 Other Income43
 23
 127
 74
 
 Other Deductions(8) (6) (22) (33) 
 Other-Than-Temporary Impairments(5) (5) (9) (25) 
 Interest Expense(12) (24) (41) (66) 
 INCOME (LOSS) BEFORE INCOME TAXES234
 229
 (211) 528
 
 Income Tax Benefit (Expense)(98) (90) 80
 (208) 
 NET INCOME (LOSS)$136
 $139
 $(131) $320
 
      

   
          
 
Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$767
 $918
 $2,170
 $2,187
 
 OPERATING EXPENSES        
 Energy Costs373
 386
 1,119
 1,078
 
 Operation and Maintenance268
 256
 514
 488
 
 Depreciation and Amortization84
 465
 166
 1,115
 
 Total Operating Expenses725
 1,107
 1,799
 2,681
 
 OPERATING INCOME (LOSS)42
 (189) 371
 (494) 
 Income from Equity Method Investments5
 5
 7
 8
 
 Net Gains (Losses) on Trust Investments8
 24
 (14) 43
 
 Other Income (Deductions)13
 12
 24
 23
 
 Non-Operating Pension and OPEB Credits (Costs)3
 2
 7
 4
 
 Interest Expense(11) (13) (18) (29) 
 INCOME (LOSS) BEFORE INCOME TAXES60
 (159) 377
 (445) 
 Income Tax Benefit (Expense)(19) 62
 (102) 178
 
 NET INCOME (LOSS)$41
 $(97) $275
 $(267) 
      

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


Table of Contents


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

          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
 NET INCOME (LOSS)$136
 $139
 $(131) $320
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(14), $(23), $(41) and $(48) for the three and nine months ended 2017 and 2016, respectively15
 22
 44
 47
 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(4), $(5), $(11) and $(15) for the three and nine months ended 2017 and 2016, respectively5
 7
 15
 21
 
 Other Comprehensive Income (Loss), net of tax20
 29
 59
 68
 
 COMPREHENSIVE INCOME (LOSS)$156
 $168
 $(72) $388
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 NET INCOME (LOSS)$41
 $(97) $275
 $(267) 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $3, $(9), $11 and $(27) for the three and six months ended 2018 and 2017, respectively(4) 10
 (15) 29
 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(2), $(3), $(5) and $(7) for the three and six months ended 2018 and 2017, respectively6
 5
 12
 10
 
 Other Comprehensive Income (Loss), net of tax2
 15
 (3) 39
 
 COMPREHENSIVE INCOME (LOSS)$43
 $(82) $272
 $(228) 
          
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.


Table of Contents


PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  September 30,
2017		 December 31,
2016		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$22
 $11
 
 Accounts Receivable206
 276
 
 Accounts Receivable—Affiliated Companies86
 205
 
 Short-Term Loan to Affiliate1
 87
 
 Fuel348
 326
 
 Materials and Supplies, net391
 381
 
 Derivative Contracts84
 162
 
 Prepayments20
 10
 
 Other4
 2
 
 Total Current Assets1,162
 1,460
 
 PROPERTY, PLANT AND EQUIPMENT11,256
 12,655
 
 Less: Accumulated Depreciation and Amortization(3,184) (4,135) 
 Net Property, Plant and Equipment8,072
 8,520
 
 NONCURRENT ASSETS    
 NDT Fund2,012
 1,859
 
 Long-Term Investments90
 102
 
 Goodwill16
 16
 
 Other Intangibles88
 98
 
 Other Special Funds57
 53
 
 Derivative Contracts62
 24
 
 Other72
 61
 
 Total Noncurrent Assets2,397
 2,213
 
 TOTAL ASSETS$11,631
 $12,193
 
      
      
  June 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$20
 $32
 
 Accounts Receivable313
 380
 
 Accounts Receivable—Affiliated Companies81
 221
 
 Short-Term Loan to Affiliate519
 —
 
 Fuel218
 289
 
 Materials and Supplies, net376
 376
 
 Derivative Contracts24
 29
 
 Prepayments10
 11
 
 Other4
 3
 
 Total Current Assets1,565
 1,341
 
 PROPERTY, PLANT AND EQUIPMENT12,046
 11,755
 
 Less: Accumulated Depreciation and Amortization(3,267) (3,159) 
 Net Property, Plant and Equipment8,779
 8,596
 
 NONCURRENT ASSETS    
 NDT Fund2,049
 2,133
 
 Long-Term Investments87
 87
 
 Goodwill16
 16
 
 Other Intangibles127
 114
 
 Rabbi Trust Fund56
 57
 
 Derivative Contracts21
 7
 
 Other72
 67
 
 Total Noncurrent Assets2,428
 2,481
 
 TOTAL ASSETS$12,772
 $12,418
 
      
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.


Table of Contents


PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2017		 December 31,
2016		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Accounts Payable$499
 $539
 
 Accounts Payable—Affiliated Companies128
 25
 
 Derivative Contracts7
 8
 
 Accrued Interest43
 20
 
 Other87
 88
 
 Total Current Liabilities764
 680
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC1,962
 2,170
 
 Asset Retirement Obligations530
 511
 
 OPEB Costs258
 251
 
 Derivative Contracts1
 3
 
 Accrued Pension Costs174
 191
 
 Long-Term Accrued Taxes57
 77
 
 Other123
 129
 
 Total Noncurrent Liabilities3,105
 3,332
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 LONG-TERM DEBT2,385
 2,382
 
 MEMBER’S EQUITY
   
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings4,301
 4,782
 
 Accumulated Other Comprehensive Loss(152) (211) 
 Total Member’s Equity5,377
 5,799
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$11,631
 $12,193
 
      
      
  June 30,
2018		 December 31,
2017		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$250
 $250
 
 Accounts Payable468
 712
 
 Accounts Payable—Affiliated Companies148
 57
 
 Short-Term Loan from Affiliate—
 281
 
 Derivative Contracts23
 16
 
 Accrued Interest22
 20
 
 Other62
 99
 
 Total Current Liabilities973
 1,435
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC1,451
 1,406
 
 Asset Retirement Obligations831
 810
 
 OPEB Costs287
 283
 
 Derivative Contracts1
 5
 
 Accrued Pension Costs169
 184
 
 Long-Term Accrued Taxes45
 52
 
 Other143
 140
 
 Total Noncurrent Liabilities2,927
 2,880
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 LONG-TERM DEBT2,833
 2,136
 
 MEMBER’S EQUITY
   
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings5,161
 4,911
 
 Accumulated Other Comprehensive Loss(350) (172) 
 Total Member’s Equity6,039
 5,967
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$12,772
 $12,418
 
      
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.


Table of Contents


PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)

      
  Nine Months Ended 
  September 30, 
  2017 2016 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income (Loss)$(131) $320
 
 Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization1,191
 245
 
 Amortization of Nuclear Fuel152
 154
 
 Provision for Deferred Income Taxes and ITC(259) (34) 
 Interest Accretion on Asset Retirement Obligation23
 20
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives8
 96
 
 
Impairment Costs for Early Plant Retirements

—
 102
 
 Renewable Energy Credit (REC) Compliance Accrual79
 87
 
 Non-Cash Employee Benefit Plan Costs21
 28
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(86) (12) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies(32) (27) 
 Margin Deposit64
 (4)
 Accounts Receivable19
 (11) 
 Accounts Payable(32) (29) 
 Accounts Receivable/Payable—Affiliated Companies, net205
 235
 
 Other Current Assets and Liabilities11
 20
 
 Employee Benefit Plan Funding and Related Payments(5) (10) 
 Other21
 80
 
 Net Cash Provided By (Used In) Operating Activities1,249
 1,260
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(903) (923) 
 Purchase of Emissions Allowances and RECs(90) (77) 
 Proceeds from Sales of Available-for-Sale Securities886
 490
 
 Investments in Available-for-Sale Securities(900) (512) 
 Short-Term Loan—Affiliated Company, net86
 (151) 
 Other37
 22
 
 Net Cash Provided By (Used In) Investing Activities(884) (1,151) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Issuance of Long-Term Debt—
 700
 
 Cash Dividend Paid(350) (250) 
 Redemption of Long-Term Debt—
 (553) 
 Other(4) (6) 
 Net Cash Provided By (Used In) Financing Activities(354) (109) 
 Net Increase (Decrease) in Cash and Cash Equivalents11
 —
 
 Cash and Cash Equivalents at Beginning of Period11
 12
 
 Cash and Cash Equivalents at End of Period$22
 $12
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$75
 $(7) 
 Interest Paid, Net of Amounts Capitalized$30
 $51
 
 Accrued Property, Plant and Equipment Expenditures$241
 $175
 
      
      
  Six Months Ended 
  June 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income (Loss)$275
 $(267) 
 Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization166
 1,115
 
 Amortization of Nuclear Fuel95
 101
 
 Provision for Deferred Income Taxes and ITC51
 (226) 
 Interest Accretion on Asset Retirement Obligation20
 15
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(54) (42) 
 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual

46
 51
 
 Non-Cash Employee Benefit Plan Costs11
 14
 
 Net (Gains) Losses and (Income) Expense from NDT Fund(8) (58) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies71
 58
 
 Margin Deposit24
 59

 Accounts Receivable84
 36
 
 Accounts Payable(90) (14) 
 Accounts Receivable/Payable—Affiliated Companies, net227
 75
 
 Other Current Assets and Liabilities(35) 7
 
 Employee Benefit Plan Funding and Related Payments(5) (4) 
 Other(9) 12
 
 Net Cash Provided By (Used In) Operating Activities869
 932
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(547) (576) 
 Purchase of Emissions Allowances and RECs(44) (29) 
 Proceeds from Sales of Trust Investments785
 602
 
 Purchases of Trust Investments(793) (616) 
 Short-Term Loan—Affiliated Company(519) (146) 
 Other23
 30
 
 Net Cash Provided By (Used In) Investing Activities(1,095) (735) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Issuance of Long-Term Debt700
 —
 
 Cash Dividend Paid(200) (175) 
 Short-Term Loan—Affiliated Company(281) —
 
 Other(5) (4) 
 Net Cash Provided By (Used In) Financing Activities214
 (179) 
 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash(12) 18
 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period32
 11
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$20
 $29
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(72) $66
 
 Interest Paid, Net of Amounts Capitalized$18
 $29
 
 Accrued Property, Plant and Equipment Expenditures$189
 $194
 
      
See disclosures regarding PSEG Power LLC included in the Notes to the Condensed Consolidated Financial Statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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Note 1. Organization, and Basis of Presentation and Significant Accounting Policies
Organization
Public Service Enterprise Group Incorporated (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:
Public 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 related programs in New Jersey, which are regulated by the BPU.
PSEG Power LLC (Power)—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. 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’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases;are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; 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, 2016.2017.
The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All significant intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2016.2017.
Significant Accounting Policies
Cash, Cash Equivalents and Restricted Cash
Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G.
The followingprovides a reconciliation of cash, cash equivalents and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same such amounts for the beginning (December 31, 2017) and ending periods shown in the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2018.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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  PSE&G Power Other (A) Consolidated 
  Millions 
 As of December 31, 2017        
 Cash and Cash Equivalents$242
 $32
 $39
 $313
 
 Restricted Cash in Other Current Assets—
 —
 —
 —
 
 Restricted Cash in Other Noncurrent Assets2
 —
 —
 2
 
 Cash, Cash Equivalents and Restricted Cash$244
 $32
 $39
 $315
 
 As of June 30, 2018        
 Cash and Cash Equivalents$20
 $20
 $55
 $95
 
 Restricted Cash in Other Current Assets4
 —
 —
 4
 
 Restricted Cash in Other Noncurrent Assets12
 —
 —
 12
 
 Cash, Cash Equivalents and Restricted Cash$36
 $20
 $55
 $111
 
          
(A)Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services.

Note 2. Recent Accounting Standards
New StandardStandards Issued and Adopted
Business Combinations: ClarifyingRevenue from Contracts With Customers—Accounting Standard Update (ASU) 2014-09, updated by ASUs 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, 2017-14
This accounting standard, and related updates, were adopted on January 1, 2018 using the Definitionfull retrospective transition method. There was no effect on net income as a result of adoption. However, certain retrospective adjustments were recorded in accordance with the new standard. At PSE&G, retrospective adjustments increased Operating Revenues by $25 million and $39 million, Energy Costs by $16 million and $25 million, and Operation and Maintenance (O&M) Expense by $9 million and $14 million for the three and six months ended June 30, 2017, respectively. At Power, retrospective adjustments reduced Operating Revenues and Energy Costs by $11 million and $26 million for the three and six months ended June 30, 2017, respectively. For disclosure requirements under this standard, including Nature of Goods and Services, Disaggregation of Revenues, and Remaining Performance Obligations under Fixed Consideration Contracts, see Note 3. Revenues.
Recognition and Measurement of Financial Assets and Financial Liabilities—ASU 2016-01
Power maintains an external master trust fund to provide for the costs of decommissioning upon termination of operations of its nuclear facilities. In addition, PSEG maintains a Businessgrantor trust which was established to meet the obligations related to its non-qualified pension plans and deferred compensation plans, commonly referred to as a “Rabbi Trust.”
This accounting standard was issued mainlyadopted on January 1, 2018. Under the new guidance, equity investments in Power’s Nuclear Decommissioning Trust (NDT) and PSEG’s Rabbi Trust Funds are measured at fair value with the unrealized gains and losses now recognized through Net Income instead of Other Comprehensive Income (Loss). The debt securities in these trusts continue to provide more consistencybe classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust securities are also included in Net Gains (Losses) on Trust Investments. A cumulative effect adjustment was made to reclassify the net unrealized gains related to equity investments of $342 million ($176 million, net of tax) from Accumulated Other Comprehensive Income to Retained Earnings on January 1, 2018. See Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax and Note 8. Trust Investments for further discussion.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments—ASU 2016-15
This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the definitionStatement of a business is applied to acquisitions or dispositions. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes consideration of whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business.Cash Flows.
The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG adopted this standard in the third quarter 2017 with the acquisition ofon January 1, 2018 using a solar project. This standard upon adoptionretrospective transition method and had no impactchanges in its presentation of its Statement of Cash Flows for each period presented.
Statement of Cash Flows:  Restricted Cash—ASU 2016-18
This accounting standard was adopted on PSEG’s financial statements.January 1, 2018. PSEG will continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG has provided a reconciliation of cash and cash equivalents and restricted
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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cash or restricted cash equivalents and has included a description of these amounts in Note 1. Organization, Basis of Presentation and Significant Accounting Policies. The effect of adoption on the June 30, 2018 Consolidated Statements of Cash Flows was immaterial.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)—ASU 2017-07
This accounting standard was adopted on January 1, 2018. Under the new guidance, entities are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by their employees during the period. The other components of net benefit cost are required to be presented in the Statement of Operations separately from the service cost component after Operating Income. Additionally, only the service cost component is eligible for capitalization, when applicable. As a result of adopting this standard, PSE&G reduced its charge to expense for the three and six months ended June 30, 2018 by approximately $15 million and $29 million, respectively. The Condensed Consolidated Statements of Operations were recast to show retrospective adjustments of the non-service cost components of net benefit credits (costs) of $(1) million and $(3) million at PSE&G and $2 million and $4 million at Power, for the three and six months ended June 30, 2017, respectively, from O&M Expense to a new line item after Operating Income entitled Non-Operating Pension and OPEB Credits (Costs). See. Note 9. Pension and Other Postretirement Benefits (OPEB).
Stock Compensation - Scope of Modification Accounting—ASU 2017-09
This accounting standard was adopted on January 1, 2018. The standard will be applied prospectively to awards modified on or after January 1, 2018. PSEG does not expect a material impact from adoption of this new standard.
New Standards Issued But Not Yet Adopted
Revenue from Contracts with CustomersLeases—ASU 2016-02, updated by ASUs 2018-01, 2018-10 and 2018-11
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 is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance and possible changes in presentation. Included in the scope of the new standard are PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the distribution of electricity and gas to retail residential and commercial and industrial customers, and transmission revenues. The tariff revenue comprises substantially all of PSE&G’s revenue. PSEG expects no material change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. PSE&G’s revenue from contracts with customers will continue to be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.
Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. While those issues are out for comment, based on tentative conclusions PSEG does not expect any material changes to its revenue due to those issues. PSEG will adopt this standard on January 1, 2018 and anticipates electing the full retrospective method of transition. Under this method, PSEG will restate its prior period financial statements to align with the 2018 presentation. Certain reclassifications may affect revenue and expense due to the application of this standard; however, PSEG does not anticipate any material impact to net income.
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 expects to record a cumulative effect adjustment by reclassifying the after-tax net unrealized gain (loss) related to equity investments from Accumulated Other Comprehensive Income to Retained Earnings as of January 1, 2018, and expects increased volatility in Net Income due to changes in fair value of its equity securities within the nuclear decommissioning (NDT) and Rabbi Trust Funds.
Leases
This accounting standardupdates, 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 requiresallows lessees and lessors to apply either (i) 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,statements, or (ii) a prospective transition approach for leases existing as of January 1, 2019 with a cumulative effect adjustment to be recorded to Retained Earnings. PSEG intends to adopt this standard on a prospective basis. Existing guidance related to leveraged leases willdoes not change.
This standard permits an entity to elect an optional transition practical expedient to exclude evaluation of land easements that exist or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases.
PSEG is currently analyzing the impact of this standard on its consolidated financial statements while undertaking the following implementation activities: (i) reviewing all contract types throughout PSEG to determine the lease population; (ii) implementing a lease accounting system to capture and account for long-term (greater than one year) leases to be operational on January 1, 2019; (iii) developing internal lease accounting policies and determining the practical expedients PSEG will elect; and (iv) drafting lease disclosures required in 2019. PSEG expects adoption of this standard to have a material impact on the balance sheets of PSEG and PSE&G, but has not yet quantified this impact.
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.2018. 
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging ActivitiesActivities—ASU 2017-12
This accounting standard’s amendments more closely align hedge accounting with the companies’ risk management activities in the financial statements. The amendments expand hedge accounting for both non-financial and financial risk components by
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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permitting contractually specified components to designatebe designated as the hedged risk in a cash flow hedge involving the purchase or sale of non-financial assets or variable rate financial instruments. The amendments also permit an entity to measure the interest rate risk on the hedged item in a partial-term fair value hedge assuming the hedged item has a term that reflects only the designated cash flows being hedged. Additionally, the amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allowallowing effectiveness assessments to be performed on a qualitative basis after hedge inception.
The new guidance is effective for annual and interim periods beginning after December 15, 2018. The standard requires using a modified retrospective method upon adoption. Early adoption is permitted. PSEG analyzed the impact of this standard on its consolidated financial statements and has determined that the standard could enable PSEG to enter into certain transactions that
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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can be deemed hedges that previously would not have qualified. Adoption of this standard is not expected to have a material impact on PSEG’s financial statements.
Premium Amortization on Purchased Callable Debt Securities—ASU 2017-08
This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.
The standard is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period. If an entity early adopts the standard in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative effect adjustment directly to retained earnings as of the beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle. PSEG is currently analyzing the impact of this standard on its financial statements.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income—ASU 2018-02
This accounting standard would affect any entity that is required to apply the provisions of the Accounting Standards Codification topic, “Income Statement-Reporting Comprehensive Income,” and has items of other comprehensive income for which the related tax effects are presented in other comprehensive income as required by GAAP. Specifically, this standard would allow entities to record a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the newly enacted federal corporate income tax rate. The amount of the reclassification would be the difference between the historical corporate income tax rate and the newly enacted 21% corporate income tax rate.
The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period for public business entities for reporting periods for which financial statements have not yet been issued or made available for issuance.
An entity would be able to choose to apply this standard retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the new tax legislation enacted in 2017 is recognized or apply the standard in the reporting period adopted. PSEG is currently analyzing the impact this standard, if adopted, could have on its consolidated financial statements.
Measurement of Credit Losses on Financial Instruments—ASU 2016-13
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.
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 does not anticipate any current impact on PSEG’s financial statements. PSEG will adopt this standard as of January 1, 2018 using a retrospective transition method to each period presented.
Statement of Cash Flows: Restricted Cash
This accounting standard requires entities to explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents, either in a narrative or a tabular format. Amounts generally described as restricted cash or restricted cash equivalents should be included in entities’ reconciliation of beginning-of-period and end-of-period amounts 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 plans to adopt this standard on January 1, 2018 using a retrospective transition method for each period presented. PSEG will continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG will provide a reconciliation of cash and cash equivalents and restricted cash or restricted cash equivalents and include a description of these amounts.
Simplifying the Test for Goodwill Impairment—ASU 2017-04
This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.
An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impactdoes not expect adoption of this guidance uponstandard to have a material impact on its financial statements.
Improving
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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Note 3. Revenues
Nature of Goods and Services
The following is a description of principal activities by reportable segment from which PSEG, PSE&G and Power generate their revenues.
PSE&G
Revenues from Contracts with Customers
Electric and Gas Distribution and Transmission Revenues—PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the Presentation of Net Periodic Pension Costproduct(s) and/or services are delivered to the customer. The electric and Net Periodic Postretirement Benefit Cost (OPEB)
This accounting standard was issued to improvegas commodity and delivery tariffs are recurring contracts in effect until cancellation by the presentation of net periodic pension cost and net periodic OPEB cost.
Under the new guidance, entities are required to reportcustomer. Revenue is recognized over time as the service cost componentis rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period.
PSE&G’s transmission revenues are earned under a separate FERC tariff. The performance obligation of transmission service is satisfied over time as it is provided to and consumed by the customer. Revenue is recognized upon delivery of the transmission service. PSE&G’s revenues from the transmission of electricity are recorded based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a mechanism true-up to that estimate based on actual revenue requirements. The true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers.
Other Revenues from Contracts with Customers
Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and revenue is recognized as control of products is delivered or services are rendered.
Payment for services rendered and products transferred are typically due within 30 days of month of delivery.
Revenues Unrelated to Contracts with Customers
Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.
Power
Revenues from Contracts with Customers
Electricity and Related Products—Wholesale and retail load contracts are executed in the same line itemdifferent Independent System Operator (ISO) regions for the bundled supply of energy, capacity, renewable energy credits (RECs) and ancillary services representing Power’s performance obligations. Revenue for these contracts is recognized over time as the bundled service is provided to the customer. Transaction terms generally run from several months to three years. Power also sells to the ISOs energy and ancillary services which are separately transacted in the day-ahead or itemsreal-time energy markets. The energy and ancillary services performance obligations are typically satisfied over time as other compensation costs arising from services rendereddelivered and revenue is recognized accordingly. Power generally reports electricity sales and purchases conducted with those individual ISOs net on an hourly basis in either Operating Revenues or Energy Costs in its Consolidated Statements of Operations. The classification depends on the net hourly activity.
Power enters into capacity sales and capacity purchases through the ISOs. The transactions are reported on a net basis dependent on Power’s monthly net sale or purchase position through the individual ISOs. The performance obligations with the ISOs are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through the ISOs, Power sells capacity through bilateral contracts and the related revenue is recognized over time upon delivery of the capacity.
Gas Contracts—Power sells wholesale natural gas, primarily through an index based full requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. The BGSS contract, which extends through March 2019, will renew year-to-year thereafter unless terminated by their employees duringeither party with a two year notice. The performance obligation is primarily delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered. Based upon the period. The other componentsavailability of net benefitnatural gas, storage and pipeline capacity beyond PSE&G’s daily needs, Power also sells gas and
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costpipeline capacity to other counterparties under bilateral contracts. The performance obligation under these contracts is satisfied over time upon delivery of the gas or capacity, and revenue is recognized accordingly.
Other Revenues from Contracts with Customers
Power enters into bilateral contracts to sell solar power and solar RECs from its solar facilities. Contract terms range from 15 to 30 years. The performance obligations are requiredgenerally solar power and RECs which are transferred to customers upon generation. Revenue is recognized upon generation of the solar power.
Power has entered into long-term contracts with LIPA for energy management and fuel procurement services. Revenue is recognized over time as services are rendered.
Revenues Unrelated to Contracts with Customers
Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 12. Financial Risk Management Activities for further discussion. Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance.
Other
Revenues from Contracts with Customers
PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco) records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction. 
Revenues Unrelated to Contracts with Customers
Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.
Disaggregation of Revenues
            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Three Months Ended June 30, 2018          
 Revenues from Contracts with Customers          
 Electric Distribution$754
 $—
 $—
 $—
 $754
 
 Gas Distribution248
 —
 —
 (4) 244
 
 Transmission301
 —
 —
 —
 301
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 373
 —
 —
 373
 
          Sales to Affiliates—
 147
 —
 (147) —
 
 New York ISO—
 46
 —
 —
 46
 
 ISO New England—
 14
 —
 —
 14
 
 Gas Sales          
 Third Party Sales—
 30
 —
 —
 30
 
 Sales to Affiliates—
 108
 —
 (108) —
 
 Other Revenues from Contracts with Customers (A)63
 13
 125
 (1) 200
 
 Total Revenues from Contracts with Customers1,366
 731
 125
 (260) 1,962
 
 Revenues Unrelated to Contracts with Customers (B)20
 36
 (2) —
 54
 
 Total Operating Revenues$1,386
 $767
 $123
 $(260) $2,016
 
            
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  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Six Months Ended June 30, 2018          
 Revenues from Contracts with Customers          
 Electric Distribution$1,444
 $—
 $—
 $—
 $1,444
 
 Gas Distribution1,007
 —
 —
 (7) 1,000
 
 Transmission613
 —
 —
 —
 613
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 871
 —
 —
 871
 
          Sales to Affiliates—
 323
 —
 (323) —
 
 New York ISO—
 105
 —
 —
 105
 
 ISO New England—
 61
 —
 —
 61
 
 Gas Sales          
 Third Party Sales—
 94
 —
 —
 94
 
 Sales to Affiliates—
 505
 —
 (505) —
 
 Other Revenues from Contracts with Customers (A)135
 23
 262
 (2) 418
 
 Total Revenues from Contracts with Customers3,199
 1,982
 262
 (837) 4,606
 
 Revenues Unrelated to Contracts with Customers (B)32
 188
 8
 —
 228
 
 Total Operating Revenues$3,231
 $2,170
 $270
 $(837) $4,834
 
            
            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Three Months Ended June 30, 2017          
 Revenues from Contracts with Customers          
 Electric Distribution$757
 $—
 $—
 $—
 $757
 
 Gas Distribution233
 —
 —
 (6) 227
 
 Transmission307
 —
 —
 —
 307
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 302
 —
 —
 302
 
          Sales to Affiliates—
 171
 —
 (171) —
 
 New York ISO—
 50
 —
 —
 50
 
 ISO New England—
 9
 —
 —
 9
 
 Gas Sales          
 Third Party Sales—
 11
 —
 —
 11
 
 Sales to Affiliates—
 107
 —
 (107) —
 
 Other Revenues from Contracts with Customers (A)67
 12
 128
 (1) 206
 
 Total Revenues from Contracts with Customers1,364
 662
 128
 (285) 1,869
 
 Revenues Unrelated to Contracts with Customers (B)29
 256
 (12) —
 273
 
 Total Operating Revenues$1,393
 $918
 $116
 $(285) $2,142
 
            
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  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Six Months Ended June 30, 2017          
 Revenues from Contracts with Customers          
 Electric Distribution$1,458
 $—
 $—
 $—
 $1,458
 
 Gas Distribution988
 —
 —
 (7) 981
 
 Transmission606
 —
 —
 —
 606
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 616
 —
 —
 616
 
          Sales to Affiliates—
 355
 —
 (355) —
 
 New York ISO—
 86
 —
 —
 86
 
 ISO New England—
 20
 —
 —
 20
 
 Gas Sales          
 Third Party Sales—
 63
 —
 —
 63
 
 Sales to Affiliates—
 508
 —
 (508) —
 
 Other Revenues from Contracts with Customers (A)129
 22
 256
 (2) 405
 
 Total Revenues from Contracts with Customers3,181
 1,670
 256
 (872) 4,235
 
 Revenues Unrelated to Contracts with Customers (B)38
 517
 (57) —
 498
 
 Total Operating Revenues$3,219
 $2,187
 $199
 $(872) $4,733
 
            
(A)Includes primarily revenues from appliance repair services at PSE&G, solar power projects and energy management and fuel service contracts with LIPA at Power, and PSEG LI’s OSA with LIPA in Other.
(B)Includes primarily alternative revenues at PSE&G, derivative contracts at Power, and lease contracts in Other. For the three and six months ended June 30, 2018, Other includes a $20 million loss and for the three and six months ended June 30, 2017, Other includes a $22 million loss and a $77 million loss, respectively, related to Energy Holdings’ investments in leases.
Contract Balances
PSE&G
PSE&G does not have any material contract balances (rights to consideration for services already provided or obligations to provide services in the future for consideration already received) as of June 30, 2018 and December 31, 2017. Substantially all of PSE&G’s accounts receivable result from contracts with customers. Allowances represented approximately seven percent of accounts receivable as of June 30, 2018 and December 31, 2017.
Power
Power generally collects consideration upon satisfaction of performance obligations, and therefore, Power had no material contract balances as of June 30, 2018 and December 31, 2017.
Power’s accounts receivable include amounts resulting from contracts with customers and other contracts which are out of scope of accounting guidance for revenues from contracts with customers. The majority of these accounts receivable are subject to master netting agreements. As a result, accounts receivable resulting from contracts with customers and receivables unrelated to contracts with customers are netted within Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets. In the wholesale energy markets in which Power operates, payment for services rendered and products transferred are typically due within 30 days of month of delivery. As such, there is little credit risk associated with these receivables and Power typically records no allowances.
Other
PSEG LI does not have any material contract balances as of June 30, 2018 and December 31, 2017.
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Remaining Performance Obligations under Fixed Consideration Contracts
Power and PSE&G primarily record revenues as allowed by the guidance, which states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity's performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. PSEG has future performance obligations under contracts with fixed consideration as follows:
Power
As stated above, capacity transactions with ISOs are reported on a net basis dependent on Power’s monthly net sale or purchase position through the individual ISOs.
Capacity Payments from the PJM Reliability Pricing Model (RPM) Annual Base Residual and Incremental Auctions—The Base Residual Auction is conducted annually three years in advance of the operating period. Power expects to realize the following average capacity prices for capacity obligations to be presentedsatisfied resulting from the base and incremental auctions which have been completed:
       
 Delivery Year $ per MW-Day MW Cleared 
 June 2018 to May 2019 $205 9,200
 
 June 2019 to May 2020 $116 8,900
 
 June 2020 to May 2021 $174 7,800
 
 June 2021 to May 2022 $178 7,700
 
   ��   
Capacity Payments from the New England ISO Forward Capacity Market—The Forward Capacity Market Auction (FCM) is conducted annually three years in advance of the operating period. The table below includes Power’s cleared capacity in the StatementFCM for the Bridgeport Harbor Station 5, which cleared the 2019/2020 auction at $231/MW-day for seven years, with escalations based on the Handy-Whitman Index and the planned retirement of Operations separatelyBridgeport Harbor Station 3 in 2021. Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the service cost component after Operating Income. Additionally, only the service cost component will be eligible for capitalization, when applicable.FCM auctions which have been completed:
       
 Delivery Year $ per MW-Day MW Cleared 
 June 2018 to May 2019 $314 820
 
 June 2019 to May 2020 $231 1,330
 
 June 2020 to May 2021 $195 1,330
 
 June 2021 to May 2022 $192 950
 
 June 2022 to May 2023 $231 480
 
 June 2023 to May 2024 $231 480
 
 June 2024 to May 2025 $231 480
 
 June 2025 to May 2026 $231 480
 
       
Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $180 million.
Other
The standard requires the amendments to be applied retrospectivelyLIPA OSA is a 12-year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the presentationprovision of the service cost componentservices thereunder in 2018 is $64 million and the other cost components of net periodic pension cost and net periodic OPEB cost in the Statement of Operations and prospectively,could increase each year based on and after the effective date, for the capitalization of the service cost component of net periodic pension and OPEB costs.
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. PSEG is currently analyzing the impact of this standard on its financial statements.
Premium Amortization on Purchased Callable Debt Securities
This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.
The standard is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period. If an entity early adopts the standard in an interim period, any
adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle. PSEG is currently analyzing the impact of this standard on its financial statements.
Stock Compensation - Scope of Modification Accounting
This accounting standard provides clarity and reduces both diversity in practice and complexity when applying the stock compensation guidance to a change in the terms or conditions of a stock-based payment award. Specifically,Consumer Price Index (CPI). The incentive for 2018 can range from zero to approximately $10 million and could increase each year thereafter based on the standard provides guidance as to which changes tochange in the terms or conditions of a stock-based payment award require an entity to apply modification accounting.
The standard is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period, for reporting periods for which financial statements have not yet been issued. This standard should be applied prospectively to an award modified on or after the adoption date. PSEG plans to adopt this standard effective January 1, 2018.CPI.

Note 3.4. Early Plant Retirements
Fossil
In October 2016,On June 1, 2017, Power determined that it would ceasecompleted its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations onstations.
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For the three and six months ended June 1, 2017. Both units were available to operate through May 31, 2017 and were subsequently retired from operation on June 1, 2017.
In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 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 and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.
As of June 1,30, 2017, Power recognized total D&ADepreciation and Amortization of $390 million and $964 million, respectively, for the Hudson and Mercer units to reflect the endsignificant shortening of their expected economic useful lives in 2017. In the three and ninesix months ended SeptemberJune 30, 2017,2018, Power recognized pre-tax charges (credits) in Energy Costs of $1$(1) million and $10$3 million, respectively, primarily for coal inventory lower of cost or market adjustments. ForIn the three and ninesix months ended SeptemberJune 30, 2017, Power recognized pre-tax charges of the same nature in Energy Costs of $2 million and $9 million, respectively. In the three and six months ended June 30, 2017, Power also recognized pre-tax charges in O&M of $8$4 million and $12 million, respectively, of shut down costs and ana net increase in the Asset Retirement Obligation liability due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power currently anticipatesis exploring various opportunities with these sites, including using the sites for alternative industrial activity. However, ifactivity or the disposition of one or both of the sites. If Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material.
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As of December 31, 2016, Power had reduced the estimated useful life of Bridgeport Harbor Station unit 3 (BH3) from 2025 to the summer of 2021 as it was more likely than not it will retire the unit by this time.
PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. 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 or change in the held for use classification of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.
Nuclear
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. This situation isIn February 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure of its Oyster Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. In addition, First Energy announced in March 2018 the early retirement of four nuclear units at the Davis-Besse, Perry Nuclear and Beaver Valley nuclear plants in Ohio and Pennsylvania by 2021. These closures and retirements are generally due to thedecline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, and both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar but generally do not applyand the failure to adequately compensate nuclear generating stations.stations for the attributes they bring similar to renewable energy production. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.
In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for selection of the units under the newly enacted legislation in the state of New Jersey. Power and Exelon have agreed to cancel the funding of future capital projects at the Salem generating station that are not required to meet NRC or other regulatory requirements or that are not required to ensure its safe operation. Power and Exelon have agreed to continue to assess and, when appropriate, approve the funding of individual capital projects to ensure compliance with regulatory requirements and the safe operation of the Salem generating station and that the funding of these projects may be restored if legislation enacted in New Jersey sufficiently values the attributes of nuclear generation and Salem benefits from such legislation.
If any or all of the market trends noted above continue or worsen, Power’sSalem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. In May 2018, the governor of New Jersey signed legislation that would provide a safety net in order to prevent the loss of environmental attributes from selected nuclear generating units could cease being economically competitive which may causestations referred to as the zero emissions certificate (ZEC) program. The legislation calls for the BPU (within a 330-day period from enactment) to establish a collection process for a customer charge, determine eligibility and certification of need, and ultimately select nuclear plants to potentially receive ZECs starting in April 2019. Power cannot predict whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
If energy market prices continue to retire such units priorbe depressed, there are adverse impacts from potential changes to the endcapacity market construct being considered by FERC, or the ZEC program does not adequately compensate our nuclear generating stations for
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their useful lives.attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such potential retirement, which may include, among other things, accelerated D&Adepreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the NDT Fund would likely have abe material adverse impact on PSEG’s and Power’s future financial results and cash flows.to both PSEG and Power continue to advocate for sound policies that recognize nuclear power as a source of reliable clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio.Power.
The following table provides the balance sheet amounts by generating station as of SeptemberJune 30, 20172018 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.
           
   As of September 30, 2017 
   Hope Creek Salem Support Facilities and Other (A) Peach Bottom 
   Millions 
 Assets         
 Materials and Supplies Inventory $85
 $81
 $—
 $41
 
 Nuclear Production, net of Accumulated Depreciation 452
 557
 204
 753
 
 Nuclear Fuel In-Service, net of Accumulated Depreciation 120
 94
 —
 109
 
 Construction Work in Progress (including nuclear fuel) 216
 130
 9
 92
 
         Total Assets $873
 $862
 $213
 $995
 
 Liability         
 Asset Retirement Obligation $148
 $162
 $—
 $164
 
         Total Liabilities $148
 $162
 $—
 $164
 
          Net Assets $725
 $700
 $213
 $831
 
 NRC License Renewal Term 2046 2036/2040
 —
 2033/2034
 
 % Owned 100% 57% —
 50% 
           
           
   As of June 30, 2018 
   Hope Creek Salem Support Facilities and Other (A) Peach Bottom 
   Millions 
 Assets         
 Materials and Supplies Inventory $83
 $82
 $—
 $42
 
 Nuclear Production, net of Accumulated Depreciation 688
 646
 203
 786
 
 Nuclear Fuel In-Service, net of Accumulated Depreciation 171
 89
 —
 119
 
 Construction Work in Progress (including nuclear fuel) 140
 105
 2
 24
 
         Total Assets $1,082
 $922
 $205
 $971
 
 Liability         
 Asset Retirement Obligation $309
 $255
 $—
 $210
 
         Total Liabilities $309
 $255
 $—
 $210
 
          Net Assets $773
 $667
 $205
 $761
 
 NRC License Renewal Term 2046 2036/2040
 N/A
 2033/2034
 
 % Owned 100% 57% Various
 50% 
           
(A)Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.
The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments and
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decommissioning trust fund requirements and other commitments, as well as future energy prices. Power maintains a NDT Fund that funds its decommissioning obligations. See Note 7. Available-for-Sale Securities.8. Trust Investments.

Note 4.5. Variable Interest Entity (VIE)
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’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.
Pursuant to the OSA, Servco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.
For transactions in which Servco acts as principal and controls the services provided to LIPA, 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 O&M Expense, respectively. Servco recorded $114$109 million and $116$112 million for the three months and $338$229 million and $315$224 million for the ninesix months ended SeptemberJune 30, 2018 and
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2017, and 2016, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Condensed Consolidated Statement of Operations.

Note 5.6. Rate Filings
This Note should be read in conjunction with Note 6. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2016.2017.
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:
Electric and Gas Distribution Base Rate Filing—In January 2018, PSE&G filed a distribution base rate case as required as a condition of approval of its Energy Strong Program I (ESP I) approved by the BPU in 2014. The filing requested an approximate 1% increase in revenues and recovery of investments made to strengthen the electric and gas distribution systems. The requested increase took into account a reduction in the revenue requirement as a result of the federal corporate income tax rate reduction from 35% to 21% provided in the Tax Cuts and Jobs Act of 2017 (Tax Act), including the flow-back to customers of excess accumulated deferred income taxes. In March 2018, the BPU approved interim rate reductions for all their jurisdictional utilities, including PSE&G, reflecting the reduction in the federal corporate tax rate. The BPU approved a reduction to PSE&G’s current base electric and gas revenues effective April 1, 2018 by $71 million and $43 million, respectively, on an annual basis (or about 2% combined). The refund to customers for overcollection of revenues at the higher tax rate for the January 1 to March 31, 2018 period, and the flow-back to customers of certain excess deferred income taxes will be addressed in PSE&G’s ongoing base rate case proceeding. In May 2018, PSE&G updated its base rate filing to include nine months of actual data. As a result of the base rate reduction implemented on April 1, 2018, among other factors, PSE&G’s updated filing requests an approximate 3% increase in revenues. PSE&G anticipates a decision by the BPU that new base rates will go into effect in the fourth quarter of 2018.
Transmission Formula Rate Filings—In January 2018, PSE&G filed with FERC a revised 2018 Annual Transmission Formula Rate Update reducing its 2018 transmission annual revenue requirement to reflect the federal corporate income tax rate reduction from 35% to 21% as a result of the Tax Act. This change in the federal corporate tax rate reduces the 2018 annual revenue requirement by $148 million, effective January 1, 2018. FERC continues to assess whether, and if so how, it will address changes and flow-backs to customers relating to accumulated deferred income taxes and bonus depreciation.
In June 2017,2018, PSE&G filed its 20162017 true-up adjustment pertaining to its transmission formula rates in effect for 2016.2017. This resulted in an adjustment of $12$27 million more than the 20162017 originally filed revenues.revenues, the impact of which PSE&G had primarily recognized in its Consolidated Statement of Operations for the year ended December 31, 2017.
BGSS—In June 2018, PSE&G made its annual BGSS filing with the BPU requesting a decrease in the annual BGSS revenues of $26 million. If approved, the BGSS rate would be decreased from approximately 37 cents to 35 cents per therm for residential gas customers to be effective October 1, 2018. This matter is pending.
In April 2018, the BPU approved the final BGSS rates which were effective October 1, 2017.
In December 2017, theFebruary 2018 Annual Formula Rate update was filed with FERC and requests approximately $212 million in increased annual transmission revenue effective January 1,March 2018, subject to true-up.
Gas System Modernization Program (GSMP)—In July of each year, PSE&G filesfiled with the BPU for base rate recoveryself-implementing monthly bill credits of GSMP investments which include a return15 cents per therm for the months of and on its investment.
In October 2017, PSE&G submittedJanuary through April 2018. Monthly bill credits of $125 million were credited to customers for the planned update to its annual GSMP cost recovery petition, originally filed in July 2017, to include GSMP investments in service asmonths of September 30, 2017. This filing seeks BPU approval to recover in gas base rates an annual revenue increase of $25 million effective January 1,through April 2018. This increase represents the return of and on investment for GSMP investments in service through September 30, 2017. This proceeding is ongoing.   
Energy StrongESP I Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy StrongESP I investments which include a return of and on its investment.
In June 2017, PSE&G submitted the planned update to its March Energy Strong cost recovery petition, originally filed in March 2017, to include Energy Strong investments in service as of May 31, 2017. This filing requested estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. In August 2017,February 2018, the BPU approved these rate increases effective September 1, 2017.
In September 2017, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover theof an annual revenue requirementsrequirement of $8 million associated with Energy Strong capitalizedelectric ESP I capital investment costs placed in service from June 1, 2017 through November 30, 2017. The petition requests rates to be effective March 1, 2018, consistent with the BPU Order of approval of the
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Energy Strong program. The annualized requested increase in electric revenue requirement is approximately $9 million. This proceeding is ongoing.   
Basic Gas Supply Services (BGSS)Societal Benefits Charge—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase in the BGSS rate from approximately 34 cents to 37 cents per therm effective October 1, 2017. In September 2017,February 2018, the BPU approved a Stipulation in this matterPSE&G’s petition to increase electric rates by approximately $20 million on a provisionalan annual basis and the BGSS rate was increased.to decrease gas rates by approximately $0.8 million on an annual basis, in order to recover electric and gas costs incurred through May 31, 2017 under its Energy Efficiency and Renewable Energy and Social Programs. The new rates were effective April 1, 2018.
Weather Normalization Clause (WNC)—In April 2017,2018, the BPU gave final approval to PSE&G’s petition to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period.
In June 2017, PSE&G filed a petition requesting approval to collect $55 million in total net deficiency revenues comprised of $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and the remaining(October 1 through May 31), which resulted in a deficiency of $31 million, plus a carryover balance of $24 million in net deficiency gas revenue from the 2015-2016 Winter Period. The deficiency gas revenue would
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In June 2018, PSE&G filed its 2017-2018 WNC petition seeking a net recovery of $14 million to be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). In September 2017,Period. The $14 million net recovery is the BPU approved this petition on a provisional basis with rates effective October 1, 2017, allowing recovery duringresult of $9 million of excess revenues from the colder-than- normal 2017-2018 Winter Period.Period offset by $23 million of remaining prior Winter Period undercollection.
Green Program Recovery Charges (GPRC)—In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allowsJune 2018, PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs underfiled its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.
Each year PSE&G files with the BPU for annual recovery for the 11 combined components of its electric and gas Green Program investments which include a return on its investment and recovery of expenses.
In March 2017, the BPU gave final approval to PSE&G’s 20162018 GPRC cost recovery petition to recoverrequesting recovery of approximately $37$65 million and $13$6 million in electric and gas revenues, respectively, on an annual basis associated withbasis. This matter is pending.
Gas System Modernization Program I (GSMP I)—In July 2018, PSE&G’s implementation&G filed its annual GSMP I cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of these BPU approved GPRC programs for the period October$26 million effective January 1, 2016 through September 30, 2017. The rates were effective May 1, 2017.2019. This Order also includedincrease represents the return of approximately $5 millionand on investment for GSMP I investments expected to be in remaining overcollections from the completed Securitization Transition Charge. 
In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery of approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU-approved programs for the period October 1, 2017service through September 30, 2018. This proceeding is ongoing.
Remediation Adjustment Charge (RAC)—In June 2017, the BPU approved PSE&G's filing with respect to its RAC 24 petition allowing recovery of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016.request will be updated in October 2018 for actual costs.

Note 6.7. 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. Interest income on the loans is recorded on an accrual basis. The loans are generally paid back with solar renewable energy certificates (SRECs) generated from the installed solar electric system. In the event of a loan default, the basis of the solar loan would be recovered through a regulatory recovery mechanism. None of the solar loans are impaired; however, in the event a loan becomes impaired, the basis of the loan would be recovered through a regulatory recovery mechanism. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 Outstanding Loans by Class of Customer 
   As of As of 
 Consumer Loans September 30,
2017		 December 31,
2016		 
   Millions 
 Commercial/Industrial $160
 $164
 
 Residential 10
 11
 
 Total $170
 $175
 
       
       
 Outstanding Loans by Class of Customer 
   As of As of 
 Consumer Loans June 30,
2018		 December 31,
2017		 
   Millions 
 Commercial/Industrial $169
 $158
 
 Residential 9
 10
 
 Total $178
 $168
 
       
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’ equity investments in the leases are comprised of the total expected lease receivables 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. During the fourth quarter of 2016, Energy Holdings recorded a $10 million pre-tax charge for its best estimate of loss related to the leveraged lease receivables as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of December 31, 2016.
During the first quarter of 2017, due to continuing liquidity issues facing NRG REMA, LLC (REMA), economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain recent discussions with REMA management, Energy Holdings recorded an additionala $55 million pre-tax charge for its current best estimate of loss related to the lease receivables, which was reflected in Operating Revenues and is included in Gross Investments in Leases asreceivables. Additional pre-tax charges of September 30, 2017.
In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. GenOn is a subsidiary of NRG Energy, Inc. and is the parent of REMA. REMA was not included in the GenOn filing. Energy Holdings continues$22 million (including $7 million related to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with GenOn. During the second quarter of 2017, Energy Holdings completed its review of estimated residual values embedded in its leveraged lease portfolio of generating assets and the outcome indicated that one of the residual value estimates was lower than the recorded residual value due to a further deterioration of market conditions and changes to operating cost estimates. This decline was determined to be other than temporary. As a result, a pre-tax write-down of $7 million wasimpairment) were recorded in the quarter ended June 30, 2017. In addition, basedSubject to the terms of the Credit Support Forbearance and Rent Payment Forbearance described below, lease payments and adjustments to qualifying credit support on the REMA leases are due semiannually in January and July of each year.
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Based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15$20 million pre-tax charge in the quarter ended June 30, 2018 for its current best estimate of loss related to lease receivables. The second quarter 2017 pre-tax write-down and additional chargePre-tax charges were reflected in Operating Revenues in the first half of 2018 and 2017 and are included in Gross Investment in Leases as of June 30, 2018.
Certain subsidiaries of Energy Holdings, REMA, certain holders of the pass-through certificates and other parties have entered into a forbearance agreement (Credit Support Forbearance) relating to REMA’s obligation to procure additional qualifying credit support for September 30, 2017.the Conemaugh facility. In addition, certain subsidiaries of Energy Holdings, REMA, certain holders of the pass-through certificates and other parties have entered into forbearance agreements (Rent Payment Forbearance) relating to the Keystone, Conemaugh and Shawville facilities. The parties to the Rent Payment Forbearance have agreed to permit REMA to enter into agreements with third parties relating to certain energy management, operation and maintenance and other services and have agreed to temporarily forbear from exercising rights and remedies related to certain events of default relating to certain periodic lease rent payments required to be made by REMA in July 2018.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSThe Credit Support Forbearance will remain effective until the earlier of (i) two weeks following the date on which Energy Holdings subsidiaries, REMA and/or the consenting certificate holders provide written notice to REMA of its intention to terminate the Forbearance, and (ii) the date on which any event of termination as specified in the Credit Support Forbearance occurs. The Rent Payment Forbearance for each facility will remain effective until the earlier of (i) August 17, 2018 and (ii) the date on which any of the following events occur: (a) a new event of default occurs and is continuing under the operative documents governing the respective facilities; (b) REMA commences a case under title 11 of the United States Bankruptcy Code or (c) REMA terminates discussions with Energy Holdings and/or the consenting pass-through certificate holders regarding a potential restructuring by REMA.
(UNAUDITED)
TablePSEG cannot predict the outcome of Contents


GenOn’s restructuring process or 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 lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service (IRS). Also, if energy markets continue to deteriorate, it is possible that additional write-downs, including residual value impairment, could occur.
The following table shows Energy Holdings’ gross and net lease investment as of SeptemberJune 30, 20172018 and December 31, 2016, respectively.2017.
      
  As of As of 
  September 30,
2017		 December 31,
2016		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$546
 $629
 
 Estimated Residual Value of Leased Assets326
 346
 
 Total Investment in Rental Receivables872
 975
 
 Unearned and Deferred Income(309) (326) 
 Gross Investment in Leases563
 649
 
 Deferred Tax Liabilities(631) (674) 
 Net Investment in Leases$(68) $(25) 
      
      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$525
 $546
 
 Estimated Residual Value of Leased Assets326
 326
 
 Total Investment in Rental Receivables851
 872
 
 Unearned and Deferred Income(299) (307) 
 Gross Investment in Leases552
 565
 
 Deferred Tax Liabilities(500) (480) 
 Net Investment in Leases$52
 $85
 
      
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The corresponding receivables associated with the lease portfolio are reflected in the following table,as follows, 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 September 30, 2017   
  As of September 30, 2017 
   Millions 
 AA $15
 
 BBB+ — BBB- 316
 
 BB- 133
 
 CCC- 82
 
 Total $546
 
     
     
   
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating Standard & Poor’s (S&P) as of June 30, 2018   
  As of June 30, 2018 
   Millions 
 AA $14
 
 BBB+ — BBB- 316
 
 BB- 133
 
 CCC- 62
 
 Total $525
 
     
The “BB-” and the “CCC-” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of SeptemberJune 30, 20172018, the gross investment in the leases of such assets, net of non-recourse debt, was $337315 million ($(184)(112) million, net of deferred taxes). A more detailed description of such assets under lease as of September 30, 2017, 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 $133
 64% 1,538
 Coal BB- NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $84
 64% 1,036
 Gas BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $20
 17% 1,711
 Coal CCC- REMA (A) 
 Conemaugh Station Units 1 and 2 PA $20
 17% 1,711
 Coal CCC- REMA (A) 
 Shawville Station Units 1, 2, 3 and 4 PA $80
 100% 596
 Gas CCC- REMA (A) 
                 
                 
 Asset Location 
Gross
Investment
 
%
Owned
 Total MW 
Fuel
Type
 
Counterparties’
S&P Credit
Ratings
 Counterparty 
     Millions           
 Powerton Station Units 5 and 6 IL $132
 64% 1,538
 Coal BB- NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $85
 64% 1,036
 Gas BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $10
 17% 1,711
 Coal CCC- REMA (A) 
 Conemaugh Station Units 1 and 2 PA $10
 17% 1,711
 Coal CCC- REMA (A) 
 Shawville Station Units 1, 2, 3 and 4 PA $78
 100% 596
 Gas CCC- REMA (A) 
                 
(A)REMA’s parent company, GenOn and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Certain subsidiaries of Energy Holdings, REMA, consenting holders of the pass-through certificates and other parties have entered into a Credit Support Forbearance relating to the Conemaugh facility and the Rent Payment Forbearance relating to the Keystone, Conemaugh and Shawville facilities, as described above.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees.lease. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and 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 and trigger certain material tax obligations which could wholly or partially be mitigated by tax indemnification claims against 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 restructuring process or 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 and continues to discuss the situation with GenOn. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service (IRS).
Additional factors that 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.

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Note 7. Available-for-Sale Securities8. Trust Investments
NDT Fund
Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon their respective 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 funds are managed by third-party investment managers 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 September 30, 2017 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$706
 $331
 $(5) $1,032
 
 Debt Securities        
 Government561
 10
 (4) 567
 
 Corporate352
 7
 (1) 358
 
 Total Debt Securities913
 17
 (5) 925
 
 Other Securities55
 —
 —
 55
 
 Total NDT Available-for-Sale Securities$1,674
 $348
 $(10) $2,012
 
          
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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  As of June 30, 2018 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
 Domestic$471
 $235
 $(8) $698
 
    International321
 76
 (14) 383
 
 Total Equity Securities792
 311
 (22) 1,081
 
 Available-for Sale Debt Securities        
 Government528
 1
 (12) 517
 
 Corporate464
 —
 (14) 450
 
 Total Available-for-Sale Debt Securities992
 1
 (26) 967
 
 Other1
 —
 —
 1
 
 Total NDT Fund Investments$1,785
 $312
 $(48) $2,049
 
          
          
  As of December 31, 2016 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$705
 $263
 $(11) $957
 
 Debt Securities        
 Government518
 8
 (6) 520
 
 Corporate337
 4
 (4) 337
 
 Total Debt Securities855
 12
 (10) 857
 
 Other Securities44
 —
 —
 44
 
 Total NDT Available-for-Sale Securities (A)$1,604
 $275
 $(21) $1,858
 
          
          
  As of December 31, 2017 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
 Domestic$497
 $245
 $(2) $740
 
    International311
 99
 (3) 407
 
 Total Equity Securities808
 344
 (5) 1,147
 
 Available-for Sale Debt Securities        
 Government586
 2
 (4) 584
 
 Corporate400
 4
 (2) 402
 
 Total Available-for-Sale Debt Securities986
 6
 (6) 986
 
 Total NDT Fund Investments$1,794
 $350
 $(11) $2,133
 
          
(A)The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund.
Net unrealized gains (losses) on debt securities of $(14) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of June 30, 2018. The portion of net unrealized gains (losses) recognized during the second quarter and first half of 2018 related to equity securities still held at the end of June 30, 2018 were $12 million and $(3) million, respectively.
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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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  As of As of 
  September 30,
2017		 December 31,
2016		 
  Millions 
 Accounts Receivable$11
 $8
 
 Accounts Payable$5
 $5
 
      


      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 Accounts Receivable$11
 $24
 
 Accounts Payable$8
 $74
 
      
The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months.
                  
  As of September 30, 2017 As of December 31, 2016 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Equity Securities (A)$67
 $(5) $—
 $—
 $120
 $(10) $8
 $(1) 
 Debt Securities                
 Government (B)237
 (2) 62
 (2) 276
 (6) 4
 —
 
 Corporate (C)60
 —
 36
 (1) 139
 (3) 15
 (1) 
 Total Debt Securities297
 (2) 98
 (3) 415
 (9) 19
 (1) 
 Other Securities3
 —
 —
 —
 —
 —
 —
 —
 
 NDT Available-for-Sale Securities$367
 $(7) $98
 $(3) $535
 $(19) $27
 $(2) 
                  
                  
  As of June 30, 2018 As of December 31, 2017 
  
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)                
    Domestic$79
 $(8) $—
 $—
 $40
 $(2) $—
 $—
 
    International74
 (13) 4
 (1) 29
 (3) 2
 —
 
 Total Equity Securities153
 (21) 4
 (1) 69
 (5) 2
 —
 
 Available-for Sale Debt Securities                
 Government (B)402
 (9) 64
 (3) 343
 (2) 91
 (2) 
 Corporate (C)358
 (12) 25
 (2) 191
 (1) 27
 (1) 
 Total Available-for-Sale Debt Securities760
 (21) 89
 (5) 534
 (3) 118
 (3) 
 NDT Trust Investments$913
 $(42) $93
 $(6) $603
 $(8) $120
 $(3) 
                  
(A)Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. TheEffective January 1, 2018, unrealized gains and losses are distributed over a broad range of securities with limited impairment durations. Power does not consideron these securities to be other-than-temporarily impaired as of September 30, 2017.are recorded in Net Income.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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(B)Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will 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 SeptemberJune 30, 2017.2018.
(C)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). 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 SeptemberJune 30, 2017.2018.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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The proceeds from the sales of and the net realized gains (losses) on securities in the NDT Fund were:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
  Millions 
 Proceeds from NDT Fund Sales (A)$278
 $139
 $845
 $470
 
 Net Realized Gains (Losses) on NDT Fund:        
 Gross Realized Gains$29
 $11
 $82
 $36
 
 Gross Realized Losses(5) (3) (14) (25) 
 Net Realized Gains (Losses) on NDT Fund$24
 $8
 $68
 $11
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
  Millions 
 Proceeds from NDT Fund Sales (A)$402
 $320
 $774
 $567
 
 Net Realized Gains (Losses) on NDT Fund        
 Gross Realized Gains$34
 $32
 $58
 $53
 
 Gross Realized Losses(10) (5) (22) (9) 
 Net Realized Gains (Losses) on NDT Fund (B)$24
 $27
 $36
 $44
 
 Unrealized Gains (Losses) on Equity Securities in NDT Fund (C)(16) N/A
 (50) N/A
 
 Other-Than-Temporary-Impairments$—
 $(3) —
 (4) 
 Net Gains (Losses) on NDT Fund Investments$8
 $24
 $(14) $40
 
          
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.
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 $172 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of September 30, 2017.

(C)Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).
The NDT available-for-saleFund debt securities held as of SeptemberJune 30, 20172018 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $37
 
 1 - 5 years 236
 
 6 - 10 years 230
 
 11 - 15 years 62
 
 16 - 20 years 67
 
 Over 20 years 293
 
 Total NDT Available-for-Sale Debt Securities$925
 
     
     
 Time Frame Fair Value 
   Millions 
 Less than one year $10
 
 1 - 5 years 298
 
 6 - 10 years 196
 
 11 - 15 years 45
 
 16 - 20 years 71
 
 Over 20 years 347
 
 Total NDT Available-for-Sale Debt Securities$967
 
     
Power periodically assesses individual debt 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 incomethese 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, 2017, Other-Than-Temporary Impairments (OTTI) of$9 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be
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(UNAUDITED)
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recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
Rabbi Trust
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.
          
  As of September 30, 2017 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$22
 $1
 $—
 $23
 
 Debt Securities        
 Government82
 2
 —
 84
 
 Corporate118
 3
 (1) 120
 
 Total Debt Securities200
 5
 (1) 204
 
 Other Securities2
 —
 —
 2
 
 Total Rabbi Trust Available-for-Sale Securities$224
 $6
 $(1) $229
 
          
          
  As of June 30, 2018 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
    Domestic$21
 $3
 $—
 $24
 
    International—
 —
 —
 —
 
 Total Equity Securities21
 3
 —
 24
 
 Available-for-Sale Debt Securities        
 Government96
 —
 (2) 94
 
 Corporate110
 —
 (4) 106
 
 Total Available-for-Sale Debt Securities206
 —
 (6) 200
 
 Total Rabbi Trust Investments$227
 $3
 $(6) $224
 
          
          
  As of December 31, 2016 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$11
 $11
 $—
 $22
 
 Debt Securities        
 Government105
 —
 (2) 103
 
 Corporate92
 1
 (2) 91
 
 Total Debt Securities197
 1
 (4) 194
 
 Other Securities1
 —
 —
 1
 
 Total Rabbi Trust Available-for-Sale Securities$209
 $12
 $(4) $217
 
          
          
  As of December 31, 2017 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
    Domestic$24
 $3
 $—
 $27
 
    International—
 —
 —
 —
 
 Total Equity Securities24
 3
 —
 27
 
 Available-for-Sale Debt Securities        
 Government85
 1
 (1) 85
 
 Corporate118
 2
 (1) 119
 
 Total Available-for-Sale Debt Securities203
 3
 (2) 204
 
 Total Rabbi Trust Investments$227
 $6
 $(2) $231
 
          
Net unrealized gains (losses) on debt securities of $(4) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Condensed Consolidated Balance Sheet as of June 30, 2018. The portion of net unrealized gains (losses) recognized during both the second quarter and first half of 2018 related to equity securities still held at the end of June 30, 2018 was less than $1 million.
The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.
      
  As of As of 
  September 30,
2017		 December 31,
2016		 
  Millions 
 Accounts Receivable$2
 $5
 
 Accounts Payable$—
 $3
 
      
      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 Accounts Receivable$2
 $2
 
 Accounts Payable$—
 $1
 
      
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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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 12 months and greater than 12 months.
                  
  As of September 30, 2017 As of December 31, 2016 
  
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 (B)25
 —
 3
 —
 60
 (2) 1
 —
 
 Corporate (C)14
 (1) 4
 —
 46
 (2) 3
 —
 
 Total Debt Securities39
 (1) 7
 —
 106
 (4) 4
 —
 
 Rabbi Trust Available-for-Sale Securities$39
 $(1) $7
 $—
 $106
 $(4) $4
 $—
 
                  
                  
  As of June 30, 2018 As of December 31, 2017 
  
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 
 Available-for-Sale Debt Securities                
 Government (A)$57
 $(1) 23
 (1) $28
 $—
 $25
 $(1) 
 Corporate (B)93
 (4) 6
 —
 39
 (1) 9
 —
 
 Total Available-for-Sale Debt Securities150
 (5) 29
 (1) 67
 (1) 34
 (1) 
 Rabbi Trust Investments$150
 $(5) $29
 $(1) $67
 $(1) $34
 $(1) 
                  
(A)Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors.
(B)Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The 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. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will 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 SeptemberJune 30, 2017.2018.
(C)(B)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). 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 SeptemberJune 30, 2017.2018.
The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
  Millions 
 Proceeds from Rabbi Trust Sales (A)$24
 $20
 $168
 $81
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$—
 $2
 $17
 $5
 
 Gross Realized Losses(1) (2) (5) (4) 
 Net Realized Gains (Losses) on Rabbi Trust$(1) $—
 $12
 $1
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
  Millions 
 Proceeds from Rabbi Trust Sales (A)$22
 $93
 $47
 $144
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$—
 $2
 $2
 $17
 
 Gross Realized Losses—
 (1) (2) (4) 
 Net Realized Gains (Losses) on Rabbi Trust (B)—
 1
 —
 13
 
 Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C)—
 N/A
 —
 N/A
 
 Other-Than-Temporary-Impairments—
 $—
 —
 —
 
 Net Gains (Losses) on Rabbi Trust Investments$—
 $1
 $—
 $13
 
          
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.
Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains of $3 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of September 30, 2017.
(C)Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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The Rabbi Trust available-for-sale debt securities held as of SeptemberJune 30, 20172018 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $—
 
 1 - 5 years 40
 
 6 - 10 years 27
 
 11 - 15 years 6
 
 16 - 20 years 19
 
 Over 20 years 112
 
 Total Rabbi Trust Available-for-Sale Debt Securities$204
 
     
     
 Time Frame Fair Value 
   Millions 
 Less than one year $1
 
 1 - 5 years 39
 
 6 - 10 years 23
 
 11 - 15 years 7
 
 16 - 20 years 18
 
 Over 20 years 112
 
 Total Rabbi Trust Available-for-Sale Debt Securities$200
 
     
PSEG periodically assesses individual debt 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 an 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, 2017, no OTTIs 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 the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:
      
  As of As of 
  September 30,
2017		 December 31,
2016		 
  Millions 
 PSE&G$46
 $43
 
 Power57
 53
 
 Other126
 121
 
 Total Rabbi Trust Available-for-Sale Securities$229
 $217
 
      
      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 PSE&G$45
 $46
 
 Power56
 57
 
 Other123
 128
 
 Total Rabbi Trust Investments$224
 $231
 
      

Note 8.9. Pension and Other Postretirement Benefits (OPEB)
PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria.
As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $12 million and $36 million for the three months and nine months, ended September 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents


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 for PSEG, excluding Servco. Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for capitalization, when applicable. For additional information, see Note 2. Recent Accounting Standards.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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  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, 
  2017
 2016 2017
 2016 2017 2016 2017 2016 
  Millions 
 Components of Net Periodic Benefit Costs                
 Service Cost$29
 $28
 $4
 $5
 $86
 $82
 $12
 $13
 
 Interest Cost51
 50
 15
 15
 153
 151
 47
 44
 
 Expected Return on Plan Assets(98) (98) (8) (8) (295) (295) (25) (23) 
 Amortization of Net                
 Prior Service Cost (Credit)(5) (5) (3) (4) (14) (14) (8) (11) 
 Actuarial Loss24
 39
 13
 10
 73
 118
 38
 30
 
 Total Benefit Costs$1
 $14
 $21
 $18
 $3
 $42
 $64
 $53
 
                  
                  
  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, 
  2018
 2017 2018
 2017 2018 2017 2018 2017 
  Millions 
 Components of Net Periodic Benefit (Credits) Costs                
 Service Cost (included in O&M Expense)$33
 $28
 $5
 $4
 $65
 $57
 $9
 $8
 
 Non-Service Components of Pension and OPEB (Credits) Costs                
 Interest Cost52
 51
 17
 16
 104
 102
 33
 32
 
 Expected Return on Plan Assets(110) (99) (11) (9) (220) (197) (21) (17) 
 Amortization of Net                
 Prior Service Cost(5) (4) —
 (2) (9) (9) —
 (5) 
 Actuarial Loss21
 25
 16
 12
 42
 49
 32
 25
 
 Non-Service Components of Pension and OPEB (Credits) Costs(42) (27) 22
 17
 (83) (55) 44
 35
 
 Total Benefit (Credits) Costs$(9) $1
 $27
 $21
 $(18) $2
 $53
 $43
 
                  
Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, excluding Servco, are detailed as follows:
                  
  Pension Benefits OPEB Pension Benefits OPEB 
  Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended 
  September 30, September 30, September 30, September 30, 
  2017 2016 2017 2016 2017 2016 2017 2016 
  Millions 
 PSE&G$(1) $8
 $13
 $11
 $(3) $22
 $40
 $33
 
 Power—
 3
 7
 6
 1
 11
 20
 17
 
 Other2
 3
 1
 1
 5
 9
 4
 3
 
 Total Benefit Costs$1
 $14
 $21
 $18
 $3
 $42
 $64
 $53
 
                  
                  
  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, 
  2018 2017 2018 2017 2018 2017 2018 2017 
  Millions 
 PSE&G$(7) $(1) $17
 $13
 $(15) $(2) $34
 $27
 
 Power(3) 1
 8
 6
 (5) 1
 16
 13
 
 Other1
 1
 2
 2
 2
 3
 3
 3
 
 Total Benefit (Credits) Costs$(9) $1
 $27
 $21
 $(18) $2
 $53
 $43
 
                  
During the three months ended March 31, 2017,2018, PSEG contributed its entire planned contribution for the year 20172018 of $14 million into its OPEB plan.
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 4.5. Variable Interest Entity. 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 contribute $40 million into its pension plan trusts during 2018. Servco’s pension-related revenues and costs were $18$10 million and $16$8 million for three months ended June 30, 2018 and 2017, respectively, and $20 million and $17 million for the threesix months ended SeptemberJune 30, 2018 and 2017, and 2016, respectively, and $35 million and $28 million for the nine months ended September 30, 2017 and 2016, respectively. Servco’s pension-related costs of $35 million for the nine months ended September 30, 2017 represent its entire planned contribution for the year 2017. The OPEB-related revenues earned and costs incurred were $1$2 million and $3$1 million for the three months ended June 30, 2018 and nine2017, respectively, and $3 million and $2 million for the six months ended SeptemberJune 30, 2017. The OPEB-related revenues earned2018 and costs incurred were immaterial for the three months and nine months ended September 30, 2016.2017, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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Note 9.10. 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 as a form of collateral.
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.
Power is subject to
counterparty collateral calls related to commodity contracts, and
certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
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
the net position 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. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
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’s outstanding guarantees, current exposure and margin positions as of SeptemberJune 30, 20172018 and December 31, 2016.2017.
      
  As of As of 
  September 30,
2017		 December 31,
2016		 
  Millions 
 Face Value of Outstanding Guarantees$1,846
 $1,806
 
 Exposure under Current Guarantees$108
 $139
 
      
 Letters of Credit Margin Posted$134
 $157
 
 Letters of Credit Margin Received$59
 $99
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(2) $(1) 
    Net Broker Balance Deposited (Received)$(6) $57
 
      
 Additional Amounts Posted:    
 Other Letters of Credit$61
 $51
 
      
      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 Face Value of Outstanding Guarantees$1,780
 $1,701
 
 Exposure under Current Guarantees$129
 $153
 
      
 Letters of Credit Margin Posted$152
 $103
 
 Letters of Credit Margin Received$18
 $32
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(2) $(1) 
    Net Broker Balance Deposited (Received)$124
 $147
 
      
 Additional Amounts Posted:    
 Other Letters of Credit$63
 $61
 
      
As part of determining credit exposure, Power nets receivables and payables with the corresponding net fair values of energy contract balances.contracts. See Note 11.12. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated 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 have posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.
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 EPAThe U.S. Environmental Protection Agency (EPA) has 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 sitesCERCLA 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.River needed to be performed. 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, 73certain 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 miles of the lower Passaic River. At such time, theThe CPG alsohas agreed to allocate, on an interim basis, the associated costs of the
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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 seven7.6 percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one1.9 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 Certain PRPs are currently involved 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 agreementdiscussions with the EPA commencedregarding cost allocations and related indemnification matters. We cannot predict the removaloutcome of certain contaminated sediments at Passaic River Mile 10.9 at an estimated costthese discussions, or whether individual PRPs will be able to meet their obligations, either 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.which could have a material impact on PSE&G’s and Power’s combined shareallocation of the costcosts.
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Table of that effort is approximately three percent. The remaining CPG members, PSE&G and Power included, have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal.Contents
On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River.
The CPG, which consisted of 50 members as of September 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $195 million, which the CPG continues to incur. Of the estimated $195 million, as of September 30, 2017, the CPG had spent approximately $168 million, of which PSEG’s total share was approximately $12 million.




The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’sRiver with an estimated costscost to remediate the lower 17 miles of the Passaic River which rangeranging 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 and Power’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 FFSEPA’s own Focused Feasibility Study (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 estimatesestimated 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’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. These accruals brought the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power. There have been no additional accruals recorded since the first quarter of 2016.
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 Chemical Corporation (OCC), andone of the townsPRPs, has commenced performance 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 Shamrock, would voluntarily perform the remedial design forrequired by the ROD Remedy. On September 30, 2016, OCC and the EPA
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executed 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 remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and thecost contribution from all other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”
In June 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Maxus and Tierra are subsidiaries of YPF Holdings, Inc. (YPF Holdings). YPF Holdings is a wholly owned subsidiary of YPF S.A. (YPF), a company controlled by the Argentinian government. Neither YPF Holdings nor YPF is a party to the bankruptcy proceedings. However, Tierra and Maxus have filed a plan of liquidation that may allow the parties to assert one or more causes of action to hold YPF responsible for certain amounts owed by Tierra and Maxus. The bankruptcy plan ordered by the Delaware Court in July, 2017 created a Liquidating Trust to pursue outstanding creditors’ claims, including alter ego claims against YPF. PSEG cannot currently determine the impact, if any, that the bankruptcy of Tierra and Maxus or any related proceeding might have on its allocable share or total liability for the Passaic River matter, and therefore, PSEG, through the CPG and independently, will continue to monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs.
In March 2017, the EPA sent a letter to certain PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. The impact of this proposed settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.
In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs that received General Notice letters (excluding PRPs that settle pursuant to the early cash-out settlement that the EPA offered in March 2017, among others).PRPs. The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform and pay for the remedial action under EPA oversight. DiscussionsThe allocation process has commenced and is scheduled to be completed in late 2019. Conversations between the EPA and the PRPs regarding remediation of the Passaic River’s upper 9 miles are ongoing.
In a separate matter, two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), filed for Chapter 11 bankruptcy in Delaware Federal Bankruptcy Court. In June 2018, the trust representing the creditors in this proceeding filed a complaint asserting claims against the current and former parent entities of Tierra and Maxus, among other parties, for up to $14 billion. Any damages awarded may be used to fund, in part, the remediation costs of the lower 8.3 miles of the Passaic River. The creditor trust has reserved its right to file contribution claims against 28 PRPs, including PSEG. This matter is ongoing.
In June 2018, OCC filed a complaint in Federal District Court in Newark against various defendants, including PSE&G, seeking cost recovery and contribution under CERCLA for the remediation of the lower 8.3 miles of the Passaic River. The complaint does not quantify damages sought.
The Complaint alleges that “no single hazardous substance” is to blame for the contamination of the lower Passaic River and lists the eight Contaminants of Concern (COCs) identified by the EPA in the ROD. OCC alleges PSE&G is responsible for a portion of six of the eight COCs. PSE&G cannot predict the outcome of this matter.
Based upon the estimated cost of the ROD Remedy and PSEG’s estimate of PSE&G’s and Power’s shares of that cost, as of June 30, 2018, PSEG has accrued approximately $57 million. Of this amount, PSE&G has accrued $46 million as an Environmental Costs Liability and a corresponding Regulatory Asset based on its continued ability to recover such costs in its rates. Power has accrued $11 million as an Other Noncurrent Liability with the matter are ongoing.corresponding O&M Expense recorded in prior years when the liability was accrued.
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 and Power’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 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’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
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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.
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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 $390$332 million and $440$378 million on an undiscounted basis through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $390$332 million as of SeptemberJune 30, 2017.2018. Of this amount, $74$79 million was recorded in Other Current Liabilities and $316$253 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $390$332 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 to what extent 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.
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 (CWA) 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.
In May 2014, the EPA issued a final cooling water intake rule that establishes new requirements for the regulation of cooling water intake structuresintakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.
The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range ofbasis, based on studies related to impingement mortality and entrainment and submitby the results with their permit applications.facilities seeking renewal permits.
In September 2014, severalSeveral environmental non-governmental groupsorganizations and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Court of Appeals for the Second Circuit (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the CWA and the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit, and ain July 2018 the Second Circuit upheld the EPA’s final cooling water intake rule. The Court’s decision remains pending.allows Permitting Directors to continue to issue permits in accordance with the flexible, site-specific provisions of the final rule.
In June 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.Salem. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final NJPDES renewal permit for Salem. This matter is still pending.NJDEP has granted the hearing request, but it has not yet been scheduled. The Riverkeeper’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
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the CWA. Potential cooling 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 without making significant upgrades to existing intake structuresintakes and cooling systems.
Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations.
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 BH3. To address compliance with the EPA’s CWA Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power wouldhas proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit.
Separately, Power has also negotiatedentered into a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all of its conditions precedent conditions occur,
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which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life.
In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council (CSC) issued an order to approve siting Bridgeport Harbor Station unit 5.Unit 5 (BH5). All major environmental permits have been received; however, secondary approvals are still being obtained to allow operations to begin by June 2019.in mid-2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed.
Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance
In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the 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 dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the 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 beenwas undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter and the parties may also be subject to the assessment of civil penalties related to the discharge and response. The U.S. Coast Guard transitioned control of the federal response to the EPA in May 2018. As part of this transition, the U.S. Coast Guard rescinded its Administrative Order to PSE&G related to this matter.
The impacted cable was repaired in late-Septemberlate September 2017; however, small amounts of residual dielectric fluid believed to be contained within the investigationmarina sediment continue to appear on the surface and response actions related to the fluid discharge are ongoing.ongoing, although at a significantly reduced scale. PSE&G remains concerned about future leaks and potential environmental impacts as a result of reintroduction of fluid back into these lines and has determined that retirement of the affected facilities is appropriate. PSE&G has been unable to reach an agreement with Con Edison and, as a result, in May 2018, PSE&G filed an action at FERC to resolve the matter. Also ongoing is the process to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC, including an action filed by PSE&G in federal court in New Jersey federal court seeking damages from NADC. In that action, NADC has also pursued counterclaims against PSE&G and Con Edison seeking damages for its costs to address the leak. Based on theinformation currently available and depending on the outcome of the New Jersey federal court action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover these costs through regulatory proceedings.
Steam Electric Effluent Guidelines
In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG 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, and gasification 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 Bridgeport Harbor station and the jointly-owned Keystone and
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Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule.the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule.ELG Rule.
In April 2017,Through various orders, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay ofhas stayed the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations for the aforementioned waste streams.In September 2017, the EPA issued a rule postponing for two years compliance dates solely related to bottom ash transport waterELG Rule and flue gas desulfurization wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revisedfurther revise the requirements and compliance dates for these two waste streams.of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.
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 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
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winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.
The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 20162018 is $276.83$287.76 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 20162018 of $335.33$276.83 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.
PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:
           
  Auction Year  
  2014 2015 2016 2017  
 36-Month Terms EndingMay 2017
 May 2018
 May 2019
 May 2020
(A)  
 Load (MW)2,800
 2,900
 2,800
 2,800
   
 $ per MWh$97.39 $99.54 $96.38 $90.78   
           
           
  Auction Year  
  2015 2016 2017 2018  
 36-Month Terms EndingMay 2018
 May 2019
 May 2020
 May 2021
(A)  
 Load (MW)2,900
 2,800
 2,800
 2,900
  
 $ per MWh$99.54 $96.38 $90.78 $91.77  
           
(A)Prices set in the 20172018 BGS auction year became effective on June 1, 20172018 when the 20142015 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 18.19. 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 2020 and a significant portion through 20212022 at Salem, Hope Creek and Peach Bottom.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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Power has various multi-year contracts for natural gas and firm pipeline transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess pipelinedelivery capacity available beyond the needs of PSE&G’s customers, Power can use the gas to make third-party sales and if excess volume remains after the third-party sales, supply its fossil generating stations in New Jersey.
Power also has various long-term fuel purchase commitments for coal through 2021 to support its Keystone and Conemaugh fossil generation stations.
As of SeptemberJune 30, 2017,2018, the total minimum purchase requirements included in these commitments were as follows:
     
 Fuel Type Power's Share of Commitments through 2021 
   Millions 
 Nuclear Fuel   
 Uranium $257
 
 Enrichment $328
 
 Fabrication $178
 
 Natural Gas $963
 
 Coal $308
 
     
     
 Fuel Type Power's Share of Commitments through 2022 
   Millions 
 Nuclear Fuel   
 Uranium $244
 
 Enrichment $345
 
 Fabrication $161
 
 Natural Gas $990
 
 Coal $278
 
     
Regulatory Proceedings
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
FERC Compliance(UNAUDITED)
PJM Bidding MatterTable of Contents






Litigation
Sewaren 7 Construction
In June 2018, a complaint was filed in federal court in Newark against PSEG Fossil, LLC, a wholly owned subsidiary of Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the first quarterSewaren 7 project. Among other things, Durr seeks damages of 2014,$93 million and alleges that Power discoveredwithheld money owed to Durr and that it incorrectly calculated certain componentsPower’s intentional conduct led to the inability of its cost-based bids for its New Jersey fossil generating unitsDurr to obtain prospective contracts. Power intends to vigorously defend against these allegations. Based upon the preliminary nature of this matter, a loss is not considered probable nor is the amount of loss, if any, estimable as of June 30, 2018.
Newark Customer Incident
On the morning of July 5, 2018, PSE&G discontinued electricity to the home of a customer residing in Newark because of outstanding arrears on that customer’s account. Subsequent to the discontinuation of electricity, that customer died on the afternoon of July 5th. The family of the customer, who was on hospice care, has raised allegations in the PJM energy market. Upon discoverymedia regarding PSE&G’s conduct surrounding the discontinuation and restoration of electricity to the home of the errors,customer, claiming that the discontinuation of electric service prevented the customer from using life sustaining medical equipment. The BPU has initiated an investigation into the matter. In addition, PSE&G received a grand jury subpoena from the Essex County Prosecutor’s Office (ECPO) for records and correspondence between PSE&G and the customer. PSE&G is fully cooperating with the BPU and the ECPO in both proceedings. The PSEG Board of Directors retained outside counsel to assistconduct an independent investigation of the facts surrounding this incident with the full support and cooperation of management. PSEG cannot predict the outcome of this matter.
Other Litigation and Legal Proceedings
PSEG and its subsidiaries are party to various lawsuits in the conductordinary course of an investigation intobusiness. In view of the matterinherent difficulty in predicting the outcome of such matters, PSEG, PSE&G and self-reportedPower generally cannot predict the errors. Aseventual outcome of the internal investigation proceeded, additional pricing errors inpending matters, the bids were identified. It was further determined thattiming of 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 has implemented procedures and continues to review its policies and practices to mitigate the risk of similar issues occurring in the future. During the three months ended March 31, 2014, based upon its best estimate available at the time, Power recorded a pre-tax charge to income in the amount of $25 million related to this matter.
Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into these matters. While considerable uncertainty remains as to the finalultimate resolution of these matters, based upon developments inor the investigation in the first quarter of 2017, Power believes the disgorgement and interest costseventual loss, fines or penalties related to each pending matter.
In accordance with applicable accounting guidance, a liability is accrued when those matters present loss contingencies that are both probable and reasonably estimable. In such cases, there may be an exposure to loss in excess of any amounts accrued. PSEG will continue to monitor the cost-based bidding matter may range between approximately $35 million and $135 million, depending onfor further developments that could affect the legal interpretationamount of the principles underaccrued liability that has been previously established.
Based on current knowledge, management does not believe that loss contingencies arising from pending matters, other than the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accruedmatters described herein, could have a material adverse effect on PSEG’s, PSE&G’s or Power’s consolidated financial position or liquidity. However, in light of the low endinherent uncertainties involved in these matters, some of this range of $35 million by recording an additional pre-tax charge to income of $10 million duringwhich are beyond PSEG’s control, and the three months ended March 31, 2017. Power is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matterlarge or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, anyindeterminate damages sought in some of these amountsmatters, an adverse outcome in one or more of these matters could be individually material to PSEG and Power.
Power continues to believe that it has legal defenses that it may assert in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majorityPSEG’s, PSE&G’s or Power’s results of the hours was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial. Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement. As a result, PSEG and Power cannot predict the final outcome of these matters.
Financial Transmission Rights (FTR) Auction Matter
In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in PJM’s annual FTR auction for the 2016-2017 planning year and the monthly PJM FTR auctions for February, March and April 2016. In October 2017, FERC Staff closed the investigation with no impact to PSEG’s operations or future earnings results.liquidity for any particular reporting period.

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






Note 10.11. Debt and Credit Facilities
Long-Term Debt Financing Transactions
The following long-term debt transactions occurred in the ninesix months ended SeptemberJune 30, 2017:
PSEG
entered into an agreement for a new term loan maturing June 2019. The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.80% and can be terminated at any time without penalty.2018:
PSE&G
issued $425$375 million of 3.00%3.70% Secured Medium-Term Notes, Series LM, due May 2027.2028,
issued $325 million of 4.05% Secured Medium-Term Notes, Series M, due May 2048, and
retired $400 million of 5.30% Medium-Term Notes at maturity.
Power
issued $700 million of 3.85% Senior Notes due June 2023.
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.
In March 2017, PSEG, Power and PSE&G amended their credit agreements, extending the expiration dates to March 2022. Concurrently, PSEG increased its existing $1 billion in credit facilities to $1.5 billion and Power decreased its existing $2.6 billion in credit facilities to $2.1 billion, which includes two new 3-year $100 million letter of credit facilities that expire in March 2020.
The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of SeptemberJune 30, 2017,2018, the total available credit capacity was $3.8$3.7 billion.
As of SeptemberJune 30, 2017,2018, no single institution represented more than 8% of the total commitments in the credit facilities.
As of SeptemberJune 30, 2017,2018, total credit capacity was in excess of the total anticipated maximum liquidity requirements of PSEG, PSE&G and Power.over PSEG’s 12-month planning horizon.
Each of the 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’ liquidity needs. The total credit facilities and available liquidity as of SeptemberJune 30, 20172018 were as follows:
             
   As of September 30, 2017     
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
   5-year Credit Facilities (A) $1,500
 $215
 $1,285
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSEG $1,500
 $215
 $1,285
     
 PSE&G           
  5-year Credit Facility (A) $600
 $15
 $585
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSE&G $600
 $15
 $585
     
 Power           
   3-year LC Facilities $200
 $112
 $88
 Mar 2020 Letters of Credit 
   5-year Credit Facilities 1,900
 70
 1,830
 Mar 2022 Funding/Letters of Credit 
 Total Power $2,100
 $182
 $1,918
     
 Total $4,200
 $412
 $3,788
     
             
             
   As of June 30, 2018     
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
   5-year Credit Facilities (A) $1,500
 $88
 $1,412
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSEG $1,500
 $88
 $1,412
     
 PSE&G           
   5-year Credit Facility (A) $600
 $211
 $389
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSE&G $600
 $211
 $389
     
 Power           
   3-year Letter of Credit Facilities $200
 $162
 $38
 Mar 2020 Letters of Credit 
   5-year Credit Facilities 1,900
 40
 1,860
 Mar 2022 Funding/Letters of Credit 
 Total Power $2,100
 $202
 $1,898
     
 Total $4,200
 $501
 $3,699
     
             
(A)The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of SeptemberJune 30, 2017,2018, PSEG had $202$75 million outstanding at a weighted average interest rate of 1.37%2.32%. PSE&G had no amounts$195 million outstanding at a weighted average interest rate of 2.29% under its Commercial Paper Program as of SeptemberJune 30, 2017.2018.

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






Note 11.12. Financial Risk Management Activities

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 purchases and normal sales (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. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. 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 commodity price risk primarily relating primarily 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, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 10. Commitments and Contingent Liabilities. Changes in the fair market value of thethese derivative contracts are recorded in earnings.
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. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of SeptemberJune 30, 20172018 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $6 million for the three months and nine months ended September 30, 2016.2017.
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 primarily to variable-rate debt instruments. AsPSEG interest rate hedges totaling $500 million were executed and terminated during the second quarter of September2018 and a loss of $(1) million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power’s $700 million of 3.85% Senior Notes due June 2023. For additional information see Note 11. Debt and Credit Facilities. There were no outstanding interest rate hedges as of June 30, 20172018 and December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of December 31, 2016, the fair value of these hedges was $1 million and was immaterial as of September 30, 2017. There was no ineffectiveness as of September 30, 2017 and December 31, 2016.
The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $1 million and $2$(1) million as of SeptemberJune 30, 20172018 and was immaterial as of December 31, 2016, respectively.2017. The after-tax unrealized gainlosses on these hedges expected to be reclassified to earnings during the next 12 months isare immaterial.
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Condensed Consolidated Balance Sheets of Power and PSEG.




For additional information see Note 13. Fair Value Measurements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






The following tabular disclosure does not include the offsetting of trade receivables and payables.
             
   As of September 30, 2017 
   Power (A) PSEG (A) Consolidated 
   Not Designated     Designated as Hedges   
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Interest
Rate
Swaps
 
Total
Derivatives
 
   Millions 
 Derivative Contracts           
 Current Assets $352
 $(268) $84
 $—
 $84
 
 Noncurrent Assets 178
 (116) 62
 —
 62
 
 Total Mark-to-Market Derivative Assets $530
 $(384) $146
 $—
 $146
 
 Derivative Contracts           
 Current Liabilities $(268) $261
 $(7) $—
 $(7) 
 Noncurrent Liabilities (110) 109
 (1) —
 (1) 
 Total Mark-to-Market Derivative (Liabilities) $(378) $370
 $(8) $—
 $(8) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $152
 $(14) $138
 $—
 $138
 
             
           
   As of June 30, 2018 
   Power (A) Consolidated 
   Not Designated       
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Total
Derivatives
 
   Millions 
 Derivative Contracts         
 Current Assets $256
 $(232) $24
 $24
 
 Noncurrent Assets 132
 (111)��21
 21
 
 Total Mark-to-Market Derivative Assets $388
 $(343) $45
 $45
 
 Derivative Contracts         
 Current Liabilities $(254) $231
 $(23) $(23) 
 Noncurrent Liabilities (111) 110
 (1) (1) 
 Total Mark-to-Market Derivative (Liabilities) $(365) $341
 $(24) $(24) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $23
 $(2) $21
 $21
 
           
               
   As of December 31, 2016 
   Power (A) PSE&G (A) PSEG (A) 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 $435
 $(273) $162
 $—
 $1
 $163
 
 Noncurrent Assets 122
 (98) 24
 —
 —
 24
 
 Total Mark-to-Market Derivative Assets $557
 $(371) $186
 $—
 $1
 $187
 
 Derivative Contracts             
 Current Liabilities $(285) $277
 $(8) $(5) $—
 $(13) 
 Noncurrent Liabilities (98) 95
 (3) —
 —
 (3) 
 Total Mark-to-Market Derivative (Liabilities) $(383) $372
 $(11) $(5) $—
 $(16) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $174
 $1
 $175
 $(5) $1
 $171
 
               
           
   As of December 31, 2017 
   Power (A) Consolidated 
   Not Designated       
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Total
Derivatives
 
   Millions 
 Derivative Contracts         
 Current Assets $391
 $(362) $29
 $29
 
 Noncurrent Assets 78
 (71) 7
 7
 
 Total Mark-to-Market Derivative Assets $469
 $(433) $36
 $36
 
 Derivative Contracts         
 Current Liabilities $(403) $387
 $(16) $(16) 
 Noncurrent Liabilities (95) 90
 (5) (5) 
 Total Mark-to-Market Derivative (Liabilities) $(498) $477
 $(21) $(21) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $(29) $44
 $15
 $15
 
           
(A)Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of SeptemberJune 30, 20172018 and December 31, 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.2017.
(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 SeptemberJune 30, 2018 and December 31, 2017, Power had net cash collateral/margin payments to counterparties of $122 million and $146 million, respectively. Of these net cash/collateral (received) paidmargin payments $(2) million as of $(14)June 30, 2018 and $44 million wasas December 31, 2017 were netted against the corresponding net derivative contract positions. Of the $(2) million as of June 30, 2018, $(1) million was netted against current assets, and $(1) million was netted against noncurrent assets. Of the $44 million as of December 31, 2017, $(3) million was netted against current assets, $28 million was netted against current liabilities, and $19 million was netted against noncurrent liabilities.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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positions. Of the $(14) million as of September 30, 2017, $(7) million was netted against current assets, and $(7) million was netted against noncurrent assets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets, and $4 million was netted against current liabilities.
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 by S&P or Moody’s, 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 or 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) was $16$11 million and $19$30 million as of SeptemberJune 30, 20172018 and December 31, 2016,2017, respectively. As of each of SeptemberJune 30, 20172018 and December 31, 2016,2017, Power had the contractual right of offset of $9$6 million and $13 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $7$5 million and $10$17 million as of SeptemberJune 30, 20172018 and December 31, 2016,2017, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.
The following showsreconciles 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 and nine months ended September 30, 2017 and 2016.
             
 
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)
 
  Three Months Ended   Three Months Ended 
  September 30,   September 30, 
  2017 2016                                2017 2016 
   Millions   Millions 
 PSEG           
 Interest Rate Swaps $1
 $1
 Interest Expense $2
 $—
 
 Total PSEG $1
 $1
   $2
 $—
 
             
             
 
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)
 
  Nine Months Ended   Nine Months Ended 
  September 30,   September 30, 
  2017 2016                                2017 2016 
   Millions   Millions 
 PSEG           
 Interest Rate Swaps $1
 $3
 Interest Expense $2
 $—
 
 Total PSEG $1
 $3
   $2
 $—
 
             
There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of September 30, 2017 and
2016.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents


The following reconciles the AOCI 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, 2015 $—
 $—
 
 Gain Recognized in AOCI 3
 2
 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of December 31, 2016 $3
 $2
 
 Gain Recognized in AOCI 1
 —
 
 Less: Gain Reclassified into Income (2) (1) 
 Balance as of September 30, 2017 $2
 $1
 
       
       
 Accumulated Other Comprehensive Income Pre-Tax After-Tax 
   Millions 
 Balance as of December 31, 2016 $3
 $2
 
 Gain Recognized in AOCI —
 —
 
 Less: Gain Reclassified into Income (3) (2) 
 Balance as of December 31, 2017 $—
 $—
 
 Loss Recognized in AOCI (2) (1) 
 Less: Loss Reclassified into Income —
 —
 
 Balance as of June 30, 2018 $(2) $(1) 
       
The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and ninesix months ended SeptemberJune 30, 20172018 and 2016.2017. Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts for whichthat Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.
             
 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, 
     2017 2016 2017 2016 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $25
 $125
 $221
 $255
 
 Energy-Related Contracts Energy Costs (3) (11) (19) (3) 
 Total PSEG and Power   $22
 $114
 $202
 $252
 
             
The following reflects the gross volume, on an absolute value basis, of derivatives as of September 30, 2017 and December 31, 2016.
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of September 30, 2017           
 Natural Gas Dekatherm (Dth) 265
 —
 265
 —
 
 Electricity MWh 332
 —
 332
 —
 
 Financial Transmission Rights (FTRs) MWh 5
 —
 5
 —
 
 Interest Rate Swaps U.S. Dollars 500
 500
 —
 —
 
 As of December 31, 2016           
 Natural Gas Dth 357
 —
 348
 9
 
 Electricity MWh 323
 —
 323
 —
 
 FTRs MWh 9
 —
 9
 —
 
 Interest Rate Swaps U.S. Dollars 500
 500
 —
 —
 
             

             
 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 Pre-Tax Gain (Loss) Recognized in Income on Derivatives 
     Three Months Ended Six Months Ended 
     June 30, June 30, 
     2018 2017 2018 2017 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $(64) $112
 $(24) $190
 
 Energy-Related Contracts Energy Costs 15
 (10) 7
 (10) 
 Total PSEG and Power   $(49) $102
 $(17) $180
 
             
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of June 30, 2018 and December 31, 2017.
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of June 30, 2018           
 Natural Gas Dekatherm (Dth) 249
 —
 249
 —
 
 Electricity MWh (67) —
 (67) —
 
 Financial Transmission Rights (FTRs) MWh 24
 —
 24
 —
 
 As of December 31, 2017           
 Natural Gas Dth 154
 —
 154
 —
 
 Electricity MWh (63) —
 (63) —
 
 FTRs MWh 6
 —
 6
 —
 
             
Credit Risk
Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.
As of September 30, 2017, 99% 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, NPNS and non-derivatives).
The following table provides information on Power’s credit risk from others,ER&T wholesale counterparties, net of collateral, as of SeptemberJune 30, 2017.2018. It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it 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.
As of June 30, 2018, 98% 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, NPNS and non-derivatives).
              
 Rating 
Current
Exposure
 Collateral Held 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
   Millions   Millions  
 Investment Grade $318
 $55
 $263
 2
 $128
(A)  
 Non-Investment Grade 5
 1
 4
 —
 —
   
 Total $323
 $56
 $267
 2
 $128
   
              
              
 Rating 
Current
Exposure
 Securities held as Collateral 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
   Millions   Millions  
 Investment Grade $172
 $12
 $160
 2
 $74
(A) 
 Non-Investment Grade 4
 1
 3
 —
 —
   
 Total $176
 $13
 $163
 2
 $74
  
              
(A)IncludesRepresents net exposure of $97$56 million with PSE&G.&G and a non-affiliated counterparty of $18 million.
As of SeptemberJune 30, 2017,2018, collateral held from counterparties where Power had credit exposure included $3$1 million in cash collateral and $53$12 million in letters of credit.
As of SeptemberJune 30, 20172018, Power had 144145 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 SeptemberJune 30, 2017,2018, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of SeptemberJune 30, 2017,2018, 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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Note 12.13. 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, as well as natural gas futures contracts executed on NYMEX.
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 SeptemberJune 30, 2017,2018, these consisted primarily of certain electric load contracts and gas contracts.
Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.
The following tables present information about PSEG’s, PSE&G’s and Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of SeptemberJune 30, 20172018 and December 31, 2016,2017, 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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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   Recurring Fair Value Measurements as of September 30, 2017 
 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) $220
 $—
 $220
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $146
 $(384) $11
 $513
 $6
 
 NDT Fund (D)           
 Equity Securities $1,032
 $—
 $1,030
 $2
 $—
 
 Debt Securities—U.S. Treasury $249
 $—
 $—
 $249
 $—
 
 Debt Securities—Govt Other $318
 $—
 $—
 $318
 $—
 
 Debt Securities—Corporate $358
 $—
 $—
 $358
 $—
 
 Other Securities $55
 $—
 $55
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $23
 $—
 $23
 $—
 $—
 
 Debt Securities—U.S. Treasury $51
 $—
 $—
 $51
 $—
 
 Debt Securities—Govt Other $33
 $—
 $—
 $33
 $—
 
 Debt Securities—Corporate $120
 $—
 $—
 $120
 $—
 
 Other Securities $2
 $—
 $2
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(8) $370
 $(6) $(372) $—
 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $220
 $—
 $220
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $10
 $—
 $—
 $10
 $—
 
 Debt Securities—Govt Other $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Corporate $24
 $—
 $—
 $24
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $146
 $(384) $11
 $513
 $6
 
 NDT Fund (D)           
 Equity Securities $1,032
 $—
 $1,030
 $2
 $—
 
 Debt Securities—U.S. Treasury $249
 $—
 $—
 $249
 $—
 
 Debt Securities—Govt Other $318
 $—
 $—
 $318
 $—
 
 Debt Securities—Corporate $358
 $—
 $—
 $358
 $—
 
 Other Securities $55
 $—
 $55
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $6
 $—
 $6
 $—
 $—
 
 Debt Securities—U.S. Treasury $13
 $—
 $—
 $13
 $—
 
 Debt Securities—Govt Other $8
 $—
 $—
 $8
 $—
 
 Debt Securities—Corporate $30
 $—
 $—
 $30
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(8) $370
 $(6) $(372) $—
 
             






             
   Recurring Fair Value Measurements as of June 30, 2018 
 Description Total 

Netting (D)
 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 
   Millions 
 PSEG           
 Assets:           
 Energy-Related Contracts (B) $45
 $(343) $16
 $365
 $7
 
 NDT Fund (C)           
 Equity Securities $1,081
 $—
 $1,079
 $2
 $—
 
 Debt Securities—U.S. Treasury $211
 $—
 $—
 $211
 $—
 
 Debt Securities—Govt Other $306
 $—
 $—
 $306
 $—
 
 Debt Securities—Corporate $450
 $—
 $—
 $450
 $—
 
 Rabbi Trust (C)           
 Equity Securities $24
 $—
 $24
 $—
 $—
 
 Debt Securities—U.S. Treasury $58
 $—
 $—
 $58
 $—
 
 Debt Securities—Govt Other $36
 $—
 $—
 $36
 $—
 
 Debt Securities—Corporate $106
 $—
 $—
 $106
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(24) $341
 $(8) $(354) $(3) 
 PSE&G           
 Assets:           
 Rabbi Trust (C)           
 Equity Securities $4
 $—
 $4
 $—
 $—
 
 Debt Securities—U.S. Treasury $12
 $—
 $—
 $12
 $—
 
 Debt Securities—Govt Other $8
 $—
 $—
 $8
 $—
 
 Debt Securities—Corporate $21
 $—
 $—
 $21
 $—
 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $45
 $(343) $16
 $365
 $7
 
 NDT Fund (C)           
 Equity Securities $1,081
 $—
 $1,079
 $2
 $—
 
 Debt Securities—U.S. Treasury $211
 $—
 $—
 $211
 $—
 
 Debt Securities—Govt Other $306
 $—
 $—
 $306
 $—
 
 Debt Securities—Corporate $450
 $—
 $—
 $450
 $—
 
 Rabbi Trust (C)           
 Equity Securities $6
 $—
 $6
 $—
 $—
 
 Debt Securities—U.S. Treasury $14
 $—
 $—
 $14
 $—
 
 Debt Securities—Govt Other $9
 $—
 $—
 $9
 $—
 
 Debt Securities—Corporate $27
 $—
 $—
 $27
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(24) $341
 $(8) $(354) $(3) 
             
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






             
   Recurring Fair Value Measurements as of December 31, 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) $365
 $—
 $365
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $186
 $(371) $17
 $533
 $7
 
 Interest Rate Swaps (C) $1
 $—
 $—
 $1
 $—
 
 NDT Fund (D)           
 Equity Securities $957
 $—
 $954
 $3
 $—
 
 Debt Securities—U.S. Treasury $227
 $—
 $—
 $227
 $—
 
 Debt Securities—Govt Other $293
 $—
 $—
 $293
 $—
 
 Debt Securities—Corporate $337
 $—
 $—
 $337
 $—
 
 Other Securities $44
 $—
 $44
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $22
 $—
 $22
 $—
 $—
 
 Debt Securities—U.S. Treasury $37
 $—
 $—
 $37
 $—
 
 Debt Securities—Govt Other $66
 $—
 $—
 $66
 $—
 
 Debt Securities—Corporate $91
 $—
 $—
 $91
 $—
 
 Other Securities $1
 $—
 $1
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(16) $372
 $(18) $(364) $(6) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $365
 $—
 $365
 $—
 $—
 
 Derivative Contracts:           
 Energy Related Contracts (B) $—
 $—
 $—
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Govt Other $13
 $—
 $—
 $13
 $—
 
 Debt Securities—Corporate $18
 $—
 $—
 $18
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(5) $—
 $—
 $—
 $(5) 
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $186
 $(371) $17
 $533
 $7
 
 NDT Fund (D)           
 Equity Securities $957
 $—
 $954
 $3
 $—
 
 Debt Securities—U.S. Treasury $227
 $—
 $—
 $227
 $—
 
 Debt Securities—Govt Other $293
 $—
 $—
 $293
 $—
 
 Debt Securities—Corporate $337
 $—
 $—
 $337
 $—
 
 Other Securities $44
 $—
 $44
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $9
 $—
 $—
 $9
 $—
 
 Debt Securities—Govt Other $16
 $—
 $—
 $16
 $—
 
 Debt Securities—Corporate $23
 $—
 $—
 $23
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(11) $372
 $(18) $(364) $(1) 
             
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents


             
   Recurring Fair Value Measurements as of December 31, 2017 
 Description Total Netting  (D) 
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) $223
 $—
 $223
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $36
 $(433) $15
 $442
 $12
 
 NDT Fund (C)           
 Equity Securities $1,147
 $—
 $1,145
 $2
 $—
 
 Debt Securities—U.S. Treasury $314
 $—
 $—
 $314
 $—
 
 Debt Securities—Govt Other $270
 $—
 $—
 $270
 $—
 
 Debt Securities—Corporate $402
 $—
 $—
 $402
 $—
 
 Rabbi Trust (C)           
 Equity Securities $27
 $—
 $27
 $—
 $—
 
 Debt Securities—U.S. Treasury $51
 $—
 $—
 $51
 $—
 
 Debt Securities—Govt Other $34
 $—
 $—
 $34
 $—
 
 Debt Securities—Corporate $119
 $—
 $—
 $119
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(21) $477
 $(8) $(485) $(5) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $223
 $—
 $223
 $—
 $—
 
 Rabbi Trust (C)           
 Equity Securities $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $10
 $—
 $—
 $10
 $—
 
 Debt Securities—Govt Other $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Corporate $24
 $—
 $—
 $24
 $—
 
 Liabilities:           
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $36
 $(433) $15
 $442
 $12
 
 NDT Fund (C)           
 Equity Securities $1,147
 $—
 $1,145
 $2
 $—
 
 Debt Securities—U.S. Treasury $314
 $—
 $—
 $314
 $—
 
 Debt Securities—Govt Other $270
 $—
 $—
 $270
 $—
 
 Debt Securities—Corporate $402
 $—
 $—
 $402
 $—
 
 Rabbi Trust (C)           
 Equity Securities $6
 $—
 $6
 $—
 $—
 
 Debt Securities—U.S. Treasury $13
 $—
 $—
 $13
 $—
 
 Debt Securities—Govt Other $8
 $—
 $—
 $8
 $—
 
 Debt Securities—Corporate $30
 $—
 $—
 $30
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(21) $477
 $(8) $(485) $(5) 
             
(A)Represents money market mutual funds.
(B)Level 1— During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.
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 settled prices from similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, 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
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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—Unobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more information on the utilization of unobservable inputs.
(C)Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different thanAs of June 30, 2018, the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
(D)The fair value measurement tables exclude an immaterial amounttable excludes foreign currency of cash as of September 30, 2017 and $1 million, as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.”securities. The Rabbi Trust maintains investments in various fixed income securities and a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of September 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016.fund. 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 mutualother equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in Dreyfus money market funds which seek a high level of current income as is consistent with mainlythe preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, investments are valued based on unadjusted quoted prices in active markets.dollar-denominated debt securities and government securities. The funds’ Net Asset Value is priced and published daily. The Rabbi Trust also has an equity index fund which is valued based on quoted prices in an active market.
Level 2—NDT and Rabbi Trust fixed income securities include primarily investment grade corporate bonds, collateralized mortgage obligations, asset backedasset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds 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. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. 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)(D)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 SeptemberJune 30, 2018 and December 31, 2017, Power had net cash collateral (received) paidcollateral/margin payments to counterparties of $(14)$122 million wasand $146 million, respectively. Of these net cash collateral/margin payments $(2) million as of June 30, 2018 and $44 million as of December 31, 2017 were netted against the corresponding net derivative contract positions. The $(14)$(2) million of cash collateral as of SeptemberJune 30, 20172018 was netted against assets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1$44 million of cash collateral as of December 31, 2016,2017, $(3) million was netted against assets and $4$47 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
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Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees 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.
For PSE&G, the natural gas supply contract wasis 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
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accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The fair value of Power’s gas physical contracts at certain illiquid delivery locations are measured using average historical basis and, accordingly, are categorized as Level 3. While these gas physical contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of SeptemberJune 30, 20172018 and December 31, 2016.2017.
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position September 30, 2017 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 Power             
 Electricity Electric Load Contracts $5
 $—
 Discounted Cash flow Historic Load Variability 0% to +10% 
 Gas Other 1
 —
 
 
 
 
 Total Power   $6
 $—
       
 Total PSEG   $6
 $—
       
               
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position June 30, 2018 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 Power             
 Electricity Electric Load Contracts $2
 $(3) Discounted Cash flow Historic Load Variability 0% to 10% 
 Gas Gas Physical Contracts 5
 —
 Discounted Cash flow Average Historical Basis -40% to 0% 
 Total Power   $7
 $(3)       
 Total PSEG   $7
 $(3)       
               
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position December 31, 2016 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 PSE&G             
 Gas Natural Gas Supply Contract  $—
 $(5) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth 
 Total PSE&G   $—
 $(5)       
 Power             
 Electricity Electric Load Contracts $7
 $(1) Discounted Cash Flow Historic Load Variability 0% to +10% 
 Gas (A) Other —
 —
       
 Total Power   $7
 $(1)       
 Total PSEG   $7
 $(6)       
               
               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position December 31, 2017 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 Power             
 Electricity Electric Load Contracts $1
 $(3) Discounted Cash flow Historic Load Variability 0% to 10% 
 Gas Gas Physical Contracts 11
 (2) Discounted Cash flow Average Historical Basis -40% to -10% 
 Total Power   $12
 $(5)       
 Total PSEG   $12
 $(5)       
               
(A)Includes gas positions which were 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 energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value. For gas-related contracts in cases where Power is a buyer, an increase in the average historical basis would increase 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 six months ended SeptemberJune 30, 2018 and June 30, 2017, and September 30, 2016, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months and NineSix Months Ended SeptemberJune 30, 20172018
                 
   Three Months Ended September 30, 2017   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2017 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $6
 $3
 $—
 $—
 $(3) $—
 $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $—
 $—
 $—
 $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $6
 $3
 $—
 $—
 $(3) $—
 $6
 
                 
   Nine Months Ended September 30, 2017   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2017 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $1
 $29
 $5
 $—
 $(28) $(1) $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(5) $—
 $5
 $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $6
 $29
 $—
 $—
 $(28) $(1) $6
 
                 
                 
   Three Months Ended June 30, 2018 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of April 1, 2018 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2018 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $7
 $(3) $—
 $—
 $—
 $—
 $4
 
 Power               
 Net Derivative Assets (Liabilities) $7
 $(3) $—
 $—
 $—
 $—
 $4
 
                 
   Six Months Ended June 30, 2018 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2018 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2018 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $7
 $(4) $—
 $—
 $1
 $—
 $4
 
 Power               
 Net Derivative Assets (Liabilities) $7
 $(4) $—
 $—
 $1
 $—
 $4
 
                 

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Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Monthsand NineSix Months Ended SeptemberJune 30, 20162017
                 
   Three Months Ended September 30, 2016   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2016 
Included in
Income (E)
 
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 (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2016 
       
 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
 
                 
                 
   Three Months Ended June 30, 2017 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of April 1, 2017 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of June 30, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $3
 $7
 $(1) $—
 $(3) $—
 $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $1
 $—
 $(1) $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $2
 $7
 $—
 $—
 $(3) $—
 $6
 
                 
   Six Months Ended June 30, 2017 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2017 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $1
 $26
 $5
 $—
 $(25) $(1) $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(5) $—
 $5
 $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $6
 $26
 $—
 $—
 $(25) $(1) $6
 
                 
(A)PSEG’s and Power’s gains and lossesgains(losses) attributable to changes in net derivative assets and liabilities include $3 million and $29 million in Operating Income for the three months and ninesix months ended SeptemberJune 30, 2017, respectively. The $32018 include $(7) million and $1 million, respectively, in Operating Revenues and $4 million and $(5) million, respectively, in Energy Costs. Both the $(7) million and $1 million in Operating Income is realized.Revenues are unrealized. Of the $29$4 million and $(5) million in Operating Income, $1Energy Costs, $3 million isand $(6) million are unrealized. Unrealized gains (losses) represent the change in derivative assets and liabilities still held at the end of the reporting period.
(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.
(C)
Represents $(3) million and $(28) million in settlements for the three months and nine months ended September 30, 2017, respectively. Represents $(4) million and $(24) million in settlements for the three months and nine months
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ended September 30, 2016, respectively.
(C)Represents $1 million in settlements for the six months ended June 30, 2018. Represents settlements of $(3) million and $(25) million for the three months and six months ended June 30, 2017, respectively.
(D)During the three months and six months ended SeptemberJune 30, 20172018, there were no transfers in tointo or out of Level 3. During the ninesix months ended SeptemberJune 30, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in tointo or out of Level 3 during the three months and nine months ended SeptemberJune 30, 2016.2017.
(E)PSEG’s and Power’s gains and lossesgains(losses) attributable to changes in net derivative assets and liabilities include $8 million and $24 million in Operating Income for the three months and ninesix months ended SeptemberJune 30, 2016, respectively.2017 include $3 million and $17 million, respectively, in Operating Revenues and $4 million and $9 million, respectively, in Energy Costs. Of the $8$3 million and $17 million in Operating Income,Revenues, $2 million and $(2) million, respectively, are unrealized. Of the $4 million is unrealized. The $24and $9 million in Operating Income is realized.Energy Costs, $2 million and $3 million are unrealized.
As of SeptemberJune 30, 2017,2018, PSEG carried $2.6$2.3 billion of net assets that are measured at fair value on a recurring basis, of which $6$4 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of SeptemberJune 30, 20162017, PSEG carried $2.6$2.8 billion of net assets that are measured at fair value on a recurring basis, of which $11$6 million of net assets 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 SeptemberJune 30, 20172018 and December 31, 20162017.
          
  As of As of 
  September 30, 2017 December 31, 2016 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (Parent) (A) (B)$1,896
 $1,891
 $1,195
 $1,185
 
 PSE&G (B)8,243
 8,857
 7,818
 8,240
 
 Power - Recourse Debt (B)2,385
 2,657
 2,382
 2,578
 
 Total Long-Term Debt$12,524
 $13,405
 $11,395
 $12,003
 
          
          
  As of As of 
  June 30, 2018 December 31, 2017 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (A) (B)$2,091
 $2,042
 $2,091
 $2,081
 
 PSE&G (B)8,886
 9,055
 8,591
 9,322
 
 Power (B)3,083
 3,249
 2,386
 2,659
 
 Total Long-Term Debt$14,060
 $14,346
 $13,068
 $14,062
 
          
(A)As of September 30, 2017, fair value includes a $700 millionIncludes floating rate term loan in addition to the $500 million floating rate term loan and net offsets as of December 31, 2016.$700 million. The fair values of the term loan debt (Level 2 measurement) approximate the carrying values because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.
(B)Given that these bonds do not trade actively, 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.
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Note 13.14. Other Income and Deductions(Deductions)
          
 Other IncomePSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2017        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $41
 $—
 $41
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Rabbi Trust Realized Gains, Interest and Dividends1
 1
 —
 2
 
 Solar Loan Interest6
 —
 —
 6
 
 Other2
 1
 —
 3
 
 Total Other Income$23
 $43
 $—
 $66
 
 Nine Months Ended September 30, 2017        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $117
 $—
 $117
 
 Allowance for Funds Used During Construction42
 —
 —
 42
 
 Rabbi Trust Realized Gains, Interest and Dividends5
 6
 11
 22
 
 Solar Loan Interest16
 —
 —
 16
 
 Other7
 4
 —
 11
 
   Total Other Income$70
 $127
 $11
 $208
 
 Three Months Ended September 30, 2016        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $21
 $—
 $21
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Rabbi Trust Realized Gains, Interest and Dividends1
 —
 3
 4
 
 Solar Loan Interest6
 —
 —
 6
 
 Other1
 2
 (1) 2
 
 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
 
 Rabbi Trust Realized Gains, Interest and Dividends2
 2
 6
 10
 
 Solar Loan Interest17
 —
 —
 17
 
 Other7
 3
 (2) 8
 
 Total Other Income$61
 $74
 $4
 $139
 
          
          
 Other DeductionsPSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2017        
   NDT Fund Realized Losses and Expenses$—
 $8
 $—
 $8
 
   Other1
 —
 1
 2
 
     Total Other Deductions$1
 $8
 $1
 $10
 
 Nine Months Ended September 30, 2017        
   NDT Fund Realized Losses and Expenses$—
 $21
 $—
 $21
 
   Other3
 1
 5
 9
 
     Total Other Deductions$3
 $22
 $5
 $30
 
 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
 
          
          
  PSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended June 30, 2018        
 NDT Fund Interest and Dividends$—
 $15
 $—
 $15
 
 Allowance for Funds Used During Construction13
 —
 —
 13
 
 Solar Loan Interest5
 —
 —
 5
 
 Other2
 (2) 1
 1
 
   Total Other Income (Deductions)$20
 $13
 $1
 $34
 
 Six Months Ended June 30, 2018        
 NDT Fund Interest and Dividends$—
 $27
 $—
 $27
 
 Allowance for Funds Used During Construction27
 —
 —
 27
 
 Solar Loan Interest9
 —
 —
 9
 
 Other4
 (3) 2
 3
 
   Total Other Income (Deductions)$40
 $24
 $2
 $66
 
 Three Months Ended June 30, 2017        
 NDT Fund Interest and Dividends$—
 $13
 $—
 $13
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Solar Loan Interest5
 —
 —
 5
 
 Other2
 (1) —
 1
 
   Total Other Income (Deductions)$21
 $12
 $—
 $33
 
 Six Months Ended June 30, 2017        
 NDT Fund Interest and Dividends$—
 $23
 $—
 $23
 
 Allowance for Funds Used During Construction28
 —
 —
 28
 
 Solar Loan Interest10
 —
 —
 10
 
 Other5
 —
 (1) 4
 
 Total Other Income (Deductions)$43
 $23
 $(1) $65
 
          
(A)Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

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


Note 14.15. Income Taxes
PSEG’s, PSE&G’s and Power’s effective tax rates for the three months and ninesix months ended SeptemberJune 30, 20172018 and 20162017 were as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
 PSEG38.9% 36.5% 35.5% 36.3% 
 PSE&G38.8% 36.1% 37.4% 36.1% 
 Power41.9% 39.3% 37.9% 39.4% 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 PSEG26.5% 35.1% 26.6% 28.3% 
 PSE&G25.7% 37.2% 26.4% 36.7% 
 Power31.7% 39.0% 27.1% 40.0% 
          
For the three months and ninesix months ended SeptemberJune 30, 2017,2018, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as wella result of the Tax Act offset by changes in uncertain tax positions, plant-related items and tax credits. For the three months and six months ended June 30, 2018, the differences in PSEG’s effective tax rates as compared to the statutory tax rate of 40.85%,28.11% were due primarily to changes in uncertainplant-related items and tax positions and the NDT Fund. For the nine months ended September 30, 2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.credits.
For the three months and ninesix months ended SeptemberJune 30, 2017,2018, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as wella result of the Tax Act, offset by changes in uncertain tax positions, plant-related and other flow-through items. For the three months and
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






six months ended June 30, 2018, the differences in PSE&G’s effective tax rate as compared to the statutory tax rate of 40.85%,28.11% were due primarily to changes in uncertainplant-related items and tax positions, plant and other flow-through items.credits.
For the three months and ninesix months ended SeptemberJune 30, 2017,2018, the differences in Power’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as a result of the Tax Act, as well as changes in uncertain tax positions. For the three months and six months ended June 30, 2018, the differences in Power’s effective tax rates as compared to the statutory tax rate of 40.85%,28.11% were due primarily to changes in uncertain tax positions manufacturing deduction and the NDT Fund.tax credits.
PSEG’s federal tax returns for the years 2011 and 2012 are currently being audited by the IRS. The audit and other related claims are reasonably expected to be completed within the next 12 months. As a result, it is reasonably possible that a decrease in PSEG’s total unrecognized tax benefits may be necessary in the range of $80 million to $180$150 million based on current estimates.
In December 2017, the U.S. government enacted comprehensive tax legislation. The Tax Act establishes new tax laws that took effect in 2018, including, but not limited to (1) reduction of the U.S. federal corporate tax rate from a maximum of 35% to 21%; (2) elimination of the corporate alternative minimum tax; (3) a new limitation on deductible interest expense; (4) the repeal of the domestic production activity deduction; (5) limitations on the deductibility of certain executive compensation; and (6) limitations on net operating losses generated after December 31, 2017, to 80% of taxable income. In addition, certain changes were made to the bonus depreciation rules that will impact 2018.
The SEC staff issued Staff Accounting Bulletin 118 (SAB 118), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. PSEG, PSE&G and Power are subject to ASC 740. In accordance with SAB 118, PSEG, PSE&G and Power made reasonable, good faith estimates for which provisional amounts were recorded.
PSEG’s accounting for certain elements of the Tax Act is incomplete. However, PSEG recorded provisional adjustments for the following: the tax rules regarding the appropriate bonus depreciation rate that should be applied to assets placed in service after September 27, 2017 for Power and PSE&G, including the information required to compute the applicable depreciable tax basis, and the impact on PSEG’s, PSE&G’s and Power’s deferred taxes associated with FIN 48 reserves.
Further, the Tax Act is unclear in certain respects and will require interpretations and implementing regulations by the IRS, as well as state tax authorities. The Tax Act could also be subject to potential amendments and technical corrections which could impact PSEG, PSE&G and Power’s financial statements.
The Protecting Americans from Tax Hikes Act of 2015 (Tax(2015 Tax Act) extended, among other provisions, included an extension of the 50% bonus depreciation rules and the 30% investment tax credit for qualified property placed ininto service after 2016. Qualified property that is placed into service from January 1, 2015 through December 31, 2017. The rate2017 is reduced to 40% and 30%eligible for eligible property placed in service in 2018 and 2019, respectively. On May 8, 2017 the IRS issued guidance allowing for 50% bonus depreciation on long production property that is placed in service in 2018. For long production property placed in service in 2019, qualified costs incurred before January 1, 2019 is afforded a 40% rate, while qualified costs incurred during 2019 receives a 30% rate. For long production property placed in service in 2020, subject to a written binding contract entered into before 2020, a 30% rate is allowed for qualified costs incurred before January 1, 2020, with a 0% rate thereafter.depreciation. The provisions of the 2015 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.
This provision hashave generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These
For the period beginning September 28, 2017, subject to the transition rules, the Tax Act modified the bonus depreciation rules of the 2015 Tax Act. Subject to further guidance, it is expected that Power is entitled to 100% expensing and bonus depreciation will no longer apply to PSE&G.
In July 2018, the State of New Jersey made significant changes to its income tax benefits would have otherwise been received overlaws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an estimated average 20 year period. However,exemption for public utilities. At this time, PSEG believes PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. PSEG expects these tax benefitsnew provisions to unfavorably affect its non-utility business as it continues to analyze this newly enacted law and the impact it will have a negative impact on the rate base of several of PSE&G’s programs.PSEG.

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






Note 15.16. Accumulated Other Comprehensive Income (Loss), Net of Tax
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2017 $2
 $(386) $158
 $(226) 
 Other Comprehensive Income before Reclassifications —
 —
 25
 25
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1) 6
 (8) (3) 
 Net Current Period Other Comprehensive Income (Loss) (1) 6
 17
 22
 
 Balance as of September 30, 2017 $1
 $(380) $175
 $(204) 
           
 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) 
   Nine Months Ended September 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2016 $2
 $(398) $133
 $(263) 
 Other Comprehensive Income before Reclassifications —
 —
 78
 78
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1) 18
 (36) (19) 
 Net Current Period Other Comprehensive Income (Loss) (1) 18
 42
 59
 
 Balance as of September 30, 2017 $1
 $(380) $175
 $(204) 
           
 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) 
   Three Months Ended June 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2018 $—
 $(398) $(13) $(411) 
 Other Comprehensive Income before Reclassifications (1) —
 (6) (7) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 1
 8
 
 Net Current Period Other Comprehensive Income (Loss) (1) 7
 (5) 1
 
 Balance as of June 30, 2018 $(1) $(391) $(18) $(410) 
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2017 $2
 $(392) $148
 $(242) 
 Other Comprehensive Income before Reclassifications —
 —
 23
 23
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 6
 (13) (7) 
 Net Current Period Other Comprehensive Income (Loss) —
 6
 10
 16
 
 Balance as of June 30, 2017 $2
 $(386) $158
 $(226) 
     
 PSEG Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2017 $—
 $(406) $177
 $(229) 
 Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings —
 —
 (176) (176) 
 Current Period Other Comprehensive Income (Loss)         
 Other Comprehensive Income before Reclassifications (1) —
 (22) (23) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 15
 3
 18
 
 Net Current Period Other Comprehensive Income (Loss) (1) 15
 (19) (5) 
 Net Change in Accumulative Other Comprehensive Income (Loss) (1) 15
 (195) (181) 
 Balance as of June 30, 2018 $(1) $(391) $(18) $(410) 
           
 PSEG Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2016 $2
 $(398) $133
 $(263) 
 Other Comprehensive Income before Reclassifications —
 —
 53
 53
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 12
 (28) (16) 
 Net Current Period Other Comprehensive Income (Loss) —
 12
 25
 37
 
 Balance as of June 30, 2017 $2
 $(386) $158
 $(226) 
           
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2017 $—
 $(330) $158
 $(172) 
 Other Comprehensive Income before Reclassifications —
 —
 24
 24
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 5
 (9) (4) 
 Net Current Period Other Comprehensive Income (Loss) —
 5
 15
 20
 
 Balance as of September 30, 2017 $—
 $(325) $173
 $(152) 
     
 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) 
   Nine Months Ended September 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2016 $—
 $(340) $129
 $(211) 
 Other Comprehensive Income before Reclassifications —
 —
 74
 74
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 15
 (30) (15) 
 Net Current Period Other Comprehensive Income (Loss) —
 15
 44
 59
 
 Balance as of September 30, 2017 $—
 $(325) $173
 $(152) 
           
 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) 
   Three Months Ended June 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2018 $—
 $(341) $(11) $(352) 
 Other Comprehensive Income before Reclassifications —
 —
 (5) (5) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 6
 1
 7
 
 Net Current Period Other Comprehensive Income (Loss) —
 6
 (4) 2
 
 Balance as of June 30, 2018 $—
 $(335) $(15) $(350) 
     
 Power Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2017 $—
 $(335) $148
 $(187) 
 Other Comprehensive Income before Reclassifications —
 —
 22
 22
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 5
 (12) (7) 
 Net Current Period Other Comprehensive Income (Loss) —
 5
 10
 15
 
 Balance as of June 30, 2017 $—
 $(330) $158
 $(172) 
           
 Power Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2017 $—
 $(347) $175
 $(172) 
 Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings —
 —
 (175) (175) 
 Current Period Other Comprehensive Income (Loss)         
 Other Comprehensive Income before Reclassifications —
 —
 (18) (18) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 12
 3
 15
 
 Net Current Period Other Comprehensive Income (Loss) —
 12
 (15) (3) 
 Net Change in Accumulative Other Comprehensive Income (Loss) —
 12
 (190) (178) 
 Balance as of June 30, 2018 $—
 $(335) $(15) $(350) 
           
 Power Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2016 $—
 $(340) $129
 $(211) 
 Other Comprehensive Income before Reclassifications —
 —
 50
 50
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 10
 (21) (11) 
 Net Current Period Other Comprehensive Income (Loss) —
 10
 29
 39
 
 Balance as of June 30, 2017 $—
 $(330) $158
 $(172) 
           
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






                
 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, 2017 September 30, 2017 
  Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
    Millions 
 Cash Flow Hedges              
 Interest Rate Swaps Interest Expense$2
 $(1) $1
 $2
 $(1) $1
 
 Total Cash Flow Hedges  2
 (1) 1
 2
 (1) 1
 
 Pension and OPEB Plans            
 Amortization of Prior Service (Cost) Credit O&M Expense3
 (1) 2
 7
 (3) 4
 
    Amortization of Actuarial Loss O&M Expense(13) 5
 (8) (37) 15
 (22) 
 Total Pension and OPEB Plans(10) 4
 (6) (30) 12
 (18) 
 Available-for-Sale Securities            
 Realized Gains Other Income29
 (15) 14
 99
 (49) 50
 
 Realized Losses Other Deductions(6) 2
 (4) (19) 9
 (10) 
 OTTI OTTI(5) 3
 (2) (9) 5
 (4) 
 Total Available-for-Sale Securities18
 (10) 8
 71
 (35) 36
 
 Total  $10
 $(7) $3
 $43
 $(24) $19
 
                
                
 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, 2018 June 30, 2018 
  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 Non-Operating Pension and OPEB Credits (Costs)$1
 $—
 $1
 $2
 $—
 $2
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs)(11) 3
 (8) (23) 6
 (17) 
 Total Pension and OPEB Plans(10) 3
 (7) (21) 6
 (15) 
 Available-for-Sale Debt Securities            
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

(2) 1
 (1) (6) 3
 (3) 
 Total Available-for-Sale Debt Securities(2) 1
 (1) (6) 3
 (3) 
 Total  $(12) $4
 $(8) $(27) $9
 $(18) 
                
                 
 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, 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 Income 13
 (6) 7
 41
 (20) 21
 
 Realized Losses Other Deductions (5) 3
 (2) (29) 15
 (14) 
 OTTI OTTI (5) 2
 (3) (25) 12
 (13) 
 Total Available-for-Sale Securities 3
 (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 OperationsJune 30, 2017 June 30, 2017 
  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 Non-Operating Pension and OPEB Credits (Costs)$2
 $(1) $1
 $4
 $(2) $2
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs)(12) 5
 (7) (24) 10
 (14) 
 Total Pension and OPEB Plans(10) 4
 (6) (20) 8
 (12) 
 Available-for-Sale Securities            
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

25
 (12) 13
 53
 (25) 28
 
 Total Available-for-Sale Securities25
 (12) 13
 53
 (25) 28
 
 Total  $15
 $(8) $7
 $33
 $(17) $16
 
                
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






                 
 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, 2017 September 30, 2017 
   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
 $6
 $(3) $3
 
    Amortization of Actuarial Loss O&M Expense (11) 5
 (6) (32) 14
 (18) 
 Total Pension and OPEB Plans (9) 4
 (5) (26) 11
 (15) 
 Available-for-Sale Securities             
 Realized Gains Other Income 29
 (15) 14
 86
 (44) 42
 
 Realized Losses Other Deductions (5) 2
 (3) (15) 7
 (8) 
 OTTI OTTI (5) 3
 (2) (9) 5
 (4) 
 Total Available-for-Sale Securities 19
 (10) 9
 62
 (32) 30
 
 Total   $10
 $(6) $4
 $36
 $(21) $15
 
                 
                 
 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, 2018 June 30, 2018 
   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 Non-Operating Pension and OPEB Credits (Costs) $1
 $—
 $1
 $2
 $—
 $2
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (9) 2
 (7) (19) 5
 (14) 
 Total Pension and OPEB Plans (8) 2
 (6) (17) 5
 (12) 
 Available-for-Sale Debt Securities             
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

 (2) 1
 (1) (6) 3
 (3) 
 Total Available-for-Sale Debt Securities (2) 1
 (1) (6) 3
 (3) 
 Total   $(10) $3
 $(7) $(23) $8
 $(15) 
                 
                 
 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, 2017 June 30, 2017 
   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 Non-Operating Pension and OPEB Credits (Costs) $2
 $(1) $1
 $4
 $(2) $2
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (10) 4
 (6) (21) 9
 (12) 
 Total Pension and OPEB Plans (8) 3
 (5) (17) 7
 (10) 
 Available-for-Sale Securities             
 Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 24
 (12) 12
 43
 (22) 21
 
 Total Available-for-Sale Securities 24
 (12) 12
 43
 (22) 21
 
 Total   $16
 $(9) $7
 $26
 $(15) $11
 
                 

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






Note 16.17. Earnings Per Share (EPS) and Dividends
EPS
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:
                  
  Three Months Ended September 30, Nine Months Ended September 30, 
  2017 2016 2017 2016 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator (Millions):
                
 Net Income$395
 $395
 $327
 $327
 $618
 $618
 $985
 $985
 
 
EPS Denominator (Millions):
                
 Weighted Average Common Shares Outstanding505
 505
 505
 505
 505
 505
 505
 505
 
 Effect of Stock Based Compensation Awards—
 2
 —
 3
 —
 2
 —
 3
 
 Total Shares505
 507
 505
 508
 505
 507
 505
 508
 
                  
 EPS                
 Net Income$0.78
 $0.78
 $0.65
 $0.64
 $1.22
 $1.22
 $1.95
 $1.94
 
                  
                  
  Three Months Ended June 30, Six Months Ended June 30, 
  2018 2017 2018 2017 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator (Millions):
                
 Net Income$269
 $269
 $109
 $109
 $827
 $827
 $223
 $223
 
 
EPS Denominator (Millions):
                
 Weighted Average Common Shares Outstanding504
 504
 505
 505
 504
 504
 505
 505
 
 Effect of Stock Based Compensation Awards—
 3
 —
 2
 —
 3
 —
 2
 
 Total Shares504
 507
 505
 507
 504
 507
 505
 507
 
                  
 EPS                
 Net Income$0.53
 $0.53
 $0.22
 $0.22
 $1.64
 $1.63
 $0.44
 $0.44
 
                  
ThereFor the three months and six months ended June 30, 2017, there were approximately 0.3 million for the three months and nine months ended September 30, 2017 and approximately 0.4 million for the three months and nine months ended September 30, 2016 of stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect.
Dividends
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Dividend Payments on Common Stock2017 2016 2017 2016 
 Per Share$0.43
 $0.41
 $1.29
 $1.23
 
 In Millions$217
 $207
 $652
 $622
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Dividend Payments on Common Stock2018 2017 2018 2017 
 Per Share$0.45
 $0.43
 $0.90
 $0.86
 
 In Millions$228
 $217
 $455
 $435
 
          

On July 17, 2018, PSEG’s Board of Directors approved a $0.45 per share common stock dividend for the third quarter of 2018.

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






Note 17.18. Financial Information by Business Segment
            
  PSE&G Power Other (A) Eliminations (B) Consolidated Total 
  Millions 
 Three Months Ended September 30, 2017          
 Total Operating Revenues$1,509
 $873
 $135
 $(254) $2,263
 
 Net Income (Loss)246
 136
 13
 —
 395
 
 Gross Additions to Long-Lived Assets729
 327
 9
 —
 1,065
 
 Nine Months Ended September 30, 2017          
 Operating Revenues$4,689
 $3,086
 $334
 $(1,121) $6,988
 
 Net Income (Loss)753
 (131) (4) —
 618
 
 Gross Additions to Long-Lived Assets2,118
 903
 25
 —
 3,046
 
 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
 
 As of September 30, 2017          
 Total Assets$27,802
 $11,631
 $2,288
 $(564) $41,157
 
 Investments in Equity Method Subsidiaries$—
 $90
 $—
 $—
 $90
 
 As of December 31, 2016          
 Total Assets$26,288
 $12,193
 $2,373
 $(784) $40,070
 
 Investments in Equity Method Subsidiaries$—
 $102
 $—
 $—
 $102
 
            
            
  PSE&G Power Other (A) Eliminations (B) Consolidated Total 
  Millions 
 Three Months Ended June 30, 2018          
 Total Operating Revenues$1,386
 $767
 $123
 $(260) $2,016
 
 Net Income (Loss)231
 41
 (3) —
 269
 
 Gross Additions to Long-Lived Assets697
 248
 7
 —
 952
 
 Six Months Ended June 30, 2018          
 Operating Revenues$3,231
 $2,170
 $270
 $(837) $4,834
 
 Net Income (Loss)550
 275
 2
 —
 827
 
 Gross Additions to Long-Lived Assets1,447
 547
 11
 —
 2,005
 
 Three Months Ended June 30, 2017          
 Total Operating Revenues$1,393
 $918
 $116
 $(285) $2,142
 
 Net Income (Loss)208
 (97) (2) —
 109
 
 Gross Additions to Long-Lived Assets641
 269
 9
 —
 919
 
 Six Months Ended June 30, 2017          
 Operating Revenues$3,219
 $2,187
 $199
 $(872) $4,733
 
 Net Income (Loss)507
 (267) (17) —
 223
 
 Gross Additions to Long-Lived Assets1,389
 576
 16
 —
 1,981
 
 As of June 30, 2018          
 Total Assets$29,603
 $12,772
 $2,407
 $(1,075) $43,707
 
 Investments in Equity Method Subsidiaries$—
 $87
 $—
 $—
 $87
 
 As of December 31, 2017          
 Total Assets$28,554
 $12,418
 $2,666
 $(922) $42,716
 
 Investments in Equity Method Subsidiaries$—
 $87
 $—
 $—
 $87
 
            
(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 primarily 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 18.19. Related-Party Transactions.

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


Note 18.19. 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 presented as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2017 2016 2017 2016 
  Millions 
 Billings from Affiliates:        
 Net Billings from Power primarily through BGS and BGSS (A)$259
 $320
 $1,154
 $1,162
 
 Administrative Billings from Services (B)82
 73
 226
 224
 
 Total Billings from Affiliates$341
 $393
 $1,380
 $1,386
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Related-Party Transactions2018 2017 2018 2017 
  Millions 
 Billings from Affiliates:        
 Net Billings from Power primarily through BGS and BGSS (A)$272
 $296
 $850
 $895
 
 Administrative Billings from Services (B)85
 79
 $168
 144
 
 Total Billings from Affiliates$357
 $375
 $1,018
 $1,039
 
          
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






      
  As of As of 
 Related-Party TransactionsSeptember 30, 2017 December 31, 2016 
  Millions 
 Receivables from PSEG (C)$—
 $76
 
 Payable to Power (A)$86
 $193
 
 Payable to Services (B)46
 67
 
 Payable to PSEG (C)46
 —
 
 Accounts Payable—Affiliated Companies$178
 $260
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$83
 $130
 
      
      
  As of As of 
 Related-Party TransactionsJune 30, 2018 December 31, 2017 
  Millions 
 Receivables from PSEG (C)$18
 $—
 
 Payable to Power (A)$81
 $221
 
 Payable to Services (B)69
 78
 
 Payable to PSEG (C)—
 41
 
 Accounts Payable—Affiliated Companies$150
 $340
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$94
 $91
 
      
Power
The financial statements for Power include transactions with related parties presented as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2017 2016 2017 2016 
  Millions 
 Billings to Affiliates:        
 Net Billings to PSE&G primarily through BGS and BGSS (A)$259
 $320
 $1,154
 $1,162
 
 Billings from Affiliates:        
 Administrative Billings from Services (B)$39
 $44
 $117
 $134
 
          
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents


          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Related-Party Transactions2018 2017 2018 2017 
  Millions 
 Billings to Affiliates:        
 Net Billings to PSE&G primarily through BGS and BGSS (A)$272
 $296
 $850
 $895
 
 Billings from Affiliates:        
 Administrative Billings from Services (B)$32
 $42
 $75
 $78
 
          
      
  As of As of 
 Related-Party TransactionsSeptember 30, 2017 December 31, 2016 
  Millions 
 Receivables from PSE&G (A)$86
 $193
 
 Receivables from PSEG (C)—
 12
 
 Accounts Receivable—Affiliated Companies$86
 $205
 
 Payable to Services (B)$17
 $25
 
 Payable to PSEG (C)111
 —
 
 Accounts Payable—Affiliated Companies$128
 $25
 
 Short-Term Loan Due (to) from Affiliate (E)$1
 $87
 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$57
 $77
 
      
      
  As of As of 
 Related-Party TransactionsJune 30, 2018 December 31, 2017 
  Millions 
 Receivables from PSE&G (A)$81
 $221
 
 Payable to Services (B)$20
 $28
 
 Payable to PSEG (C)128
 29
 
 Accounts Payable—Affiliated Companies$148
 $57
 
 Short-Term Loan due (to) from Affiliate (E)$519
 $(281) 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$45
 $52
 
      
(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. The rates in the BGS and BGSS contracts are prescribed by the BPU. In addition, Power and PSE&G provide certain technical services for each other generally at cost 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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents







Note 19.20. Guarantees of Debt
Power’s Senior Notes 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 SeptemberJune 30, 20172018 and December 31, 20162017 and for the three months and ninesix months ended SeptemberJune 30, 20172018 and 2016.2017.
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended September 30, 2017          
 Operating Revenues$—
 $856
 $46
 $(29) $873
 
 Operating Expenses2
 643
 44
 (29) 660
 
 Operating Income (Loss)(2) 213
 2
 —
 213
 
 Equity Earnings (Losses) of Subsidiaries143
 (3) 3
 (140) 3
 
 Other Income24
 58
 (2) (37) 43
 
 Other Deductions—
 (8) —
 —
 (8) 
 Other-Than-Temporary Impairments—
 (5) —
 —
 (5) 
 Interest Expense(32) (12) (5) 37
 (12) 
 Income Tax Benefit (Expense)3
 (103) 2
 —
 (98) 
 Net Income (Loss)$136
 $140
 $—
 $(140) $136
 
 Comprehensive Income (Loss)$156
 $154
 $—
 $(154) $156
 
 Nine Months Ended September 30, 2017          
 Operating Revenues$—
 $3,036
 $145
 $(95) $3,086
 
 Operating Expenses4
 3,315
 139
 (95) 3,363
 
 Operating Income (Loss)(4) (279) 6
 —
 (277) 
 Equity Earnings (Losses) of Subsidiaries(111) (8) 11
 119
 11
 
 Other Income71
 155
 —
 (99) 127
 
 Other Deductions(1) (21) —
 —
 (22) 
 Other-Than-Temporary Impairments—
 (9) —
 —
 (9) 
 Interest Expense(96) (30) (14) 99
 (41) 
 Income Tax Benefit (Expense)10
 68
 2
 —
 80
 
 Net Income (Loss)$(131) $(124) $5
 $119
 $(131) 
 Comprehensive Income (Loss)$(72) $(80) $5
 $75
 $(72) 
 Nine Months Ended September 30, 2017          
 
Net Cash Provided By (Used In)
   Operating Activities
$(55) $1,159
 $142
 $3
 $1,249
 
 
Net Cash Provided By (Used In)
   Investing Activities
$738
 $(289) $(343) $(990) $(884) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(683) $(869) $211
 $987
 $(354) 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended June 30, 2018          
 Operating Revenues$—
 $747
 $51
 $(31) $767
 
 Operating Expenses3
 704
 49
 (31) 725
 
 Operating Income (Loss)(3) 43
 2
 —
 42
 
 Equity Earnings (Losses) of Subsidiaries55
 (4) 5
 (51) 5
 
  Net Gains (Losses) on Trust Investments—
 8
 —
 —
 8
 
 Other Income (Deductions)41
 40
 —
 (68) 13
 
 Non-Operating Pension and OPEB Credits (Costs)—
 2
 1
 —
 3
 
 Interest Expense(54) (19) (6) 68
 (11) 
 Income Tax Benefit (Expense)2
 (23) 2
 —
 (19) 
 Net Income (Loss)$41
 $47
 $4
 $(51) $41
 
 Comprehensive Income (Loss)$43
 $44
 $4
 $(48) $43
 
 Six Months Ended June 30, 2018          
 Operating Revenues$—
 $2,133
 $102
 $(65) $2,170
 
 Operating Expenses3
 1,760
 101
 (65) 1,799
 
 Operating Income (Loss)(3) 373
 1
 —
 371
 
 Equity Earnings (Losses) of Subsidiaries289
 (7) 7
 (282) 7
 
 Net Gains (Losses) on Trust Investments—
 (14) —
 —
 (14) 
 Other Income (Deductions)76
 73
 —
 (125) 24
 
 Non-Operating Pension and OPEB Credits (Costs)—
 6
 1
 —
 7
 
 Interest Expense(96) (36) (11) 125
 (18) 
 Income Tax Benefit (Expense)9
 (115) 4
 —
 (102) 
 Net Income (Loss)$275
 $280
 $2
 $(282) $275
 
 Comprehensive Income (Loss)$272
 $267
 $2
 $(269) $272
 
 Six Months Ended June 30, 2018          
 
Net Cash Provided By (Used In)
   Operating Activities
$34
 $745
 $(8) $98
 $869
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(840) $(867) $(196) $808
 $(1,095) 
 
Net Cash Provided By (Used In)
   Financing Activities
$806
 $123
 $191
 $(906) $214
 
            
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






            
  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) 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended June 30, 2017          
 Operating Revenues$—
 $899
 $47
 $(28) $918
 
 Operating Expenses(2) 1,094
 43
 (28) 1,107
 
 Operating Income (Loss)2
 (195) 4
 —
 (189) 
 Equity Earnings (Losses) of Subsidiaries(93) (4) 5
 97
 5
 
  Net Gains (Losses) on Trust Investments(1) 25
 —
 —
 24
 
 Other Income (Deductions)23
 21
 2
 (34) 12
 
 Non-Operating Pension and OPEB Credits (Costs)—
 2
 —
 —
 2
 
 Interest Expense(34) (9) (4) 34
 (13) 
 Income Tax Benefit (Expense)6
 60
 (4) —
 62
 
 Net Income (Loss)$(97) $(100) $3
 $97
 $(97) 
 Comprehensive Income (Loss)$(82) $(91) $3
 $88
 $(82) 
 Six Months Ended June 30, 2017          
 Operating Revenues$—
 $2,154
 $99
 $(66) $2,187
 
 Operating Expenses2
 2,650
 95
 (66) 2,681
 
 Operating Income (Loss)(2) (496) 4
 —
 (494) 
 Equity Earnings (Losses) of Subsidiaries(254) (5) 8
 259
 8
 
  Net Gains (Losses) on Trust Investments3
 40
 —
 —
 43
 
 Other Income (Deductions)43
 40
 2
 (62) 23
 
 Non-Operating Pension and OPEB Credits (Costs)—
 4
 —
 —
 4
 
 Interest Expense(64) (18) (9) 62
 (29) 
 Income Tax Benefit (Expense)7
 171
 —
 —
 178
 
 Net Income (Loss)$(267) $(264) $5
 $259
 $(267) 
 Comprehensive Income (Loss)$(228) $(234) $5
 $229
 $(228) 
 Three Months Ended June 30, 2017          
 
Net Cash Provided By (Used In)
   Operating Activities
$(32) $802
 $111
 $51
 $932
 
 
Net Cash Provided By (Used In)
   Investing Activities
$683
 $178
 $(241) $(1,355) $(735) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(651) $(978) $146
 $1,304
 $(179) 
            
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 As of September 30, 2017          
 Current Assets$4,089
 $1,324
 $182
 $(4,433) $1,162
 
 Property, Plant and Equipment, net57
 5,408
 2,607
 —
 8,072
 
 Investment in Subsidiaries4,168
 338
 —
 (4,506) —
 
 Noncurrent Assets184
 2,211
 116
 (114) 2,397
 
 Total Assets$8,498
 $9,281
 $2,905
 $(9,053) $11,631
 
 Current Liabilities$233
 $3,221
 $1,743
 $(4,433) $764
 
 Noncurrent Liabilities503
 2,192
 524
 (114) 3,105
 
 Long-Term Debt2,385
 —
 —
 —
 2,385
 
 Member’s Equity5,377
 3,868
 638
 (4,506) 5,377
 
 Total Liabilities and Member’s Equity$8,498
 $9,281
 $2,905
 $(9,053) $11,631
 
 As of December 31, 2016          
 Current Assets$4,412
 $1,593
 $152
 $(4,697) $1,460
 
 Property, Plant and Equipment, net55
 6,145
 2,320
 —
 8,520
 
 Investment in Subsidiaries4,249
 344
 —
 (4,593) —
 
 Noncurrent Assets168
 2,016
 129
 (100) 2,213
 
 Total Assets$8,884
 $10,098
 $2,601
 $(9,390) $12,193
 
 Current Liabilities$171
 $3,752
 $1,454
 $(4,697) $680
 
 Noncurrent Liabilities532
 2,398
 502
 (100) 3,332
 
 Long-Term Debt2,382
 —
 —
 —
 2,382
 
 Member’s Equity5,799
 3,948
 645
 (4,593) 5,799
 
 Total Liabilities and Member’s Equity$8,884
 $10,098
 $2,601
 $(9,390) $12,193
 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 As of June 30, 2018          
 Current Assets$4,806
 $1,411
 $216
 $(4,868) $1,565
 
 Property, Plant and Equipment, net52
 5,048
 3,679
 —
 8,779
 
 Investment in Subsidiaries4,977
 1,129
 —
 (6,106) —
 
 Noncurrent Assets243
 2,258
 110
 (183) 2,428
 
 Total Assets$10,078
 $9,846
 $4,005
 $(11,157) $12,772
 
 Current Liabilities$690
 $3,164
 $1,987
 $(4,868) $973
 
 Noncurrent Liabilities516
 2,097
 497
 (183) 2,927
 
 Long-Term Debt2,833
 —
 —
 —
 2,833
 
 Member’s Equity6,039
 4,585
 1,521
 (6,106) 6,039
 
 Total Liabilities and Member’s Equity$10,078
 $9,846
 $4,005
 $(11,157) $12,772
 
 As of December 31, 2017          
 Current Assets$4,327
 $1,500
 $200
 $(4,686) $1,341
 
 Property, Plant and Equipment, net54
 5,778
 2,764
 —
 8,596
 
 Investment in Subsidiaries4,844
 404
 —
 (5,248) —
 
 Noncurrent Assets100
 2,349
 110
 (78) 2,481
 
 Total Assets$9,325
 $10,031
 $3,074
 $(10,012) $12,418
 
 Current Liabilities$689
 $3,586
 $1,846
 $(4,686) $1,435
 
 Noncurrent Liabilities533
 1,966
 459
 (78) 2,880
 
 Long-Term Debt2,136
 —
 —
 —
 2,136
 
 Member’s Equity5,967
 4,479
 769
 (5,248) 5,967
 
 Total Liabilities and Member’s Equity$9,325
 $10,031
 $3,074
 $(10,012) $12,418
 
            

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’s business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:
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 related programs in New Jersey, which are regulated by the BPU, and
Power—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. 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’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases;are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractualan Operations and Services Agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
Our business discussion in Part I, Item 1. Business of our 20162017 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 20162017 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 20172018 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 20162017 Form 10-K.

EXECUTIVE OVERVIEW OF 20172018 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:including
improving utility operations through investment in T&D and other infrastructure projects designed to enhance system reliability and resiliency and to meet customer expectations and public policy objectives, and
maintaining and expandingmanaging a reliable, cost-effective 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.




Financial Results
The results for PSEG, PSE&G and Power for the three months and ninesix months ended SeptemberJune 30, 20172018 and 20162017 are presented as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Earnings (Losses)2017 2016 2017 2016 
  Millions 
 PSE&G$246
 $255
 $753
 $696
 
 Power (A)136
 139
 (131) 320
 
 Other (B)13
 (67) (4) (31) 
 PSEG Net Income$395
 $327
 $618
 $985
 
          
 PSEG Net Income Per Share (Diluted)$0.78
 $0.64
 $1.22
 $1.94
 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Earnings (Losses)2018 2017 2018 2017 
  Millions 
 PSE&G$231
 $208
 $550
 $507
 
 Power (A)41
 (97) 275
 (267) 
 Other (B)(3) (2) 2
 (17) 
 PSEG Net Income$269
 $109
 $827
 $223
 
          
 PSEG Net Income Per Share (Diluted)$0.53
 $0.22
 $1.63
 $0.44
 
          
(A)Includes after-tax expenses of $5$229 million and $568$563 million in the three months and ninesix months ended SeptemberJune 30, 2017, respectively, and after-tax expenses of $67 millionprimarily for the three months and nine months ended September 30, 2016accelerated depreciation related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants. See Item 1. Note 3.4. Early Plant Retirements for additional information.
(B)Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges of $45 million for the nine months ended September 30, 2017, and an after-tax impairment of $86 million for the three months and nine months ended September 30, 2016 related to its investments in NRG REMA, LLC’s (REMA) leveraged leases.leases of $14 million in the second quarter of 2018 and $13 million and $45 million in the three months and six months ended June 30, 2017, respectively. See Item 1. Note 6.7. Financing Receivables for additional 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 commodity mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.
The variances in our Net Income include theattributable to changes related to the NDT Fund and MTM are shown in the following table:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2017 2016 2017 2016 
  Millions, after tax 
 NDT Fund Income (Expense) (A) (B)$10
 $2
 $32
 $(4) 
 Non-Trading MTM Gains (Losses) (C)$(27) $34
 $—
 $(54) 
          
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
  Millions, after tax 
 NDT Fund Income (Expense) (A) (B)$5
 $14
 $(11) $22
 
 Non-Trading MTM Gains (Losses) (C)$(48) $21
 $37
 $27
 
          
(A)NDT Fund Income (Expense) includes the realized gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 1. Note 8. Trust Investments for additional information. NDT Fund Income (Expense) also includes 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(Deductions), 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 (D&A) Expense.
(B)Net of tax (expense) benefit of $(12) million, $(2) million, $(37)$(4) million and $0$(16) million for the three months and nine$4 million and $(25) million for the six months ended SeptemberJune 30, 20172018 and 2016,2017, respectively.
(C)Net of tax (expense) benefit of $19 million $(24) million, $0 million and $37$(15) million for the three months and nine$(14) million and $(19) million for the six months ended SeptemberJune 30, 20172018 and 2016,2017, respectively.
Our $68$160 million increase in Net Income for the three months ended SeptemberJune 30, 20172018 was driven primarilylargely by
an impairmentaccelerated depreciation in 2016 related to investments in certain leveraged leases at Energy Holdings,
higher charges in 20162017 related to early retirement of our Hudson and Mercer coal/gas generation units,
the favorable impact at Power
from the lower generation costs driven by lower natural gas costs and congestion costs,federal tax rate effective January 1, 2018, and
higher earnings due to continued investment in transmission revenues.and distribution clause programs,
partially offset by MTM net losses in 2018 as compared to MTM net gains in 2017, and

These favorable variances were partially offset by
lower wholesale energy sales of electricity sold underat Power in the Basic Generation Service contract and in PJM and
MTMlossesin 2017 as compared to MTM gains in 2016.
region.
Our $367$604 million decreaseincrease in Net Income for the ninesix months ended SeptemberJune 30, 20172018 was driven largely by higher charges, primarily
accelerated depreciation in 2017 related to the early retirement of our Hudson and Mercer coal/gas generation units,
the favorable impact at Power. These decreases were partially offset byPower from the lower federal tax rate effective January 1, 2018,
lower O&M Expensehigher earnings due to cost control efforts,continued investment in transmission and distribution clause programs, and
lower charges in 2018 related to leveraged lease investments (see Item 1. Note 7. Financing Receivables),
partially offset by unrealized losses on equity securities in certain leveraged leases at Energy Holdings,
MTM lossesthe NDT Fund in 2016, and
higher NDT gains and lower NDT losses in 2017.2018 related to new accounting guidance effective January 1, 2018. (See Item 1. Note 2. Recent Accounting Standards.)
During the first ninesix months of 2017,2018, we maintained a strong balance sheet. We continued to effectively deploy capital without the need forto issue 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, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has 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 tofor our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs in order to enhance the value ofoptimize cash flow generation from our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.
At PSE&G, we continue to invest in transmissionT&D projects that focus on reliability improvements and replacement of aging infrastructure, includinginfrastructure. Over the next five years, we expect to invest between $12 billion and $15.5 billion in our $275 million Newark Switch project that was approved by PJM in July 2017.business which is expected to provide an annual rate base growth of 8%—10%. We also continue to make investments to improve the resiliency of our gas and electric distribution system as partare forecasting completion of our Energy Strong program that was approved by the BPU in 2014Program I (ESP I) and to seek recovery on such investments. We also continue to modernize PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP)I (GSMP I) this year. We have received approval for the GSMP II, an expanded, five-year program totaling $1.9 billion that was approved by the BPUwill start in late 2015. 2019. In June 2018, we filed for our Energy Strong Program II (ESP II), a proposed five-year $2.5 billion program to harden, modernize and make our electric and gas distribution systems more resilient. We also expect to file our proposed Clean Energy Future program later this year, a six-year estimated $2.9 billion program focused on achieving New Jersey’s energy efficiency targets, as well as supporting electric vehicle infrastructure and battery storage initiatives.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.
As a resultPower continues to move its fleet towards improved efficiency and fuel diversity. We believe that its investment program enhances our competitive position with the addition of our Energy Strong Orderefficient, clean, reliable combined cycle gas turbine capacity. Our commitments for load, such as basic generation service (BGS) in New Jersey and other bilateral supply contracts, are backed by this generation or may be combined with the use of physical commodity purchases and financial instruments from the BPU, we are requiredmarket to file a distribution base rate case. Following discussions with BPU Staff and Rate Counsel, and as approved byoptimize the BPU at its October 20, 2017 meeting, the deadline for filing PSE&G’s distribution base rate case was moved from November 1, 2017 to December 1, 2017. The initial filing will now be based upon three monthseconomic efficiency of actual data and nine months of forecasted data updated for actual data throughout the proceeding. The distribution base rate case will provide PSE&G the opportunity to recover investments made since its last distribution base rate case, including investments that were not recovered through clauses, such as the stipulated base investment associated with GSMP, the portion of Energy Strong investment not recovered through the clause, and investments that exceededserving our depreciation levels in revenues. Recovery of these investments, coupled with updates to O&M and other adjustments, are anticipated to result in a proposed mid-single digit percentage increase in PSE&G distribution revenues. The distribution base rate case filing will include a test year through June 30, 2018 and will request the inclusion of known and measurable changes in rate base through December 31, 2018, a 10.3% return on equity (ROE) and a capitalization structure with a 54% equity component, and we expect to request new rates effective October 1, 2018. As part of the filing, we will also request approval to decouple electric and gas revenues from sales volumes for most distribution customer classes. We cannot predict the outcome of this proceeding.
In July 2017, we filed a petition with the BPU for GSMP II, a five-year extension of GSMP, which would accelerate the pace of replacement of our aging cast iron and unprotected steel mains and associated service. We proposed to invest up to $540 million per year over this five-year program beginning in 2019. In August 2017, the BPU approved our request for an extension of our Energy Efficiency program.
Although the weather in the first three months of 2017 was warmer than normal, Power’s results saw a continuing benefit from access to natural gas supplies through existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the basic gas supply (BGSS) arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter demand days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third-party sales and if excess volume remains after the third-party sales, 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.

obligations. Power’s hedging practices and ability to capitalize on market opportunities help usit to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in 2018 relates to our hedging program in combination withstrategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power, has secured approximately 60% of its estimated gross margin for the 2017-2019 period.power.
Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station unitUnit 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These highly efficient additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to improve our financial performance.
Since 2013, several nuclear generating stations inenhance the United States have closed or announced early retirement due to economic reasons, or have announced as being at risk for early retirement. This situation is generally due to the decline in market pricesenvironmental profile and overall efficiency of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electricPower’s generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.
If the market trends noted above continue or worsen, our New Jersey nuclear generating units could cease being economically competitive, which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs, and additional funding of NDT funds would likely have a material adverse impact on future financial results. We continue to advocate for sound policies that recognize nuclear power as a source of reliable and clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.
In addition, a number of states have either taken action or are investigating the situation faced by nuclear generating units. Recently, courts in Illinois and New York upheld challenges to the programs which established zero emissions credits, recognizing the importance of nuclear units for providing clean energy, free of air emissions.
In September 2017, the Secretary of the U.S. Department of Energy (DOE) issued a Notice of Proposed Rulemaking (NOPR) directing FERC to act within 60 days to develop a mechanism that would allow for the recovery of costs of fuel-secure generation units such as nuclear and coal. To be eligible for compensation under the NOPR, units must be able to provide certain essentialenergy and ancillary reliability services, have a 90-day fuel supply on site and not subject to cost-of-service rate regulation by any State or local authority. PSEG is evaluating the potential effects this NOPR could have on its generating fleet. PSEG filed comments in support of the DOE’s NOPR and contended that it should be implemented immediately as an interim measure to prevent the premature retirement of fuel-secure baseload units. PSEG also requested that FERC direct the regional transmission organizations (RTOs) to work with stakeholders to develop a long-term market-based methodology for valuing resiliency in the generator fleet. Additionally, PSEG argued that FERC should expedite the implementation of pending price formation reforms, including fast-start pricing and uplift allocation and market transparency. Finally, PSEG requested that FERC direct PJM to file its proposal that would allow baseload units to set the locational marginal prices during low load conditions. We cannot predict the outcome of this matter.
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 For additional information about regulatory, legislative and other developments that may affect the company, see Part I, Item 1. Regulatory Issues in our 2017 the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission projectAnnual Report on Form 10-K and approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. Also,Item 5. Other Information in April 2017, PJM submitted a proposal to FERC concerning the cost responsibility assigned to certain entities, including PSE&G,our Form 10-Q for the Artificial Island project. In October 2017, FERC accepted PJM’s filing on the grounds that PJM correctly applied its Tariff, but deferred any further ruling on whether the cost allocation methodology applied to the Artificial Island project is appropriate. FERC will decideperiod ending March 31, 2018 and this issue in a separate proceeding that is currently pending before it.Form 10-Q.

Transmission Planning
There are several matters pending before FERC and the U. S. Court of Appeals for the District of Columbia Circuit 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 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 ratepayerscustomers in New Jersey. In addition, as a basic generation

service (BGS)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 maywould be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effect on Power’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’ base ROEs. The results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.
Wholesale Power Market Design
Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources (seasonal resources). However, FERC held a technical conference in response to two complaints remain pending that ask FERC to investigateconsider the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions.
In May 2017, PJM announced the results of the RPM capacity auction for the 2020-2021 delivery year. Power cleared approximately 7,800 MW of its generating capacity at an average price of $174 per MW-day for the 2020-2021 delivery period. In the two prior capacity auctions covering the 2019-2020 and 2018-2019 delivery years, Power cleared approximately 8,900 MW at an average price of $116 and approximately 8,700 MW at an average price of $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.
As a result of the efforts of certain entities in PJM to obtain financial support arrangements from their state commissions, a group of suppliers requested that FERC direct PJM to expand the currently 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 generators would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ request and cannot predict the outcome of the proceeding.these matters.
In April 2018, PJM submitted two proposed alternative and mutually exclusive capacity market reforms for FERC’s approval. In June 2017, PJM2018, FERC issued an energyorder finding that PJM’s current capacity market is unjust and unreasonable because it allows resources supported by out-of-market payments to suppress capacity prices. FERC established a new proceeding to address an alternative approach in which PJM would: (1) modify PJM’s Minimum Offer Price Rule (MOPR) so that it would apply to new and existing resources that receive out-of-market payments, regardless of resource type; and (2) establish an option that would allow, on a resource-specific basis, resources receiving out-of-market support to be removed from the PJM capacity market, along with a commensurate amount of load, for some period of time. FERC’s potential action in this proceeding could cause nuclear units that receive ZEC payments to lose capacity market revenues if states do not take steps to address this potential loss of capacity revenues. In addition, depending on the outcome of this matter, our fossil generating stations could be adversely impacted. We cannot predict the outcome of this matter.
The PJM Board directed PJM staff to work with stakeholders to implement a series of price formation proposalreforms, including a 30-minute reserve product in real-time, more dynamic reserve requirements to address a flawbetter capture operator actions taken to maintain reliability, and improvement to the curves used to price reserves during reserve shortage conditions. The PJM Board letter directs PJM staff to submit some of these reforms for FERC’s approval so that they can be implemented in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price.early 2019. If placed into effect, this proposal willthese reforms should improve price formationenergy and reserve prices by ensuring that when operators commit resources to ensure reliability, the marginal costs of units serving load will be bettercommitments are reflected in market clearing prices. We cannot predict the outcome of this matter.
Distribution
In June 2017, theThe BPU issued proposedhas enacted Infrastructure Investment Program (IIP) regulations that would allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under the proposedthese regulations, utilities couldcan seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. The proposed regulations
In May 2018, the BPU approved a settlement regarding PSE&G’s GSMP II program, which is the next phase of our GSMP I. Under GSMP II, PSE&G expects to invest $1.9 billion over five years beginning in 2019 to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the remaining $300 million to be recovered through a future base rate case. As part of the settlement, PSE&G agreed to file a base rate case no later than five years from the commencement of the program, to maintain a base level of gas distribution capital expenditures of $155 million per year and to achieve certain leak reduction targets. The ROE and certain other elements for the program will be determined in the pending base rate case proceeding.
As previously disclosed, PSE&G’s ESP I, an investment program to harden and make the electric and gas distribution system more resilient, is expected to be completed during 2018. In June 2018, PSE&G filed its ESP II proposal with the BPU to invest

an additional $2.5 billion over the next five years as an extension and expansion of its ESP I. The extension seeks to continue efforts to harden the electric system against storms and make it more resilient, to implement a more proactive life cycle replacement program to modernize the electric system and to make the gas system more reliable by mitigating the impacts of potential supply curtailments. The size and duration of ESP II, as well as PSE&G’s ROE and certain other elements of the program, are subject to commentBPU approval.
In January 2018, PSE&G filed a distribution base rate case as required as a condition of approval of its ESP I approved by the BPU in 2014. The filing requested an approximate 1% increase in revenues and recovery of investments made to strengthen the electric and gas distribution systems. The requested increase took into account a reduction in the revenue requirement as a result of the federal corporate income tax rate reduction from interested parties.35% to 21% provided in the Tax Act, including the flow-back to customers of excess accumulated deferred income taxes. In March 2018, the BPU approved interim rate reductions for all their jurisdictional utilities, including PSE&G, reflecting the reduction in the federal corporate tax rate. The BPU approved a reduction to PSE&G’s base electric and gas revenues effective April 1, 2018 by $71 million and $43 million, respectively, on an annual basis (or about 2% combined). The refund to customers for overcollection of revenues at the higher tax rate for the January 1 to March 31, 2018 period, and the flow-back to customers of certain excess deferred income taxes will be addressed in PSE&G’s ongoing base rate case proceeding. As a result of the base rate reduction implemented on April 1, 2018, PSE&G’s requested revenue requirement in its filing has increased accordingly. In May 2018, PSE&G filed a required update to its base rate case, requesting an approximate three percent increase in revenues. PSE&G anticipates a decision by the BPU that the new base rates will go into effect in the fourth quarter of 2018.
Energy Efficiency
Consistent with New Jersey’s recently enacted energy efficiency legislation, which is more fully described under Part II, Item 5. Other Information, PSE&G has outlined a clean energy proposal to invest $2.9 billion over six years in energy efficiency and other programs that will reduce energy bills and combat climate change, which we refer to as our Clean Energy Future program. The program, which PSE&G expects to file with the BPU later this year, includes: $2.5 billion for energy efficiency to reduce customer bills and lower energy use, which will decrease air pollution, including emissions that accelerate climate change; $300 million for building a “smart” electric vehicle infrastructure; and $100 million for utility-scale energy storage systems that will enable greater development of renewable resources and enhance resiliency.
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 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.
In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards whichthat establish emissions standards for CO2 for certain new fossil power plants, and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In October 2017, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric

generating units). WhetherThe EPA is considering rulemaking to replace the EPA chooses to propose a replacement rule has not been decided.CPP. PSEG cannot estimateassess the impact of these actionsany such rulemaking on ourits business and future results of operations at this time.
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 9.10. Commitments and Contingent Liabilities.
FERC Compliance

Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculationTable of certain components of Power’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. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 1. Note 9. Commitments and Contingent Liabilities.Contents

Early Retirement of Hudson and Mercer UnitsPlant Retirements
Fossil
On June 1, 2017, Power completed its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operations in 2016 and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental D&A of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first nine months of 2017, Energy Costs of $10 million and O&M of $12 million were also incurred and other costs may be incurred during the remaining period in 2017. See Item 1. Note 3.4. Early Plant Retirements for additional information.
Power currently anticipatesis exploring various opportunities with these sites, including using the sites for alternative industrial activity. However, ifactivity or the disposition of one or both of the sites. If Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.
In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. 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 or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.
Nuclear
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. In February 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure of its Oyster Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. In addition, First Energy announced in March 2018 the early retirement of four nuclear units at the Davis-Besse, Perry Nuclear and Beaver Valley nuclear plants in Ohio and Pennsylvania by 2021. These closures and retirements are generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.
In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for selection of the units under the newly enacted legislation in the state of New Jersey. Power and Exelon have agreed to cancel the funding of future capital projects at the Salem generating station that are not required to meet NRC or other regulatory requirements or that are not required to ensure its safe operation. Power and Exelon have agreed to continue to assess and, when appropriate, approve the funding of individual capital projects to ensure compliance with regulatory requirements and the safe operation of the Salem generating station and that the funding of these projects may be restored if legislation enacted in New Jersey sufficiently values the attributes of nuclear generation and Salem benefits from such legislation.
If any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. In May 2018, the governor of New Jersey signed legislation that would provide a safety net in order to prevent the loss of environmental attributes from selected nuclear generating stations referred to as the zero emissions certificate (ZEC) program. The legislation calls for the BPU (within a 330-day period from enactment) to establish a collection process for a customer charge, determine eligibility and certification of need, and ultimately select nuclear plants to potentially receive ZECs starting in April 2019. Power cannot predict whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
If energy market prices continue to be depressed, there are adverse impacts from potential changes to the capacity market construct being considered by FERC, or the ZEC program does not adequately compensate our nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and

operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the NDT Fund would be material to both PSEG and Power.
Leveraged Lease PortfolioImpairments
GenOn Energy, Inc. (GenOn), the parent company of REMA, and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. REMA was not included in the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity. We continue to monitor the restructuring of GenOn and the possible related impact on REMA and continue to discuss the situation with GenOn.
During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged

lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. 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 lease receivables, and continues to discuss the situation with various parties relevant to this matter. Based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded a $20 million pre-tax charge in the quarter ended June 30, 2018 for its current best estimate of loss related to lease receivables. For additional information, see Item 1. Note 6.7. Financing Receivables. 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 and Powerton generating facilities. Similar to Shawville, Joliet was recently converted to use natural gas. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois. Each of these three 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 other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.

Tax Legislation
SalemIn December 2017, the U.S. government enacted comprehensive tax legislation (Tax Act), which, among other things, decreased the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018, and made certain changes to bonus depreciation rules.
Concurrently withAs a result of the planned refueling outage at the Salem 2 unit that was conductedenacted reduction in the second quarterstatutory U.S. corporate income tax rate, as well as other aspects of the Tax Act, in December 2017 PSE&G recorded excess deferred taxes of approximately $2.1 billion and recorded an approximate $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities where it is probable that refunds will be made to customers in future rates. The amount and timing of any such refund cannot be determined at this time.
Beginning in 2018, PSEG, on a consolidated basis, is incurring lower income tax expense resulting in a decrease in its projected effective income tax rate. This has increased PSEG’s and Power’s net income. To the extent allowed under the Tax Act, Power’s operating cash flows will reflect the full expensing of capital investments for income tax purposes. PSEG and Power expect that the interest on their debt will continue to be fully tax deductible albeit at a lower tax rate. For PSE&G, the Tax Act has led to lower customer rates due to lower income tax expense recoveries and we inspected and replaced baffle boltshave proposed to refund excess deferred income tax regulatory liabilities as part of our strategydistribution rate case filing. The impact of the lower federal income tax rate on PSE&G was reflected in PSE&G’s recently filed distribution base rate case and its 2018 transmission formula rate filings. The Tax Act is generally expected to replace baffle bolts atresult in lower operating cash flows for PSE&G resulting from the Salem station.elimination of bonus depreciation, partially offset by higher revenues due to the higher rate base.
The unit wasimpact of the Tax Act may differ from these estimates, possibly materially, due to, among other things, changes in interpretations and assumptions PSEG has made, guidance that may be issued and actions PSEG may take as a result of the Tax Act. For additional information, see Item 1. Note 15. Income Taxes.
As a result of the enactment of the Tax Act, various state regulatory authorities, including the BPU, have taken action to ensure that excess federal income taxes previously collected in rates are returned to servicecustomers. We have made filings to adjust the revenue requirement in June 2017.certain of our rate matters as a result of the change in the federal income tax rate.
In addition, FERC continues to assess whether, and if so how, it will address changes and flow-backs to customers relating to accumulated deferred income taxes and bonus depreciation. See Item 1. Note 6. Rate Filings for additional information.
In July 2018, the State of New Jersey made significant changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. We believe PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. We expect these new provisions

to unfavorably affect our non-utility business and we continue to analyze this newly enacted law and the impact it will have on us.
Operational Excellence
We emphasize operational performance exercising diligence in managing costs, while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market.market as we remain diligent in managing costs. For the first ninesix months of 2017,2018, our
utility, continued top decile performance in electric reliability,
total nuclear fleet achieved an average capacity factor of 95%,beginning with comprehensive storm preparation, efficiently and safely completed our customer restorations and then assisted neighboring utilities with their restoration efforts,
diverse fuel mix and dispatch flexibility allowed us to generate approximately 3925 terawatt hours while addressing fuel availability and price volatility, and
combined cycletotal nuclear fleet produced 11 terawatt hours atachieved an equivalent availabilityaverage capacity factor of 94%92.9%.
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 ninesix months of 20172018 as we
maintained sufficient liquidity,
maintained solid investment grade credit ratings, and
increased our indicative annual dividend for 20172018 to $1.72$1.80 per share.
We expect to be able to fund our planned capital requirements and manage the impacts of the Tax Act 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 ninesix months of 2017,2018, we
made additional investments in transmission infrastructure projects,
continued to execute our GSMP I, ESP I, Energy Efficiency and other existing BPU-approved utility programs, and
commenced commercial operation of Sewaren 7 and continued construction of our Keys and Sewaren 7BH5 generation projectsproject, which is targeted for targeted commercial operation in mid-2019.
In early July 2018, and began constructionwe started commercial operation of BH5 for targeted commercial operations in mid-2019.our Keys generation facility.
Future Outlook    
Our future success will depend on our ability to continue to maintain strong operational and financial performance in a cost-constrainedan 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,
successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,
successfully launchobtain approval of and grow our retail energy business, which complements our existing wholesale energy business,
execute our utility capital investment program, including ESP II, GSMP I and II, our Clean Energy StrongFuture 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, and obtain approval for the extension of these programs,
effectively manage construction and start-up 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’s fuel supply and generation dispatch obligations.
For 20172018 and beyond, the key issues challenges and opportunitieschallenges 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 distribution base rate case proceedingwhich was filed with the BPU in January 2018, and the timing of the return of unprotected excess deferred taxes to be filed in 2017,customers,
applying to the BPU to select our New Jersey nuclear generation units to receive payments under the ZEC program,
continuing discussions regarding the restructuring of GenOn and REMA and its potential impact on the value of our Keystone, Conemaugh and Shawville leveraged leases,
the potential for comprehensivecontinuing impacts of the Tax Act and changes in state tax reform, particularly in light of public statements by the current U.S. administration and key members of Congress,laws,
uncertainty in the national and regional economic performance,conditions, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,
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,
ensuring timely completion ofdelays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including obtaining required permitsin connection with permitting and regulatory approvals, and
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.cycles.
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 distributionT&D 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,
the expansion of our geographic footprint,

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continued or expanded participation in solar, demand response and energy efficiency and related programs, and
investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.
Power is developing a retail energy business to sell energy, which we believe complements our existing wholesale marketing business. Power began these marketing activities in 2017 and has been granted retail energy supplier licenses in New Jersey, Pennsylvania and Maryland.
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 18.19. Related-Party Transactions.
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2017 2016 2017 vs. 2016 2017 2016 2017 vs. 2016 
  Millions Millions % Millions Millions % 
 Operating Revenues$2,263
 $2,450
 $(187) (8) $6,988
 $6,971
 $17
 —
 
 Energy Costs638
 866
 (228) (26) 2,100
 2,326
 (226) (10) 
 Operation and Maintenance680
 776
 (96) (12) 2,100
 2,215
 (115) (5) 
 Depreciation and Amortization252
 231
 21
 9
 1,721
 679
 1,042
 N/A
 
 Income from Equity Method Investments3
 3
 —
 —
 11
 9
 2
 22
 
 Other Income (Deductions)56
 39
 17
 44
 178
 100
 78
 78
 
 Other-Than-Temporary Impairments5
 5
 —
 —
 9
 25
 (16) (64) 
 Interest Expense100
 99
 1
 1
 289
 288
 1
 —
 
 Income Tax Expense252
 188
 64
 34
 340
 562
 (222) (40) 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2018 2017 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$2,016
 $2,142
 $(126) (6) $4,834
 $4,733
 $101
 2
 
 Energy Costs600
 588
 12
 2
 1,552
 1,456
 96
 7
 
 Operation and Maintenance725
 718
 7
 1
 1,479
 1,435
 44
 3
 
 Depreciation and Amortization280
 641
 (361) (56) 560
 1,469
 (909) (62) 
 Income from Equity Method Investments5
 5
 —
 —
 7
 8
 (1) (13) 
 Net Gains (Losses) on Trust Investments8
 25
 (17) (68) (14) 53
 (67) (79) 
 Other Income (Deductions)34
 33
 1
 3
 66
 65
 1
 2
 
 Non-Operating Pension and OPEB Credits (Costs)19
 1
 18
 N/A
 38
 1
 37
 N/A
 
 Interest Expense111
 91
 20
 22
 214
 189
 25
 13
 
 Income Tax Expense97
 59
 38
 64
 299
 88
 211
 240
 
                  
The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.
PSE&G
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2017 2016 2017 vs. 2016 2017 2016 2017 vs. 2016 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,509
 $1,684
 $(175) (10) $4,689
 $4,746
 $(57) (1) 
 Energy Costs535
 721
 (186) (26) 1,760
 1,979
 (219) (11) 
 Operation and Maintenance346
 376
 (30) (8) 1,064
 1,110
 (46) (4) 
 Depreciation and Amortization169
 137
 32
 23
 506
 412
 94
 23
 
 Other Income (Deductions)22
 21
 1
 5
 67
 58
 9
 16
 
 Interest Expense79
 72
 7
 10
 223
 214
 9
 4
 
 Income Tax Expense156
 144
 12
 8
 450
 393
 57
 15
 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2018 2017 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,386
 $1,393
 $(7) (1) $3,231
 $3,219
 $12
 —
 
 Energy Costs488
 488
 —
 —
 1,270
 1,250
 20
 2
 
 Operation and Maintenance353
 359
 (6) (2) 744
 729
 15
 2
 
 Depreciation and Amortization187
 166
 21
 13
 377
 337
 40
 12
 
 Net Gains (Losses) on Trust Investments—
 —
 —
 —
 —
 2
 (2) (100) 
 Other Income (Deductions)20
 21
 (1) (5) 40
 43
 (3) (7) 
 Non-Operating Pension and OPEB Credits (Costs)15
 (1) 16
 N/A 30
 (3) 33
 N/A 
 Interest Expense82
 69
 13
 19
 163
 144
 19
 13
 
 Income Tax Expense80
 123
 (43) (35) 197
 294
 (97) (33) 
                  
Three Months Ended SeptemberJune 30, 20172018 as Compared to 20162017
Operating Revenues decreased $175$7 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues decreased $8 million due primarily to
Transmission, gas distribution and electric distribution revenue requirements were $62 million lower as a result of rate reductions due to the Tax Act which reduced the corporate income tax rate. This decrease is offset in Income Tax Expense.

Delivery Revenues increased $10 million due primarily to an increase in transmission revenues.
Transmission revenues were $34 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover requiredincreased investments.
Gas distribution revenues increased $5$12 million due primarily to a $1$16 million increase from higher sales volumes and a $5 million increase from the inclusion of Energy Strongthe GSMP I in base rates. These increases were partially offset by a $10 million decrease in Weather Normalization Clause (WNC) collections.
Electric distribution revenues increased $8 million due to a $4 million increase from higher ESP I investments in base rates, $3 million in higher sales volumes, and $1 million increases in both GSMP collections andhigher Green Program Recovery Charges (GPRC) and higher sales volumes.
Electric distribution revenues decreased $29 million due to a $38 million decrease due to lower sales volumes and lower GPRC of $6 million, partially offset by a $15 million increase from the inclusion of Energy Strong in base rates.$1 million.
Commodity RevenueRevenues decreased $186 millionwere flat as a result of higher Gas revenues entirely offset by lower Electric and Gas revenues. The changes in Commodity revenuerevenues for both electricgas and gaselectric are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSSbasic gas supply service (BGSS) to retail customers.
Electric commodity revenues decreased $176 million due primarily to a $153 million decrease in BGS revenues due to $97 million in lower sales volumes and $56 million from lower prices and $23 million of lower revenues from collections of Non-Utility Generation Charges (NGC).
Gas commodity revenues decreased $10increased $4 million due to lowerhigher BGSS sales pricesvolumes of $22 million partially offset by higher
lower BGSS sales volumesprices of $12$18 million.
Electric commodity revenues decreased $4 million due to $29 million from lower BGS prices partially offset by $25 million in higher BGS sales volumes.
Clause Revenues increased $1 millionwere flat due primarily to the return of $20a $6 million to customersdecrease in 2016 of overcollections of Securitization Transition Charges (STC), partiallyMargin Adjustment Clause (MAC) revenues entirely offset by lowerhigher collections of Societal Benefit Charges (SBC) of $12$4 million and a $6$2 million decreaseincrease in 2017 in Margin Adjustment Clause (MAC) revenues.collections of GPRC. The changes in the STC,MAC, SBC and MACGPRC amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC,MAC, SBC or MACGPRC collections.
Operating Expenses
Energy Costs decreased $186 million.were flat. This is entirely offset by the change in Commodity Revenue.Revenues.
Operation and Maintenance decreased $30$6 million due primarily due to a $17$4 million reduction in clause-related costs, $6 million in lower appliance service costs, $6 million of lower distribution correctiveinjuries and preventative maintenancedamages and a $5$2 million reductiondecrease in GPRC related costs,distribution maintenance, partially offset by a net$2 million increase of $4 million in certain operational expenses.seasonal storm damages.
Depreciation and Amortization increased $32$21 million due primarily to an increase of $19 million in amortization of Regulatory Assets and a $14 million increase in depreciation due to additional plant placed into service.
Non-Operating Pension and OPEB Credits (Costs) reflected an increase of $16 millionin service.creditsdue to the adoption of new accounting guidance effective January 1, 2018 which no longer allows capitalization of any portion of these benefit costs. See Item 1. Note 2. Recent Accounting Standards.
Interest Expense increased $7$13 million due primarily to an increaseincreases of $7 million in clause interest and $5 million duerelated to net debt issuances in 2016May 2018 and 2017 and a $2 million increase in other interest.December 2017.
Income Tax Expense increased $12decreased $43 million due primarily to uncertainthe decrease in the federal statutory income tax positionsrate from 35% in 2017 to 21% in 2018, partially offset by plant-related and plant-relatedflow-through items.
NineSix Months Ended SeptemberJune 30, 20172018 as Compared to 20162017
Operating Revenues decreased $57increased $12 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues increased $119$4 million due primarily to an increase in transmission revenues.
Transmission revenues were $116$80 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover requiredincreased investments.
Gas distribution revenues increased $43 million primarily due to a $48 million increase due to higher sales volumes, a $22 million increase from the inclusion of the GSMP I in base rates and a $2 million increase in GPRC collections. These increases were partially offset by a $29 million decrease in WNC collections.
Electric distribution revenues increased $8 million due to a $14$6 million increase from the inclusion of increased ESP I investments in base rates and $2 million in higher sales volumes.
Transmission, gas distribution and electric distribution revenue requirements were $127 million lower as a result of rate reductions due to the inclusion of Energy StrongTax Act which reduced the corporate income tax rate. This decrease is offset in base rates, $8 million in higher Weather Normalization Clause (WNC) revenue, a $7 million increase due to the GSMP and higher GPRC of $3 million, partially offset by $3 million of lower delivery volumes.
Electric distribution revenues decreased $26 million due to a $36 million decrease due to lower sales volumes and lower GPRC of $14 million, partially offset by a $24 million increase due to the inclusion of Energy Strong in base rates.Income Tax Expense.
Commodity RevenueRevenues decreased $219increased $20 million as a result of lowerhigher Electric revenues partially offset by higherlower Gas revenues. The changes in Commodity revenuerevenues for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
Electric commodity revenues decreased $266 million due primarily to a $188 million decrease in BGS revenues due to $116 million in lower sales volumes and $72 million of lower prices, $64 million of lower revenues from collections of NGC and a decrease of $14 million due to lower volumes of Non-Utility Generation energy sold.


Electric commodity revenues increased $30 million due primarily to $46 million in higher BGS sales volumes partially offset by $19 million in lower BGS prices and a $3 million increase from sales of solar renewable energy credits.
Gas commodity revenues increased $47decreased $10 million due primarily to $69lower BGSS prices of $49 million, ofpartially offset by higher BGSS sales prices, partially offset by $22 millionvolumes of lower sales volumes.$39 million.
Clause Revenues increased $41decreased $11 million due primarily to the 2016 return to customers of $50an $11 million of overcollections of STC, and higherdecrease in MAC revenues and lower SBC of $2 million in 2017,million. These decreases were partially offset by a $12$1 million decreaseincreases in collections of SBC.GPRC and Solar Pilot Recovery Charges (SPRC). The changes in the STC, MAC, SBC, GPRC and SBCSPRC amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC, MAC, SBC, GPRC or SBCSPRC collections.
Operating Expenses
Energy Costs decreased $219increased $20 million. This is entirely offset by the change in Commodity Revenue.Revenues.
Operation and Maintenance decreased $46increased $15 million, primarily due to increases of which the most significant components were decreases of $17$9 million in distribution corrective and preventative maintenance, $14storm costs, $8 million in transmission expenses, $7 million in appliance service costs $11and $7 million in clause-related costs and $11 million in GPRC costs,the gas distribution tariff. These increases were partially offset by a net $10 million net increasedecrease in certain operational expenses.clause and renewable related expenditures and a $4 million reduction in injuries and damages.
Depreciation and Amortization increased $94$40 million due primarily to a $39 million increase in depreciation related to additional plant in service and an increase of $4 million in amortization of Regulatory Assets partially offset by a $3 million increase in capitalized depreciation.
Non-Operating Pension and OPEB Credits (Costs) reflected an increase of$33 millionin creditsdue to the adoption of new accounting guidance effective January 1, 2018 which no longer allows capitalization of any portion of these benefit costs. See Item 1. Note 2. Recent Accounting Standards.
Interest Expense increased $19 million due primarily to an increase of $51$12 million in amortization of Regulatory Assets and a $43 million increase in depreciation due to additional plant in service.
Other Income and (Deductions) increased $9 million due primarily to an increase of $7 million in allowance for funds used during construction and a $3 million increase in realized gains on Rabbi Trust investments, partially offset by a net $1 million decrease in Solar Loan interest.
Interest Expense increased $9 million due primarily to an increase of $16 million duerelated to net debt issuances in 2016May 2018 and 2017 partially offset byand December 2017 and a $7 million decrease predominantly driven by a reduction in clause interest.increase related to clauses.
Income Tax Expense increased $57decreased $97 million due primarily to higher pre-taxthe decrease in the federal statutory income and changestax rate from 35% in 2017 to 21% in 2018, partially offset by uncertain tax positions.positions, plant-related and flow-through items.

Power
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2017 2016
 2017 vs. 2016 2017 2016 2017 vs. 2016 
  Millions Millions % Millions Millions % 
 Operating Revenues$873
 $1,075
 $(202) (19) $3,086
 $3,102
 $(16) (1) 
 Energy Costs357
 462
 (105) (23) 1,461
 1,481
 (20) (1) 
 Operation and Maintenance227
 289
 (62) (21) 711
 807
 (96) (12) 
 Depreciation and Amortization76
 86
 (10) (12) 1,191
 245
 946
 N/A
 
 Income from Equity Method Investments3
 3
 —
 —
 11
 9
 2
 22
 
 Other Income (Deductions)35
 17
 18
 N/A
 105
 41
 64
 N/A
 
 Other-Than-Temporary Impairments5
 5
 —
 —
 9
 25
 (16) (64) 
 Interest Expense12
 24
 (12) (50) 41
 66
 (25) (38) 
 Income Tax Expense (Benefit)98
 90
 8
 9
 (80) 208
 (288) N/A
 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2018 2017
 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$767
 $918
 $(151) (16) $2,170
 $2,187
 $(17) (1) 
 Energy Costs373
 386
 (13) (3) 1,119
 1,078
 41
 4
 
 Operation and Maintenance268
 256
 12
 5
 514
 488
 26
 5
 
 Depreciation and Amortization84
 465
 (381) (82) 166
 1,115
 (949) (85) 
 Income from Equity Method Investments5
 5
 —
 —
 7
 8
 (1) (13) 
 Net Gains (Losses) on Trust Investments8
 24
 (16) (67) (14) 43
 (57) N/A
 
 Other Income (Deductions)13
 12
 1
 8
 24
 23
 1
 4
 
 Non-Operating Pension and OPEB Credits (Costs)3
 2
 1
 50
 7
 4
 3
 75
 
 Interest Expense11
 13
 (2) (15) 18
 29
 (11) (38) 
 Income Tax Expense (Benefit)19
 (62) 81
 N/A
 102
 (178) 280
 N/A
 
                  
Three Months Ended SeptemberJune 30, 20172018 as Compared to 20162017
Operating Revenues decreased $202$151 million due to changes in generation and gas supply revenues.

Generation Revenues decreased $200$187 million due primarily to
a decrease of $110$123 million due to net MTM losses in 20172018 as compared to net MTM gains in 2016.2017. Of this amount, $98$133 million was due to changes in forward power prices, and $12partially offset by $10 million was due to greater gainslower losses on positions reclassified to realized upon settlement this year as compared to last year,
a net decrease of $83$75 million in energy sales due primarily to lower generation volumes and lower average realized prices in the PJM region, and
a decrease of $20 million in electricity sold under our BGS contracts due to lower volumesprices and lower prices, and
a decrease of $25 million in energy sales in the PJM region due to lower generation volumes, and lower average realized prices,

partially offset by a net increase of $18$28 million due primarily to higher capacity revenue andin electricity sold under other wholesale load contracts atin the PJM region due to higher average prices, coupled with new solar projects.volumes sold.
Gas Supply Revenues decreased $2increased $36 million due primarily to
an increase of $26 million related to sales to third parties due primarily to an increase in sales volumes, partially offset by lower MTM gainsaverage sales prices, and
an increase of $11 million in 2017 as comparedsales under the BGSS contract due primarily to 2016.an increase in sales volumes related to colder average temperatures in 2018, partially offset by lower 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 $105$13 million due to
Generation costs decreased $108$46 million due primarily to
a net decrease of $59$21 million due to charges associated with the early retirement of the Mercer and Hudson units announcednet MTM gains in October 2016, primarily related2018 as compared to a coal inventory write-down, partially offset by additional retirement costs incurrednet MTM losses in 2017,
a net decreaselower fuel costs of $26$12 million due primarily to lower natural gas costs reflecting lower volumes
a net decrease of $11 million primarily due to lower congestion costs in the PJM due to lower congestion rates coupled with less congestion volumes,region, and
a decrease of $8$9 million in energy purchases due primarily to MTM gainslower volumes on wholesale load contracts in 2017 as comparedthe New England (NE) region and lower cost to MTM lossesserve load in 2016.the PJM region.
Gas costs increased $3$33 million due mainly to a net
an increase of $2$23 million related to sales to third parties of which $5 million was due primarily to higheran increase in volumes sold, partially offset by lower average gas costs, and
an increase of $10 million related to sales under the BGSS contract due primarily to increased volumes sold due to colder average temperatures in 2018, partially offset by $3 million due to lower volumes sold.average gas costs.
Operation and Maintenance decreased $62increased $12 million due primarily to
a $51 million decrease higher planned outage costs at our fossil plants, due100%-owned Hope Creek nuclear plant in 2018 as compared to the retirement of the Hudson and Mercer units on June 1,planned outage costs incurred in 2017 and
a $10 million net decrease related tofor our 57%-owned Salem Unit 2 nuclear plants due primarily to lower labor-related costs.plant.
Depreciation and Amortization decreased $10381 million due primarily to
$19 million of lowerhigher depreciation in 2017 for Hudson and Mercer due to the early retirement of the Hudson and Mercerthose units,
partially offset by $4a $5 million of increased depreciationincrease in 2018 due to the accelerateda higher nuclear asset base primarily from increased capitalized asset retirement date at Bridgeport Harbor Station unit 3 (BH3),
$3 million of higher depreciation due to new solar projects, and
a $2 million increase due to additional nuclear plant placed into service.costs.
Other Income (Deductions)Net Gains (Losses) on Trust Investments increased $18decreased $16 million due primarily to higherthe inclusion in 2018 of net realized gainsunrealized losses on equity investments in the NDT Fund.
Interest Expense decreased $12 million due primarily to
a $7 million decrease due to higher interest capitalized for the construction of threeFund in accordance with new fossil stations: BH5, Sewaren 7 and Keys, and
a $5 million decrease due to debt maturities in September 2016.accounting guidance.
Income Tax Expense (Benefit) reflected anincreased tax expense of $8$81 million due primarily to changes in the manufacturing deduction and higher pre-tax income in 2018 as compared to a pre-tax loss in 2017. This increase in income tax expense was diminished by the decrease in the federal statutory income tax rate from 35% in 2017 to 21% in 2018.
Nine

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Six Months Ended SeptemberJune 30, 20172018 as Compared to 20162017
Operating Revenues decreased $1617 million due to changes in generation and gas supply revenues.
Generation Revenues decreased $101$47 million due primarily to
a net decrease of $115$87 million in energy sales in the PJM and New England regions due primarily to lower generation volumes and lower average realized prices in the PJM region partially offset by higher average prices in the NE and New York (NY) regions, and
a decrease of $91$29 million in electricity sold under our BGS contracts due primarily to lower volumes and lower prices,
partially offset by a net decreaseincrease of $11$36 million in operating reservesdue primarily to higher volumes of electricity sold under other wholesale load contracts in the PJM region, andpartially offset by lower volumes of electricity sold under wholesale load contracts in the NE region,
a chargean increase of $10$11 million due to an increasehigher net MTM gains in the FERC reserve accrual related to the PJM bidding matter see Item 1. Note 9. Commitments and Contingent Liabilities,

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partially offset by an increase of $86 million due to lower MTM losses in 20172018 as compared to 2016.2017. Of this amount, $110$132 million was due to lowerhigher gains on positions reclassified to realized upon settlement this year as compared to last year, partially offset bywith a $121 million decrease of $24 million due to changes in forward power prices.prices, and
a net increase of $31$8 million in capacity revenues due primarily to higher volumes of electricity sold under wholesale load contractsan increase in cleared capacity auction prices in the NE region, and
an increase of $10 million due to new solar projects.region.
Gas Supply Revenues increased $84$30 million due primarily to
an increase of $45$31 million in sales under the BGSS contract, of which $43 million was due primarily to higheran increase in sales volumes resulting from colder average temperatures during the 2018 heating season, partially offset by $12 million due to lower average sales prices, and
an increase of $25$15 million related to sales to third parties, of which $52$35 million was due to higheran increase in sales volumes, partially offset by $20 million due to lower average sales prices,
partially offset by $27 milliona decrease of lower volumes sold, and
a net increase of $14$16 million due to MTM gains in 2017 as compared tonet MTM losses in 2016.2018 compared to net gains in 2017.
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 $20increased $41 million due to
Generation costs decreased $76$3 million due primarily to
a net decrease of $57$24 million primarily due to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, partially offset by higher transmission charges due to higher rates,
a net decrease of $49 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to a coal inventory write-down partially offset by additional retirement costs incurred in 2016,
partially offset by higher fuel costs of $12 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas and oil,
a net increase of $10 million primarily due to an increase in energy purchase volumes in the NE region to serve load obligations, and
a decrease of $11 million due to net MTM gains in 2018 as compared to net losses in 2017. Of this amount, $14 million was due to changes in forward prices, partially offset by an increase of $9$3 million due to MTMhigher losses in 2017on positions reclassified to realized upon settlement this year as compared to MTM gainslast year,
partially offset by higher fuel costs of $31 million reflecting utilization of higher volumes of oil in 2016.the PJM region coupled with higher prices of natural gas in the NY region and higher coal costs in the PJM and NE regions. This was partially offset by utilization of lower gas volumes in the PJM region.
Gas costs increased $56$44 million due mainly to
an increase of $32$38 million related to sales under the BGSS contract due primarily to higherincreased volumes sold resulting from colder average temperatures during the 2018 heating season, partially offset with lower average gas costs, and
an increase of $24$6 million related to sales to third parties of which $48 million was due primarily to higher average gas costs,an increase in volumes sold, partially offset by a $24 million decrease in volumes sold.lower average gas costs.
Operation and Maintenance decreased $96increased $26 million due primarily to
a $71$21 million decreasenet increase due primarily to planned outage costs at our 100%-owned Hope Creek nuclear plant in 2018 as compared to planned outage costs incurred in 2017 for our 57%-owned Salem Unit 2, and
an $8 million net increase at our fossil plants, due primarily to the retirement of the Hudson and Mercer units and higher planned outage costs in 2016 as compared to 2017,
a $20 million net decrease related to our nuclear plants due primarily to lower labor-related costs and outage costs, and
an $8 million legal accrual for environmental expenses recorded in 2016,
partially offset by $3 million of costs related to new solar plants placed into service since September 2016.2018.
Depreciation and Amortization increaseddecreased $946949 million due primarily to
$914964 million of higher depreciation in 2017 for Hudson and Mercer due to the early retirement of the Hudson and Mercerthose units,
$11 million of increased depreciation due to the accelerated retirement date at BH3,
$9 million of higher depreciation due to new solar projects, and
a $9 million increase due to additional nuclear plant placed into service.
Other Income (Deductions) increased $64 million due primarily to $57 million of higher net realized gains in the NDT Fund and $3 million of higher net realized gains in the Rabbi Trust Fund.

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partially offset by a $10 million increase in 2018 due to a higher nuclear asset base primarily from increased capitalized asset retirement costs.
Other-Than-Temporary ImpairmentsNet Gains (Losses) on Trust Investments decreased $16$57 million due primarily to lower impairmentsthe inclusion in 2018 of $50 million of net unrealized losses on equity securitiesinvestments in the NDT Fund in 2017.accordance with new accounting guidance and an $8 million decrease in net realized gains on NDT Fund investments.
Interest Expense decreased $25$11 million due primarily to
a $16 million decrease due to higher interest capitalized for the construction of three new fossil stations:the BH5, Sewaren 7 and Keys and
a net $7 million decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.fossil stations.
Income Tax Expense (Benefit) decreased $288increased $280 million in 2017 due primarily to pre-tax income in 2018 as compared to a pre-tax loss in 2017. This increase in income tax expense was diminished by the decrease in the federal statutory income tax rate from 35% in 2017 as compared to pre-tax income21% in 2016.2018.

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 our operating cash flows combined with cash on hand and financing activities to be sufficient to fund capital expenditures and shareholder dividend payments.
For the ninesix months ended SeptemberJune 30, 20172018, our operating cash flow decreased $27122 million as compared to the same period in 2016.2017. The net change waschanges were primarily due primarily to tax refunds in 2017 at Energy Holdings combined with net changes from PSE&G and Powerour subsidiaries as discussed below as well as net tax payments at PSEG and its other subsidiaries.below.
PSE&G
PSE&G’s operating cash flow decreased $87 million from $1,401769 million to $1,393762 million for the ninesix months ended SeptemberJune 30, 20172018, as compared to the same period in 20162017, due primarily to a tax refund in 2017, partially offset by an increase of $87 million primarily due to a reduction in unbilled revenues resulting from lower tax refundsprices and a decreasevolumes in 2018, an increase of $49$66 million due to a change in regulatory deferrals, partially offset byand higher earnings.earnings in 2018.
Power
Power’s operating cash flow decreased $1163 million from $1,260932 million to $1,249869 million for the ninesix months ended SeptemberJune 30, 20172018, as compared to the same period in 2016,2017, due primarilyto lower earnings resulting from lower wholesale energy sales in the PJM region, an increase of $76 million in payments to counterparties and an increase in margin deposit requirements of $35 million, offset by tax refunds in 2018 compared to tax payments in 2017, as compared to tax refunds in 2016 and lower earnings, partially offset by a $68 million decrease in margin deposit requirements and a $30$48 million increase from net collectioncollections of counterparty receivables.
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.
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 SeptemberJune 30, 20172018 were as follows:
         
 Company/Facility As of September 30, 2017 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,500
 $215
 $1,285
 
 PSE&G 600
 15
 585
 
 Power 2,100
 182
 1,918
 
 Total $4,200
 $412
 $3,788
 
         
         
 Company/Facility As of June 30, 2018 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,500
 $88
 $1,412
 
 PSE&G 600
 211
 389
 
 Power 2,100
 202
 1,898
 
 Total $4,200
 $501
 $3,699
 
         

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As of SeptemberJune 30, 2017,2018, 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 from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s

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credit rating certain of Power’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 $899$828 million and $783$848 million as of SeptemberJune 30, 20172018 and December 31, 2016,2017, respectively.
For additional information, see Item 1. Note 10.11. Debt and Credit Facilities.
Long-Term Debt Financing
During the next twelve months, PSEG has a $700 million floating rate $500 million term loan maturing in November 2017.June 2019, PSE&G has $400 million of 5.30% Medium-Term Notes maturing in May 2018 and $350 million of 2.30% Medium-Term Notes maturing in September 2018 and $250 million of 1.80% Medium-Term Notes maturing in June 2019 and Power has $250 million of 2.45% Senior Notes maturing in November 2018.
For a discussion of our long-term debt issuances and maturities during 2017,additional information see Item 1. Note 10.11. Debt and Credit Facilities.
Common Stock Dividends
On July 18, 2017,April 17, 2018, our Board of Directors approved a $0.43$0.45 dividend per share of common stock for the second quarter of 2018. On July 17, 2018, our Board of Directors declared a $0.45 dividend per share of common stock for the third quarter of 2017. This reflects2018. These declarations reflect an indicative annual dividend rate of $1.72$1.80 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. Note16.Note17. 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’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
In April 2017, S&P published updated research and affirmed the ratings and outlooks of PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.
       
   Moody’s (A) S&P (B) 
 PSEG     
 Outlook Stable Stable 
 Senior Notes Baa1 BBB 
 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.


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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 as compared to amounts disclosed in our 20162017 Form 10-K.
PSE&G
During the ninesix months ended SeptemberJune 30, 2017,2018, PSE&G made capital expenditures of $2,118$1,458 million, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $72$84 million, which are included in operating cash flows.
In July 2017, PSE&G filed a petition with the BPU for a GSMP II program, requesting extension of our gas system modernization program through which PSE&G has proposed investing up to $540 million per year beginning in 2019 to continue to modernize our gas system. Under this proposed program, PSE&G plans to replace up to 1,250 miles of gas mains and associated service lines. This is not included in PSE&G’s projected capital expenditures.
Power
During the ninesix months ended SeptemberJune 30, 2017,2018, Power made capital expenditures of $779$521 million, excluding $12426 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.


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. 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 JulyApril through September 2017,June 2018, MTM VaR remainedwas relatively stable between a low of $5$7 million and a high of $9 million at the 95% confidence level. The range of VaR was narrower for the three months ended SeptemberJune 30, 20172018 as compared with the year ended December 31, 2016.2017.

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   MTM VaR 
   Three Months Ended September 30, 2017 Year Ended December 31, 2016 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $8
 $26
 
 Average for the Period $7
 $16
 
 High $9
 $32
 
 Low $5
 $10
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $13
 $40
 
 Average for the Period $11
 $25
 
 High $15
 $51
 
 Low $8
 $16
 
       
       
   MTM VaR 
   Three Months Ended June 30, 2018 Year Ended December 31, 2017 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $8
 $39
 
 Average for the Period $8
 $10
 
 High $9
 $39
 
 Low $7
 $5
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $13
 $60
 
 Average for the Period $12
 $15
 
 High $15
 $60
 
 Low $10
 $8
 
       
See Item 1. Note 11.12. Financial Risk Management Activities for a discussion of credit risk.

ITEM 4.CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSEG, PSE&G and Power
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 PSEG, PSE&G and Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG, PSE&G and Power 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
PSEG, PSE&G and Power
There have been no changes in internal control over financial reporting that occurred during the thirdsecond quarter of 20172018 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 environmental and regulatory matters, including 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 20162017 Annual Report on Form 10-K, see Part I, Item 1. Note 9.10. Commitments and Contingent Liabilities and Item 5. Other Information.

ITEM 1A.RISK FACTORS
The discussion of our business and operations in this Quarterly Report on Form 10-Q should be read together with the risk factors contained in Part I, Item 1A of our 20162017 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017,2018, which describe various risks and uncertainties that could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report. Except as discussed below, thereThere have been no material changes to the risk factors set forth in the above-referenced filings as of SeptemberJune 30, 2017.2018.

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Cybersecurity attacks or intrusions could adversely impact our businesses.
Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency. We rely on information technology systems that utilize sophisticated digital systems and network infrastructure to operate our generation, transmission and distribution systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and Independent System Operators (ISOs), among others. Our and third-party information technology systems may be vulnerable to cybersecurity attacks involving domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:
disruption of the operation of our assets and the power grid,
theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations, 
general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and
breaches of vendors’ infrastructures where our confidential information is stored.
We have experienced and expect to continue to experience actual or attempted cyber-attacks on our information technology systems; however, none of these incidents has had a material impact on our operations or financial condition. If a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, reputational damage and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Part 1, Item 1. Regulatory Issues in our Annual Report on Form 10-K for the year ended December 31, 2016 and Item 5. Other Information in this Quarterly Report on Form 10-Q.
The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events may evolve as the industry matures. While we maintain insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damage we experience.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table indicates ourIn December 2017, we entered into a share repurchase plan that complies with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended, solely with respect to the repurchase of shares to satisfy obligations under equity compensation awards that are expected to vest or be exercised in 2018 and under PSEG’s Employee Stock Purchase Plan for expected employee purchases in 2018. There were no common share repurchases in the open market to satisfy obligations under various equity compensation awards during the thirdsecond quarter of 20172018.
      
 Three Months Ended September 30, 2017
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 July 1 - July 31—
 $—
 
 August 1 - August 31135,277
 $45.25
 
 September 1- September 30—
 $—
 
      


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ITEM 5. OTHER INFORMATION
Certain information reported in the 20162017 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 20162017 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quartersquarter ended March 31, 2017 and June 30, 2017.2018. References are to the related pages on the FormsForm 10-K and 10-Q as printed and distributed.
Employee RelationsFederal Regulation
Energy Clearing Prices
December 31, 2016 Form 10-K page 15. In 2016, six of our eight labor unions ratified extensions of their collective bargaining agreements with us, with expiration dates from 2019 to 2021. In 2017 each of the remaining two unions ratified extensions of their collective bargaining agreements with us with expiration dates in 2021 and 2022.
Federal Regulation
FERC
Energy Clearing Prices/Price Formation Initiatives
December 31, 2016 Form 10-K page 16 and March 31, 20172018 Form 10-Q on page 76.80. Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load) which can vary by location. In addition, recent rule changes in the energy markets administered by PJM and ISO-NE (see Capacity Market Issues below) impose rigorous performance obligations and nonperformance penalties on resources during times of system stress. These FERC rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance hour.
FERC has also recently ordered certain favorable changes to energy market price formation rules improving shortage pricing and enhancing bidding flexibility for units. We continue to advocate in this context for additional changes in market rules that would provide more transparency aboutregarding operator actions affecting energy market prices. We cannot predict what action FERC might ultimately take, but such an examination could leadprices and would promote better alignment between generation dispatch decisions and energy market price outcomes. The PJM Board has directed PJM staff to future rule changes.
In June 2017, PJM issued an energywork with stakeholders to implement a series of price formation proposalreforms, including a 30-minute reserve product in real-time, more dynamic reserve requirements to address a flawbetter capture operator actions taken to maintain reliability and improvement of the curves used to price reserves during reserve shortage conditions. The PJM Board letter directs PJM staff to submit some of these reforms for FERC’s approval so that they can be implemented in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price.early 2019. If placed into effect, this proposal willthese reforms should improve price formationenergy and reserve prices by ensuring that when operators commit resources to ensure reliability, the marginal costs of units serving load will be bettercommitments are reflected in market clearing prices. We cannot predict the outcome of this matter.
Notice of Proposed Rulemaking on Baseload Generation
In September 2017, the Secretary of the U.S. Department of Energy issued a Notice of Proposed Rulemaking (NOPR) to allow a full recovery of costs for certain eligible units physically located within the FERC-approved organized markets. The NOPR directs FERC to take final action within 60 days. The NOPR contemplates a cost-of-service payment and a fair rate of return for units that are able to provide certain essential energy and ancillary reliability services, have a 90-day fuel supply on site and are not subject to cost-of-service rate regulation by any State or local authority. We are participating in this proceeding, but we are unable to predict the outcome.
Capacity Market Issues—PJM
December 31, 20162017 Form 10-K page 16 and March 31, 20172018 Form 10-Q on page 7680. In April, 2018, PJM submitted two proposed alternative and June 30, 2017 Form 10-Q on page 83. PJM, the New York Independent System Operator (NYISO)mutually exclusive capacity market reforms for FERC’s approval. One option would be to implement a two-tier clearing mechanism that accommodates states’ subsidies and the Independent System Operator New England, Inc. each have capacity marketsother option would be to extend the existing MOPR to units that have been approved by FERC.are receiving subsidies. In June 2018, FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policiesissued an order finding that support particular resources or resource attributes, whether generators are being sufficiently compensated in thePJM’s current capacity market is unjust and whether subsidizedunreasonable because it allows resources maysupported by out-of-market payments to suppress capacity prices. FERC established a new proceeding to address an alternative approach in which PJM would: (1) modify PJM’s MOPR so that it would apply to new and existing resources that receive out-of-market payments, regardless of resource type; and (2) establish an option that would allow, on a resource-specific basis, resources receiving out-of-market support to be removed from the PJM capacity market, along with a commensurate amount of load, for some period of time. FERC’s potential action in this proceeding could cause nuclear units that receive ZEC payments to lose capacity market revenues if states do not take steps to address the potential loss of capacity revenues. In addition, depending on the outcome of this matter, our fossil generating stations could be adversely affecting capacity market prices. FERC held a technical conference to seek input from the industry on potential options to integrate public policy goals in wholesale markets.impacted. We cannot predict what action, if any, FERC might take with regard to capacity market designs.
Capacity Market Issues—PJM
December 31, 2016 Form 10-K page 16, March 31, 2017 Form 10-Q on page 76 and June 30, 2017 Form 10-Q page 83. PJM issued a seriesthe outcome of white papers in response to public policies that seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes. The three proposals are intended to spur stakeholder discussion and include both potential capacity and energy market reforms. The first energy market reform (see Energy Clearing Prices/Price Formation Initiatives) would allow inflexible generating units to set prices resulting in reduced uplift payments and improved

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price signals while the second energy market reform contemplates a voluntary carbon pricing program where states that elect to participate in the program would agree to put a price on carbon emissions. The capacity market proposal contemplates a two-stage capacity auction which, in its current form, would improve prices for unsubsidized resources, but would still continue to provide capacity payments for subsidized resources.
Transmission Regulation
December 31, 2016 Form 10-K page 18. In October 2017, PSE&G filed its 2018 Annual Formula Rate Update with FERC which requests approximately $212 million in increased annual transmission revenues effective January 1, 2018, subject to true-up. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. For additional information about our transmission formula rate, see Part I Item 1. Note 5. Rate Filings.this matter.
Transmission Regulation—Transmission Policy Developments
December 31, 20162017 Form 10-K page 18, March 31, 2017 Form 10-Q on page 77 and19. In June 30, 2017 Form 10-Q on page 83.
2016, a proposed settlement was filed with FERC for a matter remanded from the federal appellate court concerning the appropriate cost allocation for certain 500 kV projects in PJM that either have been built or are in the process of being built. In May 2018, FERC approved the settlement which will result in increased annual cost allocations to customers in the PSE&G transmission zone. Under this settlement, Power, as a February 2016 order, FERC reversed a previous order and accepted a filingBGS supplier will become obligated to pay amounts previously paid by theother PJM transmission owners seeking authority to assign costs for Regional Transmission Expansion Plan projects (subject to PJM Board approval requirements) solely addressing localized needs to customers withincustomers. However, we do not believe that the local transmission owner’s zone. FERC’s action in this order provides an exemption from the Order 1000 open window procedures for projects constructed by transmission owners to meet local transmission planning criteria. FERC’s orders have been challenged at the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) and PSE&G has intervened in support of FERC.
In April 2017, the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission project and approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. In October 2017, FERC accepted PJM’s filing on the grounds that PJM correctly applied its Tariff. However, FERC deferred a ruling on whether the cost allocation methodology applied to the Artificial Island project is appropriate. FERC will decide this issue in a separate proceeding that is currently pending. We are unable to predict the outcome.
Nuclear Regulatory Commission (NRC)
December 31, 2016 Form 10-K page 20. 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 also subject to cybersecurity regulations promulgated by the NRC.
We are unable to predict the final outcome of these reviews or 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
Cybersecurity Requirements for Regulated Entities
December 31, 2016 Form 10-K page 21. In March 2016, the BPU issued an order for the regulated electric, natural gas and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The order requires these regulated utilities, including PSE&G, to, among other conditions, implement a cybersecurity program that defines and implements organization accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. New Jersey utilities, including PSE&G, were required to be compliant with these requirements by October 1, 2017. We have submitted the required certification of compliance to the BPU. 
In an effort to reduce the likelihood and severity of cyber incidents, we have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our company and our customers’ information and our systems. In addition, we are subject to maintaining key cybersecurity controls to meet mandatory cybersecurity regulatory requirements. Our cybersecurity program is built on technical, procedural, and people-focused measures to detect, protect against, respond to, and recover from cyber threats to our systems and information including company, employee and customer data. Features of our program include: identifying critical information and systems; conducting cyber risk assessments of our and third party systems; maintaining awareness of cyber threats and vulnerabilities through partnerships with public and private entities, as well as industry groups; maintaining and testing our cybersecurity incident response plans and systems; training personnel on cybersecurity issues; and raising cybersecurity awareness throughout our company with electronic notices and seminars. We cannot assure that our cybersecurity program will be effective in preventing or mitigating cybersecurity incidents. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

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Energy Efficiency 2017 Program (EE 2017)
In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.
Consolidated Tax Adjustments (CTA)
December 31, 2016 Form 10-K page 21. New Jersey is one of only a few states that make CTA in setting rates for regulated utilities. These adjustments to rate base are madeduring the rate setting process andare intended to allocate to utility customers a portion of the tax benefits realized from the filing of a consolidated federal tax return by the utility’s parent corporation. The BPU has been considering the appropriateness of the adjustment and the methodology and mechanics of the calculation for some time. In October 2014, the BPU approved a proposal by its Staff that limits the tax benefit period to be considered in the calculation to five years, sets the distribution rate base adjustment at 25%anticipated level of any such tax benefit and eliminates from the process any tax benefits tied to transmission earnings. In accordance with this October action, this CTA policy will be applied only with respect to future distribution rate base cases. In November 2014, the New Jersey Division of Rate Counsel appealed the BPU’s decision and in September 2017, the New Jersey Superior Court, Appellate Division granted that appeal on procedural grounds. While the issue has now been remanded to the BPU, it is not expected that application of a CTA willpotential payments would have a material impacteffect on PSE&G’s current earnings orPower’s financial statements. We believe that there is a mechanism in its upcoming rate case filing.
Environmental Matters
Air Pollution Control
Hazardous Air Pollutants Regulation
December 31, 2016 Form 10-K page 22. In June 2015,place under the U.S. Supreme Court held that it was unreasonableBGS contract for the EPA to refuse to consider the materialitypass-through of costsincreases in determining whether to regulate hazardous air pollutants from power plants. In April 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. Circuit challenging the EPA’s Supplemental Finding. The D.C. Circuit is holding the case in abeyance pending further directions from the EPA. We do not expect this Supplemental Finding to impact operation of our facilities.transmission charges.
Climate Change
COTransmission Regulation2 —Regulation under the Clean Air Act (CAA)Con Edison-PJM Wheel
December 31, 20162017 Form 10-K page 23.19. In MarchEffective May 1, 2017, the Presidenta wheeling arrangement which enabled Con Edison to move 1,000 MW of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO2 for certain new fossil power plants and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the CAA for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In April 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance for at least 60 days while the agency reviews the rule, which was subsequently extended by the D.C. Circuit in August 2017. In October 2017, upon completion of the review, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). Whether the EPA chooses to propose a replacement rule has not been decided. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.
Regional Greenhouse Gas Initiative (RGGI)
December 31, 2016 Form 10-K page 23. In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO2 emission reductions in the electric power industry. New Jersey withdrew from RGGI in 2012. However, certain northeastern states (RGGI States), includingsoutheastern New York and Connecticut where weacross the PSE&G system for delivery into New York City expired. Amounts that would have generation facilities, havestate-specific rules in placebeen recovered from Con Edison had this arrangement continued are now being recovered from other customers. PSE&G believes the current planning assumptions used by PJM are consistent with sound transmission planning principles. However, PSE&G disagrees with the absence of a mechanism to enable the RGGI regulatory mandate in each stateassign PJM transmission upgrade costs to cap and reduce CO2 emissions. These rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO2 emissions. Generators are required to submit an allowance for each ton emitted over a three-year period. Allowances are available through the auction or through secondary markets.Con

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Edison that reflect Con Edison’s reliance on the PJM transmission grid. PSE&G and the BPU jointly filed a rehearing application at FERC seeking reversal of a determination not to create such a mechanism in connection with a PJM/NYISO joint operating agreement. In Septemberaddition, in December 2017, the RGGI States announcedBPU filed a complaint at FERC against Con Edison, PJM, NYISO, New York Power Authority, Linden VFT, LLC and Hudson Transmission Partners, LLC petitioning FERC to create such a cost allocation mechanism that would assign PJM costs to New York, which complaint was denied. The BPU has sought rehearing of FERC’s denial of its complaint. We cannot predict the outcome of this matter.
State Regulation
Energy Efficiency Initiatives
In May 2018, the New Jersey governor signed legislation that requires the state’s electric and gas utilities to implement energy efficiency programs that are expected to achieve energy savings targets for electric and gas usage within five years of the utility’s implementation of its BPU-approved energy efficiency programs. To meet these savings targets, energy usage reductions and peak demand reductions that result from utility and non-utility based programs and investments (including building code changes) will be counted. The specific energy savings target for each public electric and gas utility will be determined from an energy efficiency study to be completed within a year from enactment of the legislation. The legislation requires utilities to make annualfilings with the BPU outlining their new post-2020 programplanned investments and proposed programs for a capcost-effectively achieving the targeted energy savings. These filings are also expected to address the utility’s return of and on regional COthose investments and recovery of lost revenues associated with the lower sales. The BPU is required to adopt rules to implement the legislation within one year of enactment.2 emissions, which would require a decline
New Jersey Energy Master Plan (EMP)
New Jersey law requires that an EMP be developed every three years. While not having the force of law, the EMP provides an overview of energy policy in CO2 emissionsNew Jersey. The EMP was last revised in 2021December 2015.
In May 2018,the New Jersey governor signed an executive order requiring the BPU and each year thereafter, resulting in a 30% reduction in the CO2 emissions cap by 2030.
Water Pollution Control
Steam Electric Effluent Guidelines
December 31, 2016 Form 10-K page 23, March 31, 2017 Form 10-Q on page 77 and June 30, 2017 Form 10-Q on page 85. In September 2015, the EPA issuedother New Jersey executive branch agencies to prepare a new Effluent Limitation Guidelines Rule (ELG Rule) for steamEMP by June 1, 2019. The new EMP will, among other issues: focus on New Jersey converting to 100% clean energy sources by January 1, 2050; incorporate New Jersey’s offshore wind development goals; include provisions to guide the continued development of solar energy, including community solar; make recommendations to bolster energy storage in New Jersey; and explore methods to incentivize the use of clean, efficient energy and 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 desulfurizationalternatives in New Jersey’s transportation sector and flue gas mercury control wastewater,at its ports.
With regard to offshore wind, the executive order directed the BPU and gasification wastewater. The EPA provides an implementation period for currently existing dischargesother state agencies to begin a process to achieve 3,500 MWs 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 Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulatedoffshore wind energy generation by the rule.year 2030. In response, the BPU issued an order directing staff to establish a rulemaking for an offshore wind renewable energy certificate (OREC) funding mechanism and rules for the solicitation of 1,100 MWs of offshore wind capacity. We are analyzing the implications to our business.
BPU 2018 Storm Investigation
In April 2017,July 2018, the EPA announcedBPU accepted the findings of an investigative report concerning a series of storms that hit New Jersey in March 2018 causing wide-spread infrastructure damage and power outages. The BPU implemented certain recommendations  that it had granted a petitiondeemed essential to facilitate the continued provision of safe, proper and adequate service, to help mitigate future outages, and to help develop more effective responses and coordination of resources. These requirements supplement prior requirements set forth post-Hurricanes Irene and Superstorm Sandy. PSE&G is reviewing the BPU’s report and its recommendations for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations for the aforementioned waste streams. In September 2017, the EPA issued a rule postponing for two years compliance dates related solely to bottom ash transport water and flue gas desulfurization wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and compliance dates for these two waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.improving storm response protocols.
Cooling Water Intake Structure
December 31, 2016 Form 10-K page 24. In May 2014, the EPA issued a final cooling water intake rule under Section 316(b) of the Clean Water Act (CWA) that establishes new requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision remains pending.

ITEM 6.EXHIBITS
A listing of exhibits being filed with this document is as follows:
a. PSEG:  
Exhibit 10
Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017
Exhibit 12: 
Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
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 10
Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017
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 10
Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017
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




SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)
  
By:
/S/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: October 31, 2017August 1, 2018

SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)
  
By:
/S/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: October 31, 2017August 1, 2018


SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PSEG POWER LLC
(Registrant)
  
By:
/S/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: October 31, 2017August 1, 2018


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