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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 March 31, 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 April 18, 2017,17, 2018, Public Service Enterprise Group Incorporated had outstanding 505,878,825505,217,435 shares of its sole class of Common Stock, without par value.
As of April 18, 2017,17, 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 2. Recent Accounting Standards
17
Note 3. Early Plant RetirementsRevenues
19
 Note 4. Variable Interest Entity (VIE)
20
Note 5. Rate Filings
21
Note 6. Financing Receivables
21
Note 7. Available-for-Sale SecuritiesEarly Plant Retirements
23
 Note 5. Variable Interest Entity (VIE)
25
Note 6. Rate Filings
26
Note 7. Financing Receivables
26
Note 8. Pension and Other Postretirement Benefits (OPEB)Trust Investments
29
 Note 9. CommitmentsPension and Contingent LiabilitiesOther Postretirement Benefits (OPEB)
3035
 Note 10. DebtCommitments and Credit FacilitiesContingent Liabilities
3836
 Note 11. Financial Risk Management ActivitiesDebt and Credit Facilities
3942
 Note 12. Fair Value MeasurementsFinancial Risk Management Activities
4443
 Note 13. Other Income and DeductionsFair Value Measurements
5147
 Note 14. Other Income Taxes(Deductions)
5254
 Note 15. Income Taxes
54
Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax
5356
 Note 16.17. Earnings Per Share (EPS) and Dividends
56
Note 17. Financial Information by Business Segments
5759
 Note 18. Related-Party TransactionsFinancial Information by Business Segment
5760
 Note 19. Related-Party Transactions
61
Note 20. Guarantees of Debt
5962
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
6164
 Executive Overview of 20172018 and Future Outlook
6164
 
Results of Operations
6772
 
Liquidity and Capital Resources
7175
 
Capital Requirements
7377
 
Accounting Matters
7377
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
7377
Item 4.
Controls and Procedures
7479
  
PART II. OTHER INFORMATION 
Item 1.
Legal Proceedings
7479
Item 1A.
Risk Factors
7479
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
7679
Item 5.
Other Information
7680
Item 6.
Exhibits
7981
 
Signatures
8082


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

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any inability to recover the carrying amount of 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 
   March 31, 
   2017 2016 
 OPERATING REVENUES $2,592
 $2,616
 
 OPERATING EXPENSES     
 Energy Costs 874
 836
 
 Operation and Maintenance 712
 729
 
 Depreciation and Amortization 828
 224
 
 Total Operating Expenses 2,414
 1,789
 
 OPERATING INCOME 178
 827
 
 Income from Equity Method Investments 3
 2
 
 Other Income 72
 48
 
 Other Deductions (11) (21) 
 Other-Than-Temporary Impairments (1) (10) 
 Interest Expense (98) (92) 
 INCOME BEFORE INCOME TAXES 143
 754
 
 Income Tax Expense (29) (283) 
 NET INCOME $114
 $471
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:     
 BASIC 505
 505
 
 DILUTED 508
 508
 
 NET INCOME PER SHARE:     
 BASIC $0.23
 $0.93
 
 DILUTED $0.22
 $0.93
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK $0.43
 $0.41
 
       
       
   Three Months Ended 
   March 31, 
   2018 2017 
 OPERATING REVENUES $2,818
 $2,591
 
 OPERATING EXPENSES     
 Energy Costs 952
 868
 
 Operation and Maintenance 754
 717
 
 Depreciation and Amortization 280
 828
 
 Total Operating Expenses 1,986
 2,413
 
 OPERATING INCOME 832
 178
 
 Income from Equity Method Investments 2
 3
 
 Net Gains (Losses) on Trust Investments (22) 28
 
 Other Income (Deductions) 32
 32
 
 Non-Operating Pension and OPEB Credits (Costs) 19
 —
 
 Interest Expense (103) (98) 
 INCOME BEFORE INCOME TAXES 760
 143
 
 Income Tax Expense (202) (29) 
 NET INCOME $558
 $114
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:     
 BASIC 504
 505
 
 DILUTED 507
 508
 
 NET INCOME PER SHARE:     
 BASIC $1.11
 $0.23
 
 DILUTED $1.10
 $0.22
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK $0.45
 $0.43
 
       
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 
   March 31, 
   2017 2016 
 NET INCOME $114
 $471
 
 Other Comprehensive Income (Loss), net of tax     
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(16) and $(16) for 2017 and 2016, respectively 15
 16
 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0 and $(1) for 2017 and 2016, respectively —
 2
 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(4) and $(6) for 2017 and 2016, respectively 6
 8
 
 Other Comprehensive Income (Loss), net of tax 21
 26
 
 COMPREHENSIVE INCOME $135
 $497
 
       
       
   Three Months Ended 
   March 31, 
   2018 2017 
 NET INCOME $558
 $114
 
 Other Comprehensive Income (Loss), net of tax     
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $9 and $(16) for 2018 and 2017, respectively (14) 15
 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(3) and $(4) for 2018 and 2017, respectively 8
 6
 
 Other Comprehensive Income (Loss), net of tax (6) 21
 
 COMPREHENSIVE INCOME $552
 $135
 
       
See Notes to Condensed Consolidated Financial Statements.


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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  March 31,
2017		 December 31,
2016		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$193
 $423
 
 Accounts Receivable, net of allowances of $67 in 2017 and $68 in 20161,212
 1,161
 
 Tax Receivable9
 78
 
 Unbilled Revenues209
 260
 
 Fuel173
 326
 
 Materials and Supplies, net566
 561
 
 Prepayments56
 76
 
 Derivative Contracts114
 163
 
 Regulatory Assets176
 199
 
 Other8
 7
 
 Total Current Assets2,716
 3,254
 
 PROPERTY, PLANT AND EQUIPMENT40,195
 39,337
 
      Less: Accumulated Depreciation and Amortization(10,850) (10,051) 
 Net Property, Plant and Equipment29,345
 29,286
 
 NONCURRENT ASSETS    
 Regulatory Assets3,287
 3,319
 
 Long-Term Investments1,001
 1,050
 
 Nuclear Decommissioning Trust (NDT) Fund1,913
 1,859
 
 Long-Term Tax Receivable113
 104
 
 Long-Term Receivable of Variable Interest Entity (VIE)595
 589
 
 Other Special Funds221
 217
 
 Goodwill16
 16
 
 Other Intangibles106
 98
 
 Derivative Contracts93
 24
 
 Other258
 254
 
 Total Noncurrent Assets7,603
 7,530
 
 TOTAL ASSETS$39,664
 $40,070
 
      
      
  March 31,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$118
 $313
 
 Accounts Receivable, net of allowances of $62 in 2018 and $59 in 20171,320
 1,348
 
 Tax Receivable121
 127
 
 Unbilled Revenues196
 296
 
 Fuel162
 289
 
 Materials and Supplies, net574
 577
 
 Prepayments114
 118
 
 Derivative Contracts43
 29
 
 Regulatory Assets139
 211
 
 Other19
 4
 
 Total Current Assets2,806
 3,312
 
 PROPERTY, PLANT AND EQUIPMENT42,033
 41,231
 
      Less: Accumulated Depreciation and Amortization(9,628) (9,434) 
 Net Property, Plant and Equipment32,405
 31,797
 
 NONCURRENT ASSETS    
 Regulatory Assets3,208
 3,222
 
 Long-Term Investments938
 932
 
 Nuclear Decommissioning Trust (NDT) Fund2,051
 2,133
 
 Long-Term Receivable of Variable Interest Entity (VIE)690
 686
 
 Rabbi Trust Fund225
 231
 
 Goodwill16
 16
 
 Other Intangibles131
 114
 
 Derivative Contracts48
 7
 
 Other272
 266
 
 Total Noncurrent Assets7,579
 7,607
 
 TOTAL ASSETS$42,790
 $42,716
 
      
See Notes to Condensed Consolidated Financial Statements.


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

 
      
  March 31,
2017		 December 31,
2016		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$500
 $500
 
 Commercial Paper and Loans315
 388
 
 Accounts Payable1,245
 1,459
 
 Derivative Contracts7
 13
 
 Accrued Interest131
 97
 
 Accrued Taxes172
 31
 
 Clean Energy Program86
 142
 
 Obligation to Return Cash Collateral135
 132
 
 Regulatory Liabilities74
 88
 
 Other446
 426
 
 Total Current Liabilities3,111
 3,276
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)8,567
 8,658
 
 Regulatory Liabilities131
 118
 
 Asset Retirement Obligations738
 726
 
 OPEB Costs1,309
 1,324
 
 OPEB Costs of Servco460
 452
 
 Accrued Pension Costs547
 568
 
 Accrued Pension Costs of Servco126
 128
 
 Environmental Costs393
 401
 
 Derivative Contracts1
 3
 
 Long-Term Accrued Taxes180
 180
 
 Other198
 211
 
 Total Noncurrent Liabilities12,650
 12,769
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 CAPITALIZATION
   
 LONG-TERM DEBT10,898
 10,895
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016—534 shares4,920
 4,936
 
 Treasury Stock, at cost, 2017 and 2016—29 shares(743) (717) 
 Retained Earnings9,070
 9,174
 
 Accumulated Other Comprehensive Loss(242) (263) 
 Total Stockholders’ Equity13,005
 13,130
 
 Total Capitalization23,903
 24,025
 
 TOTAL LIABILITIES AND CAPITALIZATION$39,664
 $40,070
 
  

   
      
  March 31,
2018		 December 31,
2017		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$1,000
 $1,000
 
 Commercial Paper and Loans594
 542
 
 Accounts Payable1,295
 1,694
 
 Derivative Contracts10
 16
 
 Accrued Interest147
 103
 
 Accrued Taxes173
 48
 
 Clean Energy Program85
 128
 
 Obligation to Return Cash Collateral136
 129
 
 Regulatory Liabilities34
 47
 
 Other474
 461
 
 Total Current Liabilities3,948
 4,168
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)5,329
 5,240
 
 Regulatory Liabilities2,942
 2,948
 
 Asset Retirement Obligations1,037
 1,024
 
 OPEB Costs1,432
 1,455
 
 OPEB Costs of Servco550
 542
 
 Accrued Pension Costs508
 537
 
 Accrued Pension Costs of Servco126
 129
 
 Environmental Costs342
 357
 
 Derivative Contracts2
 5
 
 Long-Term Accrued Taxes176
 175
 
 Other222
 221
 
 Total Noncurrent Liabilities12,666
 12,633
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 CAPITALIZATION
   
 LONG-TERM DEBT12,072
 12,068
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000 shares; issued, 2018 and 2017—534 shares4,946
 4,961
 
 Treasury Stock, at cost, 2018—30 shares; 2017—29 shares(816) (763) 
 Retained Earnings10,385
 9,878
 
 Accumulated Other Comprehensive Loss(411) (229) 
 Total Stockholders’ Equity14,104
 13,847
 
 Total Capitalization26,176
 25,915
 
 TOTAL LIABILITIES AND CAPITALIZATION$42,790
 $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)
      
  Three Months Ended 
  March 31, 
  2017 2016 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$114
 $471
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization828
 224
 
 Amortization of Nuclear Fuel54
 58
 
 Renewable Energy Credit (REC) Compliance Accrual26
 27
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC(85) 182
 
 Non-Cash Employee Benefit Plan Costs23
 32
 
 Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes(15) (15) 
 Net (Gain) Loss on Lease Investments32
 —
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(5) (21) 
 Net Change in Regulatory Assets and Liabilities(60) (105) 
 Cost of Removal(24) (35) 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(23) 3
 
 Net Change in Certain Current Assets and Liabilities:    
           Tax Receivable69
 301
 
           Accrued Taxes143
 144
 
           Margin Deposit(4) (4) 
           Other Current Assets and Liabilities163
 27
 
 Employee Benefit Plan Funding and Related Payments(28) (56) 
 Other(12) (19) 
 Net Cash Provided By (Used In) Operating Activities1,196
 1,214
 
 CASH FLOWS FROM INVESTING ACTIVITIES

   
 Additions to Property, Plant and Equipment(1,062) (1,065) 
 Purchase of Emissions Allowances and RECs(15) (16) 
 Proceeds from Sales of Available-for-Sale Securities298
 202
 
 Investments in Available-for-Sale Securities(307) (207) 
 Other7
 5
 
 Net Cash Provided By (Used In) Investing Activities(1,079) (1,081) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans(73) (352) 
 Issuance of Long-Term Debt—
 850
 
 Redemption of Long-Term Debt—
 (171) 
 Cash Dividends Paid on Common Stock(218) (207) 
 Other(56) (55) 
 Net Cash Provided By (Used In) Financing Activities(347) 65
 
 Net Increase (Decrease) in Cash and Cash Equivalents(230) 198
 
 Cash and Cash Equivalents at Beginning of Period423
 394
 
 Cash and Cash Equivalents at End of Period$193
 $592
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(80) $(299) 
 Interest Paid, Net of Amounts Capitalized$77
 $66
 
 Accrued Property, Plant and Equipment Expenditures$492
 $434
 
      
      
  Three Months Ended 
  March 31, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$558
 $114
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization280
 828
 
 Amortization of Nuclear Fuel50
 54
 
 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual

24
 26
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC76
 (85) 
 Non-Cash Employee Benefit Plan Costs17
 23
 
 Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes4
 (15) 
 Net (Gain) Loss on Lease Investments—
 32
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(119) (5) 
 Net Change in Regulatory Assets and Liabilities(6) (60) 
 Cost of Removal(38) (24) 
 Net (Gains) Losses and (Income) Expense from NDT Fund12
 (23) 
 Net Change in Certain Current Assets and Liabilities:    
           Tax Receivable6
 69
 
           Accrued Taxes125
 143
 
           Margin Deposit25
 (4) 
           Other Current Assets and Liabilities160
 163
 
 Employee Benefit Plan Funding and Related Payments(36) (28) 
 Other2
 (11) 
 Net Cash Provided By (Used In) Operating Activities1,140
 1,197
 
 CASH FLOWS FROM INVESTING ACTIVITIES

   
 Additions to Property, Plant and Equipment(1,053) (1,062) 
 Purchase of Emissions Allowances and RECs(17) (15) 
 Proceeds from Sales of Trust Investments397
 298
 
 Purchases of Trust Investments(407) (307) 
 Other7
 7
 
 Net Cash Provided By (Used In) Investing Activities(1,073) (1,079) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans52
 (73) 
 Cash Dividends Paid on Common Stock(227) (218) 
 Other(73) (56) 
 Net Cash Provided By (Used In) Financing Activities(248) (347) 
 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash(181) (229) 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period315
 426
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$134
 $197
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(4) $(80) 
 Interest Paid, Net of Amounts Capitalized$73
 $77
 
 Accrued Property, Plant and Equipment Expenditures$544
 $492
 
      

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 
  March 31, 
  2017 2016 
 OPERATING REVENUES$1,812
 $1,712
 
 OPERATING EXPENSES    
 Energy Costs753
 729
 
 Operation and Maintenance367
 382
 
 Depreciation and Amortization171
 139
 
 Total Operating Expenses1,291
 1,250
 
 OPERATING INCOME521
 462
 
 Other Income25
 20
 
 Other Deductions(1) (1) 
 Interest Expense(75) (68) 
 INCOME BEFORE INCOME TAXES470
 413
 
 Income Tax Expense(171) (151) 
 NET INCOME$299
 $262
 
      
       
   Three Months Ended 
   March 31, 
   2018 2017 
 OPERATING REVENUES $1,845
 $1,826
 
 OPERATING EXPENSES     
 Energy Costs 782
 762
 
 Operation and Maintenance 391
 370
 
 Depreciation and Amortization 190
 171
 
 Total Operating Expenses 1,363
 1,303
 
 OPERATING INCOME 482
 523
 
 Net Gains (Losses) on Trust Investments —
 2
 
 Other Income (Deductions) 20
 22
 
 Non-Operating Pension and OPEB Credits (Costs) 15
 (2) 
 Interest Expense (81) (75) 
 INCOME BEFORE INCOME TAXES 436
 470
 
 Income Tax Expense (117) (171) 
 NET INCOME $319
 $299
 
       
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 
  March 31, 
  2017 2016 
 NET INCOME$299
 $262
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $1 and $0 for 2017 and 2016, respectively(1) —
 
 COMPREHENSIVE INCOME$298
 $262
 
      
       
   Three Months Ended 
   March 31, 
   2018 2017 
 NET INCOME $319
 $299
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 and $1 for 2018 and 2017, respectively (1) (1) 
 COMPREHENSIVE INCOME $318
 $298
 
       
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)

      
  March 31,
2017		 December 31,
2016		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$153
 $390
 
 Accounts Receivable, net of allowances of $67 in 2017 and $68 in 2016895
 810
 
 Accounts Receivable—Affiliated Companies34
 76
 
 Unbilled Revenues209
 260
 
 Materials and Supplies187
 180
 
 Prepayments6
 9
 
 Regulatory Assets176
 199
 
 Derivative Contracts1
 —
 
 Other7
 6
 
 Total Current Assets1,668
 1,930
 
 PROPERTY, PLANT AND EQUIPMENT26,931
 26,347
 
 Less: Accumulated Depreciation and Amortization(5,849) (5,760) 
 Net Property, Plant and Equipment21,082
 20,587
 
 NONCURRENT ASSETS    
 Regulatory Assets3,287
 3,319
 
 Long-Term Investments301
 299
 
 Other Special Funds44
 43
 
 Other105
 110
 
 Total Noncurrent Assets3,737
 3,771
 
 TOTAL ASSETS$26,487
 $26,288
 
      
      
  March 31,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$48
 $242
 
 Accounts Receivable, net of allowances of $62 in 2018 and $59 in 2017961
 882
 
 Unbilled Revenues196
 296
 
 Materials and Supplies199
 197
 
 Prepayments22
 44
 
 Regulatory Assets139
 211
 
 Other17
 4
 
 Total Current Assets1,582
 1,876
 
 PROPERTY, PLANT AND EQUIPMENT29,689
 29,117
 
 Less: Accumulated Depreciation and Amortization(6,154) (6,101) 
 Net Property, Plant and Equipment23,535
 23,016
 
 NONCURRENT ASSETS    
 Regulatory Assets3,208
 3,222
 
 Long-Term Investments284
 280
 
 Rabbi Trust Fund45
 46
 
 Other120
 114
 
 Total Noncurrent Assets3,657
 3,662
 
 TOTAL ASSETS$28,774
 $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)

      
  March 31,
2017		 December 31,
2016		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Accounts Payable$574
 $718
 
 Accounts Payable—Affiliated Companies218
 260
 
 Accrued Interest83
 76
 
 Clean Energy Program86
 142
 
 Derivative Contracts—
 5
 
 Obligation to Return Cash Collateral135
 132
 
 Regulatory Liabilities74
 88
 
 Other319
 296
 
 Total Current Liabilities1,489
 1,717
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC6,042
 5,873
 
 OPEB Costs991
 1,009
 
 Accrued Pension Costs237
 250
 
 Regulatory Liabilities131
 118
 
 Environmental Costs324
 332
 
 Asset Retirement Obligations214
 213
 
 Long-Term Accrued Taxes116
 130
 
 Other114
 116
 
 Total Noncurrent Liabilities8,169
 8,041
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT7,819
 7,818
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150 shares authorized; issued and outstanding, 2017 and 2016—132 shares892
 892
 
 Contributed Capital945
 945
 
 Basis Adjustment986
 986
 
 Retained Earnings6,187
 5,888
 
 Accumulated Other Comprehensive Income—
 1
 
 Total Stockholder’s Equity9,010
 8,712
 
 Total Capitalization16,829
 16,530
 
 TOTAL LIABILITIES AND CAPITALIZATION$26,487
 $26,288
 
      
      
  March 31,
2018		 December 31,
2017		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$750
 $750
 
 Accounts Payable613
 728
 
 Accounts Payable—Affiliated Companies385
 340
 
 Accrued Interest92
 78
 
 Clean Energy Program85
 128
 
 Obligation to Return Cash Collateral136
 129
 
 Regulatory Liabilities34
 47
 
 Other327
 311
 
 Total Current Liabilities2,422
 2,511
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC3,443
 3,391
 
 OPEB Costs1,078
 1,103
 
 Accrued Pension Costs207
 226
 
 Regulatory Liabilities2,942
 2,948
 
 Environmental Costs268
 283
 
 Asset Retirement Obligations214
 212
 
 Long-Term Accrued Taxes93
 91
 
 Other112
 114
 
 Total Noncurrent Liabilities8,357
 8,368
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT7,843
 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 Earnings7,180
 6,861
 
 Accumulated Other Comprehensive Income(1) —
 
 Total Stockholder’s Equity10,152
 9,834
 
 Total Capitalization17,995
 17,675
 
 TOTAL LIABILITIES AND CAPITALIZATION$28,774
 $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)
      
  Three Months Ended 
  March 31, 
  2017 2016 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$299
 $262
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization171
 139
 
 Provision for Deferred Income Taxes and ITC160
 147
 
 Non-Cash Employee Benefit Plan Costs13
 18
 
 Cost of Removal(24) (35) 
 Net Change in Other Regulatory Assets and Liabilities(60) (105) 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues(34) (26) 
 Materials and Supplies(7) (6) 
 Prepayments3
 26
 
 Accounts Payable(12) (24) 
 Accounts Receivable/Payable—Affiliated Companies, net15
 197
 
 Other Current Assets and Liabilities40
 35
 
 Employee Benefit Plan Funding and Related Payments(25) (44) 
 Other(25) (16) 
 Net Cash Provided By (Used In) Operating Activities514
 568
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(748) (724) 
 Proceeds from Sales of Available-for-Sale Securities10
 5
 
 Investments in Available-for-Sale Securities(10) (5) 
 Solar Loan Investments(4) —
 
 Other2
 —
 
 Net Cash Provided By (Used In) Investing Activities(750) (724) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt—
 (153) 
 Issuance of Long-Term Debt—
 850
 
 Redemption of Long-Term Debt—
 (171) 
 Other(1) (10) 
 Net Cash Provided By (Used In) Financing Activities(1) 516
 
 Net Increase (Decrease) In Cash and Cash Equivalents(237) 360
 
 Cash and Cash Equivalents at Beginning of Period390
 198
 
 Cash and Cash Equivalents at End of Period$153
 $558
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(26) $(200) 
 Interest Paid, Net of Amounts Capitalized$65
 $53
 
 Accrued Property, Plant and Equipment Expenditures$287
 $318
 
      
      
  Three Months Ended 
  March 31, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$319
 $299
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization190
 171
 
 Provision for Deferred Income Taxes and ITC40
 160
 
 Non-Cash Employee Benefit Plan Costs9
 13
 
 Cost of Removal(38) (24) 
 Net Change in Regulatory Assets and Liabilities(6) (60) 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues24
 (34) 
 Materials and Supplies(2) (7) 
 Prepayments22
 3
 
 Accounts Payable(12) (12) 
 Accounts Receivable/Payable—Affiliated Companies, net40
 15
 
 Other Current Assets and Liabilities39
 40
 
 Employee Benefit Plan Funding and Related Payments(33) (25) 
 Other(15) (24) 
 Net Cash Provided By (Used In) Operating Activities577
 515
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(750) (748) 
 Proceeds from Sales of Trust Investments5
 10
 
 Purchases of Trust Investments(5) (10) 
 Solar Loan Investments(9) (4) 
 Other2
 2
 
 Net Cash Provided By (Used In) Investing Activities(757) (750) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Other—
 (1) 
 Net Cash Provided By (Used In) Financing Activities—
 (1) 
 Net Increase (Decrease) In Cash, Cash Equivalents and Restricted Cash(180) (236) 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period244
 393
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$64
 $157
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$—
 $(26) 
 Interest Paid, Net of Amounts Capitalized$65
 $65
 
 Accrued Property, Plant and Equipment Expenditures$326
 $287
 
      
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 
  March 31, 
  2017 2016 
 OPERATING REVENUES$1,284
 $1,313
 
 OPERATING EXPENSES    
 Energy Costs707
 638
 
 Operation and Maintenance230
 253
 
 Depreciation and Amortization650
 79
 
 Total Operating Expenses1,587
 970
 
 OPERATING INCOME (LOSS)(303) 343
 
 Income from Equity Method Investments3
 2
 
 Other Income38
 26
 
 Other Deductions(7) (18) 
 Other-Than-Temporary Impairments(1) (10) 
 Interest Expense(16) (22) 
 INCOME (LOSS) BEFORE INCOME TAXES(286) 321
 
 Income Tax Benefit (Expense)116
 (129) 
 NET INCOME (LOSS)$(170) $192
 
  

   
       
 
 Three Months Ended 
   March 31, 
   2018 2017 
 OPERATING REVENUES $1,403
 $1,269
 
 OPERATING EXPENSES     
 Energy Costs 746
 692
 
 Operation and Maintenance 246
 232
 
 Depreciation and Amortization 82
 650
 
 Total Operating Expenses 1,074
 1,574
 
 OPERATING INCOME (LOSS) 329
 (305) 
 Income from Equity Method Investments 2
 3
 
 Net Gains (Losses) on Trust Investments (22) 19
 
 Other Income (Deductions) 11
 11
 
 Non-Operating Pension and OPEB Credits (Costs) 4
 2
 
 Interest Expense (7) (16) 
 INCOME (LOSS) BEFORE INCOME TAXES 317
 (286) 
 Income Tax Benefit (Expense) (83) 116
 
 NET INCOME (LOSS) $234
 $(170) 
   

   
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 
  March 31, 
  2017 2016 
 NET INCOME (LOSS)$(170) $192
 
 Other Comprehensive Income (Loss), net of tax    
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(18) and $(16) for 2017 and 2016, respectively19
 16
 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(4) and $(5) for 2017 and 2016, respectively5
 7
 
 Other Comprehensive Income (Loss), net of tax24
 23
 
 COMPREHENSIVE INCOME (LOSS)$(146) $215
 
      
       
   Three Months Ended 
   March 31, 
   2018 2017 
 NET INCOME (LOSS) $234
 $(170) 
 Other Comprehensive Income (Loss), net of tax     
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $8 and $(18) for 2018 and 2017, respectively (11) 19
 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(3) and $(4) for 2018 and 2017, respectively 6
 5
 
 Other Comprehensive Income (Loss), net of tax (5) 24
 
 COMPREHENSIVE INCOME (LOSS) $229
 $(146) 
       
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)
 
      
  March 31,
2017		 December 31,
2016		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$18
 $11
 
 Accounts Receivable263
 276
 
 Accounts Receivable—Affiliated Companies175
 205
 
 Short-Term Loan to Affiliate157
 87
 
 Fuel173
 326
 
 Materials and Supplies, net379
 381
 
 Derivative Contracts111
 162
 
 Prepayments13
 10
 
 Other3
 2
 
 Total Current Assets1,292
 1,460
 
 PROPERTY, PLANT AND EQUIPMENT12,922
 12,655
 
 Less: Accumulated Depreciation and Amortization(4,837) (4,135) 
 Net Property, Plant and Equipment8,085
 8,520
 
 NONCURRENT ASSETS    
 NDT Fund1,913
 1,859
 
 Long-Term Investments103
 102
 
 Goodwill16
 16
 
 Other Intangibles106
 98
 
 Other Special Funds55
 53
 
 Derivative Contracts93
 24
 
 Other66
 61
 
 Total Noncurrent Assets2,352
 2,213
 
 TOTAL ASSETS$11,729
 $12,193
 
      
      
  March 31,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$11
 $32
 
 Accounts Receivable301
 380
 
 Accounts Receivable—Affiliated Companies215
 221
 
 Fuel162
 289
 
 Materials and Supplies, net370
 376
 
 Derivative Contracts43
 29
 
 Prepayments12
 11
 
 Other4
 3
 
 Total Current Assets1,118
 1,341
 
 PROPERTY, PLANT AND EQUIPMENT11,980
 11,755
 
 Less: Accumulated Depreciation and Amortization(3,291) (3,159) 
 Net Property, Plant and Equipment8,689
 8,596
 
 NONCURRENT ASSETS    
 NDT Fund2,051
 2,133
 
 Long-Term Investments86
 87
 
 Goodwill16
 16
 
 Other Intangibles131
 114
 
 Rabbi Trust Fund56
 57
 
 Derivative Contracts48
 7
 
 Other68
 67
 
 Total Noncurrent Assets2,456
 2,481
 
 TOTAL ASSETS$12,263
 $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)

      
  March 31,
2017		 December 31,
2016		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Accounts Payable$513
 $539
 
 Accounts Payable—Affiliated Companies81
 25
 
 Derivative Contracts7
 8
 
 Accrued Interest42
 20
 
 Other102
 88
 
 Total Current Liabilities745
 680
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC1,966
 2,170
 
 Asset Retirement Obligations522
 511
 
 OPEB Costs254
 251
 
 Derivative Contracts1
 3
 
 Accrued Pension Costs185
 191
 
 Long-Term Accrued Taxes78
 77
 
 Other117
 129
 
 Total Noncurrent Liabilities3,123
 3,332
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)

 

 
 LONG-TERM DEBT2,383
 2,382
 
 MEMBER’S EQUITY
   
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings4,437
 4,782
 
 Accumulated Other Comprehensive Loss(187) (211) 
 Total Member’s Equity5,478
 5,799
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$11,729
 $12,193
 
      
      
  March 31,
2018		 December 31,
2017		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$250
 $250
 
 Accounts Payable510
 712
 
 Accounts Payable—Affiliated Companies69
 57
 
 Short-Term Loan from Affiliate35
 281
 
 Derivative Contracts10
 16
 
 Accrued Interest43
 20
 
 Other108
 99
 
 Total Current Liabilities1,025
 1,435
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC1,434
 1,406
 
 Asset Retirement Obligations821
 810
 
 OPEB Costs285
 283
 
 Derivative Contracts2
 5
 
 Accrued Pension Costs176
 184
 
 Long-Term Accrued Taxes46
 52
 
 Other141
 140
 
 Total Noncurrent Liabilities2,905
 2,880
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 LONG-TERM DEBT2,137
 2,136
 
 MEMBER’S EQUITY
   
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings5,320
 4,911
 
 Accumulated Other Comprehensive Loss(352) (172) 
 Total Member’s Equity6,196
 5,967
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$12,263
 $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)

      
  Three Months Ended 
  March 31, 
  2017 2016 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income (Loss)$(170) $192
 
 Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization650
 79
 
 Amortization of Nuclear Fuel54
 58
 
 Provision for Deferred Income Taxes and ITC(226) 34
 
 Interest Accretion on Asset Retirement Obligation8
 7
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(5) (21) 
 Renewable Energy Credit (REC) Compliance Accrual26
 27
 
 Non-Cash Employee Benefit Plan Costs7
 10
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund(23) 3
 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies155
 143
 
 Margin Deposit(4) (4)
 Accounts Receivable24
 (41) 
 Accounts Payable(18) (34) 
 Accounts Receivable/Payable—Affiliated Companies, net71
 184
 
 Other Current Assets and Liabilities33
 15
 
 Employee Benefit Plan Funding and Related Payments(2) (8) 
 Other—
 19
 
 Net Cash Provided By (Used In) Operating Activities580
 663
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(307) (333) 
 Purchase of Emissions Allowances and RECs(15) (16) 
 Proceeds from Sales of Available-for-Sale Securities259
 183
 
 Investments in Available-for-Sale Securities(268) (188) 
 Short-Term Loan—Affiliated Company, net(70) (309) 
 Other7
 4
 
 Net Cash Provided By (Used In) Investing Activities(394) (659) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Cash Dividend Paid(175) —
 
 Other(4) —
 
 Net Cash Provided By (Used In) Financing Activities(179) —
 
 Net Increase (Decrease) in Cash and Cash Equivalents7
 4
 
 Cash and Cash Equivalents at Beginning of Period11
 12
 
 Cash and Cash Equivalents at End of Period$18
 $16
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$19
 $(100) 
 Interest Paid, Net of Amounts Capitalized$5
 $11
 
 Accrued Property, Plant and Equipment Expenditures$205
 $116
 
      
      
  Three Months Ended 
  March 31, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income (Loss)$234
 $(170) 
 Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization82
 650
 
 Amortization of Nuclear Fuel50
 54
 
 Provision for Deferred Income Taxes and ITC33
 (226) 
 Interest Accretion on Asset Retirement Obligation10
 8
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(119) (5) 
 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual

24
 26
 
 Non-Cash Employee Benefit Plan Costs6
 7
 
 Net (Gains) Losses and (Income) Expense from NDT Fund12
 (23) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies133
 155
 
 Margin Deposit25
 (4)
 Accounts Receivable93
 24
 
 Accounts Payable(89) (18) 
 Accounts Receivable/Payable—Affiliated Companies, net25
 71
 
 Other Current Assets and Liabilities30
 33
 
 Employee Benefit Plan Funding and Related Payments(2) (2) 
 Other(5) —
 
 Net Cash Provided By (Used In) Operating Activities542
 580
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(299) (307) 
 Purchase of Emissions Allowances and RECs(17) (15) 
 Proceeds from Sales of Trust Investments377
 259
 
 Purchases of Trust Investments(389) (268) 
 Short-Term Loan—Affiliated Company—
 (70) 
 Other11
 7
 
 Net Cash Provided By (Used In) Investing Activities(317) (394) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Cash Dividend Paid—
 (175) 
 Short-Term Loan—Affiliated Company(246) —
 
 Other—
 (4) 
 Net Cash Provided By (Used In) Financing Activities(246) (179) 
 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash(21) 7
 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period32
 11
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$11
 $18
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$2
 $19
 
 Interest Paid, Net of Amounts Capitalized$2
 $5
 
 Accrued Property, Plant and Equipment Expenditures$218
 $205
 
      
See disclosures regarding PSEG Power LLC included in the Notes to the Condensed Consolidated Financial Statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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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 demand responserelated 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 and fuel supply functions 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 three months ended March 31, 2018.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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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 March 31, 2018        
 Cash and Cash Equivalents$48
 $11
 $59
 $118
 
 Restricted Cash in Other Current Assets14
 —
 —
 14
 
 Restricted Cash in Other Noncurrent Assets2
 —
 —
 2
 
 Cash, Cash Equivalents and Restricted Cash$64
 $11
 $59
 $134
 
          
(A)Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services.

Note 2. Recent Accounting Standards
New Standards Issued But Not Yetand Adopted
Revenue from Contracts withWith 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, clarifiesand related updates, were adopted on January 1, 2018 using the principles for recognizing revenuefull 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 $14 million, Energy Costs by $9 million, and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictionsOperation and capital markets; and provides improved disclosures.
The guidance provides a five-step model to be used for recognizing revenueMaintenance (O&M) Expense by $5 million for the transferthree months ended March 31, 2017. At Power, retrospective adjustments reduced Operating Revenues and Energy Costs by $15 million for the three months ended March 31, 2017. For disclosure requirements under this standard, including Nature of promised goodsGoods and servicesServices, 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 customers in an amount that reflectsprovide for the considerationcosts of decommissioning upon termination of operations of its nuclear facilities. In addition, PSEG maintains a grantor trust which was established to whichmeet the entity expectsobligations related to be entitled in exchange for those goodsits non-qualified pension plans and services.deferred compensation plans, commonly referred to as a “Rabbi Trust.”
TheThis accounting standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expectswas adopted on January 1, 2018. Under the new guidance, equity investments in Power’s Nuclear Decommissioning Trust (NDT) and PSEG’s Rabbi Trust Funds are now measured at fair value with the unrealized gains and losses recognized through Net Income instead of Other Comprehensive Income (Loss). The debt securities in these trusts continue to resultbe 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 more detailed disclosuresearnings 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 revenue compared$342 million ($176 million, net of tax) from Accumulated Other Comprehensive Income to current guidance,Retained Earnings on January 1, 2018. See Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax and possibleNote 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 Statement of Cash Flows.
PSEG adopted this standard on January 1, 2018 using a retrospective transition method and had no changes in presentation. PSEG continues to evaluate allits presentation of its revenue streamsStatement of Cash Flows for each period presented.
Statement of Cash Flows:  Restricted Cash—ASU 2016-18
This accounting standard was adopted on 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 its contracts. Certain implementation issues are currently being finalized by the AICPA’s Revenue Recognition Working Groupcash equivalents and the FASB’s Transition Resource Group, including the ability to recognize revenue for certain contracts where there is uncertainty regardingrestricted
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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collection from customerscash or restricted cash equivalents and accounting for contributionshas included a description of these amounts in aidNote 1. Organization, Basis of construction. Upon formal resolutionPresentation and Significant Accounting Policies. The effect of adoption on the implementation issues noted above, PSEG will elect its transition method.March 31, 2017 Consolidated Statements of Cash Flows was immaterial.
RecognitionImproving the Presentation of Net Periodic Pension Cost and Measurement of Financial Assets and Financial LiabilitiesNet Periodic Postretirement Benefit Cost (OPEB)—ASU 2017-07
This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method.was adopted on January 1, 2018. Under the new guidance, equity investments (other than those accounted for usingentities are required to report the equity method)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 will be measuredeligible for capitalization, when applicable. As a result of adopting this standard, PSE&G reduced its charge to expense for the three months ended March 31, 2018 by approximately $14 million. For the three months ended March 31, 2017, the Condensed Consolidated Statements of Operations were recast to show retrospective adjustments of the non-service cost component of net benefit credits (costs) of $(2) million and $2 million 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 duePSE&G and Power, respectively, from O&M Expense to a change in their own credit risk throughnew line item after Operating Income entitled Non-Operating Pension and OPEB Credits (Costs). See Note 9. Pension and Other Comprehensive Income (Loss)Postretirement Benefits (OPEB). For equity investments which do not have readily determinable fair values, the impairment assessment
Stock Compensation - Scope of Modification Accounting—ASU 2017-09
This accounting standard was adopted on January 1, 2018. The standard will be simplified by requiringapplied prospectively to awards modified on or after January 1, 2018. PSEG does not expect a qualitative assessment to identify impairments. The new standard also changes certain disclosures.
The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG is currently analyzing thematerial impact from adoption of this standard on its financial statements; however, PSEG 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.new standard.
New Standards Issued But Not Yet Adopted
Leases—ASU 2016-02
This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.
ASU 2018-01 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.
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 consolidated financial statements.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities—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 permitting contractually specified components to be designated as the hedged risk in a cash flow hedge involving the purchase or sale of non-financial assets or variable rate financial instruments. Additionally, the amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allowing 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 is currently analyzing the impact of this standard on its consolidated 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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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 is currently analyzing the impact of this standard on its financial statements.
Statement of Cash Flows: Restricted Cash
This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in their reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early, including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements including its future disclosure requirements.
Business Combinations: Clarifying the Definition of a Business
This accounting standard was issued mainly to provide more consistency in how the definition 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 a filter that would consider 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.
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 does not have any current transactions impacted by this guidance and expects future acquisitions of individual solar plants will not qualify as business combinations. PSEG does not expect this guidance to materially impact its financial statements upon adoption.
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 impact of this guidance upon its financial statements.
Improving the Presentation
Note 3. Revenues
Nature of Net Periodic Pension CostGoods and Net Periodic Postretirement Benefit Cost (OPEB)
This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.
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 will be eligible for capitalization, when applicable.Services
The standard requires the amendmentsfollowing 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 be applied retrospectively for the presentation of the service cost componentcustomers under default commodity supply tariffs. PSE&G’s regulated electric and the other cost components of net periodic pension costgas default commodity supply and net periodic OPEB cost in the Statement of Operations and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension and OPEB costs.distribution services are separate
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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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tariffs which are satisfied as the product(s) and/or services are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until cancellation by the customer. Revenue is recognized over time as the service is 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 different 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 real-time energy markets. The energy and ancillary services performance obligations are typically satisfied over time as delivered 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 indexed 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 either 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 availability of natural gas, storage and pipeline capacity beyond PSE&G’s daily needs, Power also sells gas and pipeline 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 generally 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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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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 March 31, 2018          
 Revenues from Contracts with Customers          
 Electric Distribution$690
 $—
 $—
 $—
 $690
 
 Gas Distribution759
 —
 —
 (3) 756
 
 Transmission312
 —
 —
 —
 312
 
 Electricity and Related Product Sales        

 
  PJM        

 
 Third Party Sales—
 498
 —
 —
 498
 
          Sales to Affiliates—
 176
 —
 (176) —
 
 New York ISO—
 59
 —
 —
 59
 
 ISO New England—
 47
 —
 —
 47
 
 Gas Sales        

 
 Third Party Sales—
 64
 —
 —
 64
 
 Sales to Affiliates—
 397
 —
 (397) —
 
 Other Revenues from Contracts with Customers (A)72
 10
 137
 (1) 218
 
 Total Revenues from Contracts with Customers1,833
 1,251
 137
 (577) 2,644
 
 Revenues Unrelated to Contracts with Customers (B)12
 152
 10
 —
 174
 
 Total Operating Revenues$1,845
 $1,403
 $147
 $(577) $2,818
 
            
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Three Months Ended March 31, 2017          
 Revenues from Contracts with Customers          
 Electric Distribution$701
 $—
 $—
 $—
 $701
 
 Gas Distribution755
 —
 —
 (1) 754
 
 Transmission299
 —
 —
 —
 299
 
 Electricity and Related Product Sales        

 
  PJM        

 
 Third Party Sales—
 314
 —
 —
 314
 
          Sales to Affiliates—
 184
 —
 (184) —
 
 New York ISO—
 36
 —
 —
 36
 
 ISO New England—
 11
 —
 —
 11
 
 Gas Sales        

 
 Third Party Sales—
 52
 —
 —
 52
 
 Sales to Affiliates—
 401
 —
 (401) —
 
 Other Revenues from Contracts with Customers (A)62
 10
 128
 (1) 199
 
 Total Revenues from Contracts with Customers1,817
 1,008
 128
 (587) 2,366
 
 Revenues Unrelated to Contracts with Customers (B)9
 261
 (45) —
 225
 
 Total Operating Revenues$1,826
 $1,269
 $83
 $(587) $2,591
 
            
(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. In 2017, Other includes a $55 million loss 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 March 31, 2018 and 2017. Substantially all of PSE&G’s accounts receivable result from contracts with customers. Allowances represented approximately six percent and seven percent of accounts receivable as of March 31, 2018 and 2017, respectively.
Power
Power generally collects consideration upon satisfaction of performance obligations, and therefore, Power had no material contract balances as of March 31, 2018 and 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 March 31, 2018 and 2017.
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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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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 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 satisfied resulting from the base and incremental auctions which have been completed:
       
 Delivery Year $ per MW-Day MW Cleared 
 June 2017 to May 2018 $171 9,700
 
 June 2018 to May 2019 $205 9,200
 
 June 2019 to May 2020 $116 8,900
 
 June 2020 to May 2021 $174 7,800
 
       
Capacity Payments from the New England ISO Forward Capacity Market—The Forward Capacity Market Auction is conducted annually three years in advance of the operating period. Power expects to realize the following average capacity prices through May 2022 for capacity obligations to be satisfied resulting from the Forward Capacity Market auctions which have been completed:
       
 Delivery Year $ per MW-Day MW Cleared 
 June 2017 to May 2018 $231 850
 
 June 2018 to May 2019 $314 830
 
 June 2019 to May 2020 $231 850
 
 June 2020 to May 2021 $174 850
 
 June 2021 to May 2022 $152 460
 
       
In addition to the capacity listed in the table above, Power expects to realize payments for capacity obligations of approximately 480 MW at $231/MW-day, adjusted annually, from 2019 to 2026 at the Bridgeport Harbor Station Unit 5.
Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $180 million.
Other
The LIPA OSA is a 12-year services contract ending in 2025 with an annual fixed component. The fixed fee for the provision of services thereunder in 2018 is $64 million and will increase each year based on the change in the Consumer Price Index.

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 on June 1, 2017. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests forstations.
For the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Power expects the units to continue to be available to generate electricity and receive previously cleared capacity payments through the date the units cease operations.
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.
In the first quarter ofthree months ended March 31, 2017, Power recognized total D&A of $574 million and expects to recognize additional total D&A of $389 million in 2017 for the Hudson and Mercer units.units to reflect the significant shortening of their expected economic useful lives in 2017. In the three months ended March 31, 2018 and 2017, Power also recognized pre-tax charges in Energy Costs of $4 million and $7 million, respectively, primarily for coal inventory lower of cost or market adjustments. 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 unitUnit 3 (BH3) from 2025 to the summer of 2021 as it was more likely than not it will retire the unit by this time. The change in the estimated useful life is not expected to have a material impact on Power’s future financial results.
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 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 low natural gas prices, and the related 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, 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 fleetfleet.
In the ordinary course, management, and greaterin 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 enactment of proposed legislation in the state of New Jersey. At a co-owners meeting in February 2018, Exelon and Power 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. The companies agreed that the funding of these projects may be restored when and if legislation is enacted in New Jersey that 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 pipelinesgeneration. 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 April 2018, the New Jersey Legislature voted to pass legislation that would provide a safety net in order to prevent the loss of environmental attributes from selected nuclear generating stations. Power cannot predict whether the legislation will be enacted or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for fuel delivery.the continued operation of nuclear generating stations in New Jersey.
If trends noted abovemarket prices continue or worsen, Power’sto be depressed and legislation is not enacted that adequately compensates 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 could cease being economically competitive which may cause Power to retire suchand would anticipate retiring these units prior to the end of their useful lives.early. The costs associated with any such 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 will likely have awould be material adverse impact on PSEG’s and Power’s future financial results.to both PSEG and Power continue to advocate for sound policies that recognize nuclear power as a source of reliable and clean energy and an important part of a diverse and reliable energy portfolio.Power.
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The following table provides the balance sheet amounts by generating station as of March 31, 20172018 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.
           
   As of March 31, 2017 
   Hope Creek Salem Support Facilities and Other (A) Peach Bottom 
   Millions 
 Assets         
 Materials and Supplies Inventory $82
 $86
 $—
 $39
 
 Nuclear Production, net of Accumulated Depreciation 456
 545
 208
 774
 
 Nuclear Fuel In-Service, net of Accumulated Depreciation 152
 77
 —
 142
 
 Construction Work in Progress (including nuclear fuel) 156
 137
 12
 26
 
         Total Assets $846
 $845
 $220
 $981
 
 Liability         
 Asset Retirement Obligation $144
 $157
 $—
 $159
 
         Total Liabilities $144
 $157
 $—
 $159
 
          Net Assets $702
 $688
 $220
 $822
 
 NRC License Renewal Term 2046 2036/2040
 —
 2033/2034
 
 % Owned 100% 57% —
 50% 
           
           
   As of March 31, 2018 
   Hope Creek Salem Support Facilities and Other (A) Peach Bottom 
   Millions 
 Assets         
 Materials and Supplies Inventory $84
 $83
 $—
 $41
 
 Nuclear Production, net of Accumulated Depreciation 602
 653
 207
 797
 
 Nuclear Fuel In-Service, net of Accumulated Depreciation 88
 107
 —
 136
 
 Construction Work in Progress (including nuclear fuel) 296
 97
 1
 20
 
         Total Assets $1,070
 $940
 $208
 $994
 
 Liability         
 Asset Retirement Obligation $305
 $252
 $—
 $207
 
         Total Liabilities $305
 $252
 $—
 $207
 
          Net Assets $765
 $688
 $208
 $787
 
 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 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 $112$120 million and $98$112 million for the three months ended March 31, 20172018 and 2016,2017, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Condensed Consolidated Statement of Operations.

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Note 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 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 over-collection 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, among other factors, PSE&G’s requested revenue requirement in its filing will increase accordingly. 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.
BGSS—In April 2018, the BPU approved the final BGSS rates which were effective October 1, 2017.
In December 2017, February 2018 and March 2018, PSE&G filed with the BPU for self-implementing monthly bill credits of 15 cents per therm for the months of January through April 2018. Monthly bill credits of $104 million were credited to customers for the months of January through March and an additional $15 million is estimated to be credited in April.
Energy Strong Recovery Filing—In March 2017,and September of each year, PSE&G filed itsfiles with the BPU for base rate recovery of Energy Strong electricinvestments which include a return of and gas coston its investment.
In February 2018, the BPU approved recovery petition seeking BPU approval to recover theof an annual revenue requirements associated with Energy Strong capitalized investment costsrequirement of $8 million associated with electric and gas plant investments under the program that is anticipated to beEnergy Strong capital investment costs placed in service by May 31, 2017. The petition requests rates to be effective Septemberfrom June 1, 2017 consistent withthrough November 30, 2017.
Societal Benefits Charge—In February 2018, the BPU Order of approval of the Energy Strong Program. The annualized requested increase in revenue requirement is approximately $22 million for electric and $3 million for gas. This matter is pending.
Green Program Recovery Charges—In March 2017, the BPU gave final approval toapproved PSE&G’s petition to recoverincrease electric rates by approximately $37$20 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.and 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 are effective MayApril 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge. 2018.
Weather Normalization Clause—In April 2017,2018, the BPU gave final approval to PSE&G’s petition to collect $54$55 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period, which resulted in a deficiency of $31 million, plus a carryover balance of $24 million from the 2015-2016 Winter Period.period.

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 March 31,
2017		 December 31,
2016		 
   Millions 
 Commercial/Industrial $168
 $164
 
 Residential 11
 11
 
 Total $179
 $175
 
       

       
 Outstanding Loans by Class of Customer 
   As of As of 
 Consumer Loans March 31,
2018		 December 31,
2017		 
   Millions 
 Commercial/Industrial $168
 $158
 
 Residential 10
 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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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 leases 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, as discussed in Note 4. Early Plant Retirements, 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 investments, whichreceivables. Lease payments and adjustments to qualifying credit support on the REMA leases are received semiannually in January and July of each year.
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 to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with various parties relevant to this matter. 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 was recorded in the quarter ended June 30, 2017. In addition, based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15 million pre-tax charge in the quarter ended June 30, 2017, for its current best estimate of loss related to lease receivables. Pre-tax write-downs and additional charges were reflected in Operating Revenues in the first half of 2017 and isare included in Gross InvestmentsInvestment in Leases as of March 31, 2017.2018.
In January 2018, certain subsidiaries of Energy Holdings, REMA, certain holders of the pass-through certificates and other parties entered into a Forbearance Agreement (Forbearance) relating to the Conemaugh facility. Pursuant to the Forbearance, the parties thereto agreed to temporarily forbear from exercising rights and remedies related to certain events of default related to REMA’s obligation to procure additional qualifying credit support. The 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 Forbearance occurs. The Forbearance remains in effect.
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. 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).
The following table shows Energy Holdings’ gross and net lease investment as of March 31, 20172018 and December 31, 2016,2017, respectively.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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  As of As of 
  March 31,
2017		 December 31,
2016		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$574
 $629
 
 Estimated Residual Value of Leased Assets346
 346
 
 Total Investment in Rental Receivables920
 975
 
 Unearned and Deferred Income(324) (326) 
 Gross Investment in Leases596
 649
 
 Deferred Tax Liabilities(640) (674) 
 Net Investment in Leases$(44) $(25) 
      
      
  As of As of 
  March 31,
2018		 December 31,
2017		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$545
 $546
 
 Estimated Residual Value of Leased Assets326
 326
 
 Total Investment in Rental Receivables871
 872
 
 Unearned and Deferred Income(303) (307) 
 Gross Investment in Leases568
 565
 
 Deferred Tax Liabilities(498) (480) 
 Net Investment in Leases$70
 $85
 
      
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 March 31, 2017   
  As of March 31, 2017 
   Millions 
 AA $16
 
 BBB+ — BBB- 316
 
 BB- 133
 
 CCC- 109
 
 Total $574
 
     
     
   
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating Standard & Poor’s (S&P) as of March 31, 2018   
  As of March 31, 2018 
   Millions 
 AA $14
 
 BBB+ — BBB- 316
 
 BB- 133
 
 CCC- 82
 
 Total $545
 
     
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 March 31, 20172018, the gross investment in the leases of such assets, net of non-recourse debt, was $371335 million ($(154)(88) million, net of deferred taxes). A more detailed description of such assets under lease as of March 31, 2017, is presented in the following table.
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 Asset Location 
Gross
Investment
 
%
Owned
 Total MW 
Fuel
Type
 
Counterparties’
S&P Credit
Ratings
 Counterparty 
     Millions           
 Powerton Station Units 5 and 6 IL $134
 64% 1,538
 Coal BB- NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $83
 64% 1,036
 Gas BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $26
 17% 1,711
 Coal CCC- (A) REMA 
 Conemaugh Station Units 1 and 2 PA $29
 17% 1,711
 Coal CCC- (A) REMA 
 Shawville Station Units 1, 2, 3 and 4 PA $99
 100% 596
 Gas CCC- (A) REMA 
                 
                 
 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 $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 $78
 100% 596
 Gas CCC- REMA (A) 
                 
(A)REMA’s parent company, GenOn Energy Inc. (GenOn), reported in August 2016 that GenOnand certain of its subsidiaries (which did not expect to have sufficient liquidity to repay its senior unsecured notes due in June 2017. In January 2017, S&P further lowered its corporate credit rating on GenOn and its affiliates (includinginclude REMA) to “CCC-” from “CCC” reflecting the primary credit concernfiled voluntary petitions for relief under Chapter 11 of the near-term maturityU.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Certain subsidiaries of GenOn’s senior unsecured notes in June 2017Energy Holdings, REMA, consenting holders of the pass-through certificates and expressedother parties entered into a negative outlook reflectingForbearance relating to the continuing pressure on financial measures. In October 2016, Moody’s downgraded the GenOn Corporate Family Rating to “Caa3” to reflect its high debt burden relative to cash flow.Conemaugh facility.
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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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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 efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If 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 pay material cash tax liabilities to the Internal Revenue Service.
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.

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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.
          
  As of March 31, 2017 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$717
 $297
 $(7) $1,007
 
 Debt Securities        
 Government515
 8
 (6) 517
 
 Corporate342
 5
 (4) 343
 
 Total Debt Securities857
 13
 (10) 860
 
 Other Securities46
 —
 —
 46
 
 Total NDT Available-for-Sale Securities$1,620
 $310
 $(17) $1,913
 
          
          
  As of March 31, 2018 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
 Domestic$463
 $226
 $(7) $682
 
    International318
 93
 (7) 404
 
 Total Equity Securities781
 319
 (14) 1,086
 
 Available-for Sale Debt Securities        
 Government518
 1
 (11) 508
 
 Corporate464
 1
 (9) 456
 
 Total Available-for-Sale Debt Securities982
 2
 (20) 964
 
 Other1
 —
 —
 1
 
 Total NDT Fund Investments (A)$1,764
 $321
 $(34) $2,051
 
          
          
  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)
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(UNAUDITED)
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Net unrealized gains (losses) on debt securities of $(10) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of March 31, 2018. The NDT available-for-saleportion of net unrealized gains (losses) recognized during the first quarter of 2018 related to equity securities table excludes cashstill held at the end of $1 million which is part of the NDT Fund.March 31, 2018 was $(10) million.
The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.
      
  As of As of 
  March 31,
2017		 December 31,
2016		 
  Millions 
 Accounts Receivable$15
 $8
 
 Accounts Payable$4
 $5
 
      

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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  As of As of 
  March 31,
2018		 December 31,
2017		 
  Millions 
 Accounts Receivable$13
 $24
 
 Accounts Payable$9
 $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 March 31, 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)$80
 $(6) $4
 $(1) $120
 $(10) $8
 $(1) 
 Debt Securities                
 Government (B)276
 (6) 4
 —
 276
 (6) 4
 —
 
 Corporate (C)125
 (3) 9
 (1) 139
 (3) 15
 (1) 
 Total Debt Securities401
 (9) 13
 (1) 415
 (9) 19
 (1) 
 NDT Available-for-Sale Securities$481
 $(15) $17
 $(2) $535
 $(19) $27
 $(2) 
                  
                  
  As of March 31, 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$117
 $(7) $—
 $—
 $40
 $(2) $—
 $—
 
    International65
 (7) 1
 —
 29
 (3) 2
 —
 
 Total Equity Securities182
 (14) 1
 —
 69
 (5) 2
 —
 
 Available-for Sale Debt Securities                
 Government (B)364
 (7) 80
 (4) 343
 (2) 91
 (2) 
 Corporate (C)339
 (8) 25
 (1) 191
 (1) 27
 (1) 
 Total Available-for-Sale Debt Securities703
 (15) 105
 (5) 534
 (3) 118
 (3) 
 NDT Trust Investments$885
 $(29) $106
 $(5) $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 March 31, 2017.are recorded in Net Income.
(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 March 31, 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 March 31, 2017.2018.
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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 
   March 31, 
   2017 2016 
  Millions 
 Proceeds from NDT Fund Sales (A) $247
 $177
 
 Net Realized Gains (Losses) on NDT Fund:     
 Gross Realized Gains $21
 $15
 
 Gross Realized Losses (4) (16) 
 Net Realized Gains (Losses) on NDT Fund $17
 $(1) 
       
       
   Three Months Ended 
   March 31, 
   2018 2017 
  Millions 
 Proceeds from NDT Fund Sales (A) $372
 $247
 
 Net Realized Gains (Losses) on NDT Fund     
 Gross Realized Gains $24
 $21
 
 Gross Realized Losses (12) (4) 
 Net Realized Gains (Losses) on NDT Fund (B) 12
 17
 
 Unrealized Gains (Losses) on Equity Securities in NDT Fund (C) (34) N/A
 
 Other-Than-Temporary-Impairments —
 (1) 
 Net Gains (Losses) on NDT Fund Investments $(22) $16
 
       
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of (B)$149 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of March 31, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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The NDT available-for-sale debt securities held as of March 31, 2017 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $16
 
 1 - 5 years 257
 
 6 - 10 years 199
 
 11 - 15 years 59
 
 16 - 20 years 63
 
 Over 20 years 266
 
 Total NDT Available-for-Sale Debt Securities$860
 
     
The cost of these securities was determined on the basis of specific identification.
(C)Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).
The NDT Fund debt securities held as of March 31, 2018 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $15
 
 1 - 5 years 300
 
 6 - 10 years 201
 
 11 - 15 years 40
 
 16 - 20 years 73
 
 Over 20 years 335
 
 Total NDT Available-for-Sale Debt Securities$964
 
     
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 three months ended March 31, 2017, Other-Than-Temporary Impairments (OTTI) of $1 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
Rabbi Trust
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”
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(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 March 31, 2018 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
    Domestic$21
 $2
 $—
 $23
 
    International—
 —
 —
 —
 
 Total Equity Securities21
 2
 —
 23
 
 Available-for-Sale Debt Securities        
 Government91
 —
 (2) 89
 
 Corporate114
 1
 (2) 113
 
 Total Available-for-Sale Debt Securities205
 1
 (4) 202
 
 Total Rabbi Trust Investments$226
 $3
 $(4) $225
 
          
          
  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
 
          
          
  As of March 31, 2017 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities$22
 $—
 $—
 $22
 
 Debt Securities        
 Government99
 —
 (1) 98
 
 Corporate99
 1
 (1) 99
 
 Total Debt Securities198
 1
 (2) 197
 
 Other Securities2
 —
 —
 2
 
 Total Rabbi Trust Available-for-Sale Securities$222
 $1
 $(2) $221
 
          
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
TableNet unrealized gains (losses) on debt securities of Contents


          
  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
 
          
$(3) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Condensed Consolidated Balance Sheet as of March 31, 2018. The portion of net unrealized gains (losses) recognized during the first quarter of 2018 related to equity securities still held at the end of March 31, 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 
  March 31,
2017		 December 31,
2016		 
  Millions 
 Accounts Receivable$1
 $5
 
 Accounts Payable$1
 $3
 
      
      
  As of As of 
  March 31,
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 March 31, 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)53
 (1) 1
 —
 60
 (2) 1
 —
 
 Corporate (C)36
 (1) 3
 —
 46
 (2) 3
 —
 
 Total Debt Securities89
 (2) 4
 —
 106
 (4) 4
 —
 
 Rabbi Trust Available-for-Sale Securities$89
 $(2) $4
 $—
 $106
 $(4) $4
 $—
 
                  
                  
  As of March 31, 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$—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 
    International—
 —
 —
 —
 —
 —
 —
 —
 
��Total Equity Securities—
 —
 —
 —
 —
 —
 —
 —
 
 Available-for-Sale Debt Securities                
 Government (B)48
 (1) 23
 (1) 28
 —
 25
 (1) 
 Corporate (C)73
 (2) 8
 —
 39
 (1) 9
 —
 
 Total Available-for-Sale Debt Securities121
 (3) 31
 (1) 67
 (1) 34
 (1) 
 Rabbi Trust Investments$121
 $(3) $31
 $(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. Effective January 1, 2018, unrealized gains and losses on these securities are recorded in Net Income.
(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 March 31, 2017.2018.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents


(C)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 March 31, 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 Rabbi Trust Fund were:
       
   Three Months Ended 
   March 31, 
   2017 2016 
  Millions 
 Proceeds from Rabbi Trust Sales (A) $51
 $25
 
 Net Realized Gains (Losses) on Rabbi Trust:     
 Gross Realized Gains $15
 $1
 
 Gross Realized Losses (3) (1) 
 Net Realized Gains (Losses) on Rabbi Trust $12
 $—
 
       
       
   Three Months Ended 
   March 31, 
   2018 2017 
  Millions 
 Proceeds from Rabbi Trust Sales (A) $25
 $51
 
 Net Realized Gains (Losses) on Rabbi Trust:     
 Gross Realized Gains $2
 $15
 
 Gross Realized Losses (2) (3) 
 Net Realized Gains (Losses) on Rabbi Trust (B) —
 12
 
 Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C) —
 N/A
 
 Other-Than-Temporary-Impairments —
 —
 
 Net Gains (Losses) on Rabbi Trust Investments $—
 $12
 
       
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized losses of $(1) million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of (B)March 31, 2017.
The Rabbi Trust available-for-sale debt securities held as of March 31, 2017 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $6
 
 1 - 5 years 50
 
 6 - 10 years 42
 
 11 - 15 years 9
 
 16 - 20 years 8
 
 Over 20 years 82
 
 Total Rabbi Trust Available-for-Sale Debt Securities$197
 
     
The cost of these securities was determined on the basis of specific identification.
(C)Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).
The Rabbi Trust debt securities held as of March 31, 2018 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $1
 
 1 - 5 years 36
 
 6 - 10 years 29
 
 11 - 15 years 6
 
 16 - 20 years 17
 
 Over 20 years 113
 
 Total Rabbi Trust Available-for-Sale Debt Securities$202
 
     
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 a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the three months ended March 31, 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.
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The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:
      
  As of As of 
  March 31,
2017		 December 31,
2016		 
  Millions 
 PSE&G$44
 $43
 
 Power55
 53
 
 Other122
 121
 
 Total Rabbi Trust Available-for-Sale Securities$221
 $217
 
      
      
  As of As of 
  March 31,
2018		 December 31,
2017		 
  Millions 
 PSE&G$45
 $46
 
 Power56
 57
 
 Other124
 128
 
 Total Rabbi Trust Investments$225
 $231
 
      
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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, as of March 31, 2017, the total net periodic benefit costs decreased by approximately $12 million, net of amounts capitalized, 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.
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, exceptexcluding Servco. Amounts shown do not reflect the impacts of capitalization. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for Servco.capitalization, when applicable. For additional information, see Note 2. Recent Accounting Standards.
          
  Pension Benefits OPEB 
  Three Months Ended Three Months Ended 
  March 31, March 31, 
  2017 2016 2017 2016 
  Millions 
 Components of Net Periodic Benefit Costs        
 Service Cost$29
 $27
 $4
 $4
 
 Interest Cost51
 50
 16
 15
 
 Expected Return on Plan Assets(98) (98) (8) (8) 
 Amortization of Net        
 Prior Service Cost (Credit)(5) (4) (3) (3) 
 Actuarial Loss24
 39
 13
 10
 
 Total Benefit Costs$1
 $14
 $22
 $18
 
          
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   Pension Benefits OPEB 
   Three Months Ended Three Months Ended 
   March 31, March 31, 
   2018 2017 2018 2017 
  Millions 
 Components of Net Periodic Benefit (Credits) Costs         
 Service Cost (included in O&M Expense) $32
 $29
 $4
 $4
 
 Non-Operating Pension and OPEB (Credits) Costs         
 Interest Cost 52
 51
 16
 16
 
 Expected Return on Plan Assets (110) (98) (10) (8) 
 Amortization of Net         
 Prior Service Cost (4) (5) —
 (3) 
 Actuarial Loss 21
 24
 16
 13
 
 Non-Operating Pension and OPEB (Credits) Costs (41) (28) 22
 18
 
 Total Benefit (Credits) Costs $(9) $1
 $26
 $22
 
           
Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, except forexcluding Servco, are detailed as follows:
          
  Pension Benefits OPEB 
  Three Months Ended Three Months Ended 
  March 31, March 31, 
  2017 2016 2017 2016 
  Millions 
 PSE&G$(1) $7
 $14
 $11
 
 Power—
 4
 7
 6
 
 Other2
 3
 1
 1
 
 Total Benefit Costs$1
 $14
 $22
 $18
 
          
           
   Pension Benefits OPEB 
   Three Months Ended Three Months Ended 
   March 31, March 31, 
   2018 2017 2018 2017 
  Millions 
 PSE&G $(8) $(1) $17
 $14
 
 Power (2) —
 8
 7
 
 Other 1
 2
 1
 1
 
 Total Benefit (Credits) Costs $(9) $1
 $26
 $22
 
           
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.
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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 $35$40 million into its pension plan trusts during 2017.2018. Servco’s pension-related revenues and costs were $9$10 million and $6$9 million for the three months ended March 31, 20172018 and 2016,2017, respectively. The OPEB-related revenues earned and costs incurred were $1 million for each of the three months ended March 31, 2017 were $1 million2018 and were immaterial for the three months ended March 31, 2016.2017.

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
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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 March 31, 20172018 and December 31, 2016.2017.
      
  As of As of 
  March 31,
2017		 December 31,
2016		 
  Millions 
 Face Value of Outstanding Guarantees$1,886
 $1,806
 
 Exposure under Current Guarantees$151
 $139
 
      
 Letters of Credit Margin Posted$183
 $157
 
 Letters of Credit Margin Received$104
 $99
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(1) $(1) 
    Net Broker Balance Deposited (Received)$61
 $57
 
      
 Additional Amounts Posted:    
 Other Letters of Credit$69
 $51
 
      
      
  As of As of 
  March 31,
2018		 December 31,
2017		 
  Millions 
 Face Value of Outstanding Guarantees$1,755
 $1,701
 
 Exposure under Current Guarantees$161
 $153
 
      
 Letters of Credit Margin Posted$109
 $103
 
 Letters of Credit Margin Received$18
 $32
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(1) $(1) 
    Net Broker Balance Deposited (Received)$122
 $147
 
      
 Additional Amounts Posted:    
 Other Letters of Credit$61
 $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 hadhave posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power’s payment obligations related to its equity interest in the PennEast natural gas pipeline and a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. As previously announced, Power is currently in the process of selling its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee would terminate. 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.

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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, theThe 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 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.
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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 cost 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.
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 52 members as of March 31, 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 $190 million, which the CPG continues to incur. Of the estimated $190 million, as of March 31, 2017, the CPG had spent approximately $160 million, of which PSEG’s total share was approximately $11 million.costs.
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.
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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 estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation. Occidental Chemical Corporation, one of the PRPs, has committed to perform the remedial design required by the ROD Remedy, reserving its right of cost contribution from all other PRPs.
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. The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform the remedial action under EPA oversight. Discussions on the matter are ongoing. Conversations between the EPA and the PRPs regarding remediation of the Passaic River’s upper 9 miles are ongoing.
Based upon the estimated cost of the ROD Remedy and PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued abilityas of March 31, 2018, PSEG has accrued approximately $57 million. Of this amount, PSE&G to recover such costs in its rates, PSE&Ghas accrued $46 million as an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset andbased on its continued ability to recover such costs in its rates. Power has accrued $11 million as an additional $8 million Other Noncurrent Liability and awith the corresponding O&M Expense recorded in the first quarter of 2016. As of March 31, 2017, these accruals bringperiods when the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.
Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA 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 the 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. 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 20 PRPs, that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements in return for payments by each PRP of $280,600. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. It is unclear how the EPA made that determination or how many PRPs will accept the proposal. The settlement is subject to a 30 day public comment period that has not yet commenced. The impact of this settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.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
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will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.
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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 $386$345 million and $443$391 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 $386$345 million as of March 31, 2017.2018. Of this amount, $74$79 million was recorded in Other Current Liabilities and $312$266 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $386$345 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 whetherto 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
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ofbasis, based on studies related to impingement mortality and entrainment and submit the results with their permit applications.applications to be conducted by the 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. 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
CWA and the Endangered Species Act. The cases were subsequentlyhave been consolidated at the Second Circuit and a decision is expected by
mid-2017.remains pending.
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 Clean Water Act,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. 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 the Clean Water Act. Such serviceCWA. 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 Clean Water ActCWA 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. Based on current discussions withPower is currently awaiting action by the CTDEEP if the proposal is accepted,to issue a draft and then a final permit could be issued in 2017. See Note 3. Early Plant Retirements.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, 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. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power 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 issued an order to approve siting BH5.Bridgeport Harbor Station Unit 5 (BH5). All major environmental
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permits have been obtained. Operationsreceived; however, secondary approvals are expectedstill being obtained to allow operations to begin 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;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.matter and the parties may also be subject to the assessment of civil penalties related to the discharge and response. The impacted cable was repaired in late-September 2017; however, dielectric fluid continues to appear on the surface and so the investigation and response actions related to the fluid discharge are ongoing. The investigationPSE&G may determine that retirement of the discharge and its potential causeaffected facilities would be appropriate. Also ongoing is in the preliminary
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stages, making it difficultprocess to determine ultimate responsibility for the timing and potential costs to resolve this matter, as well as responsibility for such costs betweenaddress the leak among PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the necessary repair and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs has been extended due to the presence of debris within PSE&G’s easement. In November 2016,NADC, including an action filed by PSE&G filed an actionin federal court in New Jersey Federal Court seeking an order requiringdamages from NADC. In that action, NADC to remove its debris from PSE&G’s easement so thathas also pursued counterclaims against PSE&G and Con Edison seeking damages for its costs to address the leak. Based on the information currently available and depending on the outcome of the federal court action, PSE&G’s portion of the costs to address the leak may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informedbe material; however, PSE&G anticipates that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s debris removal activities are ongoing.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. 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 Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule.the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.ELG Rule.
In April 2017,Through various orders, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and is acting promptly to issue an administrative stay ofhas stayed the compliance dates in the rule that have not yet passed pending judicial review. The deadlines that are expectedELG Rule and has announced plans to be stayed includefurther revise the BAT limitationsrequirements and pretreatment standards for eachcompliance dates of the following waste streams:  fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater.ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or theits financial impact it may have on the company.
Coal Combustion Residuals (CCRs)
On December 19, 2014, the EPA issued a final rule that regulates CCRs as non-hazardouscondition and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power’s Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.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 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.

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PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:
           
  Auction Year  
  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 will become effective on June 1, 20172018 when the 20142015 BGS auction agreements expire.
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 20182020 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.
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 20192021 to support its fossil generation stations.
As of March 31, 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 $301
 
 Enrichment $359
 
 Fabrication $192
 
 Natural Gas $1,101
 
 Coal $181
 
     
     
 Fuel Type Power's Share of Commitments through 2022 
   Millions 
 Nuclear Fuel   
 Uranium $242
 
 Enrichment $346
 
 Fabrication $170
 
 Natural Gas $1,024
 
 Coal $286
 
     
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Regulatory Proceedings
FERC Compliance
PJM Bidding Matter
In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist
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in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power 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 asIn April 2018, a settlement agreement was entered into between PSEG and FERC Staff, approved by FERC on April 25, 2018, pursuant to which PSEG agreed to pay approximately $40 million for the finalfull resolution of these matters, based upon recent developments in the investigation,this matter. Accordingly, 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 recordingrecorded an additional pre-tax charge to income of $10$5 million duringin the three months ended March 31, 2017. Power is unable to reasonably estimate the rangefirst quarter of possible loss, if any,2018, resulting in a total liability of approximately $40 million accrued for the quantityresolution of energy offered matter or the penaltiesthis matter. The settlement agreement does not require PSEG to change its business practices in a manner that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individuallyhave a material to impact on its ongoing business operations.
Other Litigation and Legal Proceedings
PSEG and Power.
Power continuesits subsidiaries are party to believe that it has legal defenses that it may assertvarious lawsuits in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majorityordinary course of business. In view of the hours was belowinherent difficulty in predicting the allowed rate under the Tariffoutcome of such matters, PSEG, PSE&G 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 generally cannot predict the finaleventual outcome of the pending matters, the timing of the ultimate resolution of these matters.
Financial Transmission Rights (FTR) Auction Mattermatters, or the eventual loss, fines or penalties related to each pending matter.
In January 2017, ER&T received requestsaccordance 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 matter for further developments that could affect the amount of the accrued liability that has been previously established.
Based on current knowledge, management does not believe that loss contingencies arising from pending matters, other than the FERC Officematters 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 Enforcement relating to the planning and implementationinherent uncertainties involved in these matters, some of ER&T’s participation in the annual FTR auction in PJM for the 2016-2017 planning yearwhich are beyond PSEG’s control, and the monthly FTR auctionslarge or indeterminate damages sought in PJMsome of these matters, an adverse outcome in one or more of these matters could be material to PSEG’s, PSE&G’s or Power’s results of operations or liquidity for February, March and April 2016. PSEG is cooperating with FERC in this matter. PSEG cannot predict the outcome of this matter at this time.any particular reporting period.

Note 10.11. Debt and Credit Facilities

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, 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 March 31, 2017,2018, the total available credit capacity was $3.6$3.4 billion.
As of March 31, 2017,2018, no single institution represented more than 8% of the total commitments in the credit facilities.
As of March 31, 2017, the2018, total credit capacity was in excess of itsthe total anticipated maximum liquidity requirements.
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requirements 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 March 31, 20172018 were as follows:
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   As of March 31, 2017     
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
   5-year Credit Facilities (A) $1,500
 $332
 $1,168
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSEG $1,500
 $332
 $1,168
     
 PSE&G           
  5-year Credit Facility (A) $600
 $14
 $586
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSE&G $600
 $14
 $586
     
 Power           
   3-year LC Facilities $200
 $137
 $63
 Mar 2020 Letters of Credit 
   5-year Credit Facilities 1,900
 98
 1,802
 Mar 2022 Funding/Letters of Credit 
 Total Power $2,100
 $235
 $1,865
     
 Total $4,200
 $581
 $3,619
     
             

(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 March 31, 2017, PSEG had $315 million outstanding at a weighted average interest rate of 1.25%. As of March 31, 2017, PSE&G had no amounts outstanding under its Commercial Paper Program.
             
   As of March 31, 2018     
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
   5-year Credit Facilities (A) $1,500
 $609
 $891
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSEG $1,500
 $609
 $891
     
 PSE&G           
  5-year Credit Facility (A) $600
 $16
 $584
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSE&G $600
 $16
 $584
     
 Power           
   3-year Letter of Credit Facilities $200
 $112
 $88
 Mar 2020 Letters of Credit 
   5-year Credit Facilities 1,900
 46
 1,854
 Mar 2022 Funding/Letters of Credit 
 Total Power $2,100
 $158
 $1,942
     
 Total $4,200
 $783
 $3,417
     
             
(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 March 31, 2018, PSEG had $594 million outstanding at a weighted average interest rate of 2.57%. PSE&G had no amounts outstanding under its Commercial Paper Program as of March 31, 2018.

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 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.
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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 March 31, 20172018 or December 31, 2016. The fair value hedges reduced interest expense by $2 million for the three months ended March 31, 2016.2017.
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Cash Flow Hedges
PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of March 31, 2017 and December 31, 2016, PSEG hadThere were no outstanding 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 March 31, 2017 and December 31, 2016, the fair value of these hedges was $2 million and $1 million, respectively. There was no ineffectiveness as of March 31, 20172018 and December 31, 2016.
2017. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 millionimmaterial as of March 31, 20172018 and December 31, 2016.2017, respectively. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is $1 million.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.
The following tabular disclosure does not include the offsetting of trade receivables and payables.
               
   As of March 31, 2017 
   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 $525
 $(414) $111
 $1
 $2
 $114
 
 Noncurrent Assets 264
 (171) 93
 —
 —
 93
 
 Total Mark-to-Market Derivative Assets $789
 $(585) $204
 $1
 $2
 $207
 
 Derivative Contracts             
 Current Liabilities $(425) $418
 $(7) $—
 $—
 $(7) 
 Noncurrent Liabilities (168) 167
 (1) —
 —
 (1) 
 Total Mark-to-Market Derivative (Liabilities) $(593) $585
 $(8) $—
 $—
 $(8) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $196
 $—
 $196
 $1
 $2
 $199
 
               
           
   As of March 31, 2018 
   Power (A) Consolidated 
   Not Designated       
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Total
Derivatives
 
   Millions 
 Derivative Contracts         
 Current Assets $366
 $(323) $43
 $43
 
 Noncurrent Assets 156
 (108) 48
 48
 
 Total Mark-to-Market Derivative Assets $522
 $(431) $91
 $91
 
 Derivative Contracts         
 Current Liabilities $(332) $322
 $(10) $(10) 
 Noncurrent Liabilities (109) 107
 (2) (2) 
 Total Mark-to-Market Derivative (Liabilities) $(441) $429
 $(12) $(12) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $81
 $(2) $79
 $79
 
           
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   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 March 31, 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 March 31, 2018 and December 31, 2017, Power had net cash collateral/margin payments to counterparties of $121 million and $146 million, respectively. Of these net cash/collateral (received) paid was netted against the corresponding net derivative contract positions with $(4)margin payments $(2) million as of cash collateral netted against noncurrent assets,March 31, 2018 and $4$44 million netted against current liabilities. As ofas December 31, 2016, net cash collateral (received) paid of $1 million was2017 were netted against the corresponding net derivative contract positions. The $(2) million as of March 31, 2018 was netted against current assets. Of the $1$44 million as of December 31, 2016,2017, $(3) million was netted against noncurrentcurrent assets, and $4$28 million was netted against current liabilities, and $19 million was netted against noncurrent 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 $13$20 million and $19$30 million as of March 31, 20172018 and December 31, 2016,2017, respectively. As of March 31, 20172018 and December 31, 2016,2017, Power had the contractual right of offset of $7$9 million and $9$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 $6$11 million and $10$17 million as of March 31, 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.
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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 ended March 31, 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 
  March 31,   March 31, 
  2017 2016                                2017 2016 
   Millions   Millions 
 PSEG           
 Interest Rate Swaps —
 3
 Interest Expense —
 —
 
 Total PSEG $—
 $3
   $—
 $—
 
             
There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of March 31, 2017 and 2016.
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 —
 —
 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of March 31, 2017 $3
 $2
 
       
       
 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 $—
 $—
 
 Gain Recognized in AOCI —
 —
 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of March 31, 2018 $—
 $—
 
       
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 ended March 31, 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 
     March 31, 
     2017 2016 
    Millions 
 PSEG and Power       
 Energy-Related Contracts Operating Revenues $83
 $216
 
 Energy-Related Contracts Energy Costs (5) 2
 
 Total PSEG and Power   $78
 $218
 
         

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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 Derivatives Not Designated as Hedges 
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives
 Pre-Tax Gain (Loss) Recognized in Income on Derivatives 
     Three Months Ended 
     March 31, 
     2018 2017 
     Millions 
 PSEG and Power       
 Energy-Related Contracts Operating Revenues $40
 $78
 
 Energy-Related Contracts Energy Costs (8) —
 
 Total PSEG and Power   $32
 $78
 
         
The following reflectstable summarizes the grossnet notional volume on an absolute value basis,purchases/(sales) of derivativesopen derivative transactions by commodity as of March 31, 20172018 and December 31, 2016.2017.
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of March 31, 2017           
 Natural Gas Dekatherm (Dth) 357
 —
 355
 2
 
 Electricity MWh 346
 —
 346
 —
 
 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
 —
 —
 
             

             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of March 31, 2018           
 Natural Gas Dekatherm (Dth) 237
 —
 237
 —
 
 Electricity MWh (74) —
 (74) —
 
 Financial Transmission Rights (FTRs) MWh 5
 —
 5
 —
 
 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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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 March 31, 2017, 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).
The following table provides information on Power’s credit risk from others,ER&T wholesale counterparties, net of collateral, as of March 31, 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 March 31, 2018, 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).
              
 Rating 
Current
Exposure
 
Securities
Held as
Collateral
 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
   Millions   Millions�� 
 Investment Grade $433
 $94
 $339
 1
 $202
(A)  
 Non-Investment Grade 9
 1
 8
 —
 —
   
 Total $442
 $95
 $347
 1
 $202
   
              
              
 Rating 
Current
Exposure
 Securities held as Collateral 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
   Millions   Millions  
 Investment Grade $337
 $12
 $325
 1
 $191
(A)  
 Non-Investment Grade 3
 —
 3
 —
 —
   
 Total $340
 $12
 $328
 1
 $191
   
              
(A)Represents net exposure of $202 million with PSE&G.
As of March 31, 2017,2018, collateral held from counterparties where Power had credit exposure included $1 million in cash collateral and $94was comprised of $12 million in letters of credit.
As of March 31, 20172018, Power had 159142 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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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 March 31, 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 net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of March 31, 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.

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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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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 March 31, 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 March 31, 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.
             
   Recurring Fair Value Measurements as of March 31, 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) $91
 $(431) $10
 $505
 $7
 
 NDT Fund (C)           
 Equity Securities $1,086
 $—
 $1,084
 $2
 $—
 
 Debt Securities—U.S. Treasury $223
 $—
 $—
 $223
 $—
 
 Debt Securities—Govt Other $285
 $—
 $—
 $285
 $—
 
 Debt Securities—Corporate $456
 $—
 $—
 $456
 $—
 
 Rabbi Trust (C)           
 Equity Securities $23
 $—
 $23
 $—
 $—
 
 Debt Securities—U.S. Treasury $54
 $—
 $—
 $54
 $—
 
 Debt Securities—Govt Other $35
 $—
 $—
 $35
 $—
 
 Debt Securities—Corporate $113
 $—
 $—
 $113
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(12) $429
 $(6) $(435) $—
 
 PSE&G           
 Assets:           
 Rabbi Trust (C)           
 Equity Securities $4
 $—
 $4
 $—
 $—
 
 Debt Securities—U.S. Treasury $11
 $—
 $—
 $11
 $—
 
 Debt Securities—Govt Other $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Corporate $23
 $—
 $—
 $23
 $—
 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $91
 $(431) $10
 $505
 $7
 
 NDT Fund (C)           
 Equity Securities $1,086
 $—
 $1,084
 $2
 $—
 
 Debt Securities—U.S. Treasury $223
 $—
 $—
 $223
 $—
 
 Debt Securities—Govt Other $285
 $—
 $—
 $285
 $—
 
 Debt Securities—Corporate $456
 $—
 $—
 $456
 $—
 
 Rabbi Trust (C)           
 Equity Securities $6
 $—
 $6
 $—
 $—
 
 Debt Securities—U.S. Treasury $13
 $—
 $—
 $13
 $—
 
 Debt Securities—Govt Other $9
 $—
 $—
 $9
 $—
 
 Debt Securities—Corporate $28
 $—
 $—
 $28
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(12) $429
 $(6) $(435) $—
 
             
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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   Recurring Fair Value Measurements as of March 31, 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) $125
 $—
 $125
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $205
 $(585) $11
 $774
 $5
 
 Interest Rate Swaps (C) $2
 $—
 $—
 $2
 $—
 
 NDT Fund (D)           
 Equity Securities $1,007
 $—
 $1,005
 $2
 $—
 
 Debt Securities—US Treasury $223
 $—
 $—
 $223
 $—
 
 Debt Securities—Govt Other $294
 $—
 $—
 $294
 $—
 
 Debt Securities—Corporate $343
 $—
 $—
 $343
 $—
 
 Other Securities $46
 $—
 $46
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $22
 $—
 $22
 $—
 $—
 
 Debt Securities—US Treasury $36
 $—
 $—
 $36
 $—
 
 Debt Securities—Govt Other $62
 $—
 $—
 $62
 $—
 
 Debt Securities—Corporate $99
 $—
 $—
 $99
 $—
 
 Other Securities $2
 $—
 $2
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(8) $585
 $(6) $(585) $(2) 
 Interest Rate Swaps (C) $—
 $—
 $—
 $—
 $—
 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $125
 $—
 $125
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $1
 $—
 $—
 $—
 $1
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—US Treasury $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Govt Other $12
 $—
 $—
 $12
 $—
 
 Debt Securities—Corporate $20
 $—
 $—
 $20
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $—
 $—
 $—
 $—
 $—
 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $204
 $(585) $11
 $774
 $4
 
 NDT Fund (D)           
 Equity Securities $1,007
 $—
 $1,005
 $2
 $—
 
 Debt Securities—US Treasury $223
 $—
 $—
 $223
 $—
 
 Debt Securities—Govt Other $294
 $—
 $—
 $294
 $—
 
 Debt Securities—Corporate $343
 $—
 $—
 $343
 $—
 
 Other Securities $46
 $—
 $46
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $6
 $—
 $6
 $—
 $—
 
 Debt Securities—US Treasury $9
 $—
 $—
 $9
 $—
 
 Debt Securities—Govt Other $15
 $—
 $—
 $15
 $—
 
 Debt Securities—Corporate $25
 $—
 $—
 $25
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(8) $585
 $(6) $(585) $(2) 
             
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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   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—US 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—US 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—US 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—US 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—US 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) 
             
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   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
 $—
 $—
 
 Derivative Contracts:           
 Energy Related Contracts (B) $—
 $—
 $—
 $—
 $—
 
 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:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $—
 $—
 $—
 $—
 $—
 
 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.
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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 exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.
Level 3—For energy-related contracts, which includeUnobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflectiveon the utilization of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.unobservable inputs.
(C)Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different thanAs of March 31, 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 March 31, 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 March 31, 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 investment grade corporate bonds, collateralized mortgage obligations, asset backedasset-backed securities and certain government and USU.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 March 31, 2018 and December 31, 2017, $(4)Power had net cash collateral/margin payments to counterparties of $121 million and $146 million, respectively. Of these net cash collateral/margin payments $(2) million as of cash collateral was netted against assets,March 31, 2018 and $4$44 million was netted against liabilities. Asas of December 31, 2016, net cash collateral (received) paid of $1 million was2017 were netted against the corresponding net derivative contract positions. The $(2) million of cash collateral as of March 31, 2018 was netted against assets. 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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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 Risk Management CommitteeRMC 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
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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 is measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’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 March 31, 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 March 31, 2017 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 PSE&G             
 Gas Natural Gas Supply Contract $1
 $—
 Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth 
 Total PSE&G   $1
 $—
       
 Power             
 Electricity Electric Load Contracts $4
 $(2) Discounted Cash flow Historic Load Variability 0% to +10% 
 Gas (A) Other —
 —
       
 Total Power   $4
 $(2)       
 Total PSEG   $5
 $(2)       
               
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   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position March 31, 2018 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 Power             
 Electricity Electric Load Contracts $6
 $—
 Discounted Cash flow Historic Load Variability 0% to 10% 
 Gas Gas Physical Contracts 1
 —
 Discounted Cash flow Average Historical Basis -40% to 0% 
 Total Power   $7
 $—
       
 Total PSEG   $7
 $—
       
               
               
   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)       
               
(A) Includes gas positions which were immaterial as of March 31, 2017 and December 31, 2016.
               
   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)       
               
Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value. 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 ended March 31, 20172018 and March 31, 2016,2017, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months Ended March 31, 2018
                 
   Three Months Ended March 31, 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 March 31, 2018 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $7
 $(1) $—
 $—
 $1
 $—
 $7
 
 Power               
 Net Derivative Assets (Liabilities) $7
 $(1) $—
 $—
 $1
 $—
 $7
 
                 

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months Ended March 31, 2017
                 
   Three Months Ended March 31, 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 March 31, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $1
 $19
 $6
 $—
 $(22) $(1) $3
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(5) $—
 $6
 $—
 $—
 $—
 $1
 
 Power               
 Net Derivative Assets (Liabilities) $6
 $19
 $—
 $—
 $(22) $(1) $2
 
                 


(A)PSEG’s and Power’s gains(losses) attributable to changes in net derivative assets and liabilities for the three months ended March 31, 2018 include $8 million in Operating Revenues, all of which is unrealized and $(9) million in Energy Costs, all of which is unrealized. For the three months ended March 31, 2017, $14 million is included in Operating Revenues, of which $(4) million is unrealized, and $5 million is in Energy Costs, of which $1 million is unrealized. Unrealized gains (losses) represent the change in derivative assets and liabilities still held at the end of the reporting period.
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Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months Ended March 31, 2016
                 
   Three Months Ended March 31, 2016   
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2016 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of March 31, 2016 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $13
 $15
 $8
 $—
 $(15) $—
 $21
 
 PSE&G               
 Net Derivative Assets (Liabilities) $2
 $—
 $8
 $—
 $—
 $—
 $10
 
 Power               
 Net Derivative Assets (Liabilities) $11
 $15
 $—
 $—
 $(15) $—
 $11
 
                 
(A)PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $19 million and $15 million in Operating Income for the three months ended March 31, 2017 and 2016, respectively. Of the $19 million in Operating Income, $3 million is unrealized. The $15 million in Operating Income is realized.
(B)Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.
(C)Represents $(22)$1 million and $(15)$(22) million in settlements for the three months ended March 31, 20172018 and 2016,2017, respectively.
(D)
During the three months ended March 31, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in to or out of Level 3 during 2016.
As of March 31, 2018, PSEG carried $2.4 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of March 31, 2017, PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $3 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of March 31, 2016, PSEG carried $2.8 billion of net assets that are measured at fair value on a recurring basis, of which $21 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
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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 March 31, 20172018 and December 31, 20162017.
          
  As of As of 
  March 31, 2017 December 31, 2016 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (Parent) (A)$1,196
 $1,184
 $1,195
 $1,185
 
 PSE&G (B)7,819
 8,349
 7,818
 8,240
 
 Power - Recourse Debt (B)2,383
 2,611
 2,382
 2,578
 
 Total Long-Term Debt$11,398
 $12,144
 $11,395
 $12,003
 
          
          
  As of As of 
  March 31, 2018 December 31, 2017 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (A) (B)$2,092
 $2,048
 $2,091
 $2,081
 
 PSE&G (B)8,593
 8,908
 8,591
 9,322
 
 Power (B)2,387
 2,566
 2,386
 2,659
 
 Total Long-Term Debt$13,072
 $13,522
 $13,068
 $14,062
 
          
(A)Fair value includes a $500 millionIncludes floating rate term loan and net offsets.loans of $700 million. The fair valuevalues of the term loan debt (Level 2 measurement) was considered to be equal toapproximate the carrying valuevalues because the interest payments are based on LIBOR rates that are reset monthly.monthly and the debt is redeemable at face value by PSEG at any time.
(B)Given that mostthese 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.

Note 13. Other Income and Deductions
          
 Other IncomePSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended March 31, 2017        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $31
 $—
 $31
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Rabbi Trust Realized Gains, Interest and Dividends3
 4
 9
 16
 
 Solar Loan Interest5
 —
 —
 5
 
 Other3
 3
 —
 6
 
   Total Other Income$25
 $38
 $9
 $72
 
 Three Months Ended March 31, 2016        
 NDT Fund Gains, Interest, Dividend and Other Income$—
 $25
 $—
 $25
 
 Allowance for Funds Used During Construction11
 —
 —
 11
 
 Solar Loan Interest6
 —
 —
 6
 
 Other3
 1
 2
 6
 
 Total Other Income$20
 $26
 $2
 $48
 
          
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Note 14. Other Income (Deductions)
          
 Other DeductionsPSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended March 31, 2017        
   NDT Fund Realized Losses and Expenses$—
 $7
 $—
 $7
 
   Other1
 —
 3
 4
 
     Total Other Deductions$1
 $7
 $3
 $11
 
 Three Months Ended March 31, 2016        
   NDT Fund Realized Losses and Expenses$—
 $18
 $—
 $18
 
   Other1
 —
 2
 3
 
   Total Other Deductions$1
 $18
 $2
 $21
 
          
          
  PSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended March 31, 2018        
 NDT Fund Interest and Dividends$—
 $12
 $—
 $12
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Solar Loan Interest4
 —
 —
 4
 
 Other2
 (1) 1
 2
 
   Total Other Income (Deductions)$20
 $11
 $1
 $32
 
 Three Months Ended March 31, 2017        
 NDT Fund Interest and Dividends$—
 $10
 $—
 $10
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Solar Loan Interest5
 —
 —
 5
 
 Other3
 1
 (1) 3
 
 Total Other Income (Deductions)$22
 $11
 $(1) $32
 
          
(A)Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

Note 14.15. Income Taxes
PSEG’s, PSE&G’s and Power’s effective tax rates for the three months ended March 31, 20172018 and 20162017 were as follows:
       
   Three Months Ended 
   March 31, 
   2017 2016 
 PSEG 20.3% 37.5% 
 PSE&G 36.4% 36.6% 
 Power 40.6% 40.2% 
       
       
   Three Months Ended 
   March 31, 
   2018 2017 
 PSEG 26.6% 20.3% 
 PSE&G 26.8% 36.4% 
 Power 26.2% 40.6% 
       
For the three months ended March 31, 2017,2018, the overall decreasedifference in PSEG’s effective tax ratesrate as compared to the same period in the prior year was due primarily to the absence of benefits associated with uncertain tax positions and interest received in 2017 from a New Jersey state income tax refund, offset by the change in the statutory federal tax rate from 35% to 21% as wella result of the Tax Act. For the three months ended March 31, 2018, the difference in PSEG’s effective tax rate as compared to the statutory tax rate of 40.85%,28.11% was due primarily to changes in uncertain tax positions, tax credits and plant-related items.
For the three months ended March 31, 2018, the difference in PSE&G’s effective tax rate as compared to the same period in the prior year was 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 in 2017. For the three months ended March 31, 2018, the difference in PSE&G’s effective tax rate as compared to the statutory tax rate of 28.11% was due primarily to plant-related items and tax credits.
For the three months ended March 31, 2018, the difference in Power’s effective tax rate as compared to the same period in the prior year was 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 ended March 31, 2018, the difference in Power’s effective tax rate as compared to the statutory tax rate of 28.11% was due primarily to changes in uncertain tax positions and interestthe additional tax benefit on a New Jersey State refund.pre-tax loss on the NDT qualified fund being taxed at a higher rate than the statutory rate.
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 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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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. In addition, long production property placed in service in 2020 will also qualify for 30%the 50% bonus 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 tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits
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 have a negative impact on the rate base of several ofno longer apply to PSE&G’s programs.&G.

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Note 15.16. Accumulated Other Comprehensive Income (Loss), Net of Tax
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended March 31, 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 —
 —
 30
 30
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 6
 (15) (9) 
 Net Current Period Other Comprehensive Income (Loss) —
 6
 15
 21
 
 Balance as of March 31, 2017 $2
 $(392) $148
 $(242) 
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended March 31, 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
 —
 10
 12
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 8
 6
 14
 
 Net Current Period Other Comprehensive Income (Loss) 2
 8
 16
 26
 
 Balance as of March 31, 2016 $2
 $(378) $107
 $(269) 
           
           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended March 31, 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 —
 —
 28
 28
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 5
 (9) (4) 
 Net Current Period Other Comprehensive Income (Loss) —
 5
 19
 24
 
 Balance as of March 31, 2017 $—
 $(335) $148
 $(187) 
           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended March 31, 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 —
 —
 10
 10
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 6
 13
 
 Net Current Period Other Comprehensive Income (Loss) —
 7
 16
 23
 
 Balance as of March 31, 2016 $—
 $(320) $103
 $(217) 
           
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended March 31, 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 —
 —
 (16) (16) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 8
 2
 10
 
 Net Current Period Other Comprehensive Income (Loss) —
 8
 (14) (6) 
 Net Change in Accumulative Other Comprehensive Income (Loss) —
 8
 (190) (182) 
 Balance as of March 31, 2018 $—
 $(398) $(13) $(411) 
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended March 31, 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 —
 —
 30
 30
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 6
 (15) (9) 
 Net Current Period Other Comprehensive Income (Loss) —
 6
 15
 21
 
 Balance as of March 31, 2017 $2
 $(392) $148
 $(242) 
           
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2017 
   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
 
    Amortization of Actuarial Loss O&M Expense (12) 5
 (7) 
 Total Pension and OPEB Plans (10) 4
 (6) 
 Available-for-Sale Securities       
 Realized Gains Other Income 36
 (17) 19
 
 Realized Losses Other Deductions (7) 3
 (4) 
 OTTI OTTI (1) 1
 —
 
 Total Available-for-Sale Securities 28
 (13) 15
 
 Total   $18
 $(9) $9
 
           
           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended March 31, 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 —
 —
 (13) (13) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 6
 2
 8
 
 Net Current Period Other Comprehensive Income (Loss) —
 6
 (11) (5) 
 Net Change in Accumulative Other Comprehensive Income (Loss) —
 6
 (186) (180) 
 Balance as of March 31, 2018 $—
 $(341) $(11) $(352) 
           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended March 31, 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 —
 —
 28
 28
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 5
 (9) (4) 
 Net Current Period Other Comprehensive Income (Loss) —
 5
 19
 24
 
 Balance as of March 31, 2017 $—
 $(335) $148
 $(187) 
           
            
 PSEG     Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
      Three Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations  March 31, 2016 
    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
 
    Amortization of Actuarial Loss O&M Expense  (17) 7
 (10) 
 Total Pension and OPEB Plans  (14) 6
 (8) 
 Available-for-Sale Securities        
 Realized Gains Other Income  16
 (8) 8
 
 Realized Losses Other Deductions  (17) 8
 (9) 
 OTTI OTTI  (10) 5
 (5) 
 Total Available-for-Sale Securities  (11) 5
 (6) 
 Total    $(25) $11
 $(14) 
            
           
 PSEG   Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2018 
   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
 
    Amortization of Actuarial Loss 
Non-Operating Pension and OPEB Credits (Costs)

 (12) 3
 (9) 
 Total Pension and OPEB Plans (11) 3
 (8) 
 Available-for-Sale Debt Securities       
 Realized Gains (Losses) 
Net Gains (Losses) on Trust Investments

 (4) 2
 (2) 
 Total Available-for-Sale Debt Securities (4) 2
 (2) 
 Total   $(15) $5
 $(10) 
           
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2017 
   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
 
    Amortization of Actuarial Loss O&M Expense (11) 5
 (6) 
 Total Pension and OPEB Plans (9) 4
 (5) 
 Available-for-Sale Securities       
 Realized Gains Other Income 25
 (13) 12
 
 Realized Losses Other Deductions (5) 2
 (3) 
 OTTI OTTI (1) 1
 —
 
 Total Available-for-Sale Securities 19
 (10) 9
 
 Total   $10
 $(6) $4
 
           
           
 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2017 
   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
 
    Amortization of Actuarial Loss 
Non-Operating Pension and OPEB Credits (Costs)

 (12) 5
 (7) 
 Total Pension and OPEB Plans (10) 4
 (6) 
 Available-for-Sale Securities       
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

 28
 (13) 15
 
 Total Available-for-Sale Securities 28
 (13) 15
 
 Total   $18
 $(9) $9
 
           
           
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2016 
   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
 
    Amortization of Actuarial Loss O&M Expense (15) 6
 (9) 
 Total Pension and OPEB Plans (12) 5
 (7) 
 Available-for-Sale Securities       
 Realized Gains Other Income 15
 (8) 7
 
 Realized Losses Other Deductions (16) 8
 (8) 
 OTTI OTTI (10) 5
 (5) 
 Total Available-for-Sale Securities (11) 5
 (6) 
 Total   $(23) $10
 $(13) 
           
           
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2018 
   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
 
    Amortization of Actuarial Loss 
Non-Operating Pension and OPEB Credits (Costs)

 (10) 3
 (7) 
 Total Pension and OPEB Plans (9) 3
 (6) 
 Available-for-Sale Debt Securities       
 Realized Gains (Losses) 
Net Gains (Losses) on Trust Investments

 (4) 2
 (2) 
 Total Available-for-Sale Debt Securities (4) 2
 (2) 
 Total   $(13) $5
 $(8) 
           

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2017 
   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
 
    Amortization of Actuarial Loss 
Non-Operating Pension and OPEB Credits (Costs)

 (11) 5
 (6) 
 Total Pension and OPEB Plans (9) 4
 (5) 
 Available-for-Sale Securities       
 Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 19
 (10) 9
 
 Total Available-for-Sale Securities 19
 (10) 9
 
 Total   $10
 $(6) $4
 
           

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 March 31, 
   2017 2016 
   Basic Diluted Basic Diluted 
 
EPS Numerator (Millions):
         
 Net Income $114
 $114
 $471
 $471
 
 
EPS Denominator (Millions):
         
 Weighted Average Common Shares Outstanding 505
 505
 505
 505
 
 Effect of Stock Based Compensation Awards —
 3
 —
 3
 
 Total Shares 505
 508
 505
 508
 
           
 EPS         
 Net Income $0.23
 $0.22
 $0.93
 $0.93
 
           
          
  Three Months Ended March 31, 
  2018 2017 
  Basic Diluted Basic Diluted 
 
EPS Numerator (Millions):
        
 Net Income$558
 $558
 $114
 $114
 
 
EPS Denominator (Millions):
        
 Weighted Average Common Shares Outstanding504
 504
 505
 505
 
 Effect of Stock Based Compensation Awards—
 3
 —
 3
 
 Total Shares504
 507
 505
 508
 
          
 EPS        
 Net Income$1.11
 $1.10
 $0.23
 $0.22
 
          
ThereFor the three months ended March 31, 2017, there were approximately 0.3 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months ended March 31, 2017 and 2016.effect.
Dividends
      
  Three Months Ended 
  March 31, 
 Dividend Payments on Common Stock2017 2016 
 Per Share$0.43
 $0.41
 
 In Millions$218
 $207
 
      

On April 18, 2017, PSEG’s Board of Directors approved a $0.43 per share common stock dividend for the second quarter of 2017.

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Dividends
      
  Three Months Ended 
  March 31, 
 Dividend Payments on Common Stock2018 2017 
 Per Share$0.45
 $0.43
 
 In Millions$227
 $218
 
      

On April 17, 2018, PSEG’s Board of Directors approved a $0.45 per share common stock dividend for the second quarter of 2018.
Note 17.18. Financial Information by Business Segment
            
  PSE&G Power Other (A) Eliminations (B) Consolidated 
  Millions 
 Three Months Ended March 31, 2017          
 Operating Revenues$1,812
 $1,284
 $83
 $(587) $2,592
 
 Net Income (Loss)299
 (170) (15) —
 114
 
 Gross Additions to Long-Lived Assets748
 307
 7
 —
 1,062
 
 Three Months Ended March 31, 2016          
 Operating Revenues$1,712
 $1,313
 $122
 $(531) $2,616
 
 Net Income (Loss)262
 192
 17
 —
 471
 
 Gross Additions to Long-Lived Assets724
 333
 8
 —
 1,065
 
 As of March 31, 2017          
 Total Assets$26,487
 $11,729
 $2,249
 $(801) $39,664
 
 Investments in Equity Method Subsidiaries$—
 $103
 $—
 $—
 $103
 
 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 March 31, 2018          
 Operating Revenues$1,845
 $1,403
 $147
 $(577) $2,818
 
 Net Income (Loss)319
 234
 5
 —
 558
 
 Gross Additions to Long-Lived Assets750
 299
 4
 —
 1,053
 
 Three Months Ended March 31, 2017          
 Operating Revenues$1,826
 $1,269
 $83
 $(587) $2,591
 
 Net Income (Loss)299
 (170) (15) —
 114
 
 Gross Additions to Long-Lived Assets748
 307
 7
 —
 1,062
 
 As of March 31, 2018          
 Total Assets$28,774
 $12,263
 $2,481
 $(728) $42,790
 
 Investments in Equity Method Subsidiaries$—
 $86
 $—
 $—
 $86
 
 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 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.

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(UNAUDITED)
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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 
  March 31, 
 Related-Party Transactions2017 2016 
  Millions 
 Billings from Affiliates:    
 Net Billings from Power primarily through BGS and BGSS (A)$599
 $545
 
 Administrative Billings from Services (B)65
 69
 
 Total Billings from Affiliates$664
 $614
 
      
       
   Three Months Ended 
   March 31, 
 Related-Party Transactions 2018 2017 
  Millions 
 Billings from Affiliates:     
 Net Billings from Power primarily through BGS and BGSS (A) $578
 $599
 
 Administrative Billings from Services (B) 83
 65
 
 Total Billings from Affiliates $661
 $664
 
       
      
  As of As of 
 Related-Party TransactionsMarch 31, 2018 December 31, 2017 
  Millions 
 Payable to Power (A)$215
 $221
 
 Payable to Services (B)65
 78
 
 Payable to PSEG (C)105
 41
 
 Accounts Payable—Affiliated Companies$385
 $340
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$93
 $91
 
      
Power
The financial statements for Power include transactions with related parties presented as follows:
       
   Three Months Ended 
   March 31, 
 Related-Party Transactions 2018 2017 
  Millions 
 Billings to Affiliates:     
 Net Billings to PSE&G primarily through BGS and BGSS (A) $578
 $599
 
 Billings from Affiliates:     
 Administrative Billings from Services (B) $43
 $36
 
       
      
  As of As of 
 Related-Party TransactionsMarch 31, 2018 December 31, 2017 
  Millions 
 Receivables from PSE&G (A)$215
 $221
 
 Accounts Receivable—Affiliated Companies$215
 $221
 
 Payable to Services (B)$23
 $28
 
 Payable to PSEG (C)46
 29
 
 Accounts Payable—Affiliated Companies$69
 $57
 
 Short-Term Loan from Affiliate (E)$35
 $281
 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$46
 $52
 
      
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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  As of As of 
 Related-Party TransactionsMarch 31, 2017 December 31, 2016 
  Millions 
 Receivables from PSEG (C)$34
 $76
 
 Payable to Power (A)$175
 $193
 
 Payable to Services (B)43
 67
 
 Accounts Payable—Affiliated Companies$218
 $260
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$116
 $130
 
      
Power
The financial statements for Power include transactions with related parties as follows:
      
  Three Months Ended 
  March 31, 
 Related-Party Transactions2017 2016 
  Millions 
 Billings to Affiliates:    
 Net Billings to PSE&G primarily through BGS and BGSS (A)$599
 $545
 
 Billings from Affiliates:    
 Administrative Billings from Services (B)$36
 $45
 
      
      
  As of As of 
 Related-Party TransactionsMarch 31, 2017 December 31, 2016 
  Millions 
 Receivables from PSE&G (A)$175
 $193
 
 Receivables from PSEG (C)—
 12
 
 Accounts Receivable—Affiliated Companies$175
 $205
 
 Payable to Services (B)$10
 $25
 
 Payable to PSEG (C)71
 —
 
 Accounts Payable—Affiliated Companies$81
 $25
 
 Short-Term Loan Due (to) from Affiliate (E)$157
 $87
 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$78
 $77
 
      
(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)
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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 March 31, 20172018 and December 31, 20162017 and for the three months ended March 31, 20172018 and 2016.2017.
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended March 31, 2017          
 Operating Revenues$—
 $1,270
 $52
 $(38) $1,284
 
 Operating Expenses4
 1,569
 52
 (38) 1,587
 
 Operating Income (Loss)(4) (299) —
 —
 (303) 
 Equity Earnings (Losses) of Subsidiaries(161) (1) 3
 162
 3
 
 Other Income25
 41
 —
 (28) 38
 
 Other Deductions(1) (6) —
 —
 (7) 
 Other-Than-Temporary Impairments—
 (1) —
 —
 (1) 
 Interest Expense(30) (9) (5) 28
 (16) 
 Income Tax Benefit (Expense)1
 111
 4
 —
 116
 
 Net Income (Loss)$(170) $(164) $2
 $162
 $(170) 
 Comprehensive Income (Loss)$(146) $(143) $2
 $141
 $(146) 
 Three Months Ended March 31, 2017          
 
Net Cash Provided By (Used In)
   Operating Activities
$77
 $377
 $91
 $35
 $580
 
 
Net Cash Provided By (Used In)
   Investing Activities
$251
 $20
 $(154) $(511) $(394) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(328) $(395) $68
 $476
 $(179) 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended March 31, 2016          
 Operating Revenues$—
 $1,302
 $42
 $(31) $1,313
 
 Operating Expenses10
 952
 39
 (31) 970
 
 Operating Income (Loss)(10) 350
 3
 —
 343
 
 Equity Earnings (Losses) of Subsidiaries205
 (1) 2
 (204) 2
 
 Other Income17
 32
 —
 (23) 26
 
 Other Deductions—
 (18) —
 —
 (18) 
 Other-Than-Temporary Impairments—
 (10) —
 —
 (10) 
 Interest Expense(30) (10) (5) 23
 (22) 
 Income Tax Benefit (Expense)10
 (140) 1
 —
 (129) 
 Net Income (Loss)$192
 $203
 $1
 $(204) $192
 
 Comprehensive Income (Loss)$215
 $219
 $1
 $(220) $215
 
 Three Months Ended March 31, 2016          
 
Net Cash Provided By (Used In)
   Operating Activities
$271
 $480
 $47
 $(135) $663
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(598) $(428) $(246) $613
 $(659) 
 
Net Cash Provided By (Used In)
   Financing Activities
$326
 $(51) $203
 $(478) $—
 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended March 31, 2018          
 Operating Revenues$—
 $1,386
 $51
 $(34) $1,403
 
 Operating Expenses—
 1,056
 52
 (34) 1,074
 
 Operating Income (Loss)—
 330
 (1) —
 329
 
 Equity Earnings (Losses) of Subsidiaries234
 (3) 2
 (231) 2
 
 Net Gains (Losses) on Trust Investments—
 (22) —
 —
 (22) 
 Other Income (Deductions)35
 33
 —
 (57) 11
 
 Non-Operating Pension and OPEB Credits (Costs)—
 4
 —
 —
 4
 
 Interest Expense(42) (17) (5) 57
 (7) 
 Income Tax Benefit (Expense)7
 (92) 2
 —
 (83) 
 Net Income (Loss)$234
 $233
 $(2) $(231) $234
 
 Comprehensive Income (Loss)$229
 $223
 $(2) $(221) $229
 
 Three Months Ended March 31, 2018          
 
Net Cash Provided By (Used In)
   Operating Activities
$(5) $525
 $(49) $71
 $542
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(215) $(625) $(82) $605
 $(317) 
 
Net Cash Provided By (Used In)
   Financing Activities
$220
 $100
 $111
 $(677) $(246) 
            
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 As of March 31, 2017          
 Current Assets$4,244
 $1,332
 $174
 $(4,458) $1,292
 
 Property, Plant and Equipment, net56
 5,582
 2,447
 —
 8,085
 
 Investment in Subsidiaries4,104
 343
 —
 (4,447) —
 
 Noncurrent Assets175
 2,154
 129
 (106) 2,352
 
 Total Assets$8,579
 $9,411
 $2,750
 $(9,011) $11,729
 
 Current Liabilities$187
 $3,436
 $1,580
 $(4,458) $745
 
 Noncurrent Liabilities531
 2,171
 527
 (106) 3,123
 
 Long-Term Debt2,383
 —
 —
 —
 2,383
 
 Member’s Equity5,478
 3,804
 643
 (4,447) 5,478
 
 Total Liabilities and Member’s Equity$8,579
 $9,411
 $2,750
 $(9,011) $11,729
 
 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 
 Three Months Ended March 31, 2017          
 Operating Revenues$—
 $1,255
 $52
 $(38) $1,269
 
 Operating Expenses4
 1,556
 52
 (38) 1,574
 
 Operating Income (Loss)(4) (301) —
 —
 (305) 
 Equity Earnings (Losses) of Subsidiaries(161) (1) 3
 162
 3
 
  Net Gains (Losses) on Trust Investments4
 15
 —
 —
 19
 
 Other Income (Deductions)20
 19
 —
 (28) 11
 
 Non-Operating Pension and OPEB Credits (Costs)—
 2
 —
 —
 2
 
 Interest Expense(30) (9) (5) 28
 (16) 
 Income Tax Benefit (Expense)1
 111
 4
 —
 116
 
 Net Income (Loss)$(170) $(164) $2
 $162
 $(170) 
 Comprehensive Income (Loss)$(146) $(143) $2
 $141
 $(146) 
 Three Months Ended March 31, 2017          
 
Net Cash Provided By (Used In)
   Operating Activities
$77
 $377
 $91
 $35
 $580
 
 
Net Cash Provided By (Used In)
   Investing Activities
$251
 $20
 $(154) $(511) $(394) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(328) $(395) $68
 $476
 $(179) 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 As of March 31, 2018          
 Current Assets$4,168
 $1,392
 $189
 $(4,631) $1,118
 
 Property, Plant and Equipment, net55
 5,094
 3,540
 —
 8,689
 
 Investment in Subsidiaries5,089
 1,115
 —
 (6,204) —
 
 Noncurrent Assets90
 2,295
 109
 (38) 2,456
 
 Total Assets$9,402
 $9,896
 $3,838
 $(10,873) $12,263
 
 Current Liabilities$548
 $3,234
 $1,874
 $(4,631) $1,025
 
 Noncurrent Liabilities521
 1,961
 461
 (38) 2,905
 
 Long-Term Debt2,137
 —
 —
 —
 2,137
 
 Member’s Equity6,196
 4,701
 1,503
 (6,204) 6,196
 
 Total Liabilities and Member’s Equity$9,402
 $9,896
 $3,838
 $(10,873) $12,263
 
 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
 
            

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ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and Power each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG’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 demand responserelated 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 and fuel supply functions 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) transmission and distribution (T&D) system under an Operations and Services Agreement contractual agreement;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:
improving utility operations through growth in 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 expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.




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Financial Results
The results for PSEG, PSE&G and Power for the three months ended March 31, 20172018 and 20162017 are presented as follows:
       
   Three Months Ended 
   March 31, 
 Earnings (Losses) 2017 2016 
  Millions 
 PSE&G $299
 $262
 
 Power (A) (170) 192
 
 Other (B) (15) 17
 
 PSEG Net Income $114
 $471
 
       
 PSEG Net Income Per Share (Diluted) $0.22
 $0.93
 
       
      
  Three Months Ended 
  March 31, 
 Earnings (Losses)2018 2017 
  Millions 
 PSE&G$319
 $299
 
 Power (A)234
 (170) 
 Other (B)5
 (15) 
 PSEG Net Income$558
 $114
 
      
 PSEG Net Income Per Share (Diluted)$1.10
 $0.22
 
      
(A)Includes after-tax expenses of $334 million primarily for accelerated depreciation related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants infor the three months ended March 31, 2017. 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 an after-tax chargecharges of $32 million related to its investments in NRG REMA, LLC’s (REMA) leveraged leases in the three months ended March 31, 2017. 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 
   March 31, 
   2017 2016 
  Millions, after tax 
 NDT Fund Income (Expense) (A) (B) $8
 $(5) 
 Non-Trading MTM Gains (Losses) (C) $6
 $13
 
       
      
  Three Months Ended 
  March 31, 
  2018 2017 
  Millions, after tax 
 NDT Fund Income (Expense) (A) (B)$(16) $8
 
 Non-Trading MTM Gains (Losses) (C)$85
 $6
 
      
(A)NDT Fund Income (Expense) includes the realized gains and losses and other-than-temporary impairments on certain NDT securities in 2018 and 2017 and unrealized gains and losses on equity securities in 2018, all of which are recorded in Net Gains (Losses) on Trust Investments. 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 $(9)$8 million and $3$(9) million for the three months ended March 31, 20172018 and 2016,2017, respectively.
(C)Net of tax (expense) benefit of $(4)$(33) million and $(10)$(4) million for the three months ended March 31, 20172018 and 2016,2017, respectively.
Our $357$444 million decreaseincrease in Net Income for the three months ended March 31, 20172018 was driven primarilylargely by
accelerated depreciation in 2017 related to the early retirement of our Hudson and Mercer coal/gas generation units, at Power (see Item 1. Note 3. Early Plant Retirements),
a decreasecharges in energy sales due primarily to lower average realized sales prices, and
a charge2017 for estimated losses related to our leveraged lease investments, (see Item 1. Note 6. Financing Receivables).
These decreases were partially offset by:the favorable impact at Power from the lower federal tax rate effective January 1, 2018,
higher net MTM gains in 2018, and
higher transmission revenues and
increased gas distribution revenues.in 2018.

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During the first three months of 2017,2018, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, 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 to our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.
At PSE&G, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong programProgram that was approved by the BPU in 2014 and to seek recovery on such investments. We also continue to modernizeare modernizing PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. As a result of our Energy Strong Order from the BPU, we will be required to file a distribution base rate case proceeding by no later than November 1, 2017. We cannot predict the impact such proceeding will have on our distribution business.
Although the weather in the first quarter of 2017 was warmer than normal, Power’s results saw a continuing benefit from access to natural gas supplies throughPower manages its existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the BGSSbasic gas supply service (BGSS) arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power canmay 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. Power’s hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in 20172018 relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.
Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station Unit 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.
Since 2013, several nuclear generating stations in 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 low natural gas prices, and the related decline in market prices of energy, resulting from 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 electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet and greater reliance on natural gas pipelines for fuel delivery.
If trends noted above continue or worsen, our 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 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 nuclear decommissioning trust funds will 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 and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.
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.

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Transmission
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 in Hope Creek at a cost of approximately $130 million.  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) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to an adjustment,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. While we are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, theThe 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 is expected to bewas 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”)(seasonal resources). However, FERC recently scheduled a technical conference in response to two complaints remain pendingrequesting that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions. We do not expect action oncannot predict the complaints beforeoutcome of these matters.

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In April 2018, PJM submitted two proposed alternative and 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 upcoming 2020/2021 base residual auction in May 2017.
Asother option would be to extend the existing Minimum Offer Price Rule (MOPR) to units that are receiving subsidies. We are currently evaluating these two proposals. In a result of the efforts of certain entities in PJM to obtain financial support arrangements from their state commissions,related matter that is currently pending at FERC, a group of suppliers requested that FERC direct PJM to expand the currently effective “minimum offer price rule”MOPR 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 these proceedings.
In November 2017, PJM issued an energy price formation proposal to address a flaw in the energy market by allowing all resources selected for dispatch, both flexible and inflexible, to set price and consequently, result in prices that more accurately reflect the true cost to serve load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot predict the outcome of this matter.
Distribution
The BPU has enacted Infrastructure Investment Program (IIP) regulations that 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 these regulations, utilities can 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. 
In July 2017, we filed a petition with the BPU for a GSMP II program, an extension of GSMP to continue to modernize our gas system. In April 2018, we reached a settlement with the BPU Staff, Division of Rate Counsel and other parties. Under the GSMP II program, PSE&G will invest $1.9 billion over five years beginning in 2019 to replace approximately 175 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 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 Energy Strong Program, a $1.2 billion investment program to harden and make the electric and gas distribution system more resilient, is expected to be completed during 2018. PSE&G expects to file for a five year extension and expansion of the Energy Strong Program in the second quarter of 2018. The extension would seek 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 the Energy Strong Program extension, as well as PSE&G’s return on equity and certain other elements of the program, are subject to BPU approval.
In January 2018, PSE&G filed a distribution base rate case as required as a condition of approval of its Energy Strong Program 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 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 over-collection 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 will increase accordingly. 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
In April 2018, the New Jersey Legislature approved legislation that would require the state’s electric and gas utilities to implement energy efficiency programs that would achieve energy savings of at least 2% per year for electric usage and 0.75% per year for 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

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legislation. The legislation will require utilities to make filings with the BPU outlining their planned investments and proposed programs for cost-effectively achieving the targeted energy savings. These filings are also expected to address the utility’s return of and on those investments and recovery of lost revenues associated with the lower sales. PSE&G cannot predict whether the legislation will be enacted. If enacted, the BPU will issue rules to implement the legislation. PSE&G is evaluating opportunities to broaden its existing energy efficiency programs to achieve New Jersey’s targeted results, as well as make investments to facilitate the development of the electric vehicle market and a pilot program for energy storage investments. 
Environmental Regulation
We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act (FWPCA) requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.
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. Upon completionIn October 2017, the EPA Administrator signed a proposed repeal of the review,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). The EPA is expectedconsidering rulemaking to suspend, revise or rescindreplace the rules as appropriate. CPP. PSEG cannot assess the impact of any such rulemaking on its 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.

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FERC Compliance
Since SeptemberIn the first quarter of 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation ofPower discovered that it incorrectly calculated certain components of Power’sits cost-based bids for its New Jersey fossil generating units in the PJM energy marketmarket. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units compared todiffered from the amountsamount for which Power was compensated in the capacity market for those units. While considerable uncertainty remains asPSEG 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 finalrisk of similar issues occurring in the future.
Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into these matters. In April 2018, a settlement agreement was entered into between PSEG and FERC Staff, approved by FERC on April 25, 2018, pursuant to which PSEG agreed to pay approximately $40 million for the full resolution of these matters, based upon recent developments in the investigation,this matter. Accordingly, 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 recordingrecorded an additional pre-tax charge to income of $10$5 million duringin the three months ended March 31, 2017. PSEG is unable to reasonably estimate the rangefirst quarter of possible loss, if any,2018, resulting in a total liability of approximately $40 million accrued for the quantityresolution of energy offered matter or the penaltiesthis matter. The settlement agreement does not require PSEG to change its business practices in a manner that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individuallyhave a material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Note 9. Commitments and Contingent Liabilities.impact on its ongoing business operations.
Early Retirement of Hudson and Mercer Units
In October 2016,On June 1, 2017, Power determined it will ceasecompleted its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. The exact timing of the early retirement of these units may be impacted by operational and other conditions that could subsequently arise.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 continuescontinued to adversely impact their results of operations in 2017. During the first three monthsAs of June 1, 2017, Power recognizedcompleted recognition of the incremental D&ADepreciation and Amortization (D&A) of $558$938 million ($574964 million in total) and expects to recognize an additional incremental $379 million ($389 million in total) in 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first quarter of 2017, Energy Costs of $7 million for coal inventory adjustments was also incurred and other costs may be incurred during the remaining period in 2017 prior to retirement. 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

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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 enactment of proposed legislation in the state of New Jersey. At a co-owners meeting in February 2018, Exelon and Power 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. The companies agreed that the funding of these projects may be restored when and if legislation is enacted in New Jersey that 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 April 2018, the New Jersey Legislature voted to pass legislation that would provide a safety net in order to prevent the loss of environmental attributes from selected nuclear generating stations. Power cannot predict whether the legislation will be enacted or, if enacted, 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 market prices continue to be depressed and legislation is not enacted that adequately compensates 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), and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the parent company of NRGUnited States Bankruptcy Code on June 14, 2017. REMA LLC, (REMA), reportedwas not included in August 2016 that it did not expectthe GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to have sufficient liquidity to repay their senior unsecured notes due in June 2017. Although all lease payments are current,complete. PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfoliobalance sheet and improve its liquidity and the possible related impact on REMA.liquidity.
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 certain recent discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its investments in the REMA leases, which was reflected in Operating Revenues. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged leases.lease receivables, and continue to discuss the situation with various parties relevant to this matter. 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

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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 ShawvillePowerton generating facilities, which were converted to usefacilities. Converted natural gas units such as Shawville and Powerton, a coal facility. However, these unitsJoliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. AsPowerton is a result,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 leaseslease receivables associated with these facilities.

Tax Legislation
TableIn 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 Contents35% to 21%, effective January 1, 2018, and made certain changes to bonus depreciation rules.



Salem
Concurrently with the planned refueling outage at the Salem 2 unit that is scheduled for the second quarter of 2017, we intend to inspect and replace degraded baffle bolts as part of our multi-year project to replace baffle bolts at the Salem station.As a result weof the enacted reduction in the statutory 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 is also expected to increase 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 duration of this outageinterest on their debt will continue to be modestly longer than our typical refueling outage, which will reduce productionfully tax deductible albeit at a lower tax rate. For PSE&G, the Tax Act is expected to lead to lower customer rates due to lower income tax expense recoveries and the refund of deferred income tax regulatory liabilities, partially offset by the impacts of higher rate base. 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 result in lower operating cash flows for PSE&G resulting from the nuclear capacity factor for the second quarterelimination of 2017 as comparedbonus depreciation, partially offset by higher revenues due to the first quarterhigher rate base. Due to the recent enactment of 2017.the Tax Act, the full impact of these and other provisions of the Tax Act cannot be determined at this time.

The impact 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 customers. We have made filings to adjust the revenue requirement in certain of our rate matters as a result of the change in the federal income tax rate. We continue to assess whether we need to take any further action at this time.
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.
Operational Excellence
We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs. For the first three months of 2017,2018, our
utility, beginning with comprehensive storm preparation, efficiently and safely completed our utility continued top decile performance in electric reliability,
total nuclear fleet achieved an average capacity factor of 100%,customer restorations and then assisted neighboring utilities with their restoration efforts,
diverse fuel mix and dispatch flexibility allowed us to generate approximately 13 terawatt hours while addressing fuel availability and price volatility, and
combined cycletotal nuclear fleet produced three terawatt hours atachieved an equivalent availabilityaverage capacity factor of 94%99.5%.
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 three months of 20172018 as we
maintained sufficient liquidity,

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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 three months of 2017,2018, we
made additional investments in transmission infrastructure projects,
continued to execute our GSMP, Energy Strong, Energy Efficiency and other existing BPU-approved utility programs, and
continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and began construction ofour BH5 generation project for targeted commercial operationsoperation in mid-2019.
Future Outlook    
Our future success will depend on our ability to continue to maintain strong operational and financial performance in a slow-growing economy and a cost-constrained environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to:
focus on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,
successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,
execute our utility capital investment program, including our Energy Strong program,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, Energy Center (Keys) , Sewaren 7, (BH5)BH5 and other generation projects,

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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 and challenges we expect our business to confront include:
regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,
fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our distribution base rate case proceeding to bewhich was filed with the BPU in 2017,January 2018,
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 comprehensive tax reform, particularly in lightcontinuing impacts of public statements by the current U.S. administration and key members of Congress,Tax Act,
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,

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the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,
delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory approvals, 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,
continued or expanded participation in solar, demand response and energy efficiency programs, and
investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.
In 2016, Power announced its intention to developis developing a retail platformenergy business to sell physical electricity and natural gas,energy, which we believe would begin to complementcomplements our existing wholesale marketing business. Power wasbegan these marketing activities in 2017 and has been granted retail energy supplier licenses in 2016 to sell both electricity and gas in the states of New Jersey, Pennsylvania and Pennsylvania.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)
 
   March 31,  
   2017 2016 2017 vs. 2016 
   Millions Millions % 
 Operating Revenues $2,592
 $2,616
 $(24) (1) 
 Energy Costs 874
 836
 38
 5
 
 Operation and Maintenance 712
 729
 (17) (2) 
 Depreciation and Amortization 828
 224
 604
 270
 
 Income from Equity Method Investments 3
 2
 1
 50
 
 Other Income (Deductions) 61
 27
 34
 126
 
 Other-Than-Temporary Impairments 1
 10
 (9) (90) 
 Interest Expense 98
 92
 6
 7
 
 Income Tax Expense 29
 283
 (254) (90) 
           
           
   Three Months Ended 
Increase/
(Decrease)
 
   March 31,  
   2018 2017 2018 vs. 2017 
   Millions Millions % 
 Operating Revenues $2,818
 $2,591
 $227
 9
 
 Energy Costs 952
 868
 84
 10
 
 Operation and Maintenance 754
 717
 37
 5
 
 Depreciation and Amortization 280
 828
 (548) (66) 
 Income from Equity Method Investments 2
 3
 (1) (33) 
 Net Gains (Losses) on Trust Investments (22) 28
 (50) N/A
 
 Other Income (Deductions) 32
 32
 —
 —
 
 Non-Operating Pension and OPEB Credits (Costs) 19
 —
 19
 N/A
 
 Interest Expense 103
 98
 5
 5
 
 Income Tax Expense 202
 29
 173
 N/A
 
           

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The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.
PSE&G
          
  Three Months Ended 
Increase/
(Decrease)
 
  March 31,  
  2017 2016 2017 vs. 2016 
  Millions Millions % 
 Operating Revenues$1,812
 $1,712
 $100
 6
 
 Energy Costs753
 729
 24
 3
 
 Operation and Maintenance367
 382
 (15) (4) 
 Depreciation and Amortization171
 139
 32
 23
 
 Other Income (Deductions)24
 19
 5
 26
 
 Interest Expense75
 68
 7
 10
 
 Income Tax Expense171
 151
 20
 13
 
          
          
  Three Months Ended 
Increase/
(Decrease)
 
  March 31,  
  2018 2017 2018 vs. 2017 
  Millions Millions % 
 Operating Revenues$1,845
 $1,826
 $19
 1
 
 Energy Costs782
 762
 20
 3
 
 Operation and Maintenance391
 370
 21
 6
 
 Depreciation and Amortization190
 171
 19
 11
 
 Net Gains (Losses) on Trust Investments—
 2
 (2) N/A
 
 Other Income (Deductions)20
 22
 (2) (9) 
 Non-Operating Pension and OPEB Credits (Costs)15
 (2) 17
 N/A
 
 Interest Expense81
 75
 6
 8
 
 Income Tax Expense117
 171
 (54) (32) 
          
Three Months Ended March 31, 20172018 as Compared to 20162017
Operating Revenues increased $100$19 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues increased $58$7 million due primarily to an increase in transmission revenues.
Transmission revenues were $37$8 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
Gas distribution revenues increased $24$5 million due to an $11a $17 million increase from the inclusion of the GSMP in base rates, and a $7 million increase due to the inclusion of Energy Stronghigher sales volumes. These increases were partially offset by a $19 million decrease in base rates, a $5 million increase due to the Gas System Modernization Program, $4 million of higher delivery volumes, higher Green Program Recovery Charges (GPRC) of $2 million and $2 million in higher Weather Normalization Clause revenue.collections.
Electric distribution revenues decreased $3$6 million due to lower GPRC of $3$7 million and a $2 million decrease due toin lower sales volumes and lower Green Program Recovery Charges of $1 million, partially offset by a $2 million increase due tofrom the inclusion of Energy Strong Program in base rates.

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Commodity RevenueRevenues increased $24$20 million as a result of higher GasElectric revenues partially offset by lower ElectricGas revenues. The changes in Commodity revenuerevenues for both gaselectric and electricgas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of basic gas supply service (BGSS)BGS and BGSBGSS to retail customers.
GasElectric commodity revenues increased $74$34 million due primarily to a $29 million increase in BGS revenues due to $21 million in higher BGSS sales prices.
Electric commodity revenues decreased $50volumes and $8 million due primarily to $23from higher prices, a $3 million increase from sales of solar renewable energy credits and $2 million of lowerhigher revenues from collections of Non-Utility Generation Charges (NGC), a $17 million decrease in BGSCharges.
Gas commodity revenues due to lower sales prices and volumes and a decrease of $10decreased $14 million due to lower BGSS sales prices of $32 million, partially offset by higher BGSS sales volumes of Non-Utility Generation (NUG) energy sold.$18 million.
Clause Revenues increased $19decreased $11 million due primarily to the 2016 return to customers of $15a $6 million of overcollections of Securitization Transition Charges (STC),decrease in Margin Adjustment Clause (MAC) revenues and higherlower Societal Benefit Charges (SBC) of $2 million in 2017.$5 million. The changes in the STCMAC and SBC amounts are entirely offset by decreaseschanges in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, Depreciation and AmortizationD&A and Interest Expense. PSE&G does not earn margin on STCMAC or SBC collections.
Operating Expenses
Energy Costs increased $24$20 million. This is entirely offset by the change in Commodity Revenue.Revenues.
Operation and Maintenance decreased $15increased $21 million, of which the most significant components were
primarily due to a $10 million increase in transmission operating expenses, a $6 million decreaseincrease in winter storm costs, a $5 million increase in appliance service costs,
a $4$5 million decreaseincrease in the gas distribution corrective and preventative maintenance,
a $2 million decrease in pension and OPEB costs, net of capitalized amounts and
tariff, a $3 million net decreaseincrease in operationalrenewables and a $5 million increase in other operating expenses. These increases were partially offset by a $13 million reduction in clause-related expenditures.

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Depreciation and Amortization increased $32$19 million due primarily to an increase of $17 million in amortization of Regulatory Assets and a $14$18 million increase in depreciation due to additional plant in service.
Other Incomeservice and (Deductions) increased $5 million due primarily to an increase of $3$2 million in Allowance for Funds Used During Constructionamortization of Regulatory Assets.
Non-Operating Pension and a $3OPEB Credits (Costs) reflected an increase of$17 million increase in realized gains on Rabbi Trust investments.creditsdue 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$6 million due primarily to net debt issuances in 2016.May and December 2017.
Income Tax Expense increased $20decreased $54 million due primarily to higher pre-tax income.the decrease in the federal statutory income tax rate from 35% in 2017 to 21% in 2018, partially offset by uncertain tax positions and plant-related items.

Power
           
   Three Months Ended 
Increase/
(Decrease)
 
   March 31,  
   2017 2016 2017 vs. 2016 
   Millions Millions % 
 Operating Revenues $1,284
 $1,313
 $(29) (2) 
 Energy Costs 707
 638
 69
 11
 
 Operation and Maintenance 230
 253
 (23) (9) 
 Depreciation and Amortization 650
 79
 571
 N/A
 
 Income from Equity Method Investments 3
 2
 1
 50
 
 Other Income (Deductions) 31
 8
 23
 N/A
 
 Other-Than-Temporary Impairments 1
 10
 (9) (90) 
 Interest Expense 16
 22
 (6) (27) 
 Income Tax Expense (Benefit) (116) 129
 (245) N/A
 
           
           
   Three Months Ended 
Increase/
(Decrease)
 
   March 31,  
   2018 2017 2018 vs. 2017 
   Millions Millions % 
 Operating Revenues $1,403
 $1,269
 $134
 11
 
 Energy Costs 746
 692
 54
 8
 
 Operation and Maintenance 246
 232
 14
 6
 
 Depreciation and Amortization 82
 650
 (568) (87) 
 Income from Equity Method Investments 2
 3
 (1) (33) 
 Net Gains (Losses) on Trust Investments (22) 19
 (41) N/A
 
 Other Income (Deductions) 11
 11
 —
 —
 
 Non-Operating Pension and OPEB Credits (Costs) 4
 2
 2
 100
 
 Interest Expense 7
 16
 (9) (56) 
 Income Tax Expense (Benefit) 83
 (116) 199
 N/A
 
           
Three Months Ended March 31, 20172018 as Compared to 20162017
Operating Revenues decreasedincreased $29134 million due to changes in generation and gas supply revenues.

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Generation Revenues decreased $124increased $140 million due primarily to
a net decreasean increase of $95 million in energy sales in the PJM and New England (NE) regions due primarily to lower average realized prices, and
a net decrease of $24$134 million due to higher MTM lossesgains in 20172018 as compared to MTM gains in 2016.2017. Of this amount, $131$112 million was due to changes in forward power prices. The decrease was offset by an increase of $107 million due to losseshigher gains on positions reclassified to realized upon settlement this year as compared to gains last year, and
coupled with a charge of $10$22 million increase due to an increasechanges in the FERC accrual related to the PJM bidding matter, see Note 9. Commitments and Contingent Liabilities,forward prices,
partially offset by a net increase of $10 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM region offset by lower volumes of electricity sold under wholesale load contracts in the New England (NE) region, and
a net increase of $7 million in capacity revenues due primarily to increases in cleared capacity auction prices in the NE region,
partially offset by a net decrease of $13 million in energy sales due primarily to lower volumes and lower average prices.realized prices in the PJM region offset by higher average prices in the NE and New York (NY) regions, and

a decrease of $9 million in electricity sold under our BGS contracts due primarily to lower prices offset by higher volumes.
Gas Supply Revenues increaseddecreased $95$6 million due primarily to
a decrease of $13 million due to MTM losses in 2018 as compared to gains in 2017, and
a decrease of $12 million related to sales to third parties due to lower average sales prices,
partially offset by an increase of $46$19 million in sales under the BGSS contract due primarily to higher average sales prices coupled with an increase in sales volumes due to periodscolder average temperatures in the 2018 winter heating season.

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an increase of $41 million related to sales to third parties due to higher average sales prices, and
a net increase of $8 million due to higher MTM gains in 2017 as compared to 2016, primarily due to losses on positions reclassified to realized upon settlement this year as compared to gains last year.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $69$54 million due to
Generation costs decreased $1increased $43 million due primarily to
a net decrease of $26 million primarily due to lower congestion costs in PJM due to lower congestion rates and volumes,
partially offset by higher fuel costs of $14$46 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset byoil in the PJM region coupled with utilization of lowerhigher volumes and higher prices of natural gas in the NY region, and oil,
an increase of $8$10 million due to MTM losses in 2018 as compared to gains in 2017. Of this amount, $6 million was due to changes in forward prices coupled with an increase of $4 million due to higher losses on positions reclassified to realized upon settlement in 2018,
partially offset by a net decrease of $15 million primarily due to a decrease in energy purchase volumes in the NE region to serve load obligations, and
a $7 million charge associated primarily with a lower of cost or market coal inventory adjustment at Mercer.obligations.
Gas costs increased $70$11 million due mainly to
an increase of $39 million related to sales to third parties due to higher average gas costs, and
an increase of $31$29 million related to sales under the BGSS contract due primarily to increased volumes sold, coupled with higher average gas costs due to colder average temperatures during the 2018 winter heating season,
partially offset by a decrease of $18 million related to sales to third parties due primarily to lower average gas costs and an increasea decrease in volumes sold due to periods of colder weather in March.sold.
Operation and Maintenance decreased $23increased $14 million due primarily to
a $15$10 million decrease related tonet increase at our nuclearfossil plants, due primarily to lower labor-relatedhigher planned outage costs in 2018 as compared to 2017, and
a $7$5 million legal reservenet increase due primarily to higher planned outage costs at our 100%-owned Hope Creek nuclear plant in 2018 as compared to planned outage costs incurred in 2017 for environmental expenses recorded in 2016.our 57%-owned Salem Unit 2.
Depreciation and Amortization increaseddecreased $571568 million due primarily to
$558574 million of acceleratedhigher depreciation in 2017 for Hudson and Mercer due to the early retirement of the Hudson and Mercerthose units,
$4partially offset by a $5 million of greater depreciation due to the accelerated retirement date at Bridgeport Harbor 3,
a $4 million increase in 2018 due to a higher nuclear asset base and
$3 million of higher depreciation due to new solar projects.primarily from increased capitalized asset retirement costs.
Other Income (Deductions)Net Gains (Losses) on Trust Investments increased $23decreased $41 million due primarily to $17the inclusion in 2018 of $34 million of lower net realizedunrealized losses from the NDT Fund in 2017 and $3 million of higher realized gains in the Rabbi Trust Fund.

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Other-Than-Temporary Impairments decreased $9 million due to lower impairments ofon equity securitiesinvestments in the NDT Fund in 2017.accordance with new accounting guidance and a $5 million decrease in net realized gains on NDT Fund investments.
Interest Expense decreased $6$9 million due primarily to higher interest capitalized for the construction of three new fossil stations:the BH5, Sewaren 7 and Keys.Keys fossil stations.
Income Tax Expense (Benefit) decreased $245increased $199 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 three months ended March 31, 20172018, our operating cash flow decreased $1857 million as compared to the same period in 2016.2017. The net change waschanges were primarily due to the net changes from PSE&G and Power as discussed below largely offset by higher tax refunds in 2017 at Energy Holdings.Holdings combined with net changes from our subsidiaries as discussed below.
PSE&G
PSE&G’s operating cash flow decreasedincreased $5462 million from $568515 million to $514577 million for the three months ended March 31, 20172018, as compared to the same period in 20162017, due primarily to lower tax refunds, partially offset by higher earnings, and an increase of $45$58 million primarily due to a reduction in

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unbilled revenues resulting from lower prices and volumes in 2018, an increase of $54 million due to a change in regulatory deferrals.deferrals, and higher earnings in 2018, partially offset by a tax refund in 2017.
Power
Power’s operating cash flow decreased $8338 million from $663580 million to $580542 million for the three months ended March 31, 20172018, as compared to the same period in 2016,2017, due primarily due to taxan increase of $71 million in payments in 2017 as compared to tax refunds in 2016counterparties and lower earnings, partiallya $22 million decrease from fuels, materials and supplies, offset by a $65$69 million increase from net collectioncollections of counterparty receivables and a $12 million increase from fuels, materials and supplies.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.
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, 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.
Our total credit facilities and available liquidity as of March 31, 20172018 were as follows:
         
 Company/Facility As of March 31, 2017 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,500
 $332
 $1,168
 
 PSE&G 600
 14
 586
 
 Power 2,100
 235
 1,865
 
 Total $4,200
 $581
 $3,619
 
         
         
 Company/Facility As of March 31, 2018 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,500
 $609
 $891
 
 PSE&G 600
 16
 584
 
 Power 2,100
 158
 1,942
 
 Total $4,200
 $783
 $3,417
 
         
As of March 31, 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

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would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s 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 $801$867 million and $783$848 million as of March 31, 20172018 and December 31, 2016,2017, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units is not expected to have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 1. Note 3. Early Plant Retirements.
For additional information, see Item 1. Note 10.11. Debt and Credit Facilities.
Long-Term Debt Financing
PSEG ParentDuring the next twelve months, PSE&G has a floating rate $500$400 million term loanof 5.30% Medium-Term Notes maturing in May 2018 and $350 million of 2.30% Medium-Term Notes maturing in September 2018. Power has $250 million of 2.45% Senior Notes maturing in November 2017.2018.
For additional information see Item 1. Note 11. Debt and Credit Facilities.
Common Stock Dividends
On February 21, 2017,20, 2018, our Board of Directors approved a $0.43$0.45 dividend per share of common stock for the first quarter of 2017.2018. On April 18, 2017,17, 2018, our Board of Directors declared a $0.43$0.45 dividend per share of common stock for the second quarter of 2017.2018. This reflects 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.

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Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks 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. PSEG Power’s rating and outlook also remain unchanged.
       
   Moody’s (A) S&P (B) 
 PSEG     
 Outlook PositiveStable Stable 
 Senior Notes Baa2Baa1 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 at PSE&G, Power and Services as compared to amounts disclosed in our 20162017 Form 10-K.
PSE&G
During the three months ended March 31, 2017,2018, PSE&G made capital expenditures of $752$759 million, primarily for transmission and distributionT&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $24$38 million, which are included in operating cash flows.
Power
During the three months ended March 31, 2017,2018, Power made capital expenditures of $274$283 million, excluding $3316 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.

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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 January through March 2017,2018, MTM VaR remained relatively stablevaried between a low of $7$8 million and a high of $25$38 million at the 95% confidence level. The range of VaR was narrower for the three months ended March 31, 20172018 as compared with the year ended December 31, 2016.2017.

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   MTM VaR 
   Three Months Ended March 31, 2017 Year Ended December 31, 2016 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $7
 $26
 
 Average for the Period $12
 $16
 
 High $25
 $32
 
 Low $7
 $10
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $11
 $40
 
 Average for the Period $19
 $25
 
 High $39
 $51
 
 Low $10
 $16
 
       
       
   MTM VaR 
   Three Months Ended March 31, 2018 Year Ended December 31, 2017 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $9
 $39
 
 Average for the Period $21
 $10
 
 High $38
 $39
 
 Low $8
 $5
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $14
 $60
 
 Average for the Period $32
 $15
 
 High $60
 $60
 
 Low $13
 $8
 
       
See Item 1. Note 11.12. Financial Risk Management Activities for a discussion of credit risk.


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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 first 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, 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 follows, thereThere have been no material changes to the risk factors set forth in the above-referenced filingfilings as of March 31, 2017.2018.


We may be unable to obtain an adequate fuel supply in the future.
We obtain substantially all of our physical natural gas, coal and nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and other contracts to ensure that the natural gas, coal and nuclear fuel are delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.
Additionally, the PJM power market has recently experienced an increase in natural gas-fired generation assets that supply electricity to the region. As a result, there has been a corresponding increase in the need for natural gas transportation assets to serve power generation assets. When extreme cold temperatures significantly increase the demand for natural gas used for residential heating, it can also create constraints on natural gas pipelines that serve power generation assets. When these conditions exist, it could interrupt the fuel supply to our natural gas-fired power plants in the PJM power market.
We are exposed to increases in the price of natural gas, coal and nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of natural gas, coal and nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of natural gas, coal and nuclear fuel by, our power plants including the following:
transportation may be unavailable if pipeline infrastructure is damaged or disabled;
pipeline tariff changes may adversely affect our ability to, or cost to, deliver such fuels;
creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;
market liquidity for physical supplies of such fuels or availability of related services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;
variation in the quality of such fuels may adversely affect our power plant operations;
legislative or regulatory actions or requirements, including those related to pipeline integrity inspections, may increase the cost of such fuels;
fuel supplies diverted to residential heating may limit the availability of such fuels for our power plants; and
the loss of critical infrastructure, terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.
Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, such fuel may not be available at any price, or we may not be able to transport it to our facilities on a timely basis. In this case, we may not be able to run those facilities even if it would be profitable. If we had sold forward the power from such a facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.
In March 2017, Westinghouse Electric Company (WEC) announced that it had filed for Chapter 11 bankruptcy in New York. WEC provides nuclear fuel fabrication services for Salem Units 1 and 2. In the event that WEC is unable to continue to provide fabrication services, we can provide no assurance that we would be able to find alternative providers of such services in a timely manner or on acceptable terms. As a result, a failure by WEC to perform its obligations during the pendency of, or following its emergence from, bankruptcy could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.
Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our liquidity, financial condition and results of operations. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used could impact our results of operations.


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ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
In 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. The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the first quarter of 20172018.
      
 Three Months Ended March 31, 2017
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 January 1 - January 31—
 $—
 
 February 1 - February 28—
 $—
 
 March 1- March 31927,971
 $44.94
 
      
      
 Three Months Ended March 31, 2018
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 January 1 - January 311,300,000
 $50.00
 
 February 1 - February 28—
 $—
 
 March 1- March 31—
 $—
 
      

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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. References are to the related pages on the FormsForm 10-K as printed and distributed.
Federal Regulation
FERC
Capacity Market IssuesEnergy Clearing Prices
December 31, 20162017 Form 10-K page 16. FERC has 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 regarding operator actions affecting energy market prices and would promote better alignment between generation dispatch decisions and energy market price outcomes. In November 2017, PJM issued an energy price formation proposal to address a flaw in the energy market by allowing all resources selected for dispatch, both flexible and inflexible, to set price and consequently, result in prices that more accurately reflect the true cost to serve load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot predict the outcome of this matter.
Capacity Market Issues—PJM
December 31, 2017 Form 10-K page 16. PJM NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Issues presented in various forums include consideration of whether the competitive market framework can be reconciled with state public policies that support particular resources or resource attributes, whether generators are being sufficiently compensatedfully implemented in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. 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. During 2015, PJM implementedMay 2017 RPM auction for the 2020-2021 Delivery Year 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. However, aspects of FERC’s order are currently pending appeal in the Court of Appeals for the D.C. Circuit (D.C. Circuit). The CP product will be implemented fully for the 2020-2021 Delivery Year. FERC has approved changesmechanism is intended to the CP construct that will enhance the participation of intermittent and DRdemand response resources (“seasonal resources”)(seasonal resources). Specifically, FERC approved PJM’s modifications to the aggregation rules to improve the ability of seasonal resources to participate. However, FERC recently scheduled a technical conference in response to two complaints remain pendingrequesting that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions. We do not expect action oncannot predict the complaints beforeoutcome of these matters.
In April, 2018, PJM submitted two proposed alternative and 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 upcoming base residual auction in May 2017.other option would be to extend the existing Minimum Offer Price Rule to units that are receiving subsidies. We are currently evaluating these two proposals.
Capacity Market Issues—Issues—ISO-NE
December 31, 2016 Form 10-K page 17. ISO-NE’s marketRecently, ISO-NE submitted proposed changes to the Forward Capacity Market referred to as the Competitive Auctions and Sponsored Policy Resources (CASPR) proposal to accommodate clean and renewable energy policy resources. The CASPR design creates a second auction that commences immediately following the Forward Capacity Auction and provides the opportunity for installed capacity in New England provides fixed capacity payments for generators, importscertain renewable, clean and DR. The market design consists of a forward-looking auction for installed capacity that is intendedalternative energy resources to recognize the locational value of resources on the system and contains incentive mechanisms to encourage availability during stressed system conditions. ISO-NE also employs a mechanism, similar to PJM’s CP mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance. One aspect of the current market design that we do not support and are currently challengingacquire supply obligations when they cannot clear economically in the D.C. Circuit isForward Capacity Auction. The CASPR design also proposed to phase out the exemption from the MOPRminimum offer price rule (MOPR) in the capacity market afforded for up to 200 MW200MW annually (600 MW cumulatively) of renewable resources.
Price Formation Initiatives
December 31, 2016 Form 10-K page 18. Power has been actively involved both through stakeholder processes and through filings at FERC in seeking improvementsresources, an aspect of the market design that we did not support due to the rules for setting prices for energycapacity market suppression associated with this mechanism. In March 2018, FERC approved the filing, including the phase out of the 200MW renewables exemptions, with an effective date beginning with the next Forward Capacity Auction to be held in the day-ahead and real-time markets administered by PJM and other system operators. FERC recently issued a notice of proposed rulemaking (NOPR) proposing that RTOs/ISOs modify their rules governing fast-start resources. Fast-start resources typically are committed in real-time, very

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close to the interval when needed and can respond quickly to unforeseen system needs. However, without fast-start pricing, some fast-start resources are ineligible to set prices due to inflexible operating limits. As a result, prices may not reflect the marginal cost of serving load. In a separate proceeding, PJM has submitted a proposal at FERC’s request to modify its rules to allow market sellers to submit day-ahead offers that vary by hour and to allow market sellers to update their offers in real time on an hourly basis under certain circumstances. FERC has accepted PJM’s proposal which will become effective on November 1, 2017. We believe that both changes will improve price formation in the energy and ancillary services markets.February 2019.
Transmission Regulation—Transmission Policy Developments
December 31, 20162017 Form 10-K page 18. In August 2016,February 2018, FERC issued an order finding that the transmission planning procedures used by the PJM announcedtransmission owners, a group that it had suspended the Artificial Island transmission project and would be performing a comprehensive analysis to support a future course of action. In March 2017, PJM staff made its final recommendationincludes PSE&G, for supplemental projects do not adhere to the coordination and transparency principles of FERC’s Order No. 890. FERC determined that certain terms and conditions in the PJM Board with respectgoverning documents are unjust and unreasonable. FERC directed PJM and the PJM transmission owners to submit certain revisions to the project. Undermanner in which the recommended project,stakeholder process for supplemental projects is conducted. PSE&G will construct necessary upgrade workparticipated in Hope Creek, at a cost of approximately $130 million. In April 2017, the PJM Board announced that it would be lifting the suspension and approved the staff recommended project. The PJM Boardtransmission owners’ compliance filing. A number of parties also stated that it would be analyzing project beneficiaries from an alternate perspective to potentially devise an alternative cost allocation methodology for stability projects.
Transmission Regulation—Con Edison Wheeling Agreement
December 31, 2016 Form 10-K page 19. In April 2016, Con Edison informed PJM that it would allow its Wheeling Agreement to expire effective as of May 1, 2017. The Wheeling Agreement enables Con Edison to move 1,000 MW of power from southeastern New York across the PSE&G system for delivery into New York City. NYISO and PJM submitted proposed tariff provisions in January 2017. The proposal concerns future operational procedures and transmission planning assumptions associated with the affected transmission lines. FERC accepted the proposal, subject to refund, effective May 1, 2017. We cannot predict the impactsought rehearing of the proposal on energy prices or transmission planning at this time. Both PSE&G and the BPU protested certain aspectsFERC order seeking more onerous requirements that, if accepted, could be disruptive of the proposal. In a related filing, PJM submitted a proposal to FERC revising the cost responsibility assigned to certain entities, including PSE&G, due to the termination of the Wheeling Agreement. Also, PSE&G will continue to recover the costs associated with the new arrangement through its formula rate. We cannot predict the outcome of this proceeding.planning process.
State Regulation
Energy Efficiency Program (Energy Efficiency 2017)BGSS Process
In November 2017, a filing was made by the Retail Energy Supply Association (RESA) with the BPU requesting that the BPU revisit the BGSS process and establish a gas capacity release program. This filing is applicable to all New Jersey gas utilities. In March 2017, we2018, the RESA filed aan amended petition with the BPU for our Energy Efficiency 2017 program, requesting extension of three Energy Efficiency Economic sub-programs (multi-family, direct install and hospital efficiency) and the addition of two new sub-programs (smart thermostat and residential data analytics). The petition requested additional capital expenditures of approximately $74 million, additional administrative and other costs of $22 million and information technology system enhancement costs of $3 million. We proposeda formal proceeding to recover our investment in these sub-programs under the same clause recovery process as currently approved.establish a gas capacity release program. This matterfiling is pending.

Environmental Matters
Climate Change
CO2 Regulation under theClean Air Act (CAA)
December 31, 2016 Form 10-K page 23. In March 2017, the President 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, 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. Upon completion of the review, the EPA is expected to suspend, revise or rescind the rules as appropriate. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.
Water Pollution Control
Steam Electric Effluent Guidelines
December 31, 2016 Form 10-K page 23. 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. 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-

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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 regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.
In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and is acting promptly to issue an administrative stay of the compliance dates in the rule that have not yet passed pending judicial review. The deadlines that are expected to be stayed include the BAT limitations and pretreatment standards for each of the following waste streams:  fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater. Power is unable to determine how this will ultimately impact compliance requirements or the financial impact it may have on the company.
Waters of the United States
December 31, 2016 Form 10-K page 24. In April 2014, the EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published a proposed rule to clarify the definition of waters of the United States under the CWA programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad applicationapplicable to all areas of compliance under the CWA, including permitted discharges and construction activities. The final rule was published in June 2015 and various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the final rule as well as which court has jurisdiction over the rule. The U.S. Supreme Court is expected to rule on the question of jurisdiction by June 2017. Some states, including New Jersey are subject to state requirements beyond thoseimposed under federal law. While we do not anticipate material impacts to projects in New Jersey, the new definition could impose requirements in other states and regions that could impact the development of renewables.
In February 2017, the President of the United States issued an Executive Order that instructed the EPA to review the rule and issue a proposal to redefine “Waters of the United States.”
Endangered Species Act
December 31, 2016 Form 10-K page 25. In June 2015, the Sierra Club and another environmental group submitted to the NJDEP a sixty-day notice of intent to sue alleging the agency has caused violations of the Endangered Species Act by allowing our Mercer generation station to operate in a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a permit renewal action for Mercer which addresses the alleged Endangered Species Act violations. In March 2017, we submitted our Incidental Take Permit to the National Marine Fisheries Service outlining operation and monitoring requirements through retirement of the Mercer generation station on
June 1, 2017 and subsequent decommissioning.


gas utilities.

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ITEM 6.EXHIBITS
A listing of exhibits being filed with this document is as follows:
a. PSEG:  
Exhibit 12:
 
Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:
 
Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:
 
Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:
 
Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:
 
Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS: XBRL Instance Document
Exhibit 101.SCH: XBRL Taxonomy Extension Schema
Exhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF: XBRL Taxonomy Extension Definition Document
   
b. PSE&G:  
Exhibit 12.1:4a(15)
 
Supplemental Indenture dated April 1, 2018
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 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




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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)
  
By:
/S/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: April 28, 201730, 2018

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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)
  
By:
/S/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: April 28, 201730, 2018


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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PSEG POWER LLC
(Registrant)
  
By:
/S/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: April 28, 201730, 2018


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