Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JuneSeptember 30, 2018
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

  22-2625848
001-00973  
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(A New Jersey Corporation)
80 Park Plaza
Newark, New Jersey 07102
973 430-7000

  22-1212800
001-34232  
PSEG POWER LLC
(A Delaware Limited Liability Company)
80 Park Plaza
Newark, New Jersey 07102
973 430-7000

  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 July 17,October 16, 2018, Public Service Enterprise Group Incorporated had outstanding 505,323,326505,449,710 shares of its sole class of Common Stock, without par value.
As of July 17,October 16, 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) of Form 10-Q. Each is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.


Table of Contents

  Page
FORWARD-LOOKING STATEMENTS
ii
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, Basis of Presentation and Significant Accounting Policies
16
 Note 2. Recent Accounting Standards
17
 Note 3. Revenues
20
 Note 4. Early Plant Retirements
2425
 Note 5. Variable Interest Entity (VIE)
2627
 Note 6. Rate Filings
27
 Note 7. Financing Receivables
28
 Note 8. Trust Investments
31
 Note 9. Pension and Other Postretirement Benefits (OPEB)
36
 Note 10. Commitments and Contingent Liabilities
38
 Note 11. Debt and Credit Facilities
4544
 Note 12. Financial Risk Management Activities
46
 Note 13. Fair Value Measurements
50
 Note 14. Other Income (Deductions)
58
 Note 15. Income Taxes
5859
 Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax
6061
 Note 17. Earnings Per Share (EPS) and Dividends
6465
 Note 18. Financial Information by Business Segment
6566
 Note 19. Related-Party Transactions
6566
 Note 20. Guarantees of Debt
6768
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
7071
 Executive Overview of 2018 and Future Outlook
7071
 
Results of Operations
79
 
Liquidity and Capital Resources
84
 
Capital Requirements
86
 
Accounting Matters
86
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
8687
Item 4.
Controls and Procedures
8788
  
PART II. OTHER INFORMATION 
Item 1.
Legal Proceedings
8788
Item 1A.
Risk Factors
8788
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
88
Item 5.
Other Information
88
Item 6.
Exhibits
90
 
Signatures
91


i

Table of Contents

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, and PSE&G’s ability to recover costs and earn returns on authorized investments;
the impact of pending and any future rate case proceedings;
regulatory, financial, environmental, health and safety risks associated with our ownership and operation of nuclear facilities;facilities, including regulatory risks, such as compliance with the Atomic Energy Act and trade control, environmental and other regulations, as well as financial, environmental and health and safety risks;
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;

ii

Table of Contents

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


iii

Table of Contents




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

          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$2,016
 $2,142
 $4,834
 $4,733
 
 OPERATING EXPENSES        
 Energy Costs600
 588
 1,552
 1,456
 
 Operation and Maintenance725
 718
 1,479
 1,435
 
 Depreciation and Amortization280
 641
 560
 1,469
 
 Total Operating Expenses1,605
 1,947
 3,591
 4,360
 
 OPERATING INCOME411
 195
 1,243
 373
 
 Income from Equity Method Investments5
 5
 7
 8
 
 Net Gains (Losses) on Trust Investments8
 25
 (14) 53
 
 Other Income (Deductions)34
 33
 66
 65
 
 Non-Operating Pension and OPEB Credits (Costs)19
 1
 38
 1
 
 Interest Expense(111) (91) (214) (189) 
 INCOME BEFORE INCOME TAXES366
 168
 1,126
 311
 
 Income Tax Expense(97) (59) (299) (88) 
 NET INCOME$269
 $109
 $827
 $223
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:        
 BASIC504
 505
 504
 505
 
 DILUTED507
 507
 507
 507
 
 NET INCOME PER SHARE:        
 BASIC$0.53
 $0.22
 $1.64
 $0.44
 
 DILUTED$0.53
 $0.22
 $1.63
 $0.44
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.45
 $0.43
 $0.90
 $0.86
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$2,394
 $2,254
 $7,228
 $6,987
 
 OPERATING EXPENSES        
 Energy Costs804
 616
 2,356
 2,072
 
 Operation and Maintenance742
 693
 2,221
 2,128
 
 Depreciation and Amortization294
 252
 854
 1,721
 
 Total Operating Expenses1,840
 1,561
 5,431
 5,921
 
 OPERATING INCOME554
 693
 1,797
 1,066
 
 Income from Equity Method Investments5
 3
 12
 11
 
 Net Gains (Losses) on Trust Investments45
 18
 31
 71
 
 Other Income (Deductions)33
 33
 99
 98
 
 Non-Operating Pension and OPEB Credits (Costs)19
 —
 57
 1
 
 Interest Expense(127) (100) (341) (289) 
 INCOME BEFORE INCOME TAXES529
 647
 1,655
 958
 
 Income Tax Expense(117) (252) (416) (340) 
 NET INCOME$412
 $395
 $1,239
 $618
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:        
 BASIC504
 505
 504
 505
 
 DILUTED507
 507
 507
 507
 
 NET INCOME PER SHARE:        
 BASIC$0.82
 $0.78
 $2.46
 $1.22
 
 DILUTED$0.81
 $0.78
 $2.44
 $1.22
 
 DIVIDENDS PAID PER SHARE OF COMMON STOCK$0.45
 $0.43
 $1.35
 $1.29
 
          
See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
(Unaudited)
 
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 NET INCOME$269
 $109
 $827
 $223
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $4, $(9), $13 and $(25) for the three and six months ended 2018 and 2017, respectively(5) 10
 (19) 25
 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $0, $1 and $0 for the three and six months ended 2018 and 2017, respectively(1) —
 (1) —
 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(3), $(4), $(6) and $(8) for the three and six months ended 2018 and 2017, respectively7
 6
 15
 12
 
 Other Comprehensive Income (Loss), net of tax1
 16
 (5) 37
 
 COMPREHENSIVE INCOME$270
 $125
 $822
 $260
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
 NET INCOME$412
 $395
 $1,239
 $618
 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $2, $(15), $15 and $(40) for the three and nine months ended 2018 and 2017, respectively(4) 17
 (23) 42
 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $1 and $0 for the three and nine months ended 2018 and 2017, respectively—
 (1) (1) (1) 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(3), $(4), $(9) and $(12) for the three and nine months ended 2018 and 2017, respectively7
 6
 22
 18
 
 Other Comprehensive Income (Loss), net of tax3
 22
 (2) 59
 
 COMPREHENSIVE INCOME$415
 $417
 $1,237
 $677
 
          
See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
 
      
  June 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$95
 $313
 
 Accounts Receivable, net of allowances of $59 in 2018 and 20171,163
 1,348
 
 Tax Receivable111
 127
 
 Unbilled Revenues189
 296
 
 Fuel218
 289
 
 Materials and Supplies, net574
 577
 
 Prepayments324
 118
 
 Derivative Contracts24
 29
 
 Regulatory Assets296
 211
 
 Other11
 4
 
 Total Current Assets3,005
 3,312
 
 PROPERTY, PLANT AND EQUIPMENT42,809
 41,231
 
      Less: Accumulated Depreciation and Amortization(9,658) (9,434) 
 Net Property, Plant and Equipment33,151
 31,797
 
 NONCURRENT ASSETS    
 Regulatory Assets3,225
 3,222
 
 Long-Term Investments924
 932
 
 Nuclear Decommissioning Trust (NDT) Fund2,049
 2,133
 
 Long-Term Receivable of Variable Interest Entity (VIE)688
 686
 
 Rabbi Trust Fund224
 231
 
 Goodwill16
 16
 
 Other Intangibles127
 114
 
 Derivative Contracts21
 7
 
 Other277
 266
 
 Total Noncurrent Assets7,551
 7,607
 
 TOTAL ASSETS$43,707
 $42,716
 
      
      
  September 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$88
 $313
 
 Accounts Receivable, net of allowances of $56 in 2018 and $59 in 20171,240
 1,348
 
 Tax Receivable225
 127
 
 Unbilled Revenues155
 296
 
 Fuel329
 289
 
 Materials and Supplies, net590
 577
 
 Prepayments214
 118
 
 Derivative Contracts11
 29
 
 Regulatory Assets317
 211
 
 Other46
 4
 
 Total Current Assets3,215
 3,312
 
 PROPERTY, PLANT AND EQUIPMENT43,613
 41,231
 
      Less: Accumulated Depreciation and Amortization(9,832) (9,434) 
 Net Property, Plant and Equipment33,781
 31,797
 
 NONCURRENT ASSETS    
 Regulatory Assets3,761
 3,222
 
 Long-Term Investments923
 932
 
 Nuclear Decommissioning Trust (NDT) Fund2,096
 2,133
 
 Long-Term Receivable of Variable Interest Entity (VIE)682
 686
 
 Rabbi Trust Fund225
 231
 
 Goodwill16
 16
 
 Other Intangibles107
 114
 
 Derivative Contracts2
 7
 
 Other265
 266
 
 Total Noncurrent Assets8,077
 7,607
 
 TOTAL ASSETS$45,073
 $42,716
 
      
See Notes to Condensed Consolidated Financial Statements.


Table of Contents

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

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

 

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

   
      
  September 30,
2018		 December 31,
2017		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$1,450
 $1,000
 
 Commercial Paper and Loans419
 542
 
 Accounts Payable1,317
 1,694
 
 Derivative Contracts13
 16
 
 Accrued Interest159
 103
 
 Accrued Taxes36
 48
 
 Clean Energy Program187
 128
 
 Obligation to Return Cash Collateral130
 129
 
 Regulatory Liabilities303
 47
 
 Other471
 461
 
 Total Current Liabilities4,485
 4,168
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)5,720
 5,240
 
 Regulatory Liabilities3,286
 2,948
 
 Asset Retirement Obligations1,059
 1,024
 
 OPEB Costs1,410
 1,455
 
 OPEB Costs of Servco560
 542
 
 Accrued Pension Costs451
 537
 
 Accrued Pension Costs of Servco108
 129
 
 Environmental Costs348
 357
 
 Derivative Contracts2
 5
 
 Long-Term Accrued Taxes152
 175
 
 Other224
 221
 
 Total Noncurrent Liabilities13,320
 12,633
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 CAPITALIZATION
   
 LONG-TERM DEBT12,909
 12,068
 
 STOCKHOLDERS’ EQUITY
   
 Common Stock, no par, authorized 1,000 shares; issued, 2018 and 2017—534 shares4,966
 4,961
 
 Treasury Stock, at cost, 2018—30 shares; 2017—29 shares(811) (763) 
 Retained Earnings10,611
 9,878
 
 Accumulated Other Comprehensive Loss(407) (229) 
 Total Stockholders’ Equity14,359
 13,847
 
 Total Capitalization27,268
 25,915
 
 TOTAL LIABILITIES AND CAPITALIZATION$45,073
 $42,716
 
  

   
See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
      
  Six Months Ended 
  June 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$827
 $223
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization560
 1,469
 
 Amortization of Nuclear Fuel95
 101
 
 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual

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

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

      
  Nine Months Ended 
  September 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income$1,239
 $618
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization854
 1,721
 
 Amortization of Nuclear Fuel143
 152
 
 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual

74
 79
 
 Provision for Deferred Income Taxes (Other than Leases) and ITC510
 227
 
 Non-Cash Employee Benefit Plan Costs52
 67
 
 Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes(27) (7) 
 Net (Gain) Loss on Lease Investments14
 48
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives78
 8
 
 Net Change in Regulatory Assets and Liabilities(35) (121) 
 Cost of Removal(121) (72) 
 Net (Gains) Losses and (Income) Expense from NDT Fund(62) (86) 
 Net Change in Certain Current Assets and Liabilities:    
           Tax Receivable(98) 64
 
           Accrued Taxes(12) 115
 
           Margin Deposit(77) 64
 
           Other Current Assets and Liabilities12
 (71) 
 Employee Benefit Plan Funding and Related Payments(85) (64) 
 Other33
 (9) 
 Net Cash Provided By (Used In) Operating Activities2,492
 2,733
 
 CASH FLOWS FROM INVESTING ACTIVITIES

   
 Additions to Property, Plant and Equipment(3,028) (3,046) 
 Purchase of Emissions Allowances and RECs(111) (90) 
 Proceeds from Sales of Trust Investments1,085
 1,013
 
 Purchases of Trust Investments(1,100) (1,029) 
 Other41
 48
 
 Net Cash Provided By (Used In) Investing Activities(3,113) (3,104) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Commercial Paper and Loans(123) (186) 
 Issuance of Long-Term Debt2,050
 1,125
 
 Redemption of Long-Term Debt(750) —
 
 Cash Dividends Paid on Common Stock(682) (652) 
 Other(83) (62) 
 Net Cash Provided By (Used In) Financing Activities412
 225
 
 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash(209) (146) 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period315
 426
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$106
 $280
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$64
 $(16) 
 Interest Paid, Net of Amounts Capitalized$292
 $261
 
 Accrued Property, Plant and Equipment Expenditures$543
 $604
 
      
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 Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$1,386
 $1,393
 $3,231
 $3,219
 
 OPERATING EXPENSES        
 Energy Costs488
 488
 1,270
 1,250
 
 Operation and Maintenance353
 359
 744
 729
 
 Depreciation and Amortization187
 166
 377
 337
 
 Total Operating Expenses1,028
 1,013
 2,391
 2,316
 
 OPERATING INCOME358
 380
 840
 903
 
 Net Gains (Losses) on Trust Investments—
 —
 —
 2
 
 Other Income (Deductions)20
 21
 40
 43
 
 Non-Operating Pension and OPEB Credits (Costs)15
 (1) 30
 (3) 
 Interest Expense(82) (69) (163) (144) 
 INCOME BEFORE INCOME TAXES311
 331
 747
 801
 
 Income Tax Expense(80) (123) (197) (294) 
 NET INCOME$231
 $208
 $550
 $507
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$1,595
 $1,530
 $4,826
 $4,749
 
 OPERATING EXPENSES        
 Energy Costs593
 543
 1,863
 1,793
 
 Operation and Maintenance389
 357
 1,133
 1,086
 
 Depreciation and Amortization192
 169
 569
 506
 
 Total Operating Expenses1,174
 1,069
 3,565
 3,385
 
 OPERATING INCOME421
 461
 1,261
 1,364
 
 Net Gains (Losses) on Trust Investments—
 —
 —
 2
 
 Other Income (Deductions)21
 22
 61
 65
 
 Non-Operating Pension and OPEB Credits (Costs)14
 (2) 44
 (5) 
 Interest Expense(83) (79) (246) (223) 
 INCOME BEFORE INCOME TAXES373
 402
 1,120
 1,203
 
 Income Tax Expense(95) (156) (292) (450) 
 NET INCOME$278
 $246
 $828
 $753
 
          
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 Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 NET INCOME$231
 $208
 $550
 $507
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0, $0 and $1 for the three and six months ended 2018 and 2017, respectively1
 —
 —
 (1) 
 COMPREHENSIVE INCOME$232
 $208
 $550
 $506
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
 NET INCOME$278
 $246
 $828
 $753
 
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0, $0 and $1 for the three and nine months ended 2018 and 2017, respectively(1) —
 (1) (1) 
 COMPREHENSIVE INCOME$277
 $246
 $827
 $752
 
          
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)

      
  June 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$20
 $242
 
 Accounts Receivable, net of allowances of $59 in 2018 and 2017796
 882
 
 Accounts Receivable—Affiliated Companies18
 —
 
 Unbilled Revenues189
 296
 
 Materials and Supplies195
 197
 
 Prepayments205
 44
 
 Regulatory Assets296
 211
 
 Other10
 4
 
 Total Current Assets1,729
 1,876
 
 PROPERTY, PLANT AND EQUIPMENT30,396
 29,117
 
 Less: Accumulated Depreciation and Amortization(6,200) (6,101) 
 Net Property, Plant and Equipment24,196
 23,016
 
 NONCURRENT ASSETS    
 Regulatory Assets3,225
 3,222
 
 Long-Term Investments285
 280
 
 Rabbi Trust Fund45
 46
 
 Other123
 114
 
 Total Noncurrent Assets3,678
 3,662
 
 TOTAL ASSETS$29,603
 $28,554
 
      
      
  September 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS
   
 Cash and Cash Equivalents$25
 $242
 
 Accounts Receivable, net of allowances of $56 in 2018 and $59 in 2017842
 882
 
 Accounts Receivable—Affiliated Companies55
 —
 
 Unbilled Revenues155
 296
 
 Materials and Supplies200
 197
 
 Prepayments117
 44
 
 Regulatory Assets317
 211
 
 Other26
 4
 
 Total Current Assets1,737
 1,876
 
 PROPERTY, PLANT AND EQUIPMENT30,997
 29,117
 
 Less: Accumulated Depreciation and Amortization(6,241) (6,101) 
 Net Property, Plant and Equipment24,756
 23,016
 
 NONCURRENT ASSETS    
 Regulatory Assets3,761
 3,222
 
 Long-Term Investments278
 280
 
 Rabbi Trust Fund46
 46
 
 Other116
 114
 
 Total Noncurrent Assets4,201
 3,662
 
 TOTAL ASSETS$30,694
 $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)

      
  June 30,
2018		 December 31,
2017		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$600
 $750
 
 Commercial Paper and Loans195
 —
 
 Accounts Payable704
 728
 
 Accounts Payable—Affiliated Companies150
 340
 
 Accrued Interest79
 78
 
 Clean Energy Program203
 128
 
 Obligation to Return Cash Collateral131
 129
 
 Regulatory Liabilities32
 47
 
 Other376
 311
 
 Total Current Liabilities2,470
 2,511
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC3,570
 3,391
 
 OPEB Costs1,066
 1,103
 
 Accrued Pension Costs189
 226
 
 Regulatory Liabilities2,937
 2,948
 
 Clean Energy Program27
 —
 
 Environmental Costs255
 283
 
 Asset Retirement Obligations214
 212
 
 Long-Term Accrued Taxes94
 91
 
 Other111
 114
 
 Total Noncurrent Liabilities8,463
 8,368
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT8,286
 7,841
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150 shares authorized; issued and outstanding, 2018 and 2017—132 shares892
 892
 
 Contributed Capital1,095
 1,095
 
 Basis Adjustment986
 986
 
 Retained Earnings7,411
 6,861
 
 Total Stockholder’s Equity10,384
 9,834
 
 Total Capitalization18,670
 17,675
 
 TOTAL LIABILITIES AND CAPITALIZATION$29,603
 $28,554
 
      
      
  September 30,
2018		 December 31,
2017		 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$500
 $750
 
 Commercial Paper and Loans40
 —
 
 Accounts Payable666
 728
 
 Accounts Payable—Affiliated Companies164
 340
 
 Accrued Interest96
 78
 
 Clean Energy Program187
 128
 
 Obligation to Return Cash Collateral130
 129
 
 Regulatory Liabilities303
 47
 
 Other367
 311
 
 Total Current Liabilities2,453
 2,511
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC3,718
 3,391
 
 OPEB Costs1,052
 1,103
 
 Accrued Pension Costs171
 226
 
 Regulatory Liabilities3,286
 2,948
 
 Environmental Costs271
 283
 
 Asset Retirement Obligations215
 212
 
 Long-Term Accrued Taxes67
 91
 
 Other118
 114
 
 Total Noncurrent Liabilities8,898
 8,368
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 CAPITALIZATION    
 LONG-TERM DEBT8,682
 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 Earnings7,689
 6,861
 
 Accumulated Other Comprehensive Income(1) —
 
 Total Stockholder’s Equity10,661
 9,834
 
 Total Capitalization19,343
 17,675
 
 TOTAL LIABILITIES AND CAPITALIZATION$30,694
 $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)
      
  Six Months Ended 
  June 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$550
 $507
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization377
 337
 
 Provision for Deferred Income Taxes and ITC160
 330
 
 Non-Cash Employee Benefit Plan Costs19
 25
 
 Cost of Removal(84) (47) 
 Net Change in Regulatory Assets and Liabilities(58) (124) 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues195
 108
 
 Materials and Supplies2
 (15) 
 Prepayments(161) (184) 
 Accounts Payable(30) (30) 
 Accounts Receivable/Payable—Affiliated Companies, net(204) (72) 
 Other Current Assets and Liabilities66
 14
 
 Employee Benefit Plan Funding and Related Payments(50) (42) 
 Other(20) (38) 
 Net Cash Provided By (Used In) Operating Activities762
 769
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(1,447) (1,389) 
 Proceeds from Sales of Trust Investments9
 28
 
 Purchases of Trust Investments(10) (29) 
 Solar Loan Investments(11) (3) 
 Other3
 5
 
 Net Cash Provided By (Used In) Investing Activities(1,456) (1,388) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt195
 —
 
 Issuance of Long-Term Debt700
 425
 
 Redemption of Long-Term Debt(400) —
 
 Other(9) (5) 
 Net Cash Provided By (Used In) Financing Activities486
 420
 
 Net Increase (Decrease) In Cash, Cash Equivalents and Restricted Cash(208) (199) 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period244
 393
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$36
 $194
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$97
 $(75) 
 Interest Paid, Net of Amounts Capitalized$157
 $144
 
 Accrued Property, Plant and Equipment Expenditures$436
 $319
 
      
      
  Nine Months Ended 
  September 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
   Net Income$828
 $753
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization569
 506
 
 Provision for Deferred Income Taxes and ITC330
 497
 
 Non-Cash Employee Benefit Plan Costs28
 37
 
 Cost of Removal(121) (72) 
 Net Change in Regulatory Assets and Liabilities(35) (121) 
 Net Change in Certain Current Assets and Liabilities:
   
 Accounts Receivable and Unbilled Revenues184
 136
 
 Materials and Supplies(3) (13) 
 Prepayments(73) (106) 
 Accounts Payable(7) (37) 
 Accounts Receivable/Payable—Affiliated Companies, net(232) (61) 
 Other Current Assets and Liabilities10
 (14) 
 Employee Benefit Plan Funding and Related Payments(73) (55) 
 Other(8) (58) 
 Net Cash Provided By (Used In) Operating Activities1,397
 1,392
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(2,213) (2,118) 
 Proceeds from Sales of Trust Investments15
 33
 
 Purchases of Trust Investments(17) (34) 
 Solar Loan Investments(15) (2) 
 Other6
 7
 
 Net Cash Provided By (Used In) Investing Activities(2,224) (2,114) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Net Change in Short-Term Debt40
 —
 
 Issuance of Long-Term Debt1,350
 425
 
  Contributed Capital—
 150
 
 Redemption of Long-Term Debt(750) —
 
 Other(14) (5) 
 Net Cash Provided By (Used In) Financing Activities626
 570
 
 Net Increase (Decrease) In Cash, Cash Equivalents and Restricted Cash(201) (152) 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period244
 393
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$43
 $241
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$60
 $(107) 
 Interest Paid, Net of Amounts Capitalized$223
 $208
 
 Accrued Property, Plant and Equipment Expenditures$375
 $363
 
      
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 Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$767
 $918
 $2,170
 $2,187
 
 OPERATING EXPENSES        
 Energy Costs373
 386
 1,119
 1,078
 
 Operation and Maintenance268
 256
 514
 488
 
 Depreciation and Amortization84
 465
 166
 1,115
 
 Total Operating Expenses725
 1,107
 1,799
 2,681
 
 OPERATING INCOME (LOSS)42
 (189) 371
 (494) 
 Income from Equity Method Investments5
 5
 7
 8
 
 Net Gains (Losses) on Trust Investments8
 24
 (14) 43
 
 Other Income (Deductions)13
 12
 24
 23
 
 Non-Operating Pension and OPEB Credits (Costs)3
 2
 7
 4
 
 Interest Expense(11) (13) (18) (29) 
 INCOME (LOSS) BEFORE INCOME TAXES60
 (159) 377
 (445) 
 Income Tax Benefit (Expense)(19) 62
 (102) 178
 
 NET INCOME (LOSS)$41
 $(97) $275
 $(267) 
      

   
          
 
Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
 OPERATING REVENUES$868
 $846
 $3,038
 $3,033
 
 OPERATING EXPENSES        
 Energy Costs431
 330
 1,550
 1,408
 
 Operation and Maintenance231
 229
 745
 717
 
 Depreciation and Amortization94
 76
 260
 1,191
 
 Total Operating Expenses756
 635
 2,555
 3,316
 
 OPERATING INCOME (LOSS)112
 211
 483
 (283) 
 Income from Equity Method Investments5
 3
 12
 11
 
 Net Gains (Losses) on Trust Investments44
 19
 30
 62
 
 Other Income (Deductions)14
 11
 38
 34
 
 Non-Operating Pension and OPEB Credits (Costs)4
 2
 11
 6
 
 Interest Expense(29) (12) (47) (41) 
 INCOME (LOSS) BEFORE INCOME TAXES150
 234
 527
 (211) 
 Income Tax Benefit (Expense)(25) (98) (127) 80
 
 NET INCOME (LOSS)$125
 $136
 $400
 $(131) 
      

   
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 Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 NET INCOME (LOSS)$41
 $(97) $275
 $(267) 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $3, $(9), $11 and $(27) for the three and six months ended 2018 and 2017, respectively(4) 10
 (15) 29
 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(2), $(3), $(5) and $(7) for the three and six months ended 2018 and 2017, respectively6
 5
 12
 10
 
 Other Comprehensive Income (Loss), net of tax2
 15
 (3) 39
 
 COMPREHENSIVE INCOME (LOSS)$43
 $(82) $272
 $(228) 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
 NET INCOME (LOSS)$125
 $136
 $400
 $(131) 
 Other Comprehensive Income (Loss), net of tax        
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $2, $(14), $13 and $(41) for the three and nine months ended 2018 and 2017, respectively(4) 15
 (19) 44
 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(3), $(4), $(8) and $(11) for the three and nine months ended 2018 and 2017, respectively7
 5
 19
 15
 
 Other Comprehensive Income (Loss), net of tax3
 20
 —
 59
 
 COMPREHENSIVE INCOME (LOSS)$128
 $156
 $400
 $(72) 
          
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)
      
  June 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$20
 $32
 
 Accounts Receivable313
 380
 
 Accounts Receivable—Affiliated Companies81
 221
 
 Short-Term Loan to Affiliate519
 —
 
 Fuel218
 289
 
 Materials and Supplies, net376
 376
 
 Derivative Contracts24
 29
 
 Prepayments10
 11
 
 Other4
 3
 
 Total Current Assets1,565
 1,341
 
 PROPERTY, PLANT AND EQUIPMENT12,046
 11,755
 
 Less: Accumulated Depreciation and Amortization(3,267) (3,159) 
 Net Property, Plant and Equipment8,779
 8,596
 
 NONCURRENT ASSETS    
 NDT Fund2,049
 2,133
 
 Long-Term Investments87
 87
 
 Goodwill16
 16
 
 Other Intangibles127
 114
 
 Rabbi Trust Fund56
 57
 
 Derivative Contracts21
 7
 
 Other72
 67
 
 Total Noncurrent Assets2,428
 2,481
 
 TOTAL ASSETS$12,772
 $12,418
 
      
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.


Table of Contents

PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

      
  June 30,
2018		 December 31,
2017		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$250
 $250
 
 Accounts Payable468
 712
 
 Accounts Payable—Affiliated Companies148
 57
 
 Short-Term Loan from Affiliate—
 281
 
 Derivative Contracts23
 16
 
 Accrued Interest22
 20
 
 Other62
 99
 
 Total Current Liabilities973
 1,435
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC1,451
 1,406
 
 Asset Retirement Obligations831
 810
 
 OPEB Costs287
 283
 
 Derivative Contracts1
 5
 
 Accrued Pension Costs169
 184
 
 Long-Term Accrued Taxes45
 52
 
 Other143
 140
 
 Total Noncurrent Liabilities2,927
 2,880
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 LONG-TERM DEBT2,833
 2,136
 
 MEMBER’S EQUITY
   
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings5,161
 4,911
 
 Accumulated Other Comprehensive Loss(350) (172) 
 Total Member’s Equity6,039
 5,967
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$12,772
 $12,418
 
      
      
  September 30,
2018		 December 31,
2017		 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$41
 $32
 
 Accounts Receivable343
 380
 
 Accounts Receivable—Affiliated Companies121
 221
 
 Short-Term Loan to Affiliate119
 —
 
 Fuel329
 289
 
 Materials and Supplies, net386
 376
 
 Derivative Contracts11
 29
 
 Prepayments20
 11
 
 Other6
 3
 
 Total Current Assets1,376
 1,341
 
 PROPERTY, PLANT AND EQUIPMENT12,277
 11,755
 
 Less: Accumulated Depreciation and Amortization(3,408) (3,159) 
 Net Property, Plant and Equipment8,869
 8,596
 
 NONCURRENT ASSETS    
 NDT Fund2,096
 2,133
 
 Long-Term Investments88
 87
 
 Goodwill16
 16
 
 Other Intangibles107
 114
 
 Rabbi Trust Fund57
 57
 
 Derivative Contracts2
 7
 
 Other70
 67
 
 Total Noncurrent Assets2,436
 2,481
 
 TOTAL ASSETS$12,681
 $12,418
 
      
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.

Table of Contents

PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)

      
  September 30,
2018		 December 31,
2017		 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$250
 $250
 
 Accounts Payable465
 712
 
 Accounts Payable—Affiliated Companies21
 57
 
 Short-Term Loan from Affiliate—
 281
 
 Derivative Contracts13
 16
 
 Accrued Interest51
 20
 
 Other69
 99
 
 Total Current Liabilities869
 1,435
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC1,577
 1,406
 
 Asset Retirement Obligations841
 810
 
 OPEB Costs289
 283
 
 Derivative Contracts2
 5
 
 Accrued Pension Costs161
 184
 
 Long-Term Accrued Taxes1
 52
 
 Other140
 140
 
 Total Noncurrent Liabilities3,011
 2,880
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)

 

 
 LONG-TERM DEBT2,834
 2,136
 
 MEMBER’S EQUITY
   
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings5,086
 4,911
 
 Accumulated Other Comprehensive Loss(347) (172) 
 Total Member’s Equity5,967
 5,967
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$12,681
 $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)

      
  Six Months Ended 
  June 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income (Loss)$275
 $(267) 
 Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization166
 1,115
 
 Amortization of Nuclear Fuel95
 101
 
 Provision for Deferred Income Taxes and ITC51
 (226) 
 Interest Accretion on Asset Retirement Obligation20
 15
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives(54) (42) 
 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual

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

 Accounts Receivable84
 36
 
 Accounts Payable(90) (14) 
 Accounts Receivable/Payable—Affiliated Companies, net227
 75
 
 Other Current Assets and Liabilities(35) 7
 
 Employee Benefit Plan Funding and Related Payments(5) (4) 
 Other(9) 12
 
 Net Cash Provided By (Used In) Operating Activities869
 932
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(547) (576) 
 Purchase of Emissions Allowances and RECs(44) (29) 
 Proceeds from Sales of Trust Investments785
 602
 
 Purchases of Trust Investments(793) (616) 
 Short-Term Loan—Affiliated Company(519) (146) 
 Other23
 30
 
 Net Cash Provided By (Used In) Investing Activities(1,095) (735) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Issuance of Long-Term Debt700
 —
 
 Cash Dividend Paid(200) (175) 
 Short-Term Loan—Affiliated Company(281) —
 
 Other(5) (4) 
 Net Cash Provided By (Used In) Financing Activities214
 (179) 
 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash(12) 18
 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period32
 11
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$20
 $29
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$(72) $66
 
 Interest Paid, Net of Amounts Capitalized$18
 $29
 
 Accrued Property, Plant and Equipment Expenditures$189
 $194
 
      
      
  Nine Months Ended 
  September 30, 
  2018 2017 
 CASH FLOWS FROM OPERATING ACTIVITIES    
 Net Income (Loss)$400
 $(131) 
 Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:    
 Depreciation and Amortization260
 1,191
 
 Amortization of Nuclear Fuel143
 152
 
 Provision for Deferred Income Taxes and ITC177
 (259) 
 Interest Accretion on Asset Retirement Obligation31
 23
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives78
 8
 
 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual

74
 79
 
 Non-Cash Employee Benefit Plan Costs17
 21
 
 Net (Gains) Losses and (Income) Expense from NDT Fund(62) (86) 
 Net Change in Certain Current Assets and Liabilities:    
 Fuel, Materials and Supplies(50) (32) 
 Margin Deposit(77) 64

 Accounts Receivable42
 19
 
 Accounts Payable(22) (32) 
 Accounts Receivable/Payable—Affiliated Companies, net65
 205
 
 Other Current Assets and Liabilities(11) 11
 
 Employee Benefit Plan Funding and Related Payments(7) (5) 
 Other(53) 21
 
 Net Cash Provided By (Used In) Operating Activities1,005
 1,249
 
 CASH FLOWS FROM INVESTING ACTIVITIES    
 Additions to Property, Plant and Equipment(800) (903) 
 Purchase of Emissions Allowances and RECs(111) (90) 
 Proceeds from Sales of Trust Investments1,024
 886
 
 Purchases of Trust Investments(1,037) (900) 
 Short-Term Loan—Affiliated Company(119) 86
 
 Other33
 37
 
 Net Cash Provided By (Used In) Investing Activities(1,010) (884) 
 CASH FLOWS FROM FINANCING ACTIVITIES    
 Issuance of Long-Term Debt700
 —
 
 Cash Dividend Paid(400) (350) 
 Short-Term Loan—Affiliated Company(281) —
 
 Other(5) (4) 
 Net Cash Provided By (Used In) Financing Activities14
 (354) 
 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash9
 11
 
 Cash, Cash Equivalents and Restricted Cash at Beginning of Period32
 11
 
 Cash, Cash Equivalents and Restricted Cash at End of Period$41
 $22
 
 Supplemental Disclosure of Cash Flow Information:    
 Income Taxes Paid (Received)$31
 $75
 
 Interest Paid, Net of Amounts Capitalized$32
 $30
 
 Accrued Property, Plant and Equipment Expenditures$168
 $241
 
      
See disclosures regarding PSEG Power LLC included in the Notes to the Condensed Consolidated Financial Statements.

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









Note 1. Organization, 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 energy efficiency and related programs in New Jersey, which are regulated by the BPU.
PSEG Power LLC (Power)—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
PSEG’s other direct wholly owned subsidiaries 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, 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, 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 following provides 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 sixnine months ended JuneSeptember 30, 2018.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








          
  PSE&G Power Other (A) Consolidated 
  Millions 
 As of December 31, 2017        
 Cash and Cash Equivalents$242
 $32
 $39
 $313
 
 Restricted Cash in Other Current Assets—
 —
 —
 —
 
 Restricted Cash in Other Noncurrent Assets2
 —
 —
 2
 
 Cash, Cash Equivalents and Restricted Cash$244
 $32
 $39
 $315
 
 As of June 30, 2018        
 Cash and Cash Equivalents$20
 $20
 $55
 $95
 
 Restricted Cash in Other Current Assets4
 —
 —
 4
 
 Restricted Cash in Other Noncurrent Assets12
 —
 —
 12
 
 Cash, Cash Equivalents and Restricted Cash$36
 $20
 $55
 $111
 
          
          
  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 September 30, 2018        
 Cash and Cash Equivalents$25
 $41
 $22
 $88
 
 Restricted Cash in Other Current Assets6
 —
 —
 6
 
 Restricted Cash in Other Noncurrent Assets12
 —
 —
 12
 
 Cash, Cash Equivalents and Restricted Cash$43
 $41
 $22
 $106
 
          
(A)Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services.

Note 2. Recent Accounting Standards
New Standards Issued and Adopted
Revenue from Contracts With Customers—Accounting Standard Update (ASU) 2014-09, updated by ASUs 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, 2017-14
This accounting standard, and related updates, were adopted on January 1, 2018 using the full retrospective transition method. There was no effect on net income as a result of adoption. However, certain retrospective adjustments were recorded in accordance with the new standard. At PSE&G, retrospective adjustments increased Operating Revenues by $25$21 million and $39$60 million, Energy Costs by $16$8 million and $25$33 million, and Operation and Maintenance (O&M) Expense by $9$13 million and $14$27 million for the three and sixnine months ended JuneSeptember 30, 2017, respectively. At Power, retrospective adjustments reduced Operating Revenues and Energy Costs by $11$27 million and $26$53 million for the three and sixnine months ended JuneSeptember 30, 2017, respectively. For disclosure requirements under this standard, including Nature of Goods and Services, Disaggregation of Revenues, and Remaining Performance Obligations under Fixed Consideration Contracts, see Note 3. Revenues.
Recognition and Measurement of Financial Assets and Financial Liabilities—ASU 2016-01
Power maintains an external master trust fund to provide for the costs of decommissioning upon termination of operations of its nuclear facilities. In addition, PSEG maintains a grantor trust which was established to meet the obligations related to its non-qualified pension plans and deferred compensation plans, commonly referred to as a “Rabbi Trust.”
This accounting standard was 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 measured at fair value with the unrealized gains and losses now recognized through Net Income instead of Other Comprehensive Income (Loss). The debt securities in these trusts continue to be classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust securities are also included in Net Gains (Losses) on Trust Investments. A cumulative effect adjustment was made to reclassify the net unrealized gains related to equity investments of $342 million ($176 million, net of tax) from Accumulated Other Comprehensive Income to Retained Earnings on January 1, 2018. See Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax and Note 8. Trust Investments for further discussion.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments—ASU 2016-15
This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows.
PSEG adopted this standard on January 1, 2018 using a retrospective transition method and had no changes in its presentation of its Statement of Cash Flows for each period presented.
Statement of Cash Flows:  Restricted Cash—ASU 2016-18
This accounting standard was adopted on January 1, 2018. PSEG will continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG has provided a reconciliation of cash and cash equivalents and restricted
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








cash or restricted cash equivalents and has included a description of these amounts in Note 1. Organization, Basis of Presentation and Significant Accounting Policies. The effect of adoption on the JuneSeptember 30, 2018 Consolidated Statements of Cash Flows was immaterial.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)—ASU 2017-07
This accounting standard was adopted on January 1, 2018. Under the new guidance, entities are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by their employees during the period. The other components of net benefit cost are required to be presented in the Statement of Operations separately from the service cost component after Operating Income. Additionally, only the service cost component is eligible for capitalization, when applicable. As a result of adopting this standard, PSE&G reduced its charge to expense for the three and sixnine months ended JuneSeptember 30, 2018 by approximately $15 million and $29$44 million, respectively. The Condensed Consolidated Statements of Operations were recast to show retrospective adjustments of the non-service cost components of net benefit credits (costs) of $(1)$(2) million and $(3)$(5) million at PSE&G and $2 million and $4$6 million at Power, for the three and sixnine months ended JuneSeptember 30, 2017, respectively, from O&M Expense to a new line item after Operating Income entitled Non-Operating Pension and OPEB Credits (Costs). See.See Note 9. Pension and Other Postretirement Benefits (OPEB).
Stock Compensation - Scope of Modification Accounting—ASU 2017-09
This accounting standard was adopted on January 1, 2018. The standard will be applied prospectively to awards modified on or after January 1, 2018. PSEG does not expect a material impact from adoption of this new standard.
New Standards Issued But Not Yet Adopted
Leases—ASU 2016-02, updated by ASUs 2018-01, 2018-10 and 2018-11
This accounting standard, and related updates, replacesreplace existing lease accounting guidance and requiresrequire 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 allows lessees and lessors to apply either (i) a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, or (ii) a prospective transition approach for leases existing as of January 1, 2019 with a cumulative effect adjustment to be recorded to Retained Earnings. PSEG intends to adopt this standard on a prospective basis. Existing guidance related to leveraged leases does not change.
This standard permits an entity to elect an optional transition practical expedient to exclude evaluation of land easements that exist or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases.
PSEG is currently analyzing the impact of this standard on its consolidated financial statements while undertaking the following implementation activities: (i) reviewing all contract types throughout PSEG to determine the lease population; (ii) implementing a lease accounting system to capture and account for long-term (greater than one year) leases to be operational on January 1, 2019; (iii) developing internal lease accounting policies and determining the practical expedients PSEG will elect; and (iv) drafting lease disclosures required in 2019. Pending finalization of those activities, PSEG expects adoption of this standard on January 1, 2019 to impact its consolidated balance sheet by increasing its assets and liabilities by up to $300 million. PSE&G expects its assets and liabilities to each increase by up to $100 million and Power expects its assets and liabilities to each increase by up to $60 million. PSEG does not expect adoption to have a material impact on the balance sheetsConsolidated Statements of Operations of PSEG, and PSE&G but has not yet quantified this impact.and Power.
The standard is effective for annual and interim periods beginning after December 15, 2018.
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. The amendments also permit an entity to measure the interest rate risk on the hedged item in a partial-term fair value hedge assuming the hedged item has a term that reflects only the designated cash flows being hedged. Additionally, the amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allowing effectiveness assessments to be performed on a qualitative basis after hedge inception.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








The new guidance is effective for annual and interim periods beginning after December 15, 2018. The standard requires using a modified retrospective method upon adoption. Early adoption is permitted. PSEG analyzed the impact of this standard on its consolidated financial statements and has determined that the standard could enable PSEG to enter into certain transactions that
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






can be deemed hedges that previously would not have qualified. Adoption of this standard is not expected to have a material impact on PSEG’s financial statements.
Premium Amortization on Purchased Callable Debt Securities—ASU 2017-08
This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.
The standard is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period. If an entity early adopts the standard in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative effect adjustment directly to retained earnings as of the beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle. PSEG is currently analyzing the impact of this standard on its financial statements.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income—ASU 2018-02
This accounting standard would affect any entity that is required to apply the provisions of the Accounting Standards Codification (ASC) 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.
Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement—ASU 2018-13
This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements will be eliminated. The standard will also add certain other disclosure requirements for Level 3 fair value measurements.
The standard is effective for annual and interim periods beginning after December 15, 2019. Certain amendments in the standard should be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments of the standard should be applied retrospectively to all periods presented upon their effective date. Early adoption is permitted.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract—ASU 2018-15
This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal use software license. The standard follows the guidance in ASC 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position.
The standard is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. This standard should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PSEG is currently analyzing the impact of this standard on its financial statements.
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 does not expect adoption of this standard to have a material impact on its financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTSDisclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans—ASU 2018-14
(UNAUDITED)This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements.
Table of ContentsThe standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. An entity should apply the amendments in this standard on a retrospective basis to all periods presented.






Note 3. Revenues
Nature of Goods and Services
The following is a description of principal activities by reportable segment from which PSEG, PSE&G and Power generate their revenues.
PSE&G
Revenues from Contracts with Customers
Electric and Gas Distribution and Transmission Revenues—PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the 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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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 reported on a gross basis and recognized over time upon delivery of the capacity.
Gas Contracts—Power sells wholesale natural gas, primarily through an index based full requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. The BGSS contract, which extends through March 2019, will renew year-to-year thereafter unless terminated by 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






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








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 September 30, 2018          
 Revenues from Contracts with Customers          
 Electric Distribution$1,072
 $—
 $—
 $—
 $1,072
 
 Gas Distribution142
 —
 —
 (6) 136
 
 Transmission312
 —
 —
 —
 312
 
 Electricity and Related Product Sales          
 PJM          
 Third Party Sales—
 558
 —
 —
 558
 
 Sales to Affiliates—
 166
 —
 (166) —
 
 New York ISO—
 56
 —
 —
 56
 
 ISO New England—
 12
 —
 —
 12
 
 Gas Sales          
 Third Party Sales—
 24
 —
 —
 24
 
 Sales to Affiliates—
 47
 —
 (47) —
 
 Other Revenues from Contracts with Customers (A)60
 12
 142
 (1) 213
 
 Total Revenues from Contracts with Customers1,586
 875
 142
 (220) 2,383
 
 Revenues Unrelated to Contracts with Customers (B)9
 (7) 9
 —
 11
 
 Total Operating Revenues$1,595
 $868
 $151
 $(220) $2,394
 
            
            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Three Months Ended June 30, 2018          
 Revenues from Contracts with Customers          
 Electric Distribution$754
 $—
 $—
 $—
 $754
 
 Gas Distribution248
 —
 —
 (4) 244
 
 Transmission301
 —
 —
 —
 301
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 373
 —
 —
 373
 
          Sales to Affiliates—
 147
 —
 (147) —
 
 New York ISO—
 46
 —
 —
 46
 
 ISO New England—
 14
 —
 —
 14
 
 Gas Sales          
 Third Party Sales—
 30
 —
 —
 30
 
 Sales to Affiliates—
 108
 —
 (108) —
 
 Other Revenues from Contracts with Customers (A)63
 13
 125
 (1) 200
 
 Total Revenues from Contracts with Customers1,366
 731
 125
 (260) 1,962
 
 Revenues Unrelated to Contracts with Customers (B)20
 36
 (2) —
 54
 
 Total Operating Revenues$1,386
 $767
 $123
 $(260) $2,016
 
            
            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Nine Months Ended September 30, 2018          
 Revenues from Contracts with Customers          
 Electric Distribution$2,516
 $—
 $—
 $—
 $2,516
 
 Gas Distribution1,149
 —
 —
 (13) 1,136
 
 Transmission925
 —
 —
 —
 925
 
 Electricity and Related Product Sales          
 PJM          
 Third Party Sales—
 1,429
 —
 —
 1,429
 
 Sales to Affiliates—
 489
 —
 (489) —
 
 New York ISO—
 161
 —
 —
 161
 
 ISO New England—
 73
 —
 —
 73
 
 Gas Sales          
 Third Party Sales—
 118
 —
 —
 118
 
 Sales to Affiliates—
 552
 —
 (552) —
 
 Other Revenues from Contracts with Customers (A)195
 35
 404
 (3) 631
 
 Total Revenues from Contracts with Customers4,785
 2,857
 404
 (1,057) 6,989
 
 Revenues Unrelated to Contracts with Customers (B)41
 181
 17
 —
 239
 
 Total Operating Revenues$4,826
 $3,038
 $421
 $(1,057) $7,228
 
            
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Six Months Ended June 30, 2018          
 Revenues from Contracts with Customers          
 Electric Distribution$1,444
 $—
 $—
 $—
 $1,444
 
 Gas Distribution1,007
 —
 —
 (7) 1,000
 
 Transmission613
 —
 —
 —
 613
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 871
 —
 —
 871
 
          Sales to Affiliates—
 323
 —
 (323) —
 
 New York ISO—
 105
 —
 —
 105
 
 ISO New England—
 61
 —
 —
 61
 
 Gas Sales          
 Third Party Sales—
 94
 —
 —
 94
 
 Sales to Affiliates—
 505
 —
 (505) —
 
 Other Revenues from Contracts with Customers (A)135
 23
 262
 (2) 418
 
 Total Revenues from Contracts with Customers3,199
 1,982
 262
 (837) 4,606
 
 Revenues Unrelated to Contracts with Customers (B)32
 188
 8
 —
 228
 
 Total Operating Revenues$3,231
 $2,170
 $270
 $(837) $4,834
 
            
            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Three Months Ended June 30, 2017          
 Revenues from Contracts with Customers          
 Electric Distribution$757
 $—
 $—
 $—
 $757
 
 Gas Distribution233
 —
 —
 (6) 227
 
 Transmission307
 —
 —
 —
 307
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 302
 —
 —
 302
 
          Sales to Affiliates—
 171
 —
 (171) —
 
 New York ISO—
 50
 —
 —
 50
 
 ISO New England—
 9
 —
 —
 9
 
 Gas Sales          
 Third Party Sales—
 11
 —
 —
 11
 
 Sales to Affiliates—
 107
 —
 (107) —
 
 Other Revenues from Contracts with Customers (A)67
 12
 128
 (1) 206
 
 Total Revenues from Contracts with Customers1,364
 662
 128
 (285) 1,869
 
 Revenues Unrelated to Contracts with Customers (B)29
 256
 (12) —
 273
 
 Total Operating Revenues$1,393
 $918
 $116
 $(285) $2,142
 
            
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Six Months Ended June 30, 2017          
 Revenues from Contracts with Customers          
 Electric Distribution$1,458
 $—
 $—
 $—
 $1,458
 
 Gas Distribution988
 —
 —
 (7) 981
 
 Transmission606
 —
 —
 —
 606
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 616
 —
 —
 616
 
          Sales to Affiliates—
 355
 —
 (355) —
 
 New York ISO—
 86
 —
 —
 86
 
 ISO New England—
 20
 —
 —
 20
 
 Gas Sales          
 Third Party Sales—
 63
 —
 —
 63
 
 Sales to Affiliates—
 508
 —
 (508) —
 
 Other Revenues from Contracts with Customers (A)129
 22
 256
 (2) 405
 
 Total Revenues from Contracts with Customers3,181
 1,670
 256
 (872) 4,235
 
 Revenues Unrelated to Contracts with Customers (B)38
 517
 (57) —
 498
 
 Total Operating Revenues$3,219
 $2,187
 $199
 $(872) $4,733
 
            
            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Three Months Ended September 30, 2017          
 Revenues from Contracts with Customers          
 Electric Distribution$1,014
 $—
 $—
 $—
 $1,014
 
 Gas Distribution136
 —
 —
 (4) 132
 
 Transmission308
 —
 —
 —
 308
 
 Electricity and Related Product Sales          
 PJM          
 Third Party Sales—
 300
 —
 —
 300
 
 Sales to Affiliates—
 208
 —
 (208) —
 
 New York ISO—
 49
 —
 —
 49
 
 ISO New England—
 15
 —
 —
 15
 
 Gas Sales          
 Third Party Sales—
 26
 —
 —
 26
 
 Sales to Affiliates—
 44
 —
 (44) —
 
 Other Revenues from Contracts with Customers (A)59
 11
 130
 (1) 199
 
 Total Revenues from Contracts with Customers1,517
 653
 130
 (257) 2,043
 
 Revenues Unrelated to Contracts with Customers (B)13
 193
 5
 —
 211
 
 Total Operating Revenues$1,530
 $846
 $135
 $(257) $2,254
 
            
            
  PSE&G Power Other  Eliminations Consolidated 
  Millions 
 Nine Months Ended September 30, 2017          
 Revenues from Contracts with Customers          
 Electric Distribution$2,472
 $—
 $—
 $—
 $2,472
 
 Gas Distribution1,124
 —
 —
 (11) 1,113
 
 Transmission914
 —
 —
 —
 914
 
 Electricity and Related Product Sales          
  PJM          
 Third Party Sales—
 916
 —
 —
 916
 
          Sales to Affiliates—
 563
 —
 (563) —
 
 New York ISO—
 135
 —
 —
 135
 
 ISO New England—
 35
 —
 —
 35
 
 Gas Sales          
 Third Party Sales—
 89
 —
 —
 89
 
 Sales to Affiliates—
 552
 —
 (552) —
 
 Other Revenues from Contracts with Customers (A)188
 33
 386
 (3) 604
 
 Total Revenues from Contracts with Customers4,698
 2,323
 386
 (1,129) 6,278
 
 Revenues Unrelated to Contracts with Customers (B)51
 710
 (52) —
 709
 
 Total Operating Revenues$4,749
 $3,033
 $334
 $(1,129) $6,987
 
            
(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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








(B)Includes primarily alternative revenues at PSE&G, derivative contracts at Power, and lease contracts in Other. For the three and sixnine months ended JuneSeptember 30, 2018 and 2017, Other includes a $20 million loss and for the three and six months ended June 30, 2017, Other includes a $22 million loss and a $77 million loss, respectively, related to Energy Holdings’ investments in leases.
Contract Balances
PSE&G
PSE&G does not have any material contract balances (rights to consideration for services already provided or obligations to provide services in the future for consideration already received) as of JuneSeptember 30, 2018 and December 31, 2017. Substantially all of PSE&G’s accounts receivable result from contracts with customers. Allowances represented approximately seven percent of accounts receivable as of JuneSeptember 30, 2018 and December 31, 2017.
Power
Power generally collects consideration upon satisfaction of performance obligations, and therefore, Power had no material contract balances as of JuneSeptember 30, 2018 and December 31, 2017.
Power’s accounts receivable include amounts resulting from contracts with customers and other contracts which are out of scope of accounting guidance for revenues from contracts with customers. The majority of these accounts receivable are subject to master netting agreements. As a result, accounts receivable resulting from contracts with customers and receivables unrelated to contracts with customers are netted within Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets. In the wholesale energy markets in which Power operates, payment for services rendered and products transferred are typically due within 30 days of month of delivery. As such, there is little credit risk associated with these receivables and Power typically records no allowances.
Other
PSEG LI does not have any material contract balances as of JuneSeptember 30, 2018 and December 31, 2017.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






Remaining Performance Obligations under Fixed Consideration Contracts
Power and PSE&G primarily record revenues as allowed by the guidance, which states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity's performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. PSEG has future performance obligations under contracts with fixed consideration as follows:
Power
As stated above, capacity transactions with ISOs are reported on a net basis dependent on Power’s monthly net sale or purchase position through the individual ISOs.
Capacity Payments from the PJM Reliability Pricing Model (RPM) Annual Base Residual and Incremental Auctions—The Base Residual Auction is conducted annually three years in advance of the operating period. Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the base and incremental auctions which have been completed:
 
       
 Delivery Year $ per MW-Day MW Cleared 
 June 2018 to May 2019 $205 9,200
 
 June 2019 to May 2020 $116 8,900
 
 June 2020 to May 2021 $174 7,800
 
 June 2021 to May 2022 $178 7,700
 
   ��   
       
 Delivery Year $ per MW-Day MW Cleared 
 June 2018 to May 2019 $205 9,200
 
 June 2019 to May 2020 $116 8,900
 
 June 2020 to May 2021 $170 8,100
 
 June 2021 to May 2022 $178 7,700
 
       
Capacity Payments from the New England ISO Forward Capacity Market—The Forward Capacity Market Auction (FCM) is conducted annually three years in advance of the operating period. The table below includes Power’s cleared capacity in the FCM for the Bridgeport Harbor Station 5, which cleared the 2019/2020 auction at $231/MW-day for seven years, with escalations based on the Handy-Whitman Index and the planned retirement of Bridgeport Harbor Station 3 in 2021. Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM auctions which have been completed:
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








 
       
 Delivery Year $ per MW-Day MW Cleared 
 June 2018 to May 2019 $314 820
 
 June 2019 to May 2020 $231 1,330
 
 June 2020 to May 2021 $195 1,330
 
 June 2021 to May 2022 $192 950
 
 June 2022 to May 2023 $231 480
 
 June 2023 to May 2024 $231 480
 
 June 2024 to May 2025 $231 480
 
 June 2025 to May 2026 $231 480
 
       
Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $180$171 million.
Other
The LIPA OSA is a 12-year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the provision of services thereunder in 2018 is $64 million and could increase each year based on the change in the Consumer Price Index (CPI). The incentive for 2018 can range from zero to approximately $10 million and could increase each year thereafter based on the change in the CPI.

Note 4. Early Plant Retirements
Fossil
On June 1, 2017, Power completed its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
TableAs of Contents






For the three and six months ended June 30,1, 2017, Power recognized total Depreciation and Amortization of $390 million and $964 million respectively, for the Hudson and Mercer units to reflect the significant shortening of their expected economic useful lives in 2017. In the three and sixnine months ended JuneSeptember 30, 2018,2017, Power recognized pre-tax charges (credits)of $1 million and $10 million, respectively, in Energy Costs of $(1) million and $3 million, respectively, primarily for coal inventory lower of cost or market adjustments. In the three and sixnine months ended June 30, 2017, Power recognized pre-tax charges of the same nature in Energy Costs of $2 million and $9 million, respectively. In the three and six months ended JuneSeptember 30, 2017, Power also recognized pre-tax charges in O&M of $4$8 million and $12 million, respectively, of shut down costs and a net increase in the Asset Retirement Obligation liability due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. In 2018, no material costs were recorded. Power is exploring various opportunities with
these sites, including using the sites for alternative industrial activity 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.
PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the held for use classification of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.
Nuclear
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. In FebruarySeptember 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure ofshut down 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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 May 2018, the governor of New Jersey signed legislation that would provide a safety net in order to prevent the loss of environmental attributes from selected nuclear generating stations referred to as the ZEC (Zero Emissions Certificate) program. The legislation calls for the BPU to establish a collection process for a customer charge, determine eligibility and certification of need, and potentially select nuclear plants to receive ZECs starting in April 2019. The law mandates each New Jersey electric distribution company (EDC), including PSE&G, to purchase ZECs and recover its procurement of ZECs through a non-bypassable charge (ZEC charge) in the amount of $0.004 per kilowatt-hour.
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 ourPower’s nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for selection of the units under the newly enacted legislation in the state of New Jersey. Power and Exelon have agreed to cancel the funding of future capital projects at the Salem generating station that are not required to meet NRC or other regulatory requirements or that are not required to ensure its safe operation. Power and Exelon have agreed to continue to assess and, when appropriate, approve the funding of individual capital projects to ensure compliance with regulatory requirements and the safe operation of the Salem generating station and that the funding of thesepreviously postponed projects may be restored ifas a result of the legislation enacted in New Jersey sufficiently values the attributes of nuclear generation and Salem benefits from such legislation.
Power believes it may be unable to cover its costs and would be inadequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units, which would result in Power retiring these units early if (i) energy market prices continue to be depressed, (ii) there are adverse impacts from potential changes to the capacity market construct being considered by FERC, or (iii) Salem and/or Hope Creek are not selected to participate in the ZEC program or the ZEC program does not adequately compensate our nuclear generating stations for their attributes. 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. If any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. In May 2018, the governor of New Jersey signed legislation that would provide a safety net in order to prevent the loss of environmental attributes from selected nuclear generating stations referred to as the zero emissions certificate (ZEC) program. The legislation calls for the BPU (within a 330-day period from enactment) to establish a collection process for a customer charge, determine eligibility and certification of need, and ultimately select nuclear plants to potentially receive ZECs starting in April 2019. Power cannot predict whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
If energy market prices continue to be depressed, there are adverse impacts from potential changes to the capacity market construct being considered by FERC, or the ZEC program does not adequately compensate our nuclear generating stations for
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






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.
The following table provides the balance sheet amounts by generating station as of JuneSeptember 30, 2018 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.
           
   As of June 30, 2018 
   Hope Creek Salem Support Facilities and Other (A) Peach Bottom 
   Millions 
 Assets         
 Materials and Supplies Inventory $83
 $82
 $—
 $42
 
 Nuclear Production, net of Accumulated Depreciation 688
 646
 203
 786
 
 Nuclear Fuel In-Service, net of Accumulated Depreciation 171
 89
 —
 119
 
 Construction Work in Progress (including nuclear fuel) 140
 105
 2
 24
 
         Total Assets $1,082
 $922
 $205
 $971
 
 Liability         
 Asset Retirement Obligation $309
 $255
 $—
 $210
 
         Total Liabilities $309
 $255
 $—
 $210
 
          Net Assets $773
 $667
 $205
 $761
 
 NRC License Renewal Term 2046 2036/2040
 N/A
 2033/2034
 
 % Owned 100% 57% Various
 50% 
           
           
   As of September 30, 2018 
   Hope Creek Salem Support Facilities and Other (A) Peach Bottom 
   Millions 
 Assets         
 Materials and Supplies Inventory $83
 $72
 $—
 $42
 
 Nuclear Production, net of Accumulated Depreciation 684
 642
 199
 775
 
 Nuclear Fuel In-Service, net of Accumulated Depreciation 155
 72
 —
 103
 
 Construction Work in Progress (including nuclear fuel) 144
 156
 2
 87
 
         Total Assets $1,066
 $942
 $201
 $1,007
 
 Liability         
 Asset Retirement Obligation $313
 $258
 $—
 $213
 
         Total Liabilities $313
 $258
 $—
 $213
 
          Net Assets $753
 $684
 $201
 $794
 
 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.
(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 8. Trust Investments.

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








Note 5. Variable Interest Entity (VIE)
VIE for which PSEG LI is the Primary Beneficiary
PSEG LI consolidates 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 $109$126 million and $112$114 million for the three months and $229$355 million and $224$338 million for the sixnine months ended JuneSeptember 30, 2018 and
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






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.

Note 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, 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 FilingFilings—In JanuaryOctober 2018, the BPU issued an Order approving the settlement of PSE&G filed a&G’s distribution base rate case as required aswith new rates effective November 1, 2018. The settlement resulted in a conditionnet reduction in overall annual revenues of approvalapproximately $13 million, comprised of its Energy Strong Program I (ESP I) approveda $212 million increase in base revenues, including recovery of deferred storm costs, offset by the BPU in 2014.return of tax benefits of approximately $225 million. The filing requested an approximate 1% increase in revenues and recoverytax benefits include the flow-back to customers of investments made to strengthenexcess accumulated deferred income taxes resulting from 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%rates provided in the Tax Cuts and Jobs Act of 2017 (Tax Act), including as well as the flow-back to customers of excess accumulated deferred income taxes. In March 2018,taxes from previously realized tax repair deductions and tax benefits from future tax repair deductions as realized. As a result of the BPU approved interim rate reductions for all their jurisdictional utilities, including PSE&G, reflecting the reductionagreement to flow back tax repair-related accumulated deferred income taxes in the settlement, PSE&G recognized a $581 million regulatory liability and a corresponding regulatory asset as of September 30, 2018. The Order provides for a $9.5 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 54% equity component of its capitalization structure. In addition to the $13 million annual revenue reduction, the Order provides for a $28 million one-time refund to customers in November and December 2018 for taxes collected at the higher federal corporateincome tax rate.rate for the January 1 to March 31, 2018 period. The BPU approved a rate reduction to PSE&G’s current base electric and gas revenues effective April 1, 2018, byto PSE&G’s then current electric and gas base rates of approximately $71 million and $43 million, respectively, on an annual basis, (or about 2% combined). The refund to customers for overcollection of revenues atreflect the higherlower federal income tax rate for the January 1 to March 31, 2018 period and the flow-back to customers of certain excess deferred income taxes will be addressed in PSE&G’s ongoing base rate case proceeding. In May 2018, PSE&G updated its base rate filing to include nine months of actual data. As a result of the base rate reduction implemented on April 1 2018, among other factors, PSE&G’s updated filing requests an approximate 3% increase in revenues. PSE&G anticipates a decision by the BPU that new base rates will go into effect in the fourth quarter of 2018.and forward.
Transmission Formula Rate Filings—In JanuaryOctober 2018, PSE&G made two FERC filings with respect to its Transmission Formula Rate. PSE&G filed with FERC a revised 2018its 2019 Annual Transmission Formula Rate Update reducing its 2018update with FERC requesting approximately $100 million in increased annual 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, 2018.2019, subject to true-up. In addition, PSE&G filed a Section 205 filing that seeks FERC continuesapproval to assess whether, and if so how, it will address changes and flow-backsrefund approximately $155 million of transmission related “unprotected excess deferred income tax benefits” to transmission customers over the 2019 twelve month period. The amount of unprotected excess deferred taxes is subject to change pending further Internal Revenue Service (IRS) guidance. FERC approval of PSE&G’s Section 205 filing is required to commence any refund to customers relating to accumulated deferred income taxes and bonus depreciation.as such, the Annual Transmission Formula Rate update request does not include the impact of the tax refund. This matter is pending.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








In June 2018, PSE&G filed its 2017 true-up adjustment pertaining to its transmission formula rates in effect for 2017. This resulted in an adjustment of $27 million more than the 2017 originally filed revenues, the impact of which PSE&G had primarily recognized in its Consolidated Statement of Operations for the year ended December 31, 2017.
BGSS—In JuneSeptember 2018, PSE&G made its annual BGSS filing with the BPU requesting aprovisionally approved PSE&G’s request to decrease in theits BGSS rates which will decrease annual BGSS revenues ofby $26 million. If approved, theThe BGSS rate would be decreased from approximately 37 cents to 35 cents per therm for residential gas customers to be effective October 1, 2018. This matter is pending.
In April 2018, the BPU approved the final BGSS rates which were effective October 1, 2017.
Green Program Recovery Charges (GPRC)—In DecemberOctober 2018, the BPU approved PSE&G’s 2017 February 2018GPRC cost recovery petition requesting recovery of approximately $58 million and March$15 million in electric and gas revenues, respectively, on an annual basis.
In June 2018, PSE&G filed withits 2018 GPRC cost recovery petition requesting recovery of approximately $65 million and $6 million in electric and gas revenues, respectively, on an annual basis.
Remediation Adjustment Charge (RAC)—In October 2018, the BPU for self-implementing monthly bill creditsapproved PSE&G’s filing with respect to its RAC 25 petition allowing recovery of 15 cents per therm for the months of January$63 million effective November 1, 2018 related to Manufactured Gas Plant expenditures from August 1, 2016 through April 2018. Monthly bill credits of $125 million were credited to customers for the months of January through April 2018.July 31, 2017.
ESPEnergy Strong Program I (ES I) Recovery Filing—In MarchAugust 2018, the BPU approved recovery of PSE&G’s ES I capital investment petition of an annual revenue requirement increase of $0.6 million and September$0.1 million associated with electric and gas investment costs, respectively. This represents the final recovery of each year, PSE&G fileselectric and gas ES I capital investment costs consistent with the BPU for base rate recoveryOrder of ESP I investments which include a returnApproval of and on its investment.the Energy Strong Program.
In February 2018, the BPU approved recovery of an annual revenue requirement of $8 million associated with electric ESPES I capital investment costs placed in service from June 1, 2017 through November 30, 2017.
Weather Normalization Clause (WNC)—In October 2018, the BPU approved PSE&G’s 2017-2018 WNC petition on a provisional basis allowing a net recovery of $14 million to be collected over the 2018-2019 Winter Period with the new rate effective November 1, 2018. The $14 million net recovery is the result of $9 million of excess revenues from the colder-than-normal 2017-2018 Winter Period offset by $23 million of remaining prior Winter Period undercollection.
In April 2018, the BPU gave final approval to PSE&G’s petition to collect $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.
Gas System Modernization Program I (GSMP I)—In October 2018, PSE&G updated its annual GSMP I cost recovery petition to include GSMP I investments in service as of September 30, 2018. The petition seeks BPU approval to recover in gas base rates an estimated annual revenue increase of $21 million effective January 1, 2019.
Societal Benefits Charge—In February 2018, the BPU approved PSE&G’s petition to increase electric rates by approximately $20 million on an annual basis 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 were effective April 1, 2018.
Weather Normalization Clause (WNC)—In April 2018, the BPU gave final approval to PSE&G’s petition to collect $55 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period (October 1 through May 31), which resulted in a deficiency of $31 million, plus a carryover balance of $24 million from the 2015-2016 Winter Period.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






In June 2018, PSE&G filed its 2017-2018 WNC petition seeking a net recovery of $14 million to be collected over the 2018-2019 Winter Period. The $14 million net recovery is the result of $9 million of excess revenues from the colder-than- normal 2017-2018 Winter Period offset by $23 million of remaining prior Winter Period undercollection.
Green Program Recovery Charges (GPRC)—In June 2018, PSE&G filed its 2018 GPRC cost recovery petition requesting recovery of approximately $65 million and $6 million in electric and gas revenues, respectively, on an annual basis. This matter is pending.
Gas System Modernization Program I (GSMP I)—In July 2018, PSE&G filed its annual GSMP I cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $26 million effective January 1, 2019. This increase represents the return of and on investment for GSMP I investments expected to be in service through September 30, 2018. This request will be updated in October 2018 for actual costs.

Note 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
(UNAUDITED)
Table of Contents







       
 Outstanding Loans by Class of Customer 
   As of As of 
 Consumer Loans June 30,
2018		 December 31,
2017		 
   Millions 
 Commercial/Industrial $169
 $158
 
 Residential 9
 10
 
 Total $178
 $168
 
       

       
 Outstanding Loans by Class of Customer 
   As of As of 
 Consumer Loans September 30,
2018		 December 31,
2017		 
   Millions 
 Commercial/Industrial $166
 $158
 
 Residential 9
 10
 
 Total $175
 $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 first quarter of 2017, due to continuing liquidity issues facing NRG REMA, LLC (REMA), economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain discussions with REMA management, Energy Holdings recorded a $55 million pre-tax charge for its current best estimate of loss related to the lease receivables. Additional pre-tax charges of $22 million (including $7 million related to residual value impairment) were recorded in the quarter ended June 30, 2017. Subject to the terms of the Credit Support Forbearance and Rent Payment Forbearance described below, lease payments and adjustments to qualifying credit support on the REMA leases are due semiannually in January and July of each year.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






Based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $20 million pre-tax charge in the quarterthree months ended June 30, 2018 for its current best estimate of loss related to lease receivables. Pre-tax charges were reflected in Operating Revenues in the first half of 2018 and 2017 and are included in Gross Investment in Leases as of JuneSeptember 30, 2018.
Certain subsidiaries of Energy Holdings, REMA, certain holders of the pass-through certificates and other parties have entered into a forbearance agreement (Credit Support Forbearance) relating to REMA’s obligation to procure additional qualifying credit support for the Conemaugh facility. In addition,September 2018, certain subsidiaries of Energy Holdings (PSEG Entities) entered into a Restructuring Support Agreement (RSA) with REMA. Pursuant to the RSA, the PSEG Entities have agreed to support implementation of restructuring and related transactions with respect to REMA’s indebtedness. Such restructuring transactions will be implemented by REMA certain holderson an in-court basis under Chapter 11 of the pass-through certificates andBankruptcy Code. The RSA outlines a plan of reorganization under which, in addition to other parties have entered into forbearance agreements (Rent Payment Forbearance)terms, the ownership interest in the leases relating to the Keystone and Conemaugh investments will be transferred to debtholders of REMA. Upon consummation of the restructuring transactions, the PSEG Entities will receive $31.5 million in cash in exchange for (a) the full satisfaction of all claims asserted against REMA and Shawville facilities. The parties(b) approval of certain amendments to the Rent Payment Forbearance haveShawville lease. The Shawville lease amendments, among other things, will allow REMA to express tentative interest in a renewal on or after November 24, 2019, with similar changes to the other milestones in the lease renewal procedures. In addition, REMA has agreed to permit REMAfund qualifying credit support up to enter into agreements with third parties relating to certain energy management, operation and maintenance and other services and have agreed to temporarily forbear from exercising rights and remedies related to certain events of default relating to certain periodic lease rent payments required to be made by REMA in July 2018.$36 million.
The Credit Support Forbearance will remain effective until the earlier of (i) two weeks following the date on which Energy Holdings subsidiaries, REMA and/or the consenting certificate holders provide written notice to REMAwill be required upon resolution of its intention to terminate the Forbearance, and (ii) the date on which any event of termination as specified in the Credit Support Forbearance occurs. The Rent Payment Forbearance for each facility will remain effective until the earlier of (i) August 17, 2018 and (ii) the date on which any of the following events occur: (a) a new event of default occurs and is continuing under the operative documents governing the respective facilities; (b) REMA commences a case under title 11 of the United States Bankruptcy Code or (c) REMA terminates discussions with Energy Holdings and/or the consenting pass-through certificate holders regarding a potential restructuring by REMA.
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 requiredthis matter to accelerate and pay materialapproximately $40 million of state deferred tax liabilities and accelerate and pay and/or reduce $85 million of a forecasted federal tax loss to the Internal Revenue Service (IRS). Also, if energy markets continue to deteriorate, it is possible that additional write-downs, including residual value impairment, could occur.IRS.
The following table shows Energy Holdings’ gross and net lease investment asAs of JuneSeptember 30, 2018, no additional charges were recorded because the anticipated proceeds of $31.5 million from the transactions described above are in excess of the September 30, 2018 recorded amounts for the Keystone and December 31, 2017.
      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$525
 $546
 
 Estimated Residual Value of Leased Assets326
 326
 
 Total Investment in Rental Receivables851
 872
 
 Unearned and Deferred Income(299) (307) 
 Gross Investment in Leases552
 565
 
 Deferred Tax Liabilities(500) (480) 
 Net Investment in Leases$52
 $85
 
      
Conemaugh lease investments.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








The following table shows Energy Holdings’ gross and net lease investment as of September 30, 2018 and December 31, 2017.
      
  As of As of 
  September 30,
2018		 December 31,
2017		 
  Millions 
 Lease Receivables (net of Non-Recourse Debt)$524
 $546
 
 Estimated Residual Value of Leased Assets326
 326
 
 Total Investment in Rental Receivables850
 872
 
 Unearned and Deferred Income(294) (307) 
 Gross Investment in Leases556
 565
 
 Deferred Tax Liabilities(470) (480) 
 Net Investment in Leases$86
 $85
 
      
The corresponding receivables associated with the lease portfolio are reflected 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 June 30, 2018   
  As of June 30, 2018 
   Millions 
 AA $14
 
 BBB+ — BBB- 316
 
 BB- 133
 
 CCC- 62
 
 Total $525
 
     
     
   
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating Standard & Poor’s (S&P) as of September 30, 2018   
  As of September 30, 2018 
   Millions 
 AA $13
 
 BBB+ — BBB- 316
 
 BB 133
 
 NR 62
 
 Total $524
 
     
The “BB-”“BB” and the “CCC-”“NR” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of JuneSeptember 30, 2018, the gross investment in the leases of such assets, net of non-recourse debt, was $315316 million ($(112)(83) million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.
                 
 Asset Location 
Gross
Investment
 
%
Owned
 Total MW 
Fuel
Type
 
Counterparties’
S&P Credit
Ratings
 Counterparty 
     Millions           
 Powerton Station Units 5 and 6 IL $132
 64% 1,538
 Coal BB- NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $85
 64% 1,036
 Gas BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $10
 17% 1,711
 Coal CCC- REMA (A) 
 Conemaugh Station Units 1 and 2 PA $10
 17% 1,711
 Coal CCC- REMA (A) 
 Shawville Station Units 1, 2, 3 and 4 PA $78
 100% 596
 Gas CCC- REMA (A) 
                 
                 
 Asset Location 
Gross
Investment
 
%
Owned
 Total MW 
Fuel
Type
 
Counterparties’
S&P Credit
Ratings
 Counterparty 
     Millions           
 Powerton Station Units 5 and 6 IL $133
 64% 1,538
 Coal BB NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $85
 64% 1,036
 Gas BB NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $10
 17% 1,711
 Coal NR REMA (A) 
 Conemaugh Station Units 1 and 2 PA $9
 17% 1,711
 Coal NR REMA (A) 
 Shawville Station Units 1, 2, 3 and 4 PA $79
 100% 596
 Gas NR REMA (A) 
                 
(A)GenOn and certain of its subsidiaries (which did not include REMA)REMA filed a voluntary petitionspetition for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged inSee above for a balance sheet restructuring, which will take an undetermined time to complete. Certain subsidiaries of Energy Holdings, REMA, consenting holdersdiscussion of the pass-through certificates and other parties haveRSA entered into a Credit Support Forbearanceby REMA and the PSEG Entities relating to the Conemaugh facility and the Rent Payment Forbearance relating to the Keystone, Conemaugh and Shawville facilities, as described above.certain restructuring transactions by REMA.
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. 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)
Table of Contents








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, for certain leases, 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.
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.

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






Note 8. 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 (IRC) 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.
The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.
          
  As of June 30, 2018 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
 Domestic$471
 $235
 $(8) $698
 
    International321
 76
 (14) 383
 
 Total Equity Securities792
 311
 (22) 1,081
 
 Available-for Sale Debt Securities        
 Government528
 1
 (12) 517
 
 Corporate464
 —
 (14) 450
 
 Total Available-for-Sale Debt Securities992
 1
 (26) 967
 
 Other1
 —
 —
 1
 
 Total NDT Fund Investments$1,785
 $312
 $(48) $2,049
 
          
          
  As of September 30, 2018 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
 Domestic$467
 $268
 $(7) $728
 
 International330
 78
 (16) 392
 
 Total Equity Securities797
 346
 (23) 1,120
 
 Available-for Sale Debt Securities        
 Government537
 —
 (17) 520
 
 Corporate468
 1
 (13) 456
 
 Total Available-for-Sale Debt Securities1,005
 1
 (30) 976
 
 Other—
 —
 —
 —
 
 Total NDT Fund Investments$1,802
 $347
 $(53) $2,096
 
          
          
  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
 
          
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








Net unrealized gains (losses) on debt securities of $(14)$(17) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of JuneSeptember 30, 2018. The portion of net unrealized gains (losses) recognized during the secondthird quarter and first halfnine months of 2018 related to equity securities still held at the end of JuneSeptember 30, 2018 were $12$41 million and $(3)$26 million, respectively.
The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 Accounts Receivable$11
 $24
 
 Accounts Payable$8
 $74
 
      
      
  As of As of 
  September 30,
2018		 December 31,
2017		 
  Millions 
 Accounts Receivable$13
 $24
 
 Accounts Payable$14
 $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 June 30, 2018 As of December 31, 2017 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Equity Securities (A)                
    Domestic$79
 $(8) $—
 $—
 $40
 $(2) $—
 $—
 
    International74
 (13) 4
 (1) 29
 (3) 2
 —
 
 Total Equity Securities153
 (21) 4
 (1) 69
 (5) 2
 —
 
 Available-for Sale Debt Securities                
 Government (B)402
 (9) 64
 (3) 343
 (2) 91
 (2) 
 Corporate (C)358
 (12) 25
 (2) 191
 (1) 27
 (1) 
 Total Available-for-Sale Debt Securities760
 (21) 89
 (5) 534
 (3) 118
 (3) 
 NDT Trust Investments$913
 $(42) $93
 $(6) $603
 $(8) $120
 $(3) 
                  
                  
  As of September 30, 2018 As of December 31, 2017 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Equity Securities (A)                
 Domestic$78
 $(7) $4
 $—
 $40
 $(2) $—
 $—
 
 International87
 (14) 8
 (2) 29
 (3) 2
 —
 
 Total Equity Securities165
 (21) 12
 (2) 69
 (5) 2
 —
 
 Available-for Sale Debt Securities                
 Government (B)342
 (10) 153
 (7) 343
 (2) 91
 (2) 
 Corporate (C)342
 (11) 49
 (2) 191
 (1) 27
 (1) 
 Total Available-for-Sale Debt Securities684
 (21) 202
 (9) 534
 (3) 118
 (3) 
 NDT Trust Investments$849
 $(42) $214
 $(11) $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. 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 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 JuneSeptember 30, 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 JuneSeptember 30, 2018.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








The proceeds from the sales of and the net gains (losses) on securities in the NDT Fund were:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
  Millions 
 Proceeds from NDT Fund Sales (A)$402
 $320
 $774
 $567
 
 Net Realized Gains (Losses) on NDT Fund        
 Gross Realized Gains$34
 $32
 $58
 $53
 
 Gross Realized Losses(10) (5) (22) (9) 
 Net Realized Gains (Losses) on NDT Fund (B)$24
 $27
 $36
 $44
 
 Unrealized Gains (Losses) on Equity Securities in NDT Fund (C)(16) N/A
 (50) N/A
 
 Other-Than-Temporary-Impairments$—
 $(3) —
 (4) 
 Net Gains (Losses) on NDT Fund Investments$8
 $24
 $(14) $40
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
  Millions 
 Proceeds from NDT Fund Sales (A)$231
 $278
 $1,005
 $845
 
 Net Realized Gains (Losses) on NDT Fund        
 Gross Realized Gains$17
 $29
 $75
 $82
 
 Gross Realized Losses(7) (5) (29) (14) 
 Net Realized Gains (Losses) on NDT Fund (B)$10
 $24
 $46
 $68
 
 Unrealized Gains (Losses) on Equity Securities in NDT Fund (C)34
 N/A
 (16) N/A
 
 Other-Than-Temporary-Impairments (OTTI)$—
 $(5) —
 (9) 
 Net Gains (Losses) on NDT Fund Investments$44
 $19
 $30
 $59
 
          
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.
(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 JuneSeptember 30, 2018 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $10
 
 1 - 5 years 298
 
 6 - 10 years 196
 
 11 - 15 years 45
 
 16 - 20 years 71
 
 Over 20 years 347
 
 Total NDT Available-for-Sale Debt Securities$967
 
     
     
 Time Frame Fair Value 
   Millions 
 Less than one year $11
 
 1 - 5 years 282
 
 6 - 10 years 201
 
 11 - 15 years 47
 
 16 - 20 years 73
 
 Over 20 years 362
 
 Total NDT Available-for-Sale Debt Securities$976
 
     
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 these 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). 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.”
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.
          
  As of June 30, 2018 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
    Domestic$21
 $3
 $—
 $24
 
    International—
 —
 —
 —
 
 Total Equity Securities21
 3
 —
 24
 
 Available-for-Sale Debt Securities        
 Government96
 —
 (2) 94
 
 Corporate110
 —
 (4) 106
 
 Total Available-for-Sale Debt Securities206
 —
 (6) 200
 
 Total Rabbi Trust Investments$227
 $3
 $(6) $224
 
          
          
  As of September 30, 2018 
  Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
  Millions 
 Equity Securities        
 Domestic$21
 $4
 $—
 $25
 
 International—
 —
 —
 —
 
 Total Equity Securities21
 4
 —
 25
 
 Available-for-Sale Debt Securities        
 Government103
 —
 (4) 99
 
 Corporate104
 —
 (3) 101
 
 Total Available-for-Sale Debt Securities207
 —
 (7) 200
 
 Total Rabbi Trust Investments$228
 $4
 $(7) $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
 
          
Net unrealized gains (losses) on debt securities of $(4)$(5) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2018. The portion of net unrealized gains (losses) recognized during both the secondthird quarter and first halfnine months of 2018 related to equity securities still held at the end of JuneSeptember 30, 2018 was less thanwere $1 million.million and $2 million, respectively.
The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.
      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 Accounts Receivable$2
 $2
 
 Accounts Payable$—
 $1
 
      
      
  As of As of 
  September 30,
2018		 December 31,
2017		 
  Millions 
 Accounts Receivable$1
 $2
 
 Accounts Payable$—
 $1
 
      
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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 June 30, 2018 As of December 31, 2017 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Available-for-Sale Debt Securities                
 Government (A)$57
 $(1) 23
 (1) $28
 $—
 $25
 $(1) 
 Corporate (B)93
 (4) 6
 —
 39
 (1) 9
 —
 
 Total Available-for-Sale Debt Securities150
 (5) 29
 (1) 67
 (1) 34
 (1) 
 Rabbi Trust Investments$150
 $(5) $29
 $(1) $67
 $(1) $34
 $(1) 
                  
                  
  As of September 30, 2018 As of December 31, 2017 
  
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
  
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
  Millions 
 Available-for-Sale Debt Securities                
 Government (A)$70
 $(2) $28
 $(2) $28
 $—
 $25
 $(1) 
 Corporate (B)76
 (3) 14
 —
 39
 (1) 9
 —
 
 Total Available-for-Sale Debt Securities146
 (5) 42
 (2) 67
 (1) 34
 (1) 
 Rabbi Trust Investments$146
 $(5) $42
 $(2) $67
 $(1) $34
 $(1) 
                  
(A)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 JuneSeptember 30, 2018.
(B)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of JuneSeptember 30, 2018.
The proceeds from the sales of and the net gains (losses) on securities in the Rabbi Trust Fund were:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
  Millions 
 Proceeds from Rabbi Trust Sales (A)$22
 $93
 $47
 $144
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$—
 $2
 $2
 $17
 
 Gross Realized Losses—
 (1) (2) (4) 
 Net Realized Gains (Losses) on Rabbi Trust (B)—
 1
 —
 13
 
 Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C)—
 N/A
 —
 N/A
 
 Other-Than-Temporary-Impairments—
 $—
 —
 —
 
 Net Gains (Losses) on Rabbi Trust Investments$—
 $1
 $—
 $13
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
  Millions 
 Proceeds from Rabbi Trust Sales (A)$33
 $24
 $80
 $168
 
 Net Realized Gains (Losses) on Rabbi Trust:        
 Gross Realized Gains$—
 $—
 $2
 $17
 
 Gross Realized Losses(1) (1) (3) (5) 
 Net Realized Gains (Losses) on Rabbi Trust (B)(1) (1) (1) 12
 
 Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C)2
 N/A
 2
 N/A
 
 OTTI—
 —
 —
 —
 
 Net Gains (Losses) on Rabbi Trust Investments$1
 $(1) $1
 $12
 
          
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.
(C)Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








The Rabbi Trust debt securities held as of JuneSeptember 30, 2018 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $1
 
 1 - 5 years 39
 
 6 - 10 years 23
 
 11 - 15 years 7
 
 16 - 20 years 18
 
 Over 20 years 112
 
 Total Rabbi Trust Available-for-Sale Debt Securities$200
 
     
     
 Time Frame Fair Value 
   Millions 
 Less than one year $3
 
 1 - 5 years 28
 
 6 - 10 years 32
 
 11 - 15 years 7
 
 16 - 20 years 22
 
 Over 20 years 108
 
 Total Rabbi Trust Available-for-Sale Debt Securities$200
 
     
PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:
      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 PSE&G$45
 $46
 
 Power56
 57
 
 Other123
 128
 
 Total Rabbi Trust Investments$224
 $231
 
      
      
  As of As of 
  September 30,
2018		 December 31,
2017		 
  Millions 
 PSE&G$46
 $46
 
 Power57
 57
 
 Other122
 128
 
 Total Rabbi Trust Investments$225
 $231
 
      

Note 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.
The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco. Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for capitalization, when applicable. For additional information, see Note 2. Recent Accounting Standards.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








                  
  Pension Benefits OPEB Pension Benefits OPEB 
  Three Months Ended Three Months Ended Six Months Ended Six Months Ended 
  June 30, June 30, June 30, June 30, 
  2018
 2017 2018
 2017 2018 2017 2018 2017 
  Millions 
 Components of Net Periodic Benefit (Credits) Costs                
 Service Cost (included in O&M Expense)$33
 $28
 $5
 $4
 $65
 $57
 $9
 $8
 
 Non-Service Components of Pension and OPEB (Credits) Costs                
 Interest Cost52
 51
 17
 16
 104
 102
 33
 32
 
 Expected Return on Plan Assets(110) (99) (11) (9) (220) (197) (21) (17) 
 Amortization of Net                
 Prior Service Cost(5) (4) —
 (2) (9) (9) —
 (5) 
 Actuarial Loss21
 25
 16
 12
 42
 49
 32
 25
 
 Non-Service Components of Pension and OPEB (Credits) Costs(42) (27) 22
 17
 (83) (55) 44
 35
 
 Total Benefit (Credits) Costs$(9) $1
 $27
 $21
 $(18) $2
 $53
 $43
 
                  
                  
  Pension Benefits OPEB Pension Benefits OPEB 
  Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended 
  September 30, September 30, September 30, September 30, 
  2018
 2017 2018
 2017 2018 2017 2018 2017 
  Millions 
 Components of Net Periodic Benefit (Credits) Costs                
 Service Cost (included in O&M Expense)$32
 $29
 $4
 $4
 $97
 $86
 $13
 $12
 
 Non-Service Components of Pension and OPEB (Credits) Costs                
 Interest Cost52
 51
 16
 15
 156
 153
 49
 47
 
 Expected Return on Plan Assets(111) (98) (9) (8) (331) (295) (30) (25) 
 Amortization of Net                
 Prior Service Cost(4) (5) (1) (3) (13) (14) (1) (8) 
 Actuarial Loss22
 24
 16
 13
 64
 73
 48
 38
 
 Non-Service Components of Pension and OPEB (Credits) Costs(41) (28) 22
 17
 (124) (83) 66
 52
 
 Total Benefit (Credits) Costs$(9) $1
 $26
 $21
 $(27) $3
 $79
 $64
 
                  
Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, excluding Servco, are detailed as follows:
                  
  Pension Benefits OPEB Pension Benefits OPEB 
  Three Months Ended Three Months Ended Six Months Ended Six Months Ended 
  June 30, June 30, June 30, June 30, 
  2018 2017 2018 2017 2018 2017 2018 2017 
  Millions 
 PSE&G$(7) $(1) $17
 $13
 $(15) $(2) $34
 $27
 
 Power(3) 1
 8
 6
 (5) 1
 16
 13
 
 Other1
 1
 2
 2
 2
 3
 3
 3
 
 Total Benefit (Credits) Costs$(9) $1
 $27
 $21
 $(18) $2
 $53
 $43
 
                  
                  
  Pension Benefits OPEB Pension Benefits OPEB 
  Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended 
  September 30, September 30, September 30, September 30, 
  2018 2017 2018 2017 2018 2017 2018 2017 
  Millions 
 PSE&G$(8) $(1) $17
 $13
 $(23) $(3) $51
 $40
 
 Power(2) —
 8
 7
 (7) 1
 24
 20
 
 Other1
 2
 1
 1
 3
 5
 4
 4
 
 Total Benefit (Credits) Costs$(9) $1
 $26
 $21
 $(27) $3
 $79
 $64
 
                  
During the three months ended March 31, 2018, PSEG contributed its entire planned contribution for the year 2018 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 5. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.
Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco plans to contributehas contributed its entire planned contribution amount of $40 million into its pension plan trusts during 2018. Servco’s pension-related revenues and costs were $10$20 million and $8$18 million for three months ended JuneSeptember 30, 2018 and 2017, respectively, and $20$40 million and $17$35 million for the sixnine months ended JuneSeptember 30, 2018 and 2017, respectively. The OPEB-related revenues earned and costs incurred were $2 million and $1 million for each of the three months ended JuneSeptember 30, 2018 and 2017, respectively,and $4 million and $3 million and $2 million for the sixnine months ended JuneSeptember 30, 2018 and 2017, respectively.

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








Note 10. Commitments and Contingent Liabilities
Guaranteed Obligations
Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral.
Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to
support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
obtain credit.
Power is subject to
counterparty collateral calls related to commodity contracts, and
certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to
fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and
the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).
Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of JuneSeptember 30, 2018 and December 31, 2017.
      
  As of As of 
  June 30,
2018		 December 31,
2017		 
  Millions 
 Face Value of Outstanding Guarantees$1,780
 $1,701
 
 Exposure under Current Guarantees$129
 $153
 
      
 Letters of Credit Margin Posted$152
 $103
 
 Letters of Credit Margin Received$18
 $32
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(2) $(1) 
    Net Broker Balance Deposited (Received)$124
 $147
 
      
 Additional Amounts Posted:    
 Other Letters of Credit$63
 $61
 
      
      
  As of As of 
  September 30,
2018		 December 31,
2017		 
  Millions 
 Face Value of Outstanding Guarantees$1,787
 $1,701
 
 Exposure under Current Guarantees$140
 $153
 
      
 Letters of Credit Margin Posted$163
 $103
 
 Letters of Credit Margin Received$17
 $32
 
      
 Cash Deposited and Received:    
 Counterparty Cash Margin Deposited$—
 $—
 
 Counterparty Cash Margin Received$(3) $(1) 
    Net Broker Balance Deposited (Received)$226
 $147
 
      
 Additional Amounts Posted:    
 Other Letters of Credit$63
 $61
 
      
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








As part of determining credit exposure, Power nets receivables and payables with the corresponding net fair values of energy contracts. See Note 12. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.
In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power have posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table.
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)
The 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 and a comprehensive study of the entire 17 miles of the lower Passaic 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, certain 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. The CPG has 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 7.6 percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately 1.9 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. Certain PRPs are currently involved in discussions with the EPA regarding cost allocations and related indemnification matters. We cannot predict the outcome of these discussions, or whether individual PRPs will be able to meet their obligations, either of which could have a material impact on PSE&G’s and Power’s allocation of costs.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River with an estimated cost to remediate the lower 17 miles of the Passaic River ranging from approximately $518 million to $3.2 billion on an undiscounted basis.
In March 2016, the EPA released its Record of Decision (ROD) for the EPA’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 EPA estimated 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 (OCC), one of the PRPs, has commenced performance of 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 and pay for the remedial action under EPA oversight. The allocation process has commenced and is scheduled to be completed in late 2019. Conversations between
In October 2018, the EPA Region 2 issued a Directive to the CPG instructing the CPG to focus the ongoing RI/FS evaluation on various adaptive management scenarios for remediation of the upper 9 miles of the Passaic River, which approach has been agreed to in concept by the EPA and the PRPs regarding remediationCPG. The Directive does not contain estimates for anticipated costs. Adaptive management focuses on removing targeted “hot spots” of contaminated sediments rather than removing all of the Passaic River’s upper 9 miles are ongoing.sediments as in a “bank to bank” approach.
In a separate matter, two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), filed for Chapter 11 bankruptcy in Delaware Federal Bankruptcy Court. In June 2018, the trust representing the creditors in this proceeding filed a complaint asserting claims against the current and former parent entities of Tierra and Maxus, among other parties, for up to $14 billion. Any damages awarded may be used to fund, in part, the remediation costs of the lower 8.3 miles of the Passaic River. The creditor trust has reserved its right to file contribution claims against 28 PRPs, including PSEG. This matter is ongoing.
In June 2018, OCC filed a complaint in Federal District Court in Newark against various defendants, including PSE&G, seeking cost recovery and contribution under CERCLA for the remediation of the lower 8.3 miles of the Passaic River. The
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








complaint does not quantify damages sought.
The Complaint alleges that “no single hazardous substance” is to blame for the contamination of the lower Passaic River and lists the eight Contaminants of Concern (COCs) identified by the EPA in the ROD. OCC alleges PSE&G is responsible for a portion of six of the eight COCs. PSE&G cannot predict the outcome of this matter.
Based upon the estimated cost of the ROD Remedy and PSEG’s estimate of PSE&G’s and Power’s shares of that cost, as of JuneSeptember 30, 2018, PSEG has accrued approximately $57 million. Of this amount, PSE&G has accrued $46 million as an Environmental Costs Liability and a corresponding Regulatory Asset based on its continued ability to recover such costs in its rates. Power has accrued $11 million as an Other Noncurrent Liability with the corresponding O&M Expense recorded in prior years when the liability was accrued.
The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.
Natural Resource Damage Claims
In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






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 electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.
MGP Remediation Program
PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $332$343 million and $378$388 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 $332$343 million as of JuneSeptember 30, 2018. Of this amount, $79$75 million was recorded in Other Current Liabilities and $253$268 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $332$343 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding to what extent sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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 requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.
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, based on studies related to impingement mortality and entrainment by the facilities seeking renewal permits.
Several environmental organizations and certain energy industry groups have filed suit under the CWA and the Endangered Species Act. The cases were consolidated at the Second Circuit, and in July 2018 the Second Circuit upheld the EPA’s final cooling water intake rule. The Court’s decision allows Permitting Directors to continue to issue permits in accordance with the flexible, site-specific provisions of the final rule.
In June 2016, the NJDEP issued a final NJPDES permit for Salem. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final NJPDES renewal permit for Salem. 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 CWA. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intakes 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.Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s CWA Section 316(b) final rule, Power has proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit.
Power has entered 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 occur,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life.
In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting Bridgeport Harbor Station Unit 5 (BH5). All major environmental permits have been received; however, secondary approvals are still 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 October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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 declared an emergency and an emergency response action was undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter and the parties may also be subject to the assessment of civil penalties related to the discharge and response. The U.S. Coast Guard transitioned control of the federal response to the EPA in May 2018. As part of this transition,In August 2018, the U.S. Coast Guard rescinded its Administrative OrderEPA ended the federal response to PSE&G relatedthe matter. The response has now transitioned to this matter.the NJDEP site remediation program.
The impacted cable was repaired in late September 2017; however, small amounts of residual dielectric fluid believed to be contained within the marina sediment continue to appear on the surface and response actions related to the fluid discharge are ongoing, although at a significantly reduced scale. PSE&G remains concerned about future leaks and potential environmental impacts as a result of reintroduction of fluid back into these lines and has determined that retirement of the affected facilities is appropriate. PSE&G has been unable to reach an agreement with Con Edison and, as a result, in May 2018, PSE&G filed an action at FERC to resolve the matter. FERC dismissed PSE&G’s Complaint against Con Edison in September 2018. Also ongoing is the processlawsuit in federal court to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC, including an action filed by PSE&G in federal court in New Jersey seeking damages from NADC. In that action, NADC has also pursued counterclaimsaddition, Con Edison filed counter claims against PSE&G and Con EdisonNADC, including seeking damages for its costs to address the leak.injunctive relief and damages. 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 be material; however, PSE&G anticipates that it will recover these costs through regulatory proceedings.
Steam Electric Effluent Guidelines
In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the ELG Rule.
Through various orders, the EPA has stayed the compliance dates in the ELG Rule and has announced plans to further revise the requirements and compliance dates of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






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, 2018 is $287.76 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2018 of $276.83 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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  
  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 2018 BGS auction year became effective on June 1, 2018 when the 2015 BGS auction agreements expired.
Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs)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 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 20202021 and a significant portion through 2022 at Salem, Hope Creek and Peach Bottom.
Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, Power can use the gas to supply its fossil generating stations in New Jersey.
Power also has various long-term fuel purchase commitments for coal through 2021 to support its fossil generation stations.
As of JuneSeptember 30, 2018, the total minimum purchase requirements included in these commitments were as follows:
     
 Fuel Type Power's Share of Commitments through 2022 
   Millions 
 Nuclear Fuel   
 Uranium $244
 
 Enrichment $345
 
 Fabrication $161
 
 Natural Gas $990
 
 Coal $278
 
     
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






     
 Fuel Type Power's Share of Commitments through 2022 
   Millions 
 Nuclear Fuel   
 Uranium $227
 
 Enrichment $312
 
 Fabrication $158
 
 Natural Gas $922
 
 Coal $240
 
     
Litigation
Sewaren 7 Construction
In June 2018, a complaint was filed in federal court in Newark against PSEG Fossil, LLC, a wholly owned subsidiary of Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that Power withheld money owed to Durr and that Power’s intentional conduct led to the inability of Durr to obtain prospective contracts. Power intends to vigorously defend against these allegations. Based upon the preliminary nature of this matter, a loss is not considered probable nor is the amount of loss, if any, estimable as of JuneSeptember 30, 2018.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








Newark Customer Incident
On the morning of July 5, 2018, PSE&G discontinued electricity to the home of a customer residing in Newark because of outstanding arrears on that customer’s account. Subsequent to the discontinuation of electricity, that customer died on the afternoon of July 5th. The family of the customer, who was on hospice care, has raised allegations in the media regarding PSE&G’s conduct surrounding the discontinuation and restoration of electricity to the home of the customer, claiming that the discontinuation of electric service prevented the customer from using life sustaining medical equipment. The BPU has initiated an investigation into the matter.matter and that investigation is ongoing. In addition, PSE&G received a grand jury subpoena from the Essex County Prosecutor’s Office (ECPO) for records and correspondence between PSE&G and the customer. PSE&G is fully cooperating with the BPU and the ECPO in both proceedings. PSEG cannot predict the outcome of the pending proceedings regarding this incident at this time.
The PSEG Board of Directors (PSEG Board) retained outside counsel to conduct an independent investigation of the facts surrounding this incident with the full support and cooperation of management. The independent investigation concluded that the disconnection itself was not improper; however, it did identify issues related to PSE&G’s response once it was notified of the disconnection. The PSEG cannot predictBoard reviewed and considered the outcomefindings and conclusions of the investigation and PSE&G’s proposed corrective actions. PSE&G’s progress on implementation of the corrective actions will continue to be overseen by the PSEG Board.
Caithness Energy, L.L.C. (Caithness)
In August 2018, Caithness, a Long Island power plant developer, filed a complaint in federal district court in the Eastern District of New York against PSEG and PSEG LI alleging violations of state and federal antitrust laws and a claim of intentional interference of prospective business relations. Caithness alleges that PSEG and PSEG LI interfered with LIPA’s consideration of the Caithness proposal for a 750 MW combined cycle generation project that was identified as a finalist for a Request For Proposal issued by LIPA. In addition, Caithness claims that PSEG and PSEG LI induced LIPA to agree to eliminate the proposed project as a potential competitor to other PSEG affiliates with power supply operations. The complaint alleges hundreds of millions of dollars of harm and seeks treble and punitive damages. We intend to vigorously defend against these allegations. Based upon the preliminary nature of this matter.matter, a loss is not considered probable nor is the amount of loss, if any, estimable as of September 30, 2018.
Other Litigation and Legal Proceedings
PSEG and its subsidiaries are party to various lawsuits in the ordinary course of business. In view of the inherent difficulty in predicting the outcome of such matters, PSEG, PSE&G and Power generally cannot predict the eventual outcome of the pending matters, the timing of the ultimate resolution of these matters, or the eventual loss, fines or penalties related to each pending matter.
In accordance with applicable accounting guidance, a liability is accrued when those matters present loss contingencies that are both probable and reasonably estimable. In such cases, there may be an exposure to loss in excess of any amounts accrued. PSEG will continue to monitor the 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 matters described herein, could have a material adverse effect on PSEG’s, PSE&G’s or Power’s consolidated financial position or liquidity. However, in light of the inherent uncertainties involved in these matters, some of which are beyond PSEG’s control, and the large or indeterminate damages sought in some 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 any particular reporting period.

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






Note 11. Debt and Credit Facilities
Long-Term Debt Financing Transactions
The following long-term debt transactions occurred in the sixnine months ended JuneSeptember 30, 2018:
PSE&G
issued $375 million of 3.70% Secured Medium-Term Notes, Series M, due May 2028,
issued $325 million of 4.05% Secured Medium-Term Notes, Series M, due May 2048, and
issued $325 million of 3.25% Secured Medium-Term Notes, Series M, due September 2023,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








issued $325 million of 3.65% Secured Medium-Term Notes, Series M, due September 2028,
retired $400 million of 5.30% Medium-Term Notes at maturity, and
retired $350 million of 2.30% Medium-Term Notes at maturity.
Power
issued $700 million of 3.85% Senior Notes due June 2023.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
The commitments under the $4.2$4.3 billion credit facilities are provided by a diverse bank group. As of JuneSeptember 30, 2018, the total available credit capacity was $3.7$3.6 billion.
As of JuneSeptember 30, 2018, no single institution represented more than 8%9% of the total commitments in the credit facilities.
As of JuneSeptember 30, 2018, total credit capacity was in excess of the total anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon.
In September 2018, Power amended an existing 3-year $100 million letter of credit facility, extending the expiration date to September 2021. The second letter of credit facility, which is scheduled to expire in March 2020, will be terminated during the fourth quarter of 2018. Power also executed a new 3-year $100 million letter of credit facility that expires in September 2021.
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 JuneSeptember 30, 2018 were as follows:
             
   As of June 30, 2018     
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
   5-year Credit Facilities (A) $1,500
 $88
 $1,412
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSEG $1,500
 $88
 $1,412
     
 PSE&G           
   5-year Credit Facility (A) $600
 $211
 $389
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSE&G $600
 $211
 $389
     
 Power           
   3-year Letter of Credit Facilities $200
 $162
 $38
 Mar 2020 Letters of Credit 
   5-year Credit Facilities 1,900
 40
 1,860
 Mar 2022 Funding/Letters of Credit 
 Total Power $2,100
 $202
 $1,898
     
 Total $4,200
 $501
 $3,699
     
             
             
   As of September 30, 2018     
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
   5-year Credit Facilities (A) $1,500
 $393
 $1,107
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSEG $1,500
 $393
 $1,107
     
 PSE&G           
   5-year Credit Facility (A) $600
 $56
 $544
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSE&G $600
 $56
 $544
     
 Power           
   3-year Letter of Credit Facility $100
 $62
 $38
 Mar 2020 Letters of Credit 
   3-year Letter of Credit Facilities 200
 100
 $100
 Sept 2021 Letters of Credit 
   5-year Credit Facilities 1,900
 51
 1,849
 Mar 2022 Funding/Letters of Credit 
 Total Power $2,200
 $213
 $1,987
     
 Total $4,300
 $662
 $3,638
     
             
(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 JuneSeptember 30, 2018, PSEG had $75$379 million outstanding at a weighted average interest rate of 2.32%2.54%. PSE&G had $195$40 million outstanding at a weighted average interest rate of 2.29%2.35% under its Commercial Paper Program as of JuneSeptember 30, 2018.

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








Note 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 enterenters 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 these derivative contracts are recorded in earnings.
Interest Rates
PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.
Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of JuneSeptember 30, 2018 or December 31, 2017.
Cash Flow Hedges
PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. PSEG interest rate hedges totaling $500 million were executed and terminated during the second quarter of 2018 and a loss of $(1) million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power’s $700 million of 3.85% Senior Notes due June 2023. For additional information see Note 11. Debt and Credit Facilities. There were no outstanding interest rate hedges as of JuneSeptember 30, 2018 and December 31, 2017. The Accumulated Other Comprehensive Income (Loss) (after tax) related to terminated interest rate derivatives designated as cash flow hedges was $(1) million as of JuneSeptember 30, 2018 and was immaterial as of December 31, 2017. The after-tax unrealized losses on these hedges expected to be reclassified to earnings during the next 12 months are immaterial.
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Condensed Consolidated Balance Sheets of Power and PSEG. For additional information see Note 13. Fair Value Measurements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








The following tabular disclosure does not include the offsetting of trade receivables and payables.
           
   As of June 30, 2018 
   Power (A) Consolidated 
   Not Designated       
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Total
Derivatives
 
   Millions 
 Derivative Contracts         
 Current Assets $256
 $(232) $24
 $24
 
 Noncurrent Assets 132
 (111)��21
 21
 
 Total Mark-to-Market Derivative Assets $388
 $(343) $45
 $45
 
 Derivative Contracts         
 Current Liabilities $(254) $231
 $(23) $(23) 
 Noncurrent Liabilities (111) 110
 (1) (1) 
 Total Mark-to-Market Derivative (Liabilities) $(365) $341
 $(24) $(24) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $23
 $(2) $21
 $21
 
           
           
   As of September 30, 2018 
   Power (A) Consolidated 
   Not Designated       
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Total
Derivatives
 
   Millions 
 Derivative Contracts         
 Current Assets $301
 $(290) $11
 $11
 
 Noncurrent Assets 123
 (121) 2
 2
 
 Total Mark-to-Market Derivative Assets $424
 $(411) $13
 $13
 
 Derivative Contracts         
 Current Liabilities $(389) $376
 $(13) $(13) 
 Noncurrent Liabilities (149) 147
 (2) (2) 
 Total Mark-to-Market Derivative (Liabilities) $(538) $523
 $(15) $(15) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $(114) $112
 $(2) $(2) 
           
           
   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 derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of JuneSeptember 30, 2018 and December 31, 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 JuneSeptember 30, 2018 and December 31, 2017, Power had net cash collateral/margin payments to counterparties of $122$223 million and $146 million, respectively. Of these net cash/collateral margin payments $(2)$112 million as of JuneSeptember 30, 2018 and $44 million as December 31, 2017 were netted against the corresponding net derivative contract positions. Of the $(2)$112 million as of JuneSeptember 30, 2018, $(1)$(2) million was netted against current assets, and $(1) million was netted against noncurrent assets.assets, $88 million was netted against current liabilities, and $27 million was netted against noncurrent liabilities. Of the $44 million as of December 31, 2017, $(3) million was netted against current assets, $28 million was netted against current liabilities, and $19 million was netted against noncurrent liabilities.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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 $11$23 million and $30 million as of JuneSeptember 30, 2018 and December 31, 2017, respectively. As of JuneSeptember 30, 2018 and December 31, 2017, Power had the contractual right of offset of $6$7 million and $13 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $5$16 million and $17 million as of JuneSeptember 30, 2018 and December 31, 2017, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.
The following reconciles the Accumulated Other Comprehensive Income (Loss) 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, 2016 $3
 $2
 
 Gain Recognized in AOCI —
 —
 
 Less: Gain Reclassified into Income (3) (2) 
 Balance as of December 31, 2017 $—
 $—
 
 Loss Recognized in AOCI (2) (1) 
 Less: Loss Reclassified into Income —
 —
 
 Balance as of June 30, 2018 $(2) $(1) 
       
       
 Accumulated Other Comprehensive Income (Loss) Pre-Tax After-Tax 
   Millions 
 Balance as of December 31, 2016 $3
 $2
 
 Gain Recognized in AOCI —
 —
 
 Less: Gain Reclassified into Income (3) (2) 
 Balance as of December 31, 2017 $—
 $—
 
 Loss Recognized in AOCI (2) (1) 
 Less: Loss Reclassified into Income —
 —
 
 Balance as of September 30, 2018 $(2) $(1) 
       
The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and sixnine months ended JuneSeptember 30, 2018 and 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 that 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 Pre-Tax Gain (Loss) Recognized in Income on Derivatives 
     Three Months Ended Six Months Ended 
     June 30, June 30, 
     2018 2017 2018 2017 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $(64) $112
 $(24) $190
 
 Energy-Related Contracts Energy Costs 15
 (10) 7
 (10) 
 Total PSEG and Power   $(49) $102
 $(17) $180
 
             
    ��        
 Derivatives Not Designated as Hedges 
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives
 Pre-Tax Gain (Loss) Recognized in Income on Derivatives Pre-Tax Gain (Loss) Recognized in Income on Derivatives 
     Three Months Ended Nine Months Ended 
     September 30, September 30, 
     2018 2017 2018 2017 
     Millions 
 PSEG and Power           
 Energy-Related Contracts Operating Revenues $(130) $26
 $(154) $216
 
 Energy-Related Contracts Energy Costs 5
 (4) 12
 (14) 
 Total PSEG and Power   $(125) $22
 $(142) $202
 
             
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of JuneSeptember 30, 2018 and December 31, 2017.
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of June 30, 2018           
 Natural Gas Dekatherm (Dth) 249
 —
 249
 —
 
 Electricity MWh (67) —
 (67) —
 
 Financial Transmission Rights (FTRs) MWh 24
 —
 24
 —
 
 As of December 31, 2017           
 Natural Gas Dth 154
 —
 154
 —
 
 Electricity MWh (63) —
 (63) —
 
 FTRs MWh 6
 —
 6
 —
 
             
             
 Type Notional Total PSEG Power PSE&G 
     Millions 
 As of September 30, 2018           
 Natural Gas Dekatherm (Dth) 281
 —
 281
 —
 
 Electricity MWh (66) —
 (66) —
 
 Financial Transmission Rights (FTRs) MWh 24
 —
 24
 —
 
 As of December 31, 2017           
 Natural Gas Dth 154
 —
 154
 —
 
 Electricity MWh (63) —
 (63) —
 
 FTRs MWh 6
 —
 6
 —
 
             
Credit Risk
Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.
The following table provides information on Power’s credit risk from ER&T wholesale counterparties, net of collateral, as of JuneSeptember 30, 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 JuneSeptember 30, 2018, 98%97% of the net credit exposure for Power’s wholesale 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 $172
 $12
 $160
 2
 $74
(A) 
 Non-Investment Grade 4
 1
 3
 —
 —
   
 Total $176
 $13
 $163
 2
 $74
  
              
              
 Rating 
Current
Exposure
 Securities held as Collateral 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
   Millions   Millions  
 Investment Grade $112
 $12
 $100
 2
 $50
(A) 
 Non-Investment Grade 6
 2
 4
 —
 —
   
 Total $118
 $14
 $104
 2
 $50
  
              
(A)Represents net exposure of $56$39 million with PSE&G and $11 million with a non-affiliated counterparty of $18 million.counterparty.
As of JuneSeptember 30, 2018, collateral held from counterparties where Power had credit exposure included $1$2 million in cash collateral and $12 million in letters of credit.
As of JuneSeptember 30, 2018, Power had 145137 active counterparties.
PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of JuneSeptember 30, 2018, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of JuneSeptember 30, 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 13. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX.
Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of JuneSeptember 30, 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 JuneSeptember 30, 2018 and December 31, 2017, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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

Netting (D)
 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 
   Millions 
 PSEG           
 Assets:           
 Energy-Related Contracts (B) $45
 $(343) $16
 $365
 $7
 
 NDT Fund (C)           
 Equity Securities $1,081
 $—
 $1,079
 $2
 $—
 
 Debt Securities—U.S. Treasury $211
 $—
 $—
 $211
 $—
 
 Debt Securities—Govt Other $306
 $—
 $—
 $306
 $—
 
 Debt Securities—Corporate $450
 $—
 $—
 $450
 $—
 
 Rabbi Trust (C)           
 Equity Securities $24
 $—
 $24
 $—
 $—
 
 Debt Securities—U.S. Treasury $58
 $—
 $—
 $58
 $—
 
 Debt Securities—Govt Other $36
 $—
 $—
 $36
 $—
 
 Debt Securities—Corporate $106
 $—
 $—
 $106
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(24) $341
 $(8) $(354) $(3) 
 PSE&G           
 Assets:           
 Rabbi Trust (C)           
 Equity Securities $4
 $—
 $4
 $—
 $—
 
 Debt Securities—U.S. Treasury $12
 $—
 $—
 $12
 $—
 
 Debt Securities—Govt Other $8
 $—
 $—
 $8
 $—
 
 Debt Securities—Corporate $21
 $—
 $—
 $21
 $—
 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $45
 $(343) $16
 $365
 $7
 
 NDT Fund (C)           
 Equity Securities $1,081
 $—
 $1,079
 $2
 $—
 
 Debt Securities—U.S. Treasury $211
 $—
 $—
 $211
 $—
 
 Debt Securities—Govt Other $306
 $—
 $—
 $306
 $—
 
 Debt Securities—Corporate $450
 $—
 $—
 $450
 $—
 
 Rabbi Trust (C)           
 Equity Securities $6
 $—
 $6
 $—
 $—
 
 Debt Securities—U.S. Treasury $14
 $—
 $—
 $14
 $—
 
 Debt Securities—Govt Other $9
 $—
 $—
 $9
 $—
 
 Debt Securities—Corporate $27
 $—
 $—
 $27
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(24) $341
 $(8) $(354) $(3) 
             
             
   Recurring Fair Value Measurements as of September 30, 2018 
 Description Total 

Netting (C)
 
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 (A) $13
 $(411) $12
 $404
 $8
 
 NDT Fund (B)           
 Equity Securities $1,120
 $—
 $1,118
 $2
 $—
 
 Debt Securities—U.S. Treasury $209
 $—
 $—
 $209
 $—
 
 Debt Securities—Govt Other $311
 $—
 $—
 $311
 $—
 
 Debt Securities—Corporate $456
 $—
 $—
 $456
 $—
 
 Rabbi Trust (B)           
 Equity Securities $25
 $—
 $25
 $—
 $—
 
 Debt Securities—U.S. Treasury $60
 $—
 $—
 $60
 $—
 
 Debt Securities—Govt Other $39
 $—
 $—
 $39
 $—
 
 Debt Securities—Corporate $101
 $—
 $—
 $101
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (A) $(15) $523
 $(10) $(519) $(9) 
 PSE&G           
 Assets:           
 Rabbi Trust (B)           
 Equity Securities $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $12
 $—
 $—
 $12
 $—
 
 Debt Securities—Govt Other $8
 $—
 $—
 $8
 $—
 
 Debt Securities—Corporate $21
 $—
 $—
 $21
 $—
 
 Power 
         
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (A) $13
 $(411) $12
 $404
 $8
 
 NDT Fund (B)           
 Equity Securities $1,120
 $—
 $1,118
 $2
 $—
 
 Debt Securities—U.S. Treasury $209
 $—
 $—
 $209
 $—
 
 Debt Securities—Govt Other $311
 $—
 $—
 $311
 $—
 
 Debt Securities—Corporate $456
 $—
 $—
 $456
 $—
 
 Rabbi Trust (B)           
 Equity Securities $6
 $—
 $6
 $—
 $—
 
 Debt Securities—U.S. Treasury $15
 $—
 $—
 $15
 $—
 
 Debt Securities—Govt Other $10
 $—
 $—
 $10
 $—
 
 Debt Securities—Corporate $26
 $—
 $—
 $26
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (A) $(15) $523
 $(10) $(519) $(9) 
             
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








             
   Recurring Fair Value Measurements as of December 31, 2017 
 Description Total Netting  (D) 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 
   Millions 
 PSEG           
 Assets:           
 Cash Equivalents (A) $223
 $—
 $223
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $36
 $(433) $15
 $442
 $12
 
 NDT Fund (C)           
 Equity Securities $1,147
 $—
 $1,145
 $2
 $—
 
 Debt Securities—U.S. Treasury $314
 $—
 $—
 $314
 $—
 
 Debt Securities—Govt Other $270
 $—
 $—
 $270
 $—
 
 Debt Securities—Corporate $402
 $—
 $—
 $402
 $—
 
 Rabbi Trust (C)           
 Equity Securities $27
 $—
 $27
 $—
 $—
 
 Debt Securities—U.S. Treasury $51
 $—
 $—
 $51
 $—
 
 Debt Securities—Govt Other $34
 $—
 $—
 $34
 $—
 
 Debt Securities—Corporate $119
 $—
 $—
 $119
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(21) $477
 $(8) $(485) $(5) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $223
 $—
 $223
 $—
 $—
 
 Rabbi Trust (C)           
 Equity Securities $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $10
 $—
 $—
 $10
 $—
 
 Debt Securities—Govt Other $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Corporate $24
 $—
 $—
 $24
 $—
 
 Liabilities:           
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $36
 $(433) $15
 $442
 $12
 
 NDT Fund (C)           
 Equity Securities $1,147
 $—
 $1,145
 $2
 $—
 
 Debt Securities—U.S. Treasury $314
 $—
 $—
 $314
 $—
 
 Debt Securities—Govt Other $270
 $—
 $—
 $270
 $—
 
 Debt Securities—Corporate $402
 $—
 $—
 $402
 $—
 
 Rabbi Trust (C)           
 Equity Securities $6
 $—
 $6
 $—
 $—
 
 Debt Securities—U.S. Treasury $13
 $—
 $—
 $13
 $—
 
 Debt Securities—Govt Other $8
 $—
 $—
 $8
 $—
 
 Debt Securities—Corporate $30
 $—
 $—
 $30
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(21) $477
 $(8) $(485) $(5) 
             
             
   Recurring Fair Value Measurements as of December 31, 2017 
 Description Total Netting  (C) 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 
   Millions 
 PSEG           
 Assets:           
 Cash Equivalents (D) $223
 $—
 $223
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (A) $36
 $(433) $15
 $442
 $12
 
 NDT Fund (B)           
 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 (B)           
 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 (A) $(21) $477
 $(8) $(485) $(5) 
 PSE&G           
 Assets:           
 Cash Equivalents (D) $223
 $—
 $223
 $—
 $—
 
 Rabbi Trust (B)           
 Equity Securities $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $10
 $—
 $—
 $10
 $—
 
 Debt Securities—Govt Other $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Corporate $24
 $—
 $—
 $24
 $—
 
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (A) $36
 $(433) $15
 $442
 $12
 
 NDT Fund (B)           
 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 (B)           
 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 (A) $(21) $477
 $(8) $(485) $(5) 
             
(A)Represents money market mutual funds.
(B)Level 1—These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.
Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






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








significant to the overall inputs.
Level 3—Unobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more information on the utilization of unobservable inputs.
(C)(B)As of June 30, 2018, the fair value measurement table excludes foreign currency of $1 million, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in various fixed income securities and a Russell 3000 index 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 other 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 the preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, 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-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.
(D)(C)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 June 30, 2018 and December 31, 2017, Power had net cash collateral/margin payments to counterparties of $122 million and $146 million, respectively. Of these net cash collateral/margin payments $(2) million as of June 30, 2018 and $44 million as of December 31, 2017 were netted against the corresponding net derivative contract positions. The $(2) million of cash collateral as of June 30, 2018 was netted against assets. Of the $44 million of cash collateral as of December 31, 2017, $(3) million was netted against assets and $47 million was netted against liabilities.See Note 12. Financial Risk Management Activities for additional detail.
(D)Represents money market mutual funds.
Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.
For PSE&G, the natural gas supply contract 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






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 JuneSeptember 30, 2018 and December 31, 2017.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents







               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position June 30, 2018 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 Power             
 Electricity Electric Load Contracts $2
 $(3) Discounted Cash flow Historic Load Variability 0% to 10% 
 Gas Gas Physical Contracts 5
 —
 Discounted Cash flow Average Historical Basis -40% to 0% 
 Total Power   $7
 $(3)       
 Total PSEG   $7
 $(3)       
               

               
   Quantitative Information About Level 3 Fair Value Measurements   
             
         Significant   
     Fair Value as of Valuation Unobservable   
 Commodity Level 3 Position September 30, 2018 Technique(s)  Input Range 
     Assets (Liabilities)       
     Millions       
 Power             
 Electricity Electric Load Contracts $—
 $(9) Discounted Cash flow Historic Load Variability 0% to 10% 
 Gas Gas Physical Contracts 8
 —
 Discounted Cash flow Average Historical Basis -40% to 0% 
 Total Power   $8
 $(9)       
 Total PSEG   $8
 $(9)       
               
               
   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 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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and sixnine months ended JuneSeptember 30, 2018 and JuneSeptember 30, 2017, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months and SixNine Months Ended JuneSeptember 30, 2018
                 
   Three Months Ended June 30, 2018 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of April 1, 2018 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2018 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $7
 $(3) $—
 $—
 $—
 $—
 $4
 
 Power               
 Net Derivative Assets (Liabilities) $7
 $(3) $—
 $—
 $—
 $—
 $4
 
                 
   Six Months Ended June 30, 2018 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2018 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2018 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $7
 $(4) $—
 $—
 $1
 $—
 $4
 
 Power               
 Net Derivative Assets (Liabilities) $7
 $(4) $—
 $—
 $1
 $—
 $4
 
                 

                 
   Three Months Ended September 30, 2018 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2018 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2018 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $4
 $(4) $—
 $—
 $(1) $—
 $(1) 
 Power               
 Net Derivative Assets (Liabilities) $4
 $(4) $—
 $—
 $(1) $—
 $(1) 
                 
   Nine Months Ended September 30, 2018 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2018 
Included in
Income (A)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2018 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $7
 $(8) $—
 $—
 $—
 $—
 $(1) 
 Power               
 Net Derivative Assets (Liabilities) $7
 $(8) $—
 $—
 $—
 $—
 $(1) 
                 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months and SixNine Months Ended JuneSeptember 30, 2017
                 
   Three Months Ended June 30, 2017 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of April 1, 2017 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of June 30, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $3
 $7
 $(1) $—
 $(3) $—
 $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $1
 $—
 $(1) $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $2
 $7
 $—
 $—
 $(3) $—
 $6
 
                 
   Six Months Ended June 30, 2017 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2017 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of June 30, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $1
 $26
 $5
 $—
 $(25) $(1) $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(5) $—
 $5
 $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $6
 $26
 $—
 $—
 $(25) $(1) $6
 
                 
                 
   Three Months Ended September 30, 2017 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of July 1, 2017 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out
(D)
 Balance as of September 30, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $6
 $3
 $—
 $—
 $(3) $—
 $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $—
 $—
 $—
 $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $6
 $3
 $—
 $—
 $(3) $—
 $6
 
                 
   Nine Months Ended September 30, 2017 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2017 
Included in
Income (E)
 
Included in
Regulatory Assets/
Liabilities (B)
 
Purchases
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of September 30, 2017 
   Millions   
 PSEG               
 Net Derivative Assets (Liabilities) $1
 $29
 $5
 $—
 $(28) $(1) $6
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(5) $—
 $5
 $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $6
 $29
 $—
 $—
 $(28) $(1) $6
 
                 
(A)PSEG’s and Power’s gains(losses) attributable to changes in net derivative assets and liabilities for the three months and sixnine months ended JuneSeptember 30, 2018 include $(7)$(8) million and $1$(7) million, respectively, in Operating Revenues and $4 million and $(5)$(1) million, respectively, in Energy Costs. Both the $(7)$(8) million and $1$(7) million in Operating Revenues are unrealized. Of the $4 million and $(5)$(1) million in Energy Costs, $3$5 million and $(6)$(1) million are unrealized. Unrealized gains (losses) represent the change in derivative assets and liabilities still held at the end of the reporting period.
(B)Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








(C)Represents $1settlements of $(1) million in settlements for the sixthree months ended JuneSeptember 30, 2018. Represents settlements of $(3) million and $(25)$(28) million for the three months and sixnine months ended JuneSeptember 30, 2017, respectively.
(D)During the three months and sixnine months ended JuneSeptember 30, 2018, there were no transfers into or out of Level 3. During the sixnine months ended JuneSeptember 30, 2017, $(1) million of net derivatives were transferred from Level 2 to Level 3. There were no transfers into or out of Level 3 during the three months ended JuneSeptember 30, 2017.
(E)PSEG’s and Power’s gains(losses) attributable to changes in net derivative assets and liabilities for the three months and sixnine months ended JuneSeptember 30, 2017 include $3$5 million and $17$22 million, respectively, in Operating Revenues and $4$(2) million and $9$7 million, respectively, in Energy Costs. Of the $3 million and $17The $5 million in Operating Revenues $2 million and $(2) million, respectively, are unrealized. Of the $4 million and $9 million in Energy Costs $2for the three months ended September 30, 2017 are realized. Of the $22 million in Operating Revenues and the $7 million in Energy Costs, $(2) million and $3 million, respectively, are unrealized.unrealized for the nine months ended September 30, 2017.
As of JuneSeptember 30, 2018, PSEG carried $2.3 billion of net assets that are measured at fair value on a recurring basis, of which $4$1 million of net assets wereliabilities was measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of JuneSeptember 30, 2017, PSEG carried $2.8$2.6 billion of net assets that are measured at fair value on a recurring basis, of which $6 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
Fair Value of Debt
The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of JuneSeptember 30, 2018 and December 31, 2017.
          
  As of As of 
  June 30, 2018 December 31, 2017 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (A) (B)$2,091
 $2,042
 $2,091
 $2,081
 
 PSE&G (B)8,886
 9,055
 8,591
 9,322
 
 Power (B)3,083
 3,249
 2,386
 2,659
 
 Total Long-Term Debt$14,060
 $14,346
 $13,068
 $14,062
 
          
          
  As of As of 
  September 30, 2018 December 31, 2017 
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
 
  Millions 
 Long-Term Debt:        
 PSEG (A) (B)$2,093
 $2,051
 $2,091
 $2,081
 
 PSE&G (B)9,182
 9,292
 8,591
 9,322
 
 Power (B)3,084
 3,254
 2,386
 2,659
 
 Total Long-Term Debt$14,359
 $14,597
 $13,068
 $14,062
 
          
(A)Includes floating rate term loan of $700 million. The fair values of the term loan debt (Level 2 measurement) approximate the carrying values because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.
(B)Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








Note 14. Other Income (Deductions)
          
  PSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended June 30, 2018        
 NDT Fund Interest and Dividends$—
 $15
 $—
 $15
 
 Allowance for Funds Used During Construction13
 —
 —
 13
 
 Solar Loan Interest5
 —
 —
 5
 
 Other2
 (2) 1
 1
 
   Total Other Income (Deductions)$20
 $13
 $1
 $34
 
 Six Months Ended June 30, 2018        
 NDT Fund Interest and Dividends$—
 $27
 $—
 $27
 
 Allowance for Funds Used During Construction27
 —
 —
 27
 
 Solar Loan Interest9
 —
 —
 9
 
 Other4
 (3) 2
 3
 
   Total Other Income (Deductions)$40
 $24
 $2
 $66
 
 Three Months Ended June 30, 2017        
 NDT Fund Interest and Dividends$—
 $13
 $—
 $13
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Solar Loan Interest5
 —
 —
 5
 
 Other2
 (1) —
 1
 
   Total Other Income (Deductions)$21
 $12
 $—
 $33
 
 Six Months Ended June 30, 2017        
 NDT Fund Interest and Dividends$—
 $23
 $—
 $23
 
 Allowance for Funds Used During Construction28
 —
 —
 28
 
 Solar Loan Interest10
 —
 —
 10
 
 Other5
 —
 (1) 4
 
 Total Other Income (Deductions)$43
 $23
 $(1) $65
 
          
          
  PSE&G Power Other (A) Consolidated 
  Millions 
 Three Months Ended September 30, 2018        
 NDT Fund Interest and Dividends$—
 $13
 $—
 $13
 
 Allowance for Funds Used During Construction13
 —
 —
 13
 
 Solar Loan Interest5
 —
 —
 5
 
 Other3
 1
 (2) 2
 
   Total Other Income (Deductions)$21
 $14
 $(2) $33
 
 Nine Months Ended September 30, 2018        
 NDT Fund Interest and Dividends$—
 $40
 $—
 $40
 
 Allowance for Funds Used During Construction40
 —
 —
 40
 
 Solar Loan Interest14
 —
 —
 14
 
 Other7
 (2) —
 5
 
   Total Other Income (Deductions)$61
 $38
 $—
 $99
 
 Three Months Ended September 30, 2017        
 NDT Fund Interest and Dividends$—
 $12
 $—
 $12
 
 Allowance for Funds Used During Construction14
 —
 —
 14
 
 Solar Loan Interest6
 —
 —
 6
 
 Other2
 (1) —
 1
 
   Total Other Income (Deductions)$22
 $11
 $—
 $33
 
 Nine Months Ended September 30, 2017        
 NDT Fund Interest and Dividends$—
 $35
 $—
 $35
 
 Allowance for Funds Used During Construction42
 —
 —
 42
 
 Solar Loan Interest16
 —
 —
 16
 
 Other7
 (1) (1) 5
 
 Total Other Income (Deductions)$65
 $34
 $(1) $98
 
          
(A)Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

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








Note 15. Income Taxes
PSEG’s, PSE&G’s and Power’s effective tax rates for the three months and sixnine months ended JuneSeptember 30, 2018 and 2017 were as follows:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
 PSEG26.5% 35.1% 26.6% 28.3% 
 PSE&G25.7% 37.2% 26.4% 36.7% 
 Power31.7% 39.0% 27.1% 40.0% 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
 PSEG22.1% 38.9% 25.1% 35.5% 
 PSE&G25.5% 38.8% 26.1% 37.4% 
 Power16.7% 41.9% 24.1% 37.9% 
          
For the three months and sixnine months ended JuneSeptember 30, 2018, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as a result of the Tax Act offset by changes inand the remeasurement of uncertain tax positions and associated interest in connection with a 2015 claim to carry back tax-defined nuclear decommissioning costs under IRC 172(f) (nuclear carryback claim) and 2011 and 2012 federal tax audit, offset by the New Jersey (NJ) surtax, plant-related items and tax credits. For the three months and sixnine months ended JuneSeptember 30, 2018, the differences in PSEG’s effective tax rates as compared to the statutory tax rate of 28.11% were due primarily to the remeasurement of uncertain tax positions and associated interest in connection with the nuclear carryback claim and 2011 and 2012 federal tax audit, plant-related items and tax credits.credits, offset by the NJ surtax.
In August 2018, the IRS completed its audit of PSEG’s nuclear carryback claim and federal tax returns for the years 2011 and 2012. The completion of the IRS’ audit resulted in a settlement agreement with the IRS, which is subject to review by the Joint Committee on Taxation (JCT). As a result of this new information, PSEG remeasured certain unrecognized tax benefits that impacted the effective tax rate in the amount of $28 million, primarily related to the nuclear carryback claim and the associated interest, in the three months ended September 30, 2018.
For the three months and sixnine months ended JuneSeptember 30, 2018, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as a result of the Tax Act, offset by changes in uncertain tax positions, plant-related and other flow-through items. For the three months and
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents






six nine months ended JuneSeptember 30, 2018, the differences in PSE&G’s effective tax rate as compared to the statutory tax rate of 28.11% were due primarily to plant-related and other flow-through items, tax credits and changes in uncertain tax credits.positions.
For the three months and sixnine months ended JuneSeptember 30, 2018, the differences in Power’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as a result of the Tax Act as well as changes inand the remeasurement of uncertain tax positions.positions and associated interest in connection with the nuclear carryback claim and 2011 and 2012 federal tax audit, offset by the NJ surtax. For the three months and sixnine months ended JuneSeptember 30, 2018, the differences in Power’s effective tax rates as compared to the statutory tax rate of 28.11% were due primarily to changes inthe remeasurement of uncertain tax positions and associated interest in connection with the nuclear carryback claim and 2011 and 2012 federal tax credits.audit, offset by the NJ surtax.
Uncertain Tax Positions
In August 2018, the IRS completed its audit of PSEG’s nuclear carryback claim and federal tax returns for the years 2011 and 20122012. The JCT is required to review all claims over $5 million, and the tax years are currently being audited bynot considered concluded until the IRS. The audit and other related claims are reasonably expected to be completed within the next 12 months.JCT’s review has been completed. As a result, it is reasonably possible that a decrease in PSEG’s total unrecognized tax benefits may be necessarydecrease in the range of $80$50 million to $150$120 million based on current estimates.estimates within the next 12 months.
In December 2017,Tax Act
PSEG, PSE&G and Power recorded the U.S. government enacted comprehensive tax legislation. Theimpact of the Tax Act establishes new tax laws that took effect in 2018, including, but not limited to (1) reduction of the U.S. federal corporate tax rate from a maximum of 35% to 21%; (2) elimination of the corporate alternative minimum tax; (3) a new limitation on deductible interest expense; (4) the repeal of the domestic production activity deduction; (5) limitations on the deductibility of certain executive compensation; and (6) limitations on net operating losses generated aftertheir December 31, 2017 to 80% of taxable income. In addition,consolidated financial statements, including certain changes were made to the bonus depreciation rules that will impact 2018.
Theprovisional amounts, in accordance with SEC staff issuedguidance under 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 isremains incomplete. However,
In August 2018, the IRS issued a Notice of Proposed Rulemaking (Notice) regarding the application of tax depreciation rules as amended by the Tax Act. In September 2018, PSEG recorded additional provisional adjustments thatincreased plant-related deferred taxes in the amount of $53 million and $35 million to the Regulatory Liability for the following:associated excess deferred taxes.PSEG continues to analyze the tax rules regardingNotice and, as such, the appropriateamounts recorded for bonus depreciation rate that should be applied to assets placed in service after September 27,for 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.2018 remain provisional.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








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,PSEG’s, PSE&G&G’s and Power’s financial statements.
The Protecting Americans from Tax Hikes Act of 2015 (2015 Tax Act), among other provisions, included an extension of the bonus depreciation rules and the 30% investment tax credit for qualified property placed into service after 2016. Qualified property that is placed into service from January 1, 2015 through December 31, 2017 is eligible for the 50% bonus depreciation. The provisions of the 2015 Tax Act have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation.
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,review of the Notice, it is expected that Power iswill be entitled to 100% expensing for qualifying 2018 plant additions and bonus depreciation will no longer apply to PSE&G.
New Jersey State Tax Reform
In July 2018, the State of New Jersey made significant changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. At this time, PSEG believes PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. PSEG expects these new provisions to unfavorably affect its non-utility business as it continues to analyze thisbusiness. The newly enacted law and theNew Jersey tax legislation did not have a material impact it will have on PSEG.PSEG’s deferred income tax balance.

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








Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2018 $—
 $(398) $(13) $(411) 
 Other Comprehensive Income before Reclassifications (1) —
 (6) (7) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 1
 8
 
 Net Current Period Other Comprehensive Income (Loss) (1) 7
 (5) 1
 
 Balance as of June 30, 2018 $(1) $(391) $(18) $(410) 
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2017 $2
 $(392) $148
 $(242) 
 Other Comprehensive Income before Reclassifications —
 —
 23
 23
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 6
 (13) (7) 
 Net Current Period Other Comprehensive Income (Loss) —
 6
 10
 16
 
 Balance as of June 30, 2017 $2
 $(386) $158
 $(226) 
     
 PSEG Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2017 $—
 $(406) $177
 $(229) 
 Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings —
 —
 (176) (176) 
 Current Period Other Comprehensive Income (Loss)         
 Other Comprehensive Income before Reclassifications (1) —
 (22) (23) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 15
 3
 18
 
 Net Current Period Other Comprehensive Income (Loss) (1) 15
 (19) (5) 
 Net Change in Accumulative Other Comprehensive Income (Loss) (1) 15
 (195) (181) 
 Balance as of June 30, 2018 $(1) $(391) $(18) $(410) 
           
 PSEG Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2016 $2
 $(398) $133
 $(263) 
 Other Comprehensive Income before Reclassifications —
 —
 53
 53
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 12
 (28) (16) 
 Net Current Period Other Comprehensive Income (Loss) —
 12
 25
 37
 
 Balance as of June 30, 2017 $2
 $(386) $158
 $(226) 
           
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2018 $(1) $(391) $(18) $(410) 
 Other Comprehensive Income before Reclassifications —
 —
 (6) (6) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 2
 9
 
 Net Current Period Other Comprehensive Income (Loss) —
 7
 (4) 3
 
 Balance as of September 30, 2018 $(1) $(384) $(22) $(407) 
           
 PSEG Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2017 $2
 $(386) $158
 $(226) 
 Other Comprehensive Income before Reclassifications —
 —
 25
 25
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1) 6
 (8) (3) 
 Net Current Period Other Comprehensive Income (Loss) (1) 6
 17
 22
 
 Balance as of September 30, 2017 $1
 $(380) $175
 $(204) 
     
 PSEG Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2017 $—
 $(406) $177
 $(229) 
 Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings —
 —
 (176) (176) 
 Current Period Other Comprehensive Income (Loss)         
 Other Comprehensive Income before Reclassifications (1) —
 (28) (29) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 22
 5
 27
 
 Net Current Period Other Comprehensive Income (Loss) (1) 22
 (23) (2) 
 Net Change in Accumulative Other Comprehensive Income (Loss) (1) 22
 (199) (178) 
 Balance as of September 30, 2018 $(1) $(384) $(22) $(407) 
           
 PSEG Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2016 $2
 $(398) $133
 $(263) 
 Other Comprehensive Income before Reclassifications —
 —
 78
 78
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1) 18
 (36) (19) 
 Net Current Period Other Comprehensive Income (Loss) (1) 18
 42
 59
 
 Balance as of September 30, 2017 $1
 $(380) $175
 $(204) 
           
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2018 $—
 $(341) $(11) $(352) 
 Other Comprehensive Income before Reclassifications —
 —
 (5) (5) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 6
 1
 7
 
 Net Current Period Other Comprehensive Income (Loss) —
 6
 (4) 2
 
 Balance as of June 30, 2018 $—
 $(335) $(15) $(350) 
     
 Power Other Comprehensive Income (Loss) 
   Three Months Ended June 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of March 31, 2017 $—
 $(335) $148
 $(187) 
 Other Comprehensive Income before Reclassifications —
 —
 22
 22
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 5
 (12) (7) 
 Net Current Period Other Comprehensive Income (Loss) —
 5
 10
 15
 
 Balance as of June 30, 2017 $—
 $(330) $158
 $(172) 
           
 Power Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2017 $—
 $(347) $175
 $(172) 
 Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings —
 —
 (175) (175) 
 Current Period Other Comprehensive Income (Loss)         
 Other Comprehensive Income before Reclassifications —
 —
 (18) (18) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 12
 3
 15
 
 Net Current Period Other Comprehensive Income (Loss) —
 12
 (15) (3) 
 Net Change in Accumulative Other Comprehensive Income (Loss) —
 12
 (190) (178) 
 Balance as of June 30, 2018 $—
 $(335) $(15) $(350) 
           
 Power Other Comprehensive Income (Loss) 
   Six Months Ended June 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2016 $—
 $(340) $129
 $(211) 
 Other Comprehensive Income before Reclassifications —
 —
 50
 50
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 10
 (21) (11) 
 Net Current Period Other Comprehensive Income (Loss) —
 10
 29
 39
 
 Balance as of June 30, 2017 $—
 $(330) $158
 $(172) 
           
           
 Power Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2018 $—
 $(335) $(15) $(350) 
 Other Comprehensive Income before Reclassifications —
 —
 (5) (5) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 7
 1
 8
 
 Net Current Period Other Comprehensive Income (Loss) —
 7
 (4) 3
 
 Balance as of September 30, 2018 $—
 $(328) $(19) $(347) 
     
 Power Other Comprehensive Income (Loss) 
   Three Months Ended September 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of June 30, 2017 $—
 $(330) $158
 $(172) 
 Other Comprehensive Income before Reclassifications —
 —
 24
 24
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 5
 (9) (4) 
 Net Current Period Other Comprehensive Income (Loss) —
 5
 15
 20
 
 Balance as of September 30, 2017 $—
 $(325) $173
 $(152) 
           
 Power Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2018 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2017 $—
 $(347) $175
 $(172) 
 Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings —
 —
 (175) (175) 
 Current Period Other Comprehensive Income (Loss)         
 Other Comprehensive Income before Reclassifications —
 —
 (23) (23) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 19
 4
 23
 
 Net Current Period Other Comprehensive Income (Loss) —
 19
 (19) —
 
 Net Change in Accumulative Other Comprehensive Income (Loss) —
 19
 (194) (175) 
 Balance as of September 30, 2018 $—
 $(328) $(19) $(347) 
           
 Power Other Comprehensive Income (Loss) 
   Nine Months Ended September 30, 2017 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total 
   Millions 
 Balance as of December 31, 2016 $—
 $(340) $129
 $(211) 
 Other Comprehensive Income before Reclassifications —
 —
 74
 74
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 15
 (30) (15) 
 Net Current Period Other Comprehensive Income (Loss) —
 15
 44
 59
 
 Balance as of September 30, 2017 $—
 $(325) $173
 $(152) 
           
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








                
 PSEG   Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
    Three Months Ended Six Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of OperationsJune 30, 2018 June 30, 2018 
  Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
    Millions 
 Pension and OPEB Plans            
 Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs)$1
 $—
 $1
 $2
 $—
 $2
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs)(11) 3
 (8) (23) 6
 (17) 
 Total Pension and OPEB Plans(10) 3
 (7) (21) 6
 (15) 
 Available-for-Sale Debt Securities            
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

(2) 1
 (1) (6) 3
 (3) 
 Total Available-for-Sale Debt Securities(2) 1
 (1) (6) 3
 (3) 
 Total  $(12) $4
 $(8) $(27) $9
 $(18) 
                
                
 PSEG   Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
    Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of OperationsSeptember 30, 2018 September 30, 2018 
  Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
    Millions 
 Pension and OPEB Plans            
 Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs)$1
 $—
 $1
 $3
 $—
 $3
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs)(11) 3
 (8) (34) 9
 (25) 
 Total Pension and OPEB Plans(10) 3
 (7) (31) 9
 (22) 
 Available-for-Sale Debt Securities            
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

(2) —
 (2) (8) 3
 (5) 
 Total Available-for-Sale Debt Securities(2) —
 (2) (8) 3
 (5) 
 Total  $(12) $3
 $(9) $(39) $12
 $(27) 
                
                
 PSEG   Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
    Three Months Ended Six Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of OperationsJune 30, 2017 June 30, 2017 
  Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
    Millions 
 Pension and OPEB Plans            
 Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs)$2
 $(1) $1
 $4
 $(2) $2
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs)(12) 5
 (7) (24) 10
 (14) 
 Total Pension and OPEB Plans(10) 4
 (6) (20) 8
 (12) 
 Available-for-Sale Securities            
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

25
 (12) 13
 53
 (25) 28
 
 Total Available-for-Sale Securities25
 (12) 13
 53
 (25) 28
 
 Total  $15
 $(8) $7
 $33
 $(17) $16
 
                
                
 PSEG   Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
    Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of OperationsSeptember 30, 2017 September 30, 2017 
  Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
    Millions 
 Cash Flow Hedges              
 Interest Rate Swaps Interest Expense$2
 $(1) $1
 $2
 $(1) $1
 
 Total Cash Flow Hedges2
 (1) 1
 2
 (1) 1
 
 Pension and OPEB Plans            
 Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs)3
 (1) 2
 7
 (3) 4
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs)(13) 5
 (8) (37) 15
 (22) 
 Total Pension and OPEB Plans(10) 4
 (6) (30) 12
 (18) 
 Available-for-Sale Securities            
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

18
 (10) 8
 71
 (35) 36
 
 Total Available-for-Sale Securities18
 (10) 8
 71
 (35) 36
 
 Total  $10
 $(7) $3
 $43
 $(24) $19
 
                
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Six Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations June 30, 2018 June 30, 2018 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Pension and OPEB Plans             
 Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $1
 $—
 $1
 $2
 $—
 $2
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (9) 2
 (7) (19) 5
 (14) 
 Total Pension and OPEB Plans (8) 2
 (6) (17) 5
 (12) 
 Available-for-Sale Debt Securities             
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

 (2) 1
 (1) (6) 3
 (3) 
 Total Available-for-Sale Debt Securities (2) 1
 (1) (6) 3
 (3) 
 Total   $(10) $3
 $(7) $(23) $8
 $(15) 
                 
                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2018 September 30, 2018 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Pension and OPEB Plans             
 Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $1
 $—
 $1
 $3
 $—
 $3
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (11) 3
 (8) (30) 8
 (22) 
 Total Pension and OPEB Plans (10) 3
 (7) (27) 8
 (19) 
 Available-for-Sale Debt Securities             
 
Realized Gains (Losses) and OTTI

 
Net Gains (Losses) on Trust Investments

 (1) —
 (1) (7) 3
 (4) 
 Total Available-for-Sale Debt Securities (1) —
 (1) (7) 3
 (4) 
 Total   $(11) $3
 $(8) $(34) $11
 $(23) 
                 
                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Six Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations June 30, 2017 June 30, 2017 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Pension and OPEB Plans             
 Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $2
 $(1) $1
 $4
 $(2) $2
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (10) 4
 (6) (21) 9
 (12) 
 Total Pension and OPEB Plans (8) 3
 (5) (17) 7
 (10) 
 Available-for-Sale Securities             
 Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 24
 (12) 12
 43
 (22) 21
 
 Total Available-for-Sale Securities 24
 (12) 12
 43
 (22) 21
 
 Total   $16
 $(9) $7
 $26
 $(15) $11
 
                 
                 
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Three Months Ended Nine Months Ended 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2017 September 30, 2017 
   Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Pension and OPEB Plans             
 Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $2
 $(1) $1
 $6
 $(3) $3
 
 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (11) 5
 (6) (32) 14
 (18) 
 Total Pension and OPEB Plans (9) 4
 (5) (26) 11
 (15) 
 Available-for-Sale Securities             
 Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 19
 (10) 9
 62
 (32) 30
 
 Total Available-for-Sale Securities 19
 (10) 9
 62
 (32) 30
 
 Total   $10
 $(6) $4
 $36
 $(21) $15
 
                 

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








Note 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 June 30, Six Months Ended June 30, 
  2018 2017 2018 2017 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator (Millions):
                
 Net Income$269
 $269
 $109
 $109
 $827
 $827
 $223
 $223
 
 
EPS Denominator (Millions):
                
 Weighted Average Common Shares Outstanding504
 504
 505
 505
 504
 504
 505
 505
 
 Effect of Stock Based Compensation Awards—
 3
 —
 2
 —
 3
 —
 2
 
 Total Shares504
 507
 505
 507
 504
 507
 505
 507
 
                  
 EPS                
 Net Income$0.53
 $0.53
 $0.22
 $0.22
 $1.64
 $1.63
 $0.44
 $0.44
 
                  
                  
  Three Months Ended September 30, Nine Months Ended September 30, 
  2018 2017 2018 2017 
  Basic Diluted Basic Diluted Basic Diluted Basic Diluted 
 
EPS Numerator (Millions):
                
 Net Income$412
 $412
 $395
 $395
 $1,239
 $1,239
 $618
 $618
 
 
EPS Denominator (Millions):
                
 Weighted Average Common Shares Outstanding504
 504
 505
 505
 504
 504
 505
 505
 
 Effect of Stock Based Compensation Awards—
 3
 —
 2
 —
 3
 ���
 2
 
 Total Shares504
 507
 505
 507
 504
 507
 505
 507
 
                  
 EPS                
 Net Income$0.82
 $0.81
 $0.78
 $0.78
 $2.46
 $2.44
 $1.22
 $1.22
 
                  
For the three months and sixnine months ended JuneSeptember 30, 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.
Dividends
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Dividend Payments on Common Stock2018 2017 2018 2017 
 Per Share$0.45
 $0.43
 $0.90
 $0.86
 
 In Millions$228
 $217
 $455
 $435
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Dividend Payments on Common Stock2018 2017 2018 2017 
 Per Share$0.45
 $0.43
 $1.35
 $1.29
 
 In Millions$227
 $217
 $682
 $652
 
          

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

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








Note 18. Financial Information by Business Segment
            
  PSE&G Power Other (A) Eliminations (B) Consolidated Total 
  Millions 
 Three Months Ended June 30, 2018          
 Total Operating Revenues$1,386
 $767
 $123
 $(260) $2,016
 
 Net Income (Loss)231
 41
 (3) —
 269
 
 Gross Additions to Long-Lived Assets697
 248
 7
 —
 952
 
 Six Months Ended June 30, 2018          
 Operating Revenues$3,231
 $2,170
 $270
 $(837) $4,834
 
 Net Income (Loss)550
 275
 2
 —
 827
 
 Gross Additions to Long-Lived Assets1,447
 547
 11
 —
 2,005
 
 Three Months Ended June 30, 2017          
 Total Operating Revenues$1,393
 $918
 $116
 $(285) $2,142
 
 Net Income (Loss)208
 (97) (2) —
 109
 
 Gross Additions to Long-Lived Assets641
 269
 9
 —
 919
 
 Six Months Ended June 30, 2017          
 Operating Revenues$3,219
 $2,187
 $199
 $(872) $4,733
 
 Net Income (Loss)507
 (267) (17) —
 223
 
 Gross Additions to Long-Lived Assets1,389
 576
 16
 —
 1,981
 
 As of June 30, 2018          
 Total Assets$29,603
 $12,772
 $2,407
 $(1,075) $43,707
 
 Investments in Equity Method Subsidiaries$—
 $87
 $—
 $—
 $87
 
 As of December 31, 2017          
 Total Assets$28,554
 $12,418
 $2,666
 $(922) $42,716
 
 Investments in Equity Method Subsidiaries$—
 $87
 $—
 $—
 $87
 
            
            
  PSE&G Power Other (A) Eliminations (B) Consolidated Total 
  Millions 
 Three Months Ended September 30, 2018          
 Total Operating Revenues$1,595
 $868
 $151
 $(220) $2,394
 
 Net Income (Loss)278
 125
 9
 —
 412
 
 Gross Additions to Long-Lived Assets766
 253
 4
 —
 1,023
 
 Nine Months Ended September 30, 2018          
 Operating Revenues$4,826
 $3,038
 $421
 $(1,057) $7,228
 
 Net Income (Loss)828
 400
 11
 —
 1,239
 
 Gross Additions to Long-Lived Assets2,213
 800
 15
 —
 3,028
 
 Three Months Ended September 30, 2017          
 Total Operating Revenues$1,530
 $846
 $135
 $(257) $2,254
 
 Net Income (Loss)246
 136
 13
 —
 395
 
 Gross Additions to Long-Lived Assets729
 327
 9
 —
 1,065
 
 Nine Months Ended September 30, 2017          
 Operating Revenues$4,749
 $3,033
 $334
 $(1,129) $6,987
 
 Net Income (Loss)753
 (131) (4) —
 618
 
 Gross Additions to Long-Lived Assets2,118
 903
 25
 —
 3,046
 
 As of September 30, 2018          
 Total Assets$30,694
 $12,681
 $2,249
 $(551) $45,073
 
 Investments in Equity Method Subsidiaries—
 88
 —
 —
 88
 
 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. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 19. Related-Party Transactions.

Note 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 Six Months Ended 
  June 30, June 30, 
 Related-Party Transactions2018 2017 2018 2017 
  Millions 
 Billings from Affiliates:        
 Net Billings from Power primarily through BGS and BGSS (A)$272
 $296
 $850
 $895
 
 Administrative Billings from Services (B)85
 79
 $168
 144
 
 Total Billings from Affiliates$357
 $375
 $1,018
 $1,039
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2018 2017 2018 2017 
  Millions 
 Billings from Affiliates:        
 Net Billings from Power primarily through BGS and BGSS (A)$229
 $259
 $1,079
 $1,154
 
 Administrative Billings from Services (B)78
 82
 246
 226
 
 Total Billings from Affiliates$307
 $341
 $1,325
 $1,380
 
          
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








      
  As of As of 
 Related-Party TransactionsJune 30, 2018 December 31, 2017 
  Millions 
 Receivables from PSEG (C)$18
 $—
 
 Payable to Power (A)$81
 $221
 
 Payable to Services (B)69
 78
 
 Payable to PSEG (C)—
 41
 
 Accounts Payable—Affiliated Companies$150
 $340
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$94
 $91
 
      
      
  As of As of 
 Related-Party TransactionsSeptember 30, 2018 December 31, 2017 
  Millions 
 Receivables from PSEG (C)$55
 $—
 
 Payable to Power (A)$97
 $221
 
 Payable to Services (B)67
 78
 
 Payable to PSEG (C)—
 41
 
 Accounts Payable—Affiliated Companies$164
 $340
 
 Working Capital Advances to Services (D)$33
 $33
 
 
Long-Term Accrued Taxes Payable 
$67
 $91
 
      
Power
The financial statements for Power include transactions with related parties presented as follows:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Related-Party Transactions2018 2017 2018 2017 
  Millions 
 Billings to Affiliates:        
 Net Billings to PSE&G primarily through BGS and BGSS (A)$272
 $296
 $850
 $895
 
 Billings from Affiliates:        
 Administrative Billings from Services (B)$32
 $42
 $75
 $78
 
          
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Related-Party Transactions2018 2017 2018 2017 
  Millions 
 Billings to Affiliates:        
 Net Billings to PSE&G primarily through BGS and BGSS (A)$229
 $259
 $1,079
 $1,154
 
 Billings from Affiliates:        
 Administrative Billings from Services (B)$38
 $39
 $113
 $117
 
          
      
  As of As of 
 Related-Party TransactionsJune 30, 2018 December 31, 2017 
  Millions 
 Receivables from PSE&G (A)$81
 $221
 
 Payable to Services (B)$20
 $28
 
 Payable to PSEG (C)128
 29
 
 Accounts Payable—Affiliated Companies$148
 $57
 
 Short-Term Loan due (to) from Affiliate (E)$519
 $(281) 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$45
 $52
 
      
      
  As of As of 
 Related-Party TransactionsSeptember 30, 2018 December 31, 2017 
  Millions 
 Receivables from PSE&G (A)$97
 $221
 
 Receivables from PSEG (C)24
 —
 
 Accounts Receivable—Affiliated Companies$121
 $221
 
 Payable to Services (B)$21
 $28
 
 Payable to PSEG (C)—
 29
 
 Accounts Payable—Affiliated Companies$21
 $57
 
 Short-Term Loan to (from) Affiliate (E)$119
 $(281) 
 Working Capital Advances to Services (D)$17
 $17
 
 
Long-Term Accrued Taxes Payable 
$1
 $52
 
      
(A)PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. The rates in the BGS and BGSS contracts are prescribed by the BPU. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.
(B)Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.
(C)PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.
(D)PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Condensed Consolidated Balance Sheets.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








(E)Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents







Note 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 JuneSeptember 30, 2018 and December 31, 2017 and for the three months and sixnine months ended JuneSeptember 30, 2018 and 2017.
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended June 30, 2018          
 Operating Revenues$—
 $747
 $51
 $(31) $767
 
 Operating Expenses3
 704
 49
 (31) 725
 
 Operating Income (Loss)(3) 43
 2
 —
 42
 
 Equity Earnings (Losses) of Subsidiaries55
 (4) 5
 (51) 5
 
  Net Gains (Losses) on Trust Investments—
 8
 —
 —
 8
 
 Other Income (Deductions)41
 40
 —
 (68) 13
 
 Non-Operating Pension and OPEB Credits (Costs)—
 2
 1
 —
 3
 
 Interest Expense(54) (19) (6) 68
 (11) 
 Income Tax Benefit (Expense)2
 (23) 2
 —
 (19) 
 Net Income (Loss)$41
 $47
 $4
 $(51) $41
 
 Comprehensive Income (Loss)$43
 $44
 $4
 $(48) $43
 
 Six Months Ended June 30, 2018          
 Operating Revenues$—
 $2,133
 $102
 $(65) $2,170
 
 Operating Expenses3
 1,760
 101
 (65) 1,799
 
 Operating Income (Loss)(3) 373
 1
 —
 371
 
 Equity Earnings (Losses) of Subsidiaries289
 (7) 7
 (282) 7
 
 Net Gains (Losses) on Trust Investments—
 (14) —
 —
 (14) 
 Other Income (Deductions)76
 73
 —
 (125) 24
 
 Non-Operating Pension and OPEB Credits (Costs)—
 6
 1
 —
 7
 
 Interest Expense(96) (36) (11) 125
 (18) 
 Income Tax Benefit (Expense)9
 (115) 4
 —
 (102) 
 Net Income (Loss)$275
 $280
 $2
 $(282) $275
 
 Comprehensive Income (Loss)$272
 $267
 $2
 $(269) $272
 
 Six Months Ended June 30, 2018          
 
Net Cash Provided By (Used In)
   Operating Activities
$34
 $745
 $(8) $98
 $869
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(840) $(867) $(196) $808
 $(1,095) 
 
Net Cash Provided By (Used In)
   Financing Activities
$806
 $123
 $191
 $(906) $214
 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended September 30, 2018          
 Operating Revenues$—
 $849
 $59
 $(40) $868
 
 Operating Expenses2
 733
 61
 (40) 756
 
 Operating Income (Loss)(2) 116
 (2) —
 112
 
 Equity Earnings (Losses) of Subsidiaries117
 (7) 5
 (110) 5
 
  Net Gains (Losses) on Trust Investments—
 45
 (1) —
 44
 
 Other Income (Deductions)40
 45
 —
 (71) 14
 
 Non-Operating Pension and OPEB Credits (Costs)—
 4
 —
 —
 4
 
 Interest Expense(65) (28) (7) 71
 (29) 
 Income Tax Benefit (Expense)35
 (64) 4
 —
 (25) 
 Net Income (Loss)$125
 $111
 $(1) $(110) $125
 
 Comprehensive Income (Loss)$128
 $107
 $(1) $(106) $128
 
 Nine Months Ended September 30, 2018          
 Operating Revenues$—
 $2,982
 $161
 $(105) $3,038
 
 Operating Expenses5
 2,493
 162
 (105) 2,555
 
 Operating Income (Loss)(5) 489
 (1) —
 483
 
 Equity Earnings (Losses) of Subsidiaries406
 (14) 12
 (392) 12
 
 Net Gains (Losses) on Trust Investments—
 31
 (1) —
 30
 
 Other Income (Deductions)116
 118
 —
 (196) 38
 
 Non-Operating Pension and OPEB Credits (Costs)—
 10
 1
 —
 11
 
 Interest Expense(161) (64) (18) 196
 (47) 
 Income Tax Benefit (Expense)44
 (179) 8
 —
 (127) 
 Net Income (Loss)$400
 $391
 $1
 $(392) $400
 
 Comprehensive Income (Loss)$400
 $374
 $1
 $(375) $400
 
 Nine Months Ended September 30, 2018          
 
Net Cash Provided By (Used In)
   Operating Activities
$(255) $1,169
 $(26) $117
 $1,005
 
 
Net Cash Provided By (Used In)
   Investing Activities
$(417) $(1,132) $(290) $829
 $(1,010) 
 
Net Cash Provided By (Used In)
   Financing Activities
$672
 $(32) $320
 $(946) $14
 
            
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended June 30, 2017          
 Operating Revenues$—
 $899
 $47
 $(28) $918
 
 Operating Expenses(2) 1,094
 43
 (28) 1,107
 
 Operating Income (Loss)2
 (195) 4
 —
 (189) 
 Equity Earnings (Losses) of Subsidiaries(93) (4) 5
 97
 5
 
  Net Gains (Losses) on Trust Investments(1) 25
 —
 —
 24
 
 Other Income (Deductions)23
 21
 2
 (34) 12
 
 Non-Operating Pension and OPEB Credits (Costs)—
 2
 —
 —
 2
 
 Interest Expense(34) (9) (4) 34
 (13) 
 Income Tax Benefit (Expense)6
 60
 (4) —
 62
 
 Net Income (Loss)$(97) $(100) $3
 $97
 $(97) 
 Comprehensive Income (Loss)$(82) $(91) $3
 $88
 $(82) 
 Six Months Ended June 30, 2017          
 Operating Revenues$—
 $2,154
 $99
 $(66) $2,187
 
 Operating Expenses2
 2,650
 95
 (66) 2,681
 
 Operating Income (Loss)(2) (496) 4
 —
 (494) 
 Equity Earnings (Losses) of Subsidiaries(254) (5) 8
 259
 8
 
  Net Gains (Losses) on Trust Investments3
 40
 —
 —
 43
 
 Other Income (Deductions)43
 40
 2
 (62) 23
 
 Non-Operating Pension and OPEB Credits (Costs)—
 4
 —
 —
 4
 
 Interest Expense(64) (18) (9) 62
 (29) 
 Income Tax Benefit (Expense)7
 171
 —
 —
 178
 
 Net Income (Loss)$(267) $(264) $5
 $259
 $(267) 
 Comprehensive Income (Loss)$(228) $(234) $5
 $229
 $(228) 
 Three Months Ended June 30, 2017          
 
Net Cash Provided By (Used In)
   Operating Activities
$(32) $802
 $111
 $51
 $932
 
 
Net Cash Provided By (Used In)
   Investing Activities
$683
 $178
 $(241) $(1,355) $(735) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(651) $(978) $146
 $1,304
 $(179) 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 Three Months Ended September 30, 2017          
 Operating Revenues$—
 $829
 $46
 $(29) $846
 
 Operating Expenses2
 618
 44
 (29) 635
 
 Operating Income (Loss)(2) 211
 2
 —
 211
 
 Equity Earnings (Losses) of Subsidiaries143
 (3) 3
 (140) 3
 
  Net Gains (Losses) on Trust Investments—
 19
 —
 —
 19
 
 Other Income (Deductions)24
 26
 (2) (37) 11
 
 Non-Operating Pension and OPEB Credits (Costs)—
 2
 —
 —
 2
 
 Interest Expense(32) (12) (5) 37
 (12) 
 Income Tax Benefit (Expense)3
 (103) 2
 —
 (98) 
 Net Income (Loss)$136
 $140
 $—
 $(140) $136
 
 Comprehensive Income (Loss)$156
 $154
 $—
 $(154) $156
 
 Nine Months Ended September 30, 2017          
 Operating Revenues$—
 $2,983
 $145
 $(95) $3,033
 
 Operating Expenses4
 3,268
 139
 (95) 3,316
 
 Operating Income (Loss)(4) (285) 6
 —
 (283) 
 Equity Earnings (Losses) of Subsidiaries(111) (8) 11
 119
 11
 
  Net Gains (Losses) on Trust Investments3
 59
 —
 —
 62
 
 Other Income (Deductions)67
 66
 —
 (99) 34
 
 Non-Operating Pension and OPEB Credits (Costs)—
 6
 —
 —
 6
 
 Interest Expense(96) (30) (14) 99
 (41) 
 Income Tax Benefit (Expense)10
 68
 2
 —
 80
 
 Net Income (Loss)$(131) $(124) $5
 $119
 $(131) 
 Comprehensive Income (Loss)$(72) $(80) $5
 $75
 $(72) 
 Nine Months Ended September 30, 2017          
 
Net Cash Provided By (Used In)
   Operating Activities
$(55) $1,159
 $142
 $3
 $1,249
 
 
Net Cash Provided By (Used In)
   Investing Activities
$738
 $(289) $(343) $(990) $(884) 
 
Net Cash Provided By (Used In)
   Financing Activities
$(683) $(869) $211
 $987
 $(354) 
            
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Table of Contents








            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 As of June 30, 2018          
 Current Assets$4,806
 $1,411
 $216
 $(4,868) $1,565
 
 Property, Plant and Equipment, net52
 5,048
 3,679
 —
 8,779
 
 Investment in Subsidiaries4,977
 1,129
 —
 (6,106) —
 
 Noncurrent Assets243
 2,258
 110
 (183) 2,428
 
 Total Assets$10,078
 $9,846
 $4,005
 $(11,157) $12,772
 
 Current Liabilities$690
 $3,164
 $1,987
 $(4,868) $973
 
 Noncurrent Liabilities516
 2,097
 497
 (183) 2,927
 
 Long-Term Debt2,833
 —
 —
 —
 2,833
 
 Member’s Equity6,039
 4,585
 1,521
 (6,106) 6,039
 
 Total Liabilities and Member’s Equity$10,078
 $9,846
 $4,005
 $(11,157) $12,772
 
 As of December 31, 2017          
 Current Assets$4,327
 $1,500
 $200
 $(4,686) $1,341
 
 Property, Plant and Equipment, net54
 5,778
 2,764
 —
 8,596
 
 Investment in Subsidiaries4,844
 404
 —
 (5,248) —
 
 Noncurrent Assets100
 2,349
 110
 (78) 2,481
 
 Total Assets$9,325
 $10,031
 $3,074
 $(10,012) $12,418
 
 Current Liabilities$689
 $3,586
 $1,846
 $(4,686) $1,435
 
 Noncurrent Liabilities533
 1,966
 459
 (78) 2,880
 
 Long-Term Debt2,136
 —
 —
 —
 2,136
 
 Member’s Equity5,967
 4,479
 769
 (5,248) 5,967
 
 Total Liabilities and Member’s Equity$9,325
 $10,031
 $3,074
 $(10,012) $12,418
 
            
            
  Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
  Millions 
 As of September 30, 2018          
 Current Assets$4,497
 $1,353
 $302
 $(4,776) $1,376
 
 Property, Plant and Equipment, net55
 5,074
 3,740
 —
 8,869
 
 Investment in Subsidiaries5,086
 1,124
 —
 (6,210) —
 
 Noncurrent Assets245
 2,302
 106
 (217) 2,436
 
 Total Assets$9,883
 $9,853
 $4,148
 $(11,203) $12,681
 
 Current Liabilities$616
 $3,030
 $1,999
 $(4,776) $869
 
 Noncurrent Liabilities466
 2,129
 633
 (217) 3,011
 
 Long-Term Debt2,834
 —
 —
 —
 2,834
 
 Member’s Equity5,967
 4,694
 1,516
 (6,210) 5,967
 
 Total Liabilities and Member’s Equity$9,883
 $9,853
 $4,148
 $(11,203) $12,681
 
 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
 
            

Table of Contents

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 energy efficiency and related programs in New Jersey, which are regulated by the BPU, and
Power—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
PSEG’s other direct wholly owned subsidiaries 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 Services Agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
Our business discussion in Part I, Item 1. Business of our 2017 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 2017 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2018 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 2017 Form 10-K.

EXECUTIVE OVERVIEW OF 2018 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
PSE&G
At PSE&G, our focus is 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 investmentinvesting capital in T&D and other infrastructure projects designed tothat enhance system reliability and resiliency, and clean energy projects to meet customer expectations and support public policy objectives,objectives. Over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. Over the next five years, we expect to invest between $12 billion and
$16 billion in our business which is expected to provide an annual rate base growth of 8%—10%. We have completed our Energy Strong Program I (ES I) and are forecasting completion of our Gas System Modernization Program I (GSMP I) early next year.
managing a reliable, cost-effective generation fleetIn May 2018, we received approval for the Gas System Modernization Program II (GSMP II), an expanded, five-year program to invest $1.9 billion over five years beginning in 2019 to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the flexibilityremaining $300 million to utilizebe recovered through a diverse mixfuture base rate case. As part of fuels which allows usthe settlement, PSE&G agreed to respondfile a base rate case no later than five years from the commencement of the program, to market volatilitymaintain a base level of gas distribution capital expenditures of $155 million per year and capitalize on opportunitiesto achieve certain leak reduction targets.
In June 2018, we filed for our Energy Strong Program II (ES II), a proposed five-year $2.5 billion program to harden, modernize and make our electric and gas distribution systems more resilient. The size and duration of ES II, as they arise.well as certain other elements of the program, are subject to BPU approval.

Table of Contents

Financial ResultsIn October 2018, we filed our proposed Clean Energy Future (CEF) program with the BPU, a six-year estimated $3.6 billion investment program focused on achieving New Jersey’s energy efficiency targets, supporting electric vehicle infrastructure, deploying energy storage, and implementing an Energy Cloud program which will include installing 2.2 million advanced meter infrastructure (AMI) smart meters and associated infrastructure.
Also, in October 2018, the BPU issued an Order approving the settlement of our distribution base rate case with new rates effective November 1, 2018. The results for PSEG, PSE&G and Power for the three months and six months ended June 30, 2018 and 2017 are presented as follows:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
 Earnings (Losses)2018 2017 2018 2017 
  Millions 
 PSE&G$231
 $208
 $550
 $507
 
 Power (A)41
 (97) 275
 (267) 
 Other (B)(3) (2) 2
 (17) 
 PSEG Net Income$269
 $109
 $827
 $223
 
          
 PSEG Net Income Per Share (Diluted)$0.53
 $0.22
 $1.63
 $0.44
 
          
(A)Includes after-tax expenses of $229 million and $563 million in the three months and six months ended June 30, 2017, respectively, primarily for accelerated depreciation related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants. See Item 1. Note 4. Early Plant Retirements for additional information.
(B)Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges related to its investments in NRG REMA, LLC’s (REMA) leveraged leases of $14 million in the second quarter of 2018 and $13 million and $45 million in the three months and six months ended June 30, 2017, respectively. See Item 1. Note 7. Financing Receivables for additional information.
Power’s results above include the Nuclear Decommissioning Trust (NDT) Fund activity and the impactssettlement resulted in a net reduction in overall annual revenues of non-trading commodity mark-to-market (MTM) activity, which consistapproximately $13 million, comprised of the financial impact from positions with future delivery dates.
The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:
          
  Three Months Ended Six Months Ended 
  June 30, June 30, 
  2018 2017 2018 2017 
  Millions, after tax 
 NDT Fund Income (Expense) (A) (B)$5
 $14
 $(11) $22
 
 Non-Trading MTM Gains (Losses) (C)$(48) $21
 $37
 $27
 
          
(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 1. Note 8. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in Other Income (Deductions), interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.
(B)Net of tax (expense) benefit of $(4) million and $(16) million for the three months and $4 million and $(25) million for the six months ended June 30, 2018 and 2017, respectively.
(C)Net of tax (expense) benefit of $19 million and $(15) million for the three months and $(14) million and $(19) million for the six months ended June 30, 2018 and 2017, respectively.
Our $160a $212 million increase in Net Incomebase revenues, which includes the recovery of deferred storm costs, and the return of tax benefits largely due to tax reform of approximately $225 million. The Order provides for a distribution rate base of $9.5 billion, a 9.6% return on equity (ROE) for our distribution business and a 54% equity component of our capitalization structure. In addition to the $13 million annual revenue reduction, the Order provides for a one-time refund for taxes collected at the higher federal income tax rate for the three months ended June 30, 2018 was driven largely by
accelerated depreciation in 2017 related to early retirement of our Hudson and Mercer coal/gas generation units,
the favorable impact at Power from the lower federal tax rate effective January 1 to March 31, 2018 and
higher earnings due to continued investment in transmission and distribution clause programs,
partially offset by MTM net losses in 2018 as compared to MTM net gains in 2017, and

Table of Contents

lower wholesale energy sales at Power in the PJM region.
Our $604 million increase in Net Income for the six months ended June 30, 2018 was driven largely by
accelerated depreciation in 2017 related to early retirement of our Hudson and Mercer coal/gas generation units,
the favorable impact at Power from the lower federal tax rate effective January 1, 2018,
higher earnings due to continued investment in transmission and distribution clause programs, and
lower charges in 2018 related to leveraged lease investments (see Item 1. Note 7. Financing Receivables),
partially offset by unrealized losses on equity securities in the NDT Fund in 2018 related to new accounting guidance effective January 1, 2018. (See Item 1. Note 2. Recent Accounting Standards.)
During the first six months of 2018, we maintainedperiod. As a strong balance sheet. We continued to effectively deploy capital without the need to issue additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns atresult, PSE&G our regulated utility,will refund $28 million to customers in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generatorNovember 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 for our customers and bolstering our system resiliency. December 2018.
Power
At Power, we strive to improve performance and reduce costs in order to optimize cash flow generation from our fleet in light of low wholesale power and gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.
At PSE&G, we continue to invest in T&D projects that focus on reliability improvements and replacement of aging infrastructure. Over the next five years, we expect to invest between $12 billion and $15.5 billion in our business which is expected to provide an annual rate base growth of 8%—10%. We are forecasting completion of our Energy Strong Program I (ESP I) and Gas System Modernization Program I (GSMP I) this year. We have received approval for the GSMP II, an expanded, five-year program totaling $1.9 billion that will start in 2019. In June 2018, we filed for our Energy Strong Program II (ESP II), a proposed five-year $2.5 billion program to harden, modernize and make our electric and gas distribution systems more resilient. We also expect to file our proposed Clean Energy Future program later this year, a six-year estimated $2.9 billion program focused on achieving New Jersey’s energy efficiency targets, as well as supporting electric vehicle infrastructure and battery storage initiatives.Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G.
Power continues to move its fleet towards improved efficiency and fuel diversity. We believebelieves that its investment program enhances ourits competitive position with the addition of efficient, clean, reliable combined cycle gas turbine capacity. Our commitments for load, such as basic generation service (BGS) in New Jersey and other bilateral supply contracts, are backed by this generation or may be combined with the use of physical commodity purchases and financial instruments from the market to optimize the economic efficiency of serving our obligations. 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 2018 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 enhance the environmental profile and overall efficiency of Power’s generation fleet.
Financial Results
The results for PSEG, PSE&G and Power for the three months and nine months ended September 30, 2018 and 2017 are presented as follows:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
 Earnings (Losses)2018 2017 2018 2017 
  Millions 
 PSE&G$278
 $246
 $828
 $753
 
 Power (A)125
 136
 400
 (131) 
 Other (B)9
 13
 11
 (4) 
 PSEG Net Income$412
 $395
 $1,239
 $618
 
          
 PSEG Net Income Per Share (Diluted)$0.81
 $0.78
 $2.44
 $1.22
 
          
(A)Includes after-tax expenses of $5 million and $568 million in the three months and nine months ended September 30, 2017, respectively, related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants. See Item 1. Note 4. Early Plant Retirements for additional information.
(B)Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges related to its investments in NRG REMA, LLC’s (REMA) leveraged leases of $14 million and $45 million in the nine months ended September 30, 2018 and 2017, respectively. See Item 1. Note 7. Financing Receivables for additional information.
Power’s results above include the Nuclear Decommissioning Trust (NDT) Fund 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.

Table of Contents

The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:
          
  Three Months Ended Nine Months Ended 
  September 30, September 30, 
  2018 2017 2018 2017 
  Millions, after tax 
 NDT Fund Income (Expense) (A) (B)$27
 $10
 $16
 $32
 
 Non-Trading MTM Gains (Losses) (C)$(96) $(27) $(59) $—
 
          
(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 1. Note 8. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in Other Income (Deductions), interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.
(B)Net of tax (expense) benefit of $(16) million and $(12) million for the three months and $(12) million and $(37) million for the nine months ended September 30, 2018 and 2017, respectively.
(C)Net of tax (expense) benefit of $37 million and $19 million for the three months and $23 million and $0 million for the nine months ended September 30, 2018 and 2017, respectively.
Our $17 million increase in Net Income for the three months ended September 30, 2018 was driven largely by
higher earnings due to continued investment in transmission and distribution clause programs,
the favorable impact at Power from the lower federal tax rate effective January 1, 2018 and remeasurement of uncertain tax positions and associated interest in connection with the nuclear carryback claim and 2011 and 2012 federal tax audit, and
higher volumes of electricity sold in the PJM region generated by our new Keys and Sewaren combined cycle facilities,
largely offset by higher MTM net losses in 2018, and
higher generation costs driven by increased volumes of gas purchased at higher average prices in the PJM region.
Our $621 million increase in Net Income for the nine months ended September 30, 2018 was driven largely by
accelerated depreciation in 2017 related to early retirement of our Hudson and Mercer coal/gas generation units,
the favorable impact at Power from the lower federal tax rate effective January 1, 2018 and remeasurement of uncertain tax positions and associated interest in connection with the nuclear carryback claim and 2011 and 2012 federal tax audit,
higher earnings due to continued investment in transmission and distribution clause programs,
higher volumes of electricity sold under wholesale load contracts in the PJM region, and
lower charges in 2018 related to leveraged lease investments (see Item 1. Note 7. Financing Receivables),
partially offset by MTM losses in 2018,
higher fuel generation costs,
and lower volumes of electricity sold at lower prices under our BGS contracts.
The greater emphasis on capital spending in recent years for projects on which we receive contemporaneous returns at PSE&G has yielded strong results, which when combined with the cash flow generated by Power, has allowed us to increase our dividend annually. These actions to meet customer needs, market conditions and investor expectations reflect our long-term

Table of Contents

approach to managing our company. 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.
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 nine months of 2018, our
utility achieved continued strong reliability and customer satisfaction results, as well as comprehensive storm preparation and restoration efforts, and ongoing cost control,
diverse fuel mix and dispatch flexibility allowed us to generate approximately 42 terawatt hours while addressing fuel availability and price volatility, and
total nuclear fleet achieved a capacity factor of 92.9%.
Financial Strength
Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first nine months of 2018 as we
maintained sufficient liquidity,
maintained solid investment grade credit ratings, and
increased our indicative annual dividend for 2018 to $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. For additional information on the impacts of the Tax Act, see Item 1. Note 6. Rate Filings and Note 15. Income Taxes.
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 nine months of 2018, we
made additional investments in T&D infrastructure projects,
continued to execute our GSMP I, Energy Efficiency and other existing BPU-approved utility programs,
received approval for our GSMP II program and filed our proposed ES II and CEF programs, and
commenced commercial operation of Sewaren 7 and Keys generation facilities and continued construction of our BH5 generation project, which is targeted for commercial operation in mid-2019.
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. For additional information about regulatory, legislative and other developments that may affect the company, see Part I, Item 1. Regulatory Issues in our 2017 Annual Report on Form 10-K and Item 5. Other Information in our FormForms 10-Q for the periodperiods ending March 31, 2018 and June 30, 2018 and this Form 10-Q.

Table of Contents

Transmission Planning
There are several matters pending before FERC and the U. S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) that concernmay impact the allocation of costs associated with transmission projects, including those 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 customers in New Jersey. In addition, as a 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 would be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.

Table of Contents

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).ROE. Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ base ROEs. The results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.
Wholesale Power Market Design
Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remainsIn October 2018, FERC issued an important focus for us. During 2015, PJM implementedorder establishing a new “Capacity Performance” (CP) mechanism that createdframework for determining whether a more robust capacity product with enhanced incentives for performance during emergency conditionscompany’s ROE is unjust and significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequentunreasonable. FERC proposes to its implementation, FERC approved changesrely on financial models to the CP constructestablish a composite zone of reasonableness that will enhancebe used to determine whether an ROE complaint should be dismissed. If FERC determines that an existing ROE is unjust and unreasonable, it intends to reset the participationROE based on averaging the results of intermittentvarious financial models. We are still analyzing the potential impact of these methodologies and demand response resources (seasonal resources). However, FERC held a technical conference in response to two complaints to consider the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions. We cannot predict the outcome of these matters.this proceeding. See Part II, Item 5. Other Information for additional information.
In April 2018, PJM submitted two proposed alternative and mutually exclusive capacity market reforms for FERC’s approval. Wholesale Power Market Design
In June 2018, FERC issued an order finding that PJM’s current capacity market is unjust and unreasonable because it allows resources supported by out-of-market payments to suppress capacity prices. FERC established a new proceeding to addressconsider an alternative approach in which PJM would: (1) modify PJM’s Minimum Offer Price Rule (MOPR) so that it would apply to new and existing resources that receive out-of-market payments, regardless of resource type; and (2) establish an option that would allow, on a resource-specific basis, resources receiving out-of-market support to be removed from the PJM capacity market along with a commensurate amount of load, for some period of time.design. FERC’s potential action in this proceeding could cause nuclear units that receive ZECzero emissions certificates (ZEC) payments to lose capacity market revenues if states do not take steps to address this potential loss of capacity revenues. In addition, depending on the outcome of this matter, our fossil generating stations could also be adversely impacted. We cannot predict the outcome of this matter.
The PJM Board directed PJM staff to work with stakeholders to implement a series of price formation reforms, including a 30-minute reserve product in real-time, more dynamic reserve requirements to better capture operator actions taken to maintain reliability, and improvement to the curves used to price reserves during reserve shortage conditions. The PJM Board letter directs PJM staff to submit some of these reforms for FERC’s approval so that they can be implemented in early 2019. If placed into effect, these reforms should improve energy and reserve prices by ensuring that when operators commit resources to ensure reliability, the commitments are reflected in market 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 producingtraditional utility infrastructure that enhances reliability, resiliency, and/or safety.
In May 2018, the BPU approved a settlement regarding PSE&G’s GSMP II program, which is the next phase of our GSMP I. Under GSMP II, PSE&G expects to invest $1.9 billion over five years beginning in 2019 to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the remaining $300 million to be recovered through a future base rate case. As part of the settlement, PSE&G agreed to file a base rate case no later than five years from the commencement of the program, to maintain a base level of gas distribution capital expenditures of $155 million per year and to achieve certain leak reduction targets. The ROE and certain other elements for the program will be determined in the pending base rate case proceeding.
As previously disclosed, PSE&G’s ESP I, an investment program to harden and make the electric and gas distribution system more resilient, is expected to be completed during 2018. In June 2018, PSE&G filed its ESP II proposal with the BPU to invest

Table of Contents

an additional $2.5 billion over the next five years as an extension and expansion of its ESP I. The extension seeks to continue efforts to harden the electric system against storms and make it more resilient, to implement a more proactive life cycle replacement program to modernize the electric system and to make the gas system more reliable by mitigating the impacts of potential supply curtailments. The size and duration of ESP II, as well as PSE&G’s ROE and certain other elements of the program, are subject to BPU approval.
In January 2018, PSE&G filed a distribution base rate case as required as a condition of approval of its ESP I approved by the BPU in 2014. The filing requested an approximate 1% increase in revenues and recovery of investments made to strengthen the electric and gas distribution systems. The requested increase took into account a reduction in the revenue requirement as a result of the federal corporate income tax rate reduction from 35% to 21% provided in the Tax Act, including the flow-back to customers of excess accumulated deferred income taxes. In March 2018, the BPU approved interim rate reductions for all their jurisdictional utilities, including PSE&G, reflecting the reduction in the federal corporate tax rate. The BPU approved a reduction to PSE&G’s base electric and gas revenues effective April 1, 2018 by $71 million and $43 million, respectively, on an annual basis (or about 2% combined). The refund to customers for overcollection of revenues at the higher tax rate for the January 1 to March 31, 2018 period, and the flow-back to customers of certain excess deferred income taxes will be addressed in PSE&G’s ongoing base rate case proceeding. As a result of the base rate reduction implemented on April 1, 2018, PSE&G’s requested revenue requirement in its filing has increased accordingly. In May 2018, PSE&G filed a required update to its base rate case, requesting an approximate three percent increase in revenues. PSE&G anticipates a decision by the BPU that the new base rates will go into effect in the fourth quarter of 2018.
Energy Efficiency
Consistent with New Jersey’s recently enacted energy efficiency legislation, which is more fully described under Part II, Item 5. Other Information, PSE&G has outlined a clean energy proposal to invest $2.9 billion over six years in energy efficiency and other programs that will reduce energy bills and combat climate change, which we refer to as our Clean Energy Future program. The program, which PSE&G expects to file with the BPU later this year, includes: $2.5 billion for energy efficiency to reduce customer bills and lower energy use, which will decrease air pollution, including emissions that accelerate climate change; $300 million for building a “smart” electric vehicle infrastructure; and $100 million for utility-scale energy storage systems that will enable greater development of renewable resources and enhance resiliency.
Environmental Regulation
We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.
In March 2017, the President of the United States issued an Executive Order that instructedAugust 2018, the EPA to reviewreleased the New Source Performance Standards that establish emissions standardsproposed Affordable Clean Energy (ACE) rule as a replacement for CO2 for certain new fossil power plants, and the EPA’s Clean Power Plan (CPP),Plan. The proposed ACE rule gives states great flexibility to evaluate specific heat rate improvement technologies and practices to be applied at coal-fired electric generating units. States have three years from the date of finalization to submit a greenhouse gas emissions regulation under the Clean Air Act for existing power plantsplan that establishes state-specific emission rate targets based on implementationa standard of performance that reflects the best systemdegree of emission reduction. In October 2017,limitation through the EPA Administrator signed a proposed repealapplication of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). The EPA is considering rulemaking to replace the CPP. PSEGheat rate improvement technologies and practices. We cannot assessestimate the impact of any such rulemakingthis action on itsour business and futureor results of operations at this time.
We are also 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 10. Commitments and Contingent Liabilities.Liabilities.

Table of Contents

Early Plant Retirements
Fossil    
On June 1, 2017, Power completed its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operations in 2016 and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental D&A Expense of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. See Item 1. Note 4. Early Plant Retirements for additional information.
Power is exploring various opportunities with these sites, including using the sites for alternative industrial activity or the
disposition of one or both of the sites. If Power determines not to use the sites for alternative industrial activity, the early
retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible
remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.
In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.
Nuclear
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. In FebruarySeptember 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure ofshut down 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 May 2018, the governor of New Jersey signed legislation that would provide a safety net in order to prevent the loss of environmental attributes from selected nuclear generating stations referred to as the ZEC program. The legislation calls for the BPU to establish a collection process for a customer charge, determine eligibility and certification of need, and potentially select nuclear plants to receive ZECs starting in April 2019. The law mandates each New Jersey electric distribution company, including PSE&G, to purchase ZECs and recover its procurement of ZECs through a non-bypassable charge (ZEC charge) in the amount of $0.004 per kilowatt-hour.
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 RPMReliability Pricing Model capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for selection of the units under the newly enacted legislation in the state of New Jersey. Power and Exelon have agreed to cancel the funding of future capital projects at the Salem generating station that are not required to meet NRC or other regulatory requirements or that are not required to ensure its safe operation. Power and Exelon have agreed to continue to assess and, when appropriate, approve the funding of individual capital projects to ensure compliance with regulatory requirements and the safe operation of the Salem generating station and that the funding of thesepreviously postponed projects may be restored ifas a result of the legislation enacted in New Jersey sufficiently values the attributes of nuclear generation and Salem benefits from such legislation.
Power believes it may be unable to cover its costs and would be inadequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units, which would result in Power retiring these units early, if (i) energy market prices continue to be depressed, (ii) there are adverse impacts from potential changes to the capacity market construct being considered by FERC, or (iii) Salem and/or Hope Creek are not selected to participate in the ZEC program or the ZEC program does not adequately compensate our nuclear generating stations for their attributes. 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. If

Table of Contents

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.
Leveraged Leases
In MaySeptember 2018, certain subsidiaries of Energy Holdings (PSEG Entities) entered into a Restructuring Support Agreement (RSA) with REMA. Pursuant to the governorRSA, the PSEG Entities have agreed to support the implementation of New Jersey signed legislation that would provide a safety net in orderrestructuring and related transactions with respect to prevent the loss of environmental attributes from selected nuclear generating stations referred to as the zero emissions certificate (ZEC) program. The legislation calls for the BPU (within a 330-day period from enactment) to establish a collection process for a customer charge, determine eligibility and certification of need, and ultimately select nuclear plants to potentially receive ZECs starting in April 2019. Power cannot predict whether our nuclear generating stations in New JerseyREMA’s indebtedness. Such restructuring transactions will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
If energy market prices continue to be depressed, there are adverse impacts from potential changes to the capacity market construct being consideredimplemented by FERC, or the ZEC program does not adequately compensate our nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and

Table of Contents

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 Impairments
GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for reliefREMA on an in-court basis under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. REMA was not includedCode. The RSA outlines a plan of reorganization under which, in addition to other terms, the ownership interest in the GenOn bankruptcy filing. GenOn is currently engagedleases relating to the Keystone and Conemaugh investments will be transferred to holders of certain debtholders of REMA. Upon consummation of the restructuring transactions, the PSEG Entities will receive $31.5 million in cash in exchange for (a) the full satisfaction of all claims asserted against REMA and (b) approval of certain amendments to the Shawville lease. The Shawville lease amendments, among other things, will allow REMA to express tentative interest in a balance sheet restructuring, which will take an undetermined time to complete. PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity.
PSEG continues to monitor anyrenewal on or after November 24, 2019, with similar changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’the other milestones in the lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged lease receivables, and continuesrenewal procedures. In addition, REMA has agreed to discuss the situation with various parties relevantfund qualifying credit support up to this matter. Based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives,$36 million. Energy Holdings recordedwill be required upon resolution of this matter to accelerate and pay approximately $40 million of state deferred tax liabilities and accelerate and pay and/or reduce $85 million of a $20 million pre-tax charge inforecasted federal tax loss to the quarter ended June 30, 2018 for its current best estimate of loss related to lease receivables. For additional information, see Item 1. Note 7. Financing Receivables. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.Internal Revenue Service.
Additional facilities in our leveraged lease portfolio include the Joliet and Powerton generating facilities. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois. Each of these three facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.
Tax Legislation
In December 2017, the U.S. government enacted comprehensive tax legislation (Tax Act), which, among other things, decreased the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018, and made certain changes to bonus depreciation rules.
As a result of 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.Liabilities.
Beginning in 2018, PSEG, on a consolidated basis, is incurring lower income tax expense resulting in a decrease in its projected effective income tax rate. This has increased PSEG’s and Power’s net income. To the extent allowed under the Tax Act, Power’s operating cash flows will reflect the full expensing of capital investments for income tax purposes. PSEG and Power expect that the interest on their debt will continue to be fully tax deductible albeit at a lower tax rate. For PSE&G, the Tax Act has led to lower customer rates due to lower income tax expense recoveries and we have proposedthe BPU has approved our proposal to refund excess deferred income tax regulatory liabilities as part of our distribution rate case filing.liabilities. 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 elimination of bonus depreciation, partially offset by higher revenues due to the higher rate base.
In August 2018, the Internal Revenue Service issued a Notice of Proposed Rulemaking (Notice) regarding the application of tax depreciation rules as amended by the Tax Act. While the Notice provides some guidance as to the application of the changes made by the Tax Act to the bonus depreciation rules, certain aspects still remain unclear. Until clarity is provided, the amounts recorded for bonus depreciation for 2017 and 2018 remain provisional and are based on a reasonable interpretation of the Notice.
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.
In addition, FERC continues to assess whether, and if so how, it will address changes and flow-backs to customers relating to accumulated deferred income taxes and bonus depreciation. See Item 1. Note 6. Rate Filings for additional information.
In July 2018, the State of New Jersey made significant changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as

Table of Contents

requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. We believe PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. We expect these new provisions

Table of Contents

to unfavorably affect our non-utility business and we continuebusiness. In accordance with GAAP accounting for income taxes, deferred taxes are required to analyze thisbe measured at the enacted tax rate expected to apply to taxable income in the periods in which the deferred taxes are expected to settle. The newly enacted law and theNew Jersey tax legislation did not have a material impact it will have on us.
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 six months of 2018, our
utility, beginning with comprehensive storm preparation, efficiently and safely completed our customer restorations and then assisted neighboring utilities with their restoration efforts,
diverse fuel mix and dispatch flexibility allowed us to generate approximately 25 terawatt hours while addressing fuel availability and price volatility, and
total nuclear fleet achieved an average capacity factor of 92.9%.
Financial Strength
Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first six months of 2018 as we
maintained sufficient liquidity,
maintained solid investment grade credit ratings, and
increased our indicative annual dividend for 2018 to $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 six months of 2018, we
made additional investments in transmission infrastructure projects,
continued to execute our GSMP I, ESP I, Energy Efficiency and other existing BPU-approved utility programs, and
commenced commercial operation of Sewaren 7 and continued construction of our BH5 generation project, which is targeted for commercial operation in mid-2019.
In early July 2018, we started commercial operation of our Keys generation facility.PSEG’s deferred income tax balance.
Future Outlook    
Our future success will depend on our ability to continue to maintain strong operational and financial performance in an 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 prices and demand,
obtain approval of and execute our utility capital investment program, including ESPES II, GSMP I and II, our Clean Energy FutureCEF program 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 of our BH5 and other generation projects,
advocate for measures to ensure the implementation by PJM and FERC of market design and transmission planning rules that continue to promote fair and efficient electricity markets,

Table of Contents

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.
ForIn addition to the risks describe elsewhere in this Form 10-Q and our Form 10-K for the year ended December 31, 2017, for 2018 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 which was filed with the BPU in January 2018, and the timing of the return of unprotected excess deferred taxes to customers,proceedings,
applying to the BPU to select our New Jersey nuclear generation units to receive payments under the ZEC program,
continuing discussions regarding the restructuring of GenOn and REMA and its potential impact on the value of our Keystone, Conemaugh and Shawville leveraged leases,
the continuing impacts of the Tax Act and changes in state tax laws,
national and regional economic conditions, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,
the potential for continuedimpact of reductions in demand and sustained lower natural gas and electricity prices both at market hubs and the locations where we operate,
the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,costs.
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.
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, customers 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 T&D facilities, clean energy investments and/or generation units,projects, in each case including offshore wind opportunities,
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.
Power is developing ahas stopped taking new customers in its retail energy businessbusiness. Power will continue to sell energy, which we believe complementsmeet all of its obligations to our existing wholesale marketing business. Power began these marketing activities in 2017 and has been granted retail energy supplier licenses in New Jersey, Pennsylvania and Maryland.customers through the end of their current contracts.

Table of Contents

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.

Table of Contents


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 19. Related-Party Transactions.
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2018 2017 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$2,016
 $2,142
 $(126) (6) $4,834
 $4,733
 $101
 2
 
 Energy Costs600
 588
 12
 2
 1,552
 1,456
 96
 7
 
 Operation and Maintenance725
 718
 7
 1
 1,479
 1,435
 44
 3
 
 Depreciation and Amortization280
 641
 (361) (56) 560
 1,469
 (909) (62) 
 Income from Equity Method Investments5
 5
 —
 —
 7
 8
 (1) (13) 
 Net Gains (Losses) on Trust Investments8
 25
 (17) (68) (14) 53
 (67) (79) 
 Other Income (Deductions)34
 33
 1
 3
 66
 65
 1
 2
 
 Non-Operating Pension and OPEB Credits (Costs)19
 1
 18
 N/A
 38
 1
 37
 N/A
 
 Interest Expense111
 91
 20
 22
 214
 189
 25
 13
 
 Income Tax Expense97
 59
 38
 64
 299
 88
 211
 240
 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2018 2017 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$2,394
 $2,254
 $140
 6
 $7,228
 $6,987
 $241
 3
 
 Energy Costs804
 616
 188
 31
 2,356
 2,072
 284
 14
 
 Operation and Maintenance742
 693
 49
 7
 2,221
 2,128
 93
 4
 
 Depreciation and Amortization294
 252
 42
 17
 854
 1,721
 (867) (50) 
 Income from Equity Method Investments5
 3
 2
 67
 12
 11
 1
 9
 
 Net Gains (Losses) on Trust Investments45
 18
 27
 N/A
 31
 71
 (40) (56) 
 Other Income (Deductions)33
 33
 —
 —
 99
 98
 1
 1
 
 Non-Operating Pension and OPEB Credits (Costs)19
 —
 19
 N/A
 57
 1
 56
 N/A
 
 Interest Expense127
 100
 27
 27
 341
 289
 52
 18
 
 Income Tax Expense117
 252
 (135) (54) 416
 340
 76
 22
 
                  
The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.
PSE&G
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2018 2017 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,386
 $1,393
 $(7) (1) $3,231
 $3,219
 $12
 —
 
 Energy Costs488
 488
 —
 —
 1,270
 1,250
 20
 2
 
 Operation and Maintenance353
 359
 (6) (2) 744
 729
 15
 2
 
 Depreciation and Amortization187
 166
 21
 13
 377
 337
 40
 12
 
 Net Gains (Losses) on Trust Investments—
 —
 —
 —
 —
 2
 (2) (100) 
 Other Income (Deductions)20
 21
 (1) (5) 40
 43
 (3) (7) 
 Non-Operating Pension and OPEB Credits (Costs)15
 (1) 16
 N/A 30
 (3) 33
 N/A 
 Interest Expense82
 69
 13
 19
 163
 144
 19
 13
 
 Income Tax Expense80
 123
 (43) (35) 197
 294
 (97) (33) 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2018 2017 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$1,595
 $1,530
 $65
 4
 $4,826
 $4,749
 $77
 2
 
 Energy Costs593
 543
 50
 9
 1,863
 1,793
 70
 4
 
 Operation and Maintenance389
 357
 32
 9
 1,133
 1,086
 47
 4
 
 Depreciation and Amortization192
 169
 23
 14
 569
 506
 63
 12
 
 Net Gains (Losses) on Trust Investments—
 —
 —
 N/A
 —
 2
 (2) N/A
 
 Other Income (Deductions)21
 22
 (1) (5) 61
 65
 (4) (6) 
 Non-Operating Pension and OPEB Credits (Costs)14
 (2) 16
 N/A
 44
 (5) 49
 N/A
 
 Interest Expense83
 79
 4
 5
 246
 223
 23
 10
 
 Income Tax Expense95
 156
 (61) (39) 292
 450
 (158) (35) 
                  
Three Months Ended JuneSeptember 30, 2018 as Compared to 2017
Operating Revenues decreased $7increased $65 million due to changes in delivery, commodity, clause and other operating revenues.

Table of Contents

Delivery Revenues decreasedincreased $8 million due primarily to
Transmission, gaselectric distribution and electricgas distribution revenue requirements were $62$78 million lower as a result of rate reductions due to the Tax Act which reduced the corporate income tax rate. This decrease is offset in Income Tax Expense.

Gas distribution revenues decreased $1 million due primarily to a $2 million decrease from lower sales volumes and a $1 million decrease from ES I investments, partially offset by a $2 million increase from the inclusion of the GSMP I in base rates.
TableElectric distribution revenues increased $45 million due to $33 million in higher sales volumes, a $10 million increase from higher ES I investments in base rates and higher Green Program Recovery Charges (GPRC) of Contents

$2 million.
Transmission revenues were $34$42 million higher due to revenue requirements calculated through our transmission formula rate, primarily to recover increased investments.
Gas distribution revenues increased $12 million due primarily to a $16 million increase from higher sales volumes and a $5 million increase from the inclusion of the GSMP I in base rates. These increases were partially offset by a $10 million decrease in Weather Normalization Clause (WNC) collections.
Electric distribution revenues increased $8 million due to a $4 million increase from higher ESP I investments in base rates, $3 million in higher sales volumes, and higher Green Program Recovery Charges (GPRC) of $1 million.
Commodity Revenues were flatincreased $50 million as a result of higher Electric and Gas revenues entirely offset by lower Electric revenues. The changes in Commodity revenues for both gaselectric and electricgas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and basic gas supply service (BGSS) to retail customers.
GasElectric commodity revenues increased $4$47 million due to higher BGSS sales volumes of $22 million partially offset by
lower BGSS sales prices of $18 million.
Electric commodity revenues decreased $4 million due to $29 million from lower BGS prices partially offset by $25$79 million in higher BGS sales volumes.volumes, partially offset by $32 million from lower BGS prices.
Gas commodity revenues increased $3 million due primarily to higher BGSS sales prices of $4 million, partially offset by lower BGSS sales volumes of $1 million.
Clause Revenues were flatincreased $5 million due primarily to a $6 million decrease in Margin Adjustment Clause (MAC) revenues entirely offset by higher collections of Societal Benefit Charges (SBC) of $4$6 million and a $2$5 million increase in Margin Adjustment Clause (MAC) revenues, partially offset by a $7 million decrease in collections of GPRC. The changes in the SBC, MAC SBC and GPRC amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on SBC, MAC SBC or GPRC collections.
Operating Expenses
Energy Costs were flat.increased. This is entirely offset by the change in Commodity Revenues.
Operation and Maintenance decreased $6increased $32 million due primarily to a $4increases of $7 million reductionin clause and renewable related net expenditures, $7 million in distribution maintenance, $6 million in transmission maintenance, $5 million in injuries and damages and a $2$4 million decrease in distribution maintenance, partially offset by a $2 million increase in seasonal storm damages.appliance service costs.
Depreciation and Amortization increased $21$23 million due primarily to an increase in depreciation due to additional plant placed into service.
Non-Operating Pension and OPEB Credits (Costs) reflected an increase of $16 million in credits due to the adoption of new accounting guidance effective January 1, 2018 which no longer allows capitalization of any portion of these benefit costs. See Item 1. Note 2. Recent Accounting Standards.
Interest Expense increased $13$4 million due primarily to increases of $7 million in clause interest and $5$6 million related to net debt issuances in May and September 2018 and December 2017.2017, partially offset by a reduction of $1 million related to clauses.
Income Tax Expense decreased $43$61 million due primarily to the decrease in the federal statutory income tax rate from 35% in 2017 to 21% in 2018, partially offset by plant-related and flow-through items.2018.
SixNine Months Ended JuneSeptember 30, 2018 as Compared to 2017
Operating Revenues increased $12$77 million due to changes in delivery, commodity, clause and other operating revenues.
Delivery Revenues increased $4$9 million due primarily to
Transmission, revenues were $80 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover increased investments.
Gas distribution revenues increased $43 million primarily due to a $48 million increase due to higher sales volumes, a $22 million increase from the inclusion of the GSMP I in base rates and a $2 million increase in GPRC collections. These increases were partially offset by a $29 million decrease in WNC collections.
Electric distribution revenues increased $8 million due to a $6 million increase from the inclusion of increased ESP I investments in base rates and $2 million in higher sales volumes.
Transmission, gaselectric distribution and electricgas distribution revenue requirements were $127$207 million lower as a result of rate reductions due to the Tax Act which reduced the corporate income tax rate. This decrease is offset in Income Tax Expense.
Transmission revenues were $122 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover increased investments.
Electric distribution revenues increased $52 million due to $36 million in higher sales volumes and a $16 million increase from the inclusion of increased ES I investments in base rates.

Table of Contents

Gas distribution revenues increased $42 million due primarily to a $44 million increase due to higher sales volumes, a $24 million increase from the inclusion of the GSMP I in base rates and a $3 million increase in GPRC collections. These increases were partially offset by a $29 million decrease in WNC collections.
Commodity Revenues increased $20$70 million as a result of higher Electric revenues partially offset by lower Gas revenues. The changes in Commodity revenues for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

Table of Contents

Electric commodity revenues increased $30$77 million due primarily to $46$127 million in higher BGS sales volumes partially offset by $19 million in lower BGS prices and a $3 million increase from sales of solar renewable energy credits.credits, partially offset by $53 million in lower BGS prices.
Gas commodity revenues decreased $10$7 million due to lower BGSS prices of $49$47 million, partially offset by higher BGSS sales volumes of $39$40 million.
Clause Revenues decreased $11$7 million due primarily to an $11a $6 million decrease in MAC revenues and lower SBC of $2 million.a $6 million decrease in GPRC. These decreases were partially offset by higher SBC collections of $4 million and a $1 million increasesincrease in GPRC andcollections of Solar Pilot Recovery Charges (SPRC). The changes in the MAC, GPRC, SBC GPRC and SPRC amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on MAC, GPRC, SBC GPRC or SPRC collections.
Other Operating Revenues increased $5 million due primarily to an increase in appliance service revenues.
Operating Expenses
Energy Costs increased $20$70 million. This is entirely offset by the change in Commodity Revenues.
Operation and Maintenance increased $15$47 million, due primarily due to increases of $13 million in transmission maintenance, $12 million in appliance service costs, $9 million in storm costs, $8$9 million in transmission expenses, $7 million in appliance service costsdistribution maintenance and $7 million in the gas distribution tariff. These increases were partially offset by a net $10$4 million decrease in clause and renewable related expenditures and a $4 million reduction in injuries and damages.expenditures.
Depreciation and Amortization increased $40$63 million due primarily to a $39$61 million increase in depreciation related to additional plant inplaced into service and an increase of $4$5 million in amortization of Regulatory Assets, partially offset by a $3$4 million increase in capitalized depreciation.
Non-Operating Pension and OPEB Credits (Costs) reflected an increase of $3349 million in credits due to the adoption of new accounting guidance effective January 1, 2018 which no longer allows capitalization of any portion of these benefit costs. See Item 1. Note 2. Recent Accounting Standards.
Interest Expense increased $19$23 million due primarily to an increase of $12$17 million related to net debt issuances in May 2018 and 2017September 2018 and December 2017 and a $7$6 million increase related to clauses.
Income Tax Expense decreased $97$158 million due primarily to the decrease in the federal statutory income tax rate from 35% in 2017 to 21% in 2018, partially offset by uncertain tax positions, plant-related and flow-through items.


Table of Contents
Power

Power
                  
  Three Months Ended 
Increase/
(Decrease)
 Six Months Ended 
Increase/
(Decrease)
 
  June 30,  June 30,  
  2018 2017
 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$767
 $918
 $(151) (16) $2,170
 $2,187
 $(17) (1) 
 Energy Costs373
 386
 (13) (3) 1,119
 1,078
 41
 4
 
 Operation and Maintenance268
 256
 12
 5
 514
 488
 26
 5
 
 Depreciation and Amortization84
 465
 (381) (82) 166
 1,115
 (949) (85) 
 Income from Equity Method Investments5
 5
 —
 —
 7
 8
 (1) (13) 
 Net Gains (Losses) on Trust Investments8
 24
 (16) (67) (14) 43
 (57) N/A
 
 Other Income (Deductions)13
 12
 1
 8
 24
 23
 1
 4
 
 Non-Operating Pension and OPEB Credits (Costs)3
 2
 1
 50
 7
 4
 3
 75
 
 Interest Expense11
 13
 (2) (15) 18
 29
 (11) (38) 
 Income Tax Expense (Benefit)19
 (62) 81
 N/A
 102
 (178) 280
 N/A
 
                  
                  
  Three Months Ended 
Increase/
(Decrease)
 Nine Months Ended 
Increase/
(Decrease)
 
  September 30,  September 30,  
  2018 2017
 2018 vs. 2017 2018 2017 2018 vs. 2017 
  Millions Millions % Millions Millions % 
 Operating Revenues$868
 $846
 $22
 3
 $3,038
 $3,033
 $5
 —
 
 Energy Costs431
 330
 101
 31
 1,550
 1,408
 142
 10
 
 Operation and Maintenance231
 229
 2
 1
 745
 717
 28
 4
 
 Depreciation and Amortization94
 76
 18
 24
 260
 1,191
 (931) (78) 
 Income from Equity Method Investments5
 3
 2
 67
 12
 11
 1
 9
 
 Net Gains (Losses) on Trust Investments44
 19
 25
 N/A
 30
 62
 (32) (52) 
 Other Income (Deductions)14
 11
 3
 27
 38
 34
 4
 12
 
 Non-Operating Pension and OPEB Credits (Costs)4
 2
 2
 100
 11
 6
 5
 83
 
 Interest Expense29
 12
 17
 N/A
 47
 41
 6
 15
 
 Income Tax Expense (Benefit)25
 98
 (73) (74) 127
 (80) 207
 N/A
 
                  
Three Months Ended JuneSeptember 30, 2018 as Compared to 2017
Operating Revenues decreased $151increased $22 million due primarily to changes in generation and gas supply revenues.

Table of Contents

Gas Supply Revenues increased $24 million due primarily to an increase in sales to third parties due primarily to higher average sale prices coupled with an increase in sales volumes.
Generation Revenues decreased $187$1 million due primarily to
a decrease of $123$84 million due to higher net MTM losses in 2018 as compared to net MTM gains in 2017. Of this amount, $133$136 million was due to changes in forward power prices, partially offset by $10$52 million due to lower losses on positions reclassified to realized upon settlement this year as compared to last year, and
a net decrease of $75 million in energy sales due primarily to lower generation volumes and lower average realized prices in the PJM region, and
a decrease of $20 million in electricity sold under our BGS contracts due to lower prices and lower volumes,
partially offset by a net increase of $28 million in electricity sold under other wholesale load contracts in the PJM region due to higher volumes sold.
Gas Supply Revenues increased $36 million due primarily to
an increase of $26 million related to sales to third parties due primarily to an increase in sales volumes, partially offset by lower average sales prices, and
an increase of $11 million in sales under the BGSS contract due primarily to an increase in sales volumes related to colder average temperatures in 2018, partially offset by lower average sales prices.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $13 million due to
Generation costs decreased $46 million due primarily to
a decrease of $21 million due to net MTM gains in 2018 as compared to net MTM losses in 2017,
lower fuel costs of $12 million due primarily to lower natural gas costs reflecting lower volumes in the PJM region, and
a decrease of $9 million in energy purchases due primarily to lower volumes on wholesale load contracts in the New England (NE) region and lower cost to serve load in the PJM region.
Gas costs increased $33 million due mainly to
an increase of $23 million related to sales to third parties due primarily to an increase in volumes sold, partially offset by lower average gas costs, and
an increase of $10 million related to sales under the BGSS contract due primarily to increased volumes sold due to colder average temperatures in 2018, partially offset by lower average gas costs.
Operation and Maintenance increased $12 million 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 our 57%-owned Salem Unit 2 nuclear plant.
Depreciation and Amortization decreased$381 milliondue primarily to
higher depreciation in 2017 for Hudson and Mercer due to the early retirement of those units,
partially offset by a $5 million increase in 2018 due to a higher nuclear asset base primarily from increased capitalized asset retirement costs.
Net Gains (Losses) on Trust Investments decreased $16 million due primarily to the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.
Income Tax Expense (Benefit) increased $81 million 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 to 21% in 2018.

Table of Contents

Six Months Ended June 30, 2018 as Compared to 2017
Operating Revenuesdecreased$17 million due to changes in generation and gas supply revenues.
Generation Revenues decreased $47 million due primarily to
a net decrease of $87 million in energy sales due primarily to lower generation volumes and lower average realized prices in the PJM region partially offset by higher average prices in the NE and New York (NY) regions, and
a decrease of $29$14 million in electricity sold under our BGS contracts due primarily to lower prices,
partially offset by a net increase of $36$48 million in energy sales due primarily to higher net volumes sold, which includes the commencement of electricity sold under other wholesale load contractscommercial operations of Keys and Sewaren 7, partially offset by lower average realized prices in the PJM region, partially offset by lower
an increase of $41 million due to higher volumes of electricity sold under wholesale load contracts primarily in the NEPJM region,
an increase of $11 million due to higher net MTM gains in 2018 as compared to 2017. Of this amount, $132 million was due to higher gains on positions reclassified to realized upon settlement this year as compared to last year, partially offset with a $121 million decrease due to changes in forward prices, and
a net increase of $8 million in capacity revenues due primarily to an increaseincreases in cleared capacity and auction prices in the NEPJM region.
Gas Supply Revenuesincreased $30 million due primarily to
an increase of $31 million in sales under the BGSS contract, of which $43 million was due to an increase in sales volumes resulting from colder average temperatures during the 2018 heating season, partially offset by $12 million due to lower average sales prices, and
an increase of $15 million related to sales to third parties, of which $35 million was due to an increase in sales volumes, partially offset by $20 million due to lower average sales prices,
partially offset by a decrease of $16 million due to net MTM losses in 2018 compared to net gains in 2017.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $41$101 million due to
Generation costs increased $75 million due primarily to higher fuel costs reflecting utilization of higher volumes of gas and higher natural gas prices in the PJM region. Higher gas volumes were primarily driven by the commencement of commercial operations of Keys and Sewaren 7.
Gas costs increased $26 million due mainly to an increase in sales to third parties due primarily to higher average gas costs coupled with an increase in volumes sold.
Depreciation and Amortization increased$18 milliondue primarily to
an $11 million increase due to Keys and Sewaren 7 fossil stations placed into service, and

Table of Contents

a $6 million increase due primarily to a higher nuclear asset base from increased capitalized asset retirement costs.
Net Gains (Losses) on Trust Investments increased $25 million due primarily to the inclusion in 2018 of $34 million of net unrealized gains on equity investments in the NDT Fund in accordance with new accounting guidance and a $5 million decrease in other-than-temporary impairments of equity securities in the NDT Fund, offset by a $14 million decrease in net realized gains on NDT Fund investments.
Interest Expense increased $17 million due primarily to $11 million in lower interest capitalized from Keys and Sewaren 7 fossil stations being placed into service, partially offset by higher interest capitalized for the construction of BH5 and a $7 million increase due to a June 2018 debt issuance.
Income Tax Expense (Benefit) decreased $3$73 million due primarily to lower pre-tax income resulting in $34 million of the decrease, the remeasurement of the reserve for uncertain tax positions in connection with the nuclear carryback claim and 2011 and 2012 federal tax audit of $28 million and the decrease in the federal statutory income tax rate from 35% in 2017 to 21% in 2018 of $19 million, partially offset by the New Jersey surtax of $7 million.
Nine Months Ended September 30, 2018 as Compared to 2017
Operating Revenues increased $5 million due primarily to changes in generation and gas supply revenues.
Gas Supply Revenuesincreased $54 million due primarily to
an increase of $40 million related to sales to third parties due primarily to an increase in sales volumes, and
a net increase of $31 million in sales under the BGSS contract, of which $43 million was due to an increase in sales volumes due to colder average temperatures during the 2018 heating season, partially offset by $12 million due to lower average sales prices,
partially offset by a decrease of $17 million due to net MTM losses in 2018 compared to net gains in 2017.
Generation Revenues decreased $48 million due primarily to
a net decrease of $24 million primarily due to a decrease in energy purchase volumes in the NE region to serve load obligations, and
a decrease of $11$73 million due to higher net MTM gainslosses in 2018 as compared to net losses in 2017. Of this amount, $14there was a $214 million wasdecrease due to changes in forward prices, partially offset by an increase of $3$141 million due to higher lossesin gains on positions reclassified to realized upon settlement this year as compared to last year,
a decrease of $43 million in electricity sold under our BGS contracts due primarily to lower prices, and
a net decrease of $39 million in energy sales due primarily to lower average realized prices in the PJM region partially offset by higher net volumes in PJM, which includes the commencement of commercial operations of Keys and Sewaren 7, and higher average prices in the New England (NE) and New York (NY) regions,
partially offset by a net increase of $77 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM region, partially offset by lower volumes of electricity sold under wholesale load contracts in the NE region,
a net increase of $16 million in capacity revenues due primarily to increases in cleared capacity and auction prices in the PJM and NE regions, and
a net increase of $7 million due to higher sales related to new solar projects.

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 $142 million due to
Generation costs increased $72 million due primarily to
higher fuel costs of $31$109 million reflecting utilization of higher volumes of gas and oil in the PJM region, due primarily to the commencement of commercial operations of Keys and Sewaren 7, coupled with higher prices of natural gas in the PJM and NY regionregions and higher coal costs in the PJM and NE regions. This was regions,
partially offset by utilizationa net decrease of lower gas volumes$24 million due primarily to a decrease in the PJM region.volume of energy purchased in the NE region to serve load obligations, and
a decrease of $10 million due to MTM gains in 2018 as compared to losses in 2017 due to changes in forward prices.

Table of Contents

Gas costs increased $44$70 million due mainly to
ana net increase of $38 million related to sales under the BGSS contract due primarily to increased volumes sold resulting fromdue to colder average temperatures during the 2018 heating season, partially offset withby lower average gas costs, and
ana net increase of $6$32 million related to sales to third parties due primarily to an increase in volumes sold,the volume of gas purchased, partially offset by lower average gas costs.
Operation and Maintenance increased $26$28 million due primarily to
a $21 million net increase related to our nuclear plants, due primarily to planned outage costs at our 100%-owned Hope Creek nuclear plant in 2018 as compared to planned outage costs incurred in 2017 for our 57%-owned Salem Unit 2, and
an $8 million net increase at our fossil plants, due primarily to higher planned outage costs in 2018.2.
Depreciation and Amortization decreased $949931 million due primarily to
$964 million of higher depreciation in 2017 for Hudson and Mercer due to the early retirement of those units,

Table of Contents

partially offset by a $10$15 million increase in 2018 due primarily to a higher nuclear asset base primarily from increased capitalized asset retirement costs.costs, and
a $14 million increase due to Keys and Sewaren 7 fossil stations placed into service.
Net Gains (Losses) on Trust Investments decreased $57$32 million due primarily to a $22 million decrease in net realized gains on NDT Fund investments and the inclusion in 2018 of $50$16 million of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance, and an $8partially offset by a $9 million decrease in net realized gains onother-than-temporary impairments of equity securities in the NDT Fund investments.Fund.
Interest Expense decreased $11increased $6 million due primarily to higher interesta $9 million increase due to a June 2018 debt issuance, partially offset by a decrease of $2 million in capitalized for the construction of the BH5, Sewaren 7 and Keys fossil stations.interest.
Income Tax Expense (Benefit) increased $280$207 million 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 to 21% in 2018.2018 and the remeasurement of the reserve for uncertain tax positions in connection with the nuclear carryback claim and the 2011 and 2012 federal tax audit.

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 sixnine months ended JuneSeptember 30, 2018, our operating cash flow decreased $122241 million as compared to the same period in 2017. The net changes werechange was due primarily due to tax refunds in 2017 at Energy Holdings combined withthe net changeschange from our subsidiariesPower as discussed below.
PSE&G
PSE&G’s operating cash flow decreasedincreased $75 million from $7691,392 million to $7621,397 million for the sixnine months ended JuneSeptember 30, 2018, as compared to the same period in 2017, due primarily to a tax refund in 2017, partially offset by an increase of $87$86 million due to a change in regulatory deferrals, higher earnings, and an increase of $48 million due primarily due to a reduction in unbilled revenues resulting from lower prices and volumes in 2018, an increase of $66 million due tooffset by a changetax refund in regulatory deferrals, and higher earnings in 2018.2017.
Power
Power’s operating cash flow decreased $63244 million from $9321,249 million to $8691,005 million for the sixnine months ended JuneSeptember 30, 2018, as compared to the same period in 2017, due to lower earnings resulting from lower wholesale energy sales in the PJM region, an increase of $76 million in payments to counterparties and an increase in margin deposit requirements of $35$141 million, and higher generation costs, offset by lower tax refundspayments in 2018 compared to tax payments in 2017, and a $48$23 million increase from net collections of counterparty receivables.receivables, and a decrease of $10 million in payments to counterparties.
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.

Table of Contents

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.
Our total credit facilities and available liquidity as of JuneSeptember 30, 2018 were as follows:
         
 Company/Facility As of June 30, 2018 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,500
 $88
 $1,412
 
 PSE&G 600
 211
 389
 
 Power 2,100
 202
 1,898
 
 Total $4,200
 $501
 $3,699
 
         

Table of Contents

         
 Company/Facility As of September 30, 2018 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,500
 $393
 $1,107
 
 PSE&G 600
 56
 544
 
 Power 2,200
 213
 1,987
 
 Total $4,300
 $662
 $3,638
 
         
As of JuneSeptember 30, 2018, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power losing its investment grade credit rating from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s 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 $828$888 million and $848 million as of JuneSeptember 30, 2018 and December 31, 2017, respectively.
For additional information, see Item 1. Note 11. Debt and Credit Facilities.
Long-Term Debt Financing
During the next twelve months, PSEG has a $700 million floating rate term loan maturing in June 2019, PSE&G has $350 million of 2.30% Medium-Term Notes maturing in September 2018 and $250 million of 1.80% Medium-Term Notes maturing in June 2019 and $250 million of 2.00% Medium-Term Notes maturing in August 2019 and Power has $250 million of 2.45% Senior Notes maturing in November 2018.
For additional information see Item 1. Note 11. Debt and Credit Facilities.
Common Stock Dividends
On AprilJuly 17, 2018, our Board of Directors approved a $0.45 dividend per share of common stock for the second quarter of 2018. On July 17, 2018, our Board of Directors declared a $0.45 dividend per share of common stock for the third quarter of 2018. These declarations reflect an indicative annual dividend rate of $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. Note17. Earnings Per Share (EPS) and Dividends.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

Table of Contents

       
   Moody’s (A) S&P (B) 
 PSEG     
 Outlook Stable Stable 
 Senior Notes Baa1 BBB 
 Commercial Paper P2 A2 
 PSE&G     
 Outlook Stable Stable 
 Mortgage Bonds Aa3 A 
 Commercial Paper P1 A2 
 Power     
 Outlook Stable Stable 
 Senior Notes Baa1 BBB+ 
       
(A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.
(B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

Table of Contents

CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures as compared to amounts disclosed in our 2017 Form 10-K.10-K other than the inclusion of GSMP II, which was approved in May 2018. See Executive Overview of 2018 and Future Outlook for additional information.
PSE&G
During the sixnine months ended JuneSeptember 30, 2018, PSE&G made capital expenditures of $1,458$2,228 million, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $84$121 million, which are included in operating cash flows.
Power
During the sixnine months ended JuneSeptember 30, 2018, Power made capital expenditures of $521$679 million, excluding $26121 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.


Table of Contents


ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.
Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.
Commodity Contracts
The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.
Value-at-Risk (VaR) Models
VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.
MTM VaR consists of MTM derivatives that are economic hedges. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities.
The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.
From AprilJuly through JuneSeptember 2018, MTM VaR was relatively stable between a low of $7$6 million and a high of $9$11 million at the 95% confidence level. The range of VaR was narrower for the three months ended JuneSeptember 30, 2018 as compared with the year ended December 31, 2017.

Table of Contents

       
   MTM VaR 
   Three Months Ended June 30, 2018 Year Ended December 31, 2017 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $8
 $39
 
 Average for the Period $8
 $10
 
 High $9
 $39
 
 Low $7
 $5
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $13
 $60
 
 Average for the Period $12
 $15
 
 High $15
 $60
 
 Low $10
 $8
 
       
       
   MTM VaR 
   Three Months Ended September 30, 2018 Year Ended December 31, 2017 
   Millions 
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $10
 $39
 
 Average for the Period $7
 $10
 
 High $11
 $39
 
 Low $6
 $5
 
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $16
 $60
 
 Average for the Period $11
 $15
 
 High $17
 $60
 
 Low $9
 $8
 
       
See Item 1. Note 12. Financial Risk Management Activities for a discussion of credit risk.


Table of Contents

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 secondthird quarter of 2018 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 information regarding material legal proceedings, including updates to information reported in Item 3 of Part I of the 2017 Annual Report on Form 10-K, see Part I, Item 1. Note 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 2017 Annual Report on Form 10-K, and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, which describedescribes 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. There have been no material changes to the risk factors set forth in the above-referenced filings as of JuneSeptember 30, 2018.

Table of Contents


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. There were no common share repurchases in the open market during the secondthird quarter of 2018.

ITEM 5. OTHER INFORMATION
Certain information reported in the 2017 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 2017 Annual Report on Form 10-K and the Quarterly ReportReports on Form 10-Q for the quarterquarters ended March 31, 2018 and June 30, 2018. References are to the related pages on the Form 10-K and 10-Q as printed and distributed.

Table of Contents

Federal Regulation
Energy Clearing Prices
December 31, 2017 Form 10-K page 16 and March 31, 2018 Form 10-Q on page 80. 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. The PJM Board has directed PJM staff to work with stakeholders to implement a series of price formation reforms, including a 30-minute reserve product in real-time, more dynamic reserve requirements to better capture operator actions taken to maintain reliability and improvement of the curves used to price reserves during reserve shortage conditions. The PJM Board letter directs PJM staff to submit some of these reforms for FERC’s approval so that they can be implemented in early 2019. If placed into effect, these reforms should improve energy and reserve prices by ensuring that when operators commit resources to ensure reliability, the commitments are reflected in market clearing prices. We cannot predict the outcome of this matter.
Capacity Market Issues—PJM
December 31, 2017 Form 10-K page 16, and March 31, 2018 Form 10-Q on page 80.80 and June 30, 2018 Form 10-Q on page 88. 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 other option would be to extend the existing MOPR to units that are receiving subsidies. In June 2018, FERC issued an order finding that PJM’s current capacity market is unjust and unreasonable because it allows resources supported by out-of-market payments to suppress capacity prices. FERCand established a new proceeding to address an alternative approach in which PJM would: (1) modify PJM’s MOPRMinimum Offer Price Rule so that it would apply to new and existing resources that receive out-of-market payments, regardless of resource type; and (2) establish an option that would allow, on a resource-specific basis, resources receiving out-of-market support to be removed from the PJM capacity market, along with a commensurate amount of load, for some period of time. In response, PJM proposed a two-settlement auction mechanism in which the first stage would set the resource commitment and the second stage would establish the clearing price. During the second stage, the resources receiving out-of-market support would be removed from the auction before the price is established. We generally support PJM’s proposal, but have some concerns about aspects of it that could reduce payments to nuclear units that receive out-of-market support payments. FERC’s potential action in this proceeding could cause nuclear units that receive ZEC payments to lose capacity market revenues if states do not take steps to address the potential loss of capacity revenues. In addition, depending on the outcome of this matter, our fossil generating stations could be adversely impacted. We cannot predict the outcome of this matter.
Transmission Regulation—-Transmission Policy Developments
March 31, 2018 Form 10-Q on page 80. In February 2018, FERC issued an order finding that the transmission planning procedures used by the PJM transmission owners, a group that includes 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 governing documents are unjust and unreasonable. FERC directed PJM and the PJM transmission owners to submit certain revisions to the manner in which the stakeholder process for supplemental projects is conducted. PSE&G participated in the PJM transmission owners’ compliance filing, which was approved by FERC.
Transmission Regulation—Return on Equity (ROE)
In October 2018, FERC issued an order establishing a new framework for determining whether a company’s ROE is unjust and unreasonable. The order was issued in a proceeding that was remanded to FERC from D.C. Circuit concerning the establishment of the New England Transmission Owners’ ROE. FERC’s order proposes a new method for evaluating whether an existing ROE remains just and reasonable. Under FERC’s approach, FERC will determine a composite zone of reasonableness based on the results of three financial models, and if the targeted utility’s existing ROE falls within the range of just and reasonable ROEs for its risk profile, FERC will dismiss the complaint. However, if FERC determines that an existing ROE is unjust and unreasonable, it proposes to rely on four financial models: a discounted cash flow, a risk premium analysis, a capital-asset pricing model analysis and an expected earnings analysis. We are still analyzing the potential impact of these methodologies and cannot predict the outcome of this proceeding.
Environmental Matters
Climate Change—C02 Regulation under the Clean Air Act
December 31, 2017 Form 10-K on page 19.22. In June 2016,August 2018, the EPA released the proposed Affordable Clean Energy (ACE) rule as a replacement for the EPA’s Clean Power Plan (CPP). In 2017, The EPA Administrator signed a proposed settlement was filed with FERC for a matter remandedrepeal of the CPP which had established state-specific greenhouse gas emissions targets on the basis that the CPP exceeded the EPA’s statutory authority by considering measures that were beyond the control of the owners of existing fossil fuel-fired electric generating units. The proposed ACE rule gives states great flexibility to evaluate specific heat rate improvement technologies and practices to be applied at coal-fired electric generating units. States have three years from the federal appellate court concerningdate of finalization to submit a plan that establishes a standard of performance that reflects the appropriate cost allocation for certain 500 kV projects in PJM that either have been built or are indegree of emission limitation through the processapplication of being built. In May 2018, FERC approved the settlement which will result in increased annual cost allocations to customers in the PSE&G transmission zone. Under this settlement, Power, as a BGS supplier will become obligated to pay amounts previously paid by other PJM transmission customers. However, we do not believe that the anticipated level of any such potential payments would have a material effect on Power’s financial statements. We believe that there is a mechanism in place under the BGS contract for the pass-through of increases in transmission charges.
Transmission Regulation—Con Edison-PJM Wheel
December 31, 2017 Form 10-K page 19. Effective May 1, 2017, a wheeling arrangement which enabled Con Edison to move 1,000 MW of power from southeastern New York across the PSE&G system for delivery into New York City expired. Amounts that would have been recovered from Con Edison had this arrangement continued are now being recovered from other customers. PSE&G believes the current planning assumptions used by PJM are consistent with sound transmission planning principles. However, PSE&G disagrees with the absence of a mechanism to assign PJM transmission upgrade costs to Con

Table of Contents

Edison that reflect Con Edison’s reliance on the PJM transmission grid. PSE&Gheat rate improvement technologies and the BPU jointly filed a rehearing application at FERC seeking reversal of a determination not to create such a mechanism in connection with a PJM/NYISO joint operating agreement. In addition, in December 2017, the BPU filed a complaint at FERC against Con Edison, PJM, NYISO, New York Power Authority, Linden VFT, LLC and Hudson Transmission Partners, LLC petitioning FERC to create such a cost allocation mechanism that would assign PJM costs to New York, which complaint was denied. The BPU has sought rehearing of FERC’s denial of its complaint.practices. We cannot predictestimate the outcomeimpact of this matter.
State Regulation
Energy Efficiency Initiatives
In May 2018, the New Jersey governor signed legislation that requires the state’s electric and gas utilities to implement energy efficiency programs that are expected to achieve energy savings targets for electric and gas usage within five yearsaction on our business or results of the utility’s implementation of its BPU-approved energy efficiency programs. To meet these savings targets, energy usage reductions and peak demand reductions that result from utility and non-utility based programs and investments (including building code changes) will be counted. The specific energy savings target for each public electric and gas utility will be determined from an energy efficiency study to be completed within a year from enactment of the legislation. The legislation requires utilities to make annualoperations.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. The BPU is required to adopt rules to implement the legislation within one year of enactment.
New Jersey Energy Master Plan (EMP)
New Jersey law requires that an EMP be developed every three years. While not having the force of law, the EMP provides an overview of energy policy in New Jersey. The EMP was last revised in December 2015.
In May 2018,the New Jersey governor signed an executive order requiring the BPU and other New Jersey executive branch agencies to prepare a new EMP by June 1, 2019. The new EMP will, among other issues: focus on New Jersey converting to 100% clean energy sources by January 1, 2050; incorporate New Jersey’s offshore wind development goals; include provisions to guide the continued development of solar energy, including community solar; make recommendations to bolster energy storage in New Jersey; and explore methods to incentivize the use of clean, efficient energy and electric technology alternatives in New Jersey’s transportation sector and at its ports.
With regard to offshore wind, the executive order directed the BPU and other state agencies to begin a process to achieve 3,500 MWs of offshore wind energy generation by the year 2030. In response, the BPU issued an order directing staff to establish a rulemaking for an offshore wind renewable energy certificate (OREC) funding mechanism and rules for the solicitation of 1,100 MWs of offshore wind capacity. We are analyzing the implications to our business.
BPU 2018 Storm Investigation
In July 2018, the BPU accepted the findings of an investigative report concerning a series of storms that hit New Jersey in March 2018 causing wide-spread infrastructure damage and power outages. The BPU implemented certain recommendations  that it deemed essential to facilitate the continued provision of safe, proper and adequate service, to help mitigate future outages, and to help develop more effective responses and coordination of resources. These requirements supplement prior requirements set forth post-Hurricanes Irene and Superstorm Sandy. PSE&G is reviewing the BPU’s report and its recommendations for improving storm response protocols.


Table of Contents

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 Plus Preferred Securities Dividend Requirements
Exhibit 31:
 
Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:
 
Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:
 
Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:
 
Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS: XBRL Instance Document
Exhibit 101.SCH: XBRL Taxonomy Extension Schema
Exhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF: XBRL Taxonomy Extension Definition Document
   
b. PSE&G:  
Exhibit 12.1:
 
Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.2:
 
Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:
 
Certification by 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




Table of Contents

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: August 1,October 30, 2018

SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)
  
By:
/S/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: August 1,October 30, 2018

SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
PSEG POWER LLC
(Registrant)
  
By:
/S/ STUART J. BLACK
 
Stuart J. Black
Vice President and Controller
(Principal Accounting Officer)
Date: August 1,October 30, 2018


91