~~table~~Table of ~~contents~~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 and Basis of Presentation	16
	Note 2. Recent Accounting Standards	16
	Note 3. Variable Interest Entities (VIEs)	1718
	Note 4. Rate Filings	18
	Note 5. Financing Receivables	19
	Note 6. Available-for-Sale Securities	21
	Note 7. Pension and Other Postretirement Benefits (OPEB)	2726
	Note 8. Commitments and Contingent Liabilities	28
	Note 9. ~~Changes in Capitalization~~Debt and Credit Facilities	35
	Note 10. Financial Risk Management Activities	3536
	Note 11. Fair Value Measurements	4243
	Note 12. Other Income and Deductions	5051
	Note 13. Income Taxes	5152
	Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax	5253
	Note 15. Earnings Per Share (EPS) and Dividends	5657
	Note 16. Financial Information by Business Segments	5758
	Note 17. Related-Party Transactions	5859
	Note 18. Guarantees of Debt	6061
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6364
	Executive Overview of ~~2015~~2016 and Future Outlook	6364
	Results of Operations	6870
	Liquidity and Capital Resources	7375
	Capital Requirements	7577
	Accounting Matters	7577
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	7678
Item 4.	Controls and Procedures	7779

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	7779
Item 1A.	Risk Factors	7779
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	7779
Item 5.	Other Information	7779
Item 6.	Exhibits	8183
	Signatures	8284

~~table~~Table of ~~contents~~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 and available on our website: http://www.pseg.com. These factors include, but are not limited to:

adverse changes in the demand for or ~~the price~~ongoing low pricing of the capacity and energy that we sell into wholesale electricity markets,

adverse changes in energy industry law, policies and regulations, including market structures and transmission planning,

any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators, including prudency reviews, disallowances and changes in authorized returns,

any deterioration in our credit quality or the credit quality of our counterparties,

changes in federal and state environmental regulations and enforcement that could increase our costs or limit our operations,

adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry,

changes in nuclear regulation and/or general developments in the nuclear power industry, including various impacts from any accidents or incidents experienced at our facilities or by others in the industry, that could limit operations or increase the cost of our nuclear generating units,

actions or activities at one of our nuclear units located on a multi-unit site that might adversely affect our ability to continue to operate that unit or other units located at the same site,

any inability to manage our energy obligations, available supply and risks,

~~adverse outcomes of any legal, regulatory~~delays or ~~other proceeding, settlement, investigation or claim applicable to us and/~~unforeseen cost escalations in our construction and development activities, or the ~~energy industry,~~

~~any deterioration in our credit quality or~~inability to recover the ~~credit quality~~carrying amount of our ~~counterparties,~~assets,

availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs,

increases in competition in energy supply markets as well as for transmission projects,

changes in ~~the cost of, or interruption~~technology, such as distributed generation, storage and micro grids, and greater reliance on these technologies,

changes in ~~the supply of, fuel~~customer behaviors, including increases in energy efficiency, net-metering and ~~other commodities necessary to the operation~~demand response,

adverse performance of our ~~generating units,~~

~~delays~~decommissioning and defined benefit plan trust fund investments and changes in ~~receipt of necessary permits and approvals for our construction and development activities,~~

~~delays or unforeseen cost escalations in our construction and development activities,~~

~~any inability to achieve, or continue to sustain, our expected levels of operating performance,~~funding requirements,

any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers, and any inability to obtain sufficient insurance coverage or recover proceeds of insurance with respect to such events,

acts of terrorism, cybersecurity attacks or intrusions that could adversely impact our businesses,

~~increases~~delays in ~~competition~~receipt of necessary permits and approvals for our construction and development activities,

any inability to achieve, or continue to sustain, our expected levels of operating performance,

changes in ~~energy~~the cost of, or interruption in the supply ~~markets as well as for transmission projects,~~of, fuel and other commodities necessary to the operation of our generating units,

~~any~~an extended economic recession,

an inability to realize anticipated tax benefits or retain tax credits,

challenges associated with recruitment and/or retention of a qualified workforce,

~~adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in funding requirements,~~

~~changes in technology, such as distributed generation and micro grids, and greater reliance on these technologies,~~ and

changes in ~~customer behaviors, including increases in energy efficiency, net-metering~~the credit quality and ~~demand response.~~

the ability of lessees to meet their obligations under our domestic leveraged leases.

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected

Table of Contents

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

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

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FILING FORMAT

~~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,
2015 2014 2015 2014
OPERATING REVENUES $ 2,314
$ 2,249
$ 5,449
$ 5,472

OPERATING EXPENSES
Energy Costs 668
789
1,762
2,145

Operation and Maintenance 761
800
1,424
1,656

Depreciation and Amortization 317
295
647
601

Total Operating Expenses 1,746
1,884
3,833
4,402

OPERATING INCOME 568
365
1,616
1,070

Income from Equity Method Investments 4
3
7
7

Other Income 76
62
124
110

Other Deductions (10 ) (10 ) (22 ) (22 )
Other-Than-Temporary Impairments (10 ) (2 ) (15 ) (4 )
Interest Expense (97 ) (94 ) (195 ) (191 )
INCOME BEFORE INCOME TAXES 531
324
1,515
970

Income Tax Expense (186 ) (112 ) (584 ) (372 )
NET INCOME $ 345
$ 212
$ 931
$ 598

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC 506
506
506
506

DILUTED 508
508
508
508

NET INCOME PER SHARE:
BASIC $ 0.68
$ 0.42
$ 1.84
$ 1.18

DILUTED $ 0.68
$ 0.42
$ 1.83
$ 1.18

DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.39
$ 0.37
$ 0.78
$ 0.74

~~See Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED~~

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~Millions~~

~~(Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
NET INCOME $ 345
$ 212
$ 931
$ 598

Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $15, $(9), $2 and $(12) for the three and six months ended 2015 and 2014, respectively (15 ) 11
(1 ) 13

Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $7, and $(2) for the three and six months ended 2015 and 2014, respectively —
1
(9 ) 3

Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(6), $(1), $(12) and $(3) for three and six months ended 2015 and 2014, respectively 8
2
16
6

Other Comprehensive Income (Loss), net of tax (7 ) 14
6
22

COMPREHENSIVE INCOME $ 338
$ 226
$ 937
$ 620

~~See Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~Millions~~

~~(Unaudited)~~

June 30,
2015 December 31,
2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 597
$ 402

Accounts Receivable, net of allowances of $60 and $52 in 2015 and 2014, respectively 1,126
1,254

Tax Receivable 23
211

Unbilled Revenues 247
284

Fuel 358
538

Materials and Supplies, net 466
484

Prepayments 272
108

Derivative Contracts 155
240

Deferred Income Taxes —
11

Regulatory Assets 235
323

Regulatory Assets of Variable Interest Entities (VIEs) 123
249

Other 25
15

Total Current Assets 3,627
4,119

PROPERTY, PLANT AND EQUIPMENT 33,603
32,196

Less: Accumulated Depreciation and Amortization (8,796 ) (8,607 )
Net Property, Plant and Equipment 24,807
23,589

NONCURRENT ASSETS
Regulatory Assets 3,170
3,192

Long-Term Investments 1,273
1,307

Nuclear Decommissioning Trust (NDT) Fund 1,792
1,780

Long-Term Tax Receivable 165
64

Long-Term Receivable of VIE 602
580

Other Special Funds 234
212

Goodwill 16
16

Other Intangibles 101
84

Derivative Contracts 107
77

Restricted Cash of VIEs 25
24

Other 293
289

Total Noncurrent Assets 7,778
7,625

TOTAL ASSETS $ 36,212
$ 35,333

~~See Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~Millions~~

~~(Unaudited)~~

June 30,
2015 December 31,
2014
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 491
$ 624

Securitization Debt of VIEs Due Within One Year 134
259

Accounts Payable 1,156
1,178

Derivative Contracts 72
132

Accrued Interest 96
95

Accrued Taxes 148
21

Deferred Income Taxes 14
173

Clean Energy Program 200
142

Obligation to Return Cash Collateral 128
121

Regulatory Liabilities 143
186

Other 525
547

Total Current Liabilities 3,107
3,478

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC) 7,578
7,303

Regulatory Liabilities 176
258

Regulatory Liabilities of VIEs 47
39

Asset Retirement Obligations 765
743

Other Postretirement Benefit (OPEB) Costs 1,254
1,277

OPEB Costs of Servco 471
452

Accrued Pension Costs 392
440

Accrued Pension Costs of Servco 128
126

Clean Energy Program 27
—

Environmental Costs 421
417

Derivative Contracts 24
33

Long-Term Accrued Taxes 282
208

Other 143
112

Total Noncurrent Liabilities 11,708
11,408

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

CAPITALIZATION

LONG-TERM DEBT
Total Long-Term Debt 8,689
8,261

STOCKHOLDERS’ EQUITY

Common Stock, no par, authorized 1,000,000,000 shares; issued, 2015 and 2014—533,556,660 shares 4,883
4,876

Treasury Stock, at cost, 2015— 27,743,506 shares; 2014— 27,720,068 shares (663 ) (635 )
Retained Earnings 8,764
8,227

Accumulated Other Comprehensive Loss (277 ) (283 )
Total Common Stockholders’ Equity 12,707
12,185

Noncontrolling Interest 1
1

Total Stockholders’ Equity 12,708
12,186

Total Capitalization 21,397
20,447

TOTAL LIABILITIES AND CAPITALIZATION $ 36,212
$ 35,333

~~See Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~Millions~~

~~(Unaudited)~~

Six Months Ended
June 30,
2015 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 931
$ 598

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 647
601

Amortization of Nuclear Fuel 106
98

Provision for Deferred Income Taxes (Other than Leases) and ITC 170
70

Non-Cash Employee Benefit Plan Costs 81
24

Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes (22 ) (44 )
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives (9 ) 297

Change in Accrued Storm Costs 15
(3 )
Net Change in Other Regulatory Assets and Liabilities (53 ) 192

Cost of Removal (58 ) (50 )
Net Realized (Gains) Losses and (Income) Expense from NDT Fund (21 ) (59 )
Net Change in Certain Current Assets and Liabilities:
          Tax Receivable 188
9

          Accrued Taxes 71
54

          Margin Deposit 69
(234 )
          Other Current Assets and Liabilities 98
(116 )
Employee Benefit Plan Funding and Related Payments (67 ) (50 )
Other 88
61

Net Cash Provided By (Used In) Operating Activities 2,234
1,448

CASH FLOWS FROM INVESTING ACTIVITIES

Additions to Property, Plant and Equipment (1,743 ) (1,229 )
Proceeds from Sales of Capital Leases and Investments 5
11

Proceeds from Sales of Available-for-Sale Securities 885
584

Investments in Available-for-Sale Securities (918 ) (599 )
Other (2 ) (49 )
Net Cash Provided By (Used In) Investing Activities (1,773 ) (1,282 )
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans —
(60 )
Issuance of Long-Term Debt 600
500

Redemption of Long-Term Debt (300 ) —

Redemption of Securitization Debt (125 ) (111 )
Cash Dividends Paid on Common Stock (394 ) (374 )
Other (47 ) (44 )
Net Cash Provided By (Used In) Financing Activities (266 ) (89 )
Net Increase (Decrease) in Cash and Cash Equivalents 195
77

Cash and Cash Equivalents at Beginning of Period 402
493

Cash and Cash Equivalents at End of Period $ 597
$ 570

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 184
$ 296

Interest Paid, Net of Amounts Capitalized $ 195
$ 192

Accrued Property, Plant and Equipment Expenditures $ 324
$ 240

~~See Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ELECTRIC AND GAS COMPANY~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~Millions~~

~~(Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
OPERATING REVENUES $ 1,466
$ 1,435
$ 3,468
$ 3,580

OPERATING EXPENSES
Energy Costs 544
565
1,436
1,610

Operation and Maintenance 368
362
780
824

Depreciation and Amortization 234
217
481
444

Total Operating Expenses 1,146
1,144
2,697
2,878

OPERATING INCOME 320
291
771
702

Other Income 19
14
37
28

Other Deductions (1 ) (1 ) (2 ) (1 )
Interest Expense (67 ) (67 ) (136 ) (135 )
INCOME BEFORE INCOME TAXES 271
237
670
594

Income Tax Expense (104 ) (86 ) (261 ) (229 )
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 167
$ 151
$ 409
$ 365

~~See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ELECTRIC AND GAS COMPANY~~

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~Millions~~

~~(Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
NET INCOME $ 167
$ 151
$ 409
$ 365

Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 for the three and six months ended 2015 and 2014, respectively (1 ) —
(1 ) —

COMPREHENSIVE INCOME $ 166
$ 151
$ 408
$ 365

~~See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ELECTRIC AND GAS COMPANY~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~Millions~~

~~(Unaudited)~~

June 30,
2015 December 31,
2014
ASSETS
CURRENT ASSETS

Cash and Cash Equivalents $ 166
$ 310

Accounts Receivable, net of allowances of $60 and $52 in 2015 and 2014, respectively 848
864

Accounts Receivable-Affiliated Companies 52
274

Unbilled Revenues 247
284

Materials and Supplies 143
133

Prepayments 204
42

Regulatory Assets 235
323

Regulatory Assets of VIEs 123
249

Derivative Contracts 5
18

Deferred Income Taxes —
24

Other 7
7

Total Current Assets 2,030
2,528

PROPERTY, PLANT AND EQUIPMENT 22,274
21,103

Less: Accumulated Depreciation and Amortization (5,336 ) (5,183 )
Net Property, Plant and Equipment 16,938
15,920

NONCURRENT ASSETS
Regulatory Assets 3,170
3,192

Long-Term Investments 346
348

Other Special Funds 54
53

Derivative Contracts —
8

Restricted Cash of VIEs 25
24

Other 158
150

Total Noncurrent Assets 3,753
3,775

TOTAL ASSETS $ 22,721
$ 22,223

~~See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ELECTRIC AND GAS COMPANY~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~Millions~~

~~(Unaudited)~~

June 30,
2015 December 31,
2014
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 171
$ 300

Securitization Debt of VIEs Due Within One Year 134
259

Accounts Payable 612
574

Accounts Payable—Affiliated Companies 215
379

Accrued Interest 68
68

Clean Energy Program 200
142

Deferred Income Taxes 13
165

Obligation to Return Cash Collateral 128
121

Regulatory Liabilities 143
186

Other 358
381

Total Current Liabilities 2,042
2,575

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 4,810
4,575

Other Postretirement Benefit (OPEB) Costs 936
967

Accrued Pension Costs 144
173

Regulatory Liabilities 176
258

Regulatory Liabilities of VIEs 47
39

Clean Energy Program 27
—

Environmental Costs 370
364

Asset Retirement Obligations 299
290

Long-Term Accrued Taxes 161
116

Other 74
67

Total Noncurrent Liabilities 7,044
6,849

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

CAPITALIZATION
LONG-TERM DEBT

Total Long-Term Debt 6,440
6,012

STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2015 and 2014—132,450,344 shares 892
892

Contributed Capital 695
695

Basis Adjustment 986
986

Retained Earnings 4,621
4,212

Accumulated Other Comprehensive Income 1
2

Total Stockholder’s Equity 7,195
6,787

Total Capitalization 13,635
12,799

TOTAL LIABILITIES AND CAPITALIZATION $ 22,721
$ 22,223

~~See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.~~

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~~PUBLIC SERVICE ELECTRIC AND GAS COMPANY~~

~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~Millions~~

~~(Unaudited)~~

Six Months Ended
June 30,
2015 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 409
$ 365

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 481
444

Provision for Deferred Income Taxes and ITC 79
73

Non-Cash Employee Benefit Plan Costs 48
13

Cost of Removal (58 ) (50 )
Change in Accrued Storm Costs 15
(3 )
Net Change in Other Regulatory Assets and Liabilities (53 ) 192

Net Change in Certain Current Assets and Liabilities:

Accounts Receivable and Unbilled Revenues 53
44

Materials and Supplies (10 ) (11 )
Prepayments (162 ) (162 )
Accounts Payable 48
16

Accounts Receivable/Payable—Affiliated Companies, net 154
(98 )
Other Current Assets and Liabilities (27 ) (31 )
Employee Benefit Plan Funding and Related Payments (55 ) (44 )
Other (13 ) (11 )
Net Cash Provided By (Used In) Operating Activities 909
737

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (1,230 ) (996 )
Proceeds from Sales of Available-for-Sale Securities 12
8

Investments in Available-for-Sale Securities (14 ) (6 )
Other 12
(1 )
Net Cash Provided By (Used In) Investing Activities (1,220 ) (995 )
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt —
(60 )
Issuance of Long-Term Debt 600
500

Redemption of Long-Term Debt (300 ) —

Redemption of Securitization Debt (125 ) (111 )
Contributed Capital —
175

Other (8 ) (7 )
Net Cash Provided By (Used In) Financing Activities 167
497

Net Increase (Decrease) In Cash and Cash Equivalents (144 ) 239

Cash and Cash Equivalents at Beginning of Period 310
18

Cash and Cash Equivalents at End of Period $ 166
$ 257

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ (74 ) $ 102

Interest Paid, Net of Amounts Capitalized $ 131
$ 127

Accrued Property, Plant and Equipment Expenditures $ 282
$ 192

~~See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.~~

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~~PSEG POWER LLC~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~

~~Millions~~

~~(Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
OPERATING REVENUES $ 1,025
$ 986
$ 2,750
$ 2,686

OPERATING EXPENSES
Energy Costs 409
520
1,302
1,564

Operation and Maintenance 313
327
485
629

Depreciation and Amortization 75
72
151
144

Total Operating Expenses 797
919
1,938
2,337

OPERATING INCOME 228
67
812
349

Income from Equity Method Investments 5
3
8
7

Other Income 55
46
84
79

Other Deductions (7 ) (9 ) (18 ) (19 )
Other-Than-Temporary Impairments (10 ) (2 ) (15 ) (4 )
Interest Expense (33 ) (29 ) (64 ) (61 )
INCOME BEFORE INCOME TAXES 238
76
807
351

Income Tax Expense (72 ) (22 ) (306 ) (133 )
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 166
$ 54
$ 501
$ 218

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

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~~PSEG POWER LLC~~

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~Millions~~

~~(Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
NET INCOME $ 166
$ 54
$ 501
$ 218

Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $14, $(9), $1 and $(11) for the three and six months ended 2015 and 2014, respectively (14 ) 9
—
11

Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $(1), $7 and $(2) for the three and six months ended 2015 and 2014, respectively —
2
(9 ) 3

Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(1), $(10) and $(3) for the three and six months ended 2015 and 2014, respectively 7
2
14
5

Other Comprehensive Income (Loss), net of tax (7 ) 13
5
19

COMPREHENSIVE INCOME $ 159
$ 67
$ 506
$ 237

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

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~~PSEG POWER LLC~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~Millions~~

~~(Unaudited)~~

June 30,
2015 December 31,
2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 12
$ 9

Accounts Receivable 235
334

Accounts Receivable—Affiliated Companies 158
313

Tax Receivable 3
3

Short-Term Loan to Affiliate 950
584

Fuel 358
538

Materials and Supplies, net 321
350

Derivative Contracts 139
207

Prepayments 22
17

Other 13
4

Total Current Assets 2,211
2,359

PROPERTY, PLANT AND EQUIPMENT 10,942
10,732

Less: Accumulated Depreciation and Amortization (3,235 ) (3,217 )
Net Property, Plant and Equipment 7,707
7,515

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund 1,792
1,780

Long-Term Investments 116
121

Goodwill 16
16

Other Intangibles 101
84

Other Special Funds 57
49

Derivative Contracts 103
62

Other 63
60

Total Noncurrent Assets 2,248
2,172

TOTAL ASSETS $ 12,166
$ 12,046

~~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,
2015 December 31,
2014
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 300
$ 300

Accounts Payable 387
424

Accounts Payable-Affiliated Companies 128
118

Derivative Contracts 72
132

Deferred Income Taxes 22
43

Accrued Interest 27
27

Other 141
140

Total Current Liabilities 1,077
1,184

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC) 2,152
2,065

Asset Retirement Obligations 462
450

Other Postretirement Benefit (OPEB) Costs 254
248

Derivative Contracts 24
33

Accrued Pension Costs 139
153

Long-Term Accrued Taxes 56
41

Other 94
71

Total Noncurrent Liabilities 3,181
3,061

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

LONG-TERM DEBT
Total Long-Term Debt 2,244
2,243

MEMBER’S EQUITY
Contributed Capital 2,214
2,214

Basis Adjustment (986 ) (986 )
Retained Earnings 4,659
4,558

Accumulated Other Comprehensive Loss (223 ) (228 )
Total Member’s Equity 5,664
5,558

TOTAL LIABILITIES AND MEMBER’S EQUITY $ 12,166
$ 12,046

~~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,
2015 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 501
$ 218

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 151
144

Amortization of Nuclear Fuel 106
98

Provision for Deferred Income Taxes and ITC 64
(22 )
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives (9 ) 297

Non-Cash Employee Benefit Plan Costs 24
7

Net Realized (Gains) Losses and (Income) Expense from NDT Fund (21 ) (59 )
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies 209
132

Margin Deposit 69
(234 )
Accounts Receivable 76
16

Accounts Payable (62 ) (72 )
Accounts Receivable/Payable—Affiliated Companies, net 123
229

Other Current Assets and Liabilities (21 ) 13

Employee Benefit Plan Funding and Related Payments (7 ) (3 )
Other 89
50

Net Cash Provided By (Used In) Operating Activities 1,292
814

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (487 ) (226 )
Proceeds from Sales of Available-for-Sale Securities 837
563

Investments in Available-for-Sale Securities (854 ) (577 )
Short-Term Loan—Affiliated Company, net (366 ) 50

Other (17 ) (46 )
Net Cash Provided By (Used In) Investing Activities (887 ) (236 )
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid (400 ) (575 )
Other (2 ) (3 )
Net Cash Provided By (Used In) Financing Activities (402 ) (578 )
Net Increase (Decrease) in Cash and Cash Equivalents 3
—

Cash and Cash Equivalents at Beginning of Period 9
6

Cash and Cash Equivalents at End of Period $ 12
$ 6

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 218
$ 47

Interest Paid, Net of Amounts Capitalized $ 62
$ 62

Accrued Property, Plant and Equipment Expenditures $ 42
$ 48

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

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 is 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,
	2016			2015			2016			2015
OPERATING REVENUES	$	1,905		$	2,314		$	4,521		$	5,449
OPERATING EXPENSES
Energy Costs	624			668			1,460			1,762
Operation and Maintenance	710			761			1,439			1,424
Depreciation and Amortization	224			317			448			647
Total Operating Expenses	1,558			1,746			3,347			3,833
OPERATING INCOME	347			568			1,174			1,616
Income from Equity Method Investments	4			4			6			7
Other Income	44			76			92			124
Other Deductions	(10		)	(10		)	(31		)	(22		)
Other-Than-Temporary Impairments	(10		)	(10		)	(20		)	(15		)
Interest Expense	(97		)	(97		)	(189		)	(195		)
INCOME BEFORE INCOME TAXES	278			531			1,032			1,515
Income Tax Expense	(91		)	(186		)	(374		)	(584		)
NET INCOME	$	187		$	345		$	658		$	931
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			506			505			506
DILUTED	508			508			508			508
NET INCOME PER SHARE:
BASIC	$	0.37		$	0.68		$	1.30		$	1.84
DILUTED	$	0.37		$	0.68		$	1.30		$	1.83
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.41		$	0.39		$	0.82		$	0.78

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,
	2016			2015			2016		2015
NET INCOME	$	187		$	345		$	658	$	931
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(10), $15, $(26) and $2 for the three and six months ended 2016 and 2015, respectively	10			(15		)	26		(1		)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $(1) and $7 for the three and six months ended 2016 and 2015, respectively	(1		)	—			1		(9		)
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(6), $(6), $(12) and $(12) for the three and six months ended 2016 and 2015, respectively	8			8			16		16
Other Comprehensive Income (Loss), net of tax	17			(7		)	43		6
COMPREHENSIVE INCOME	$	204		$	338		$	701	$	937

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	June 30, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	648		$	394
Accounts Receivable, net of allowances of $65 and $67 in 2016 and 2015, respectively	988			1,068
Tax Receivable	4			305
Unbilled Revenues	202			197
Fuel	351			463
Materials and Supplies, net	554			513
Prepayments	271			135
Derivative Contracts	152			242
Regulatory Assets	310			164
Other	9			13
Total Current Assets	3,489			3,494
PROPERTY, PLANT AND EQUIPMENT	37,285			35,494
Less: Accumulated Depreciation and Amortization	(9,271		)	(8,955		)
Net Property, Plant and Equipment	28,014			26,539
NONCURRENT ASSETS
Regulatory Assets	3,120			3,196
Long-Term Investments	1,218			1,233
Nuclear Decommissioning Trust (NDT) Fund	1,797			1,754
Long-Term Tax Receivable	183			171
Long-Term Receivable of Variable Interest Entity (VIE)	513			495
Other Special Funds	246			227
Goodwill	16			16
Other Intangibles	131			102
Derivative Contracts	76			77
Other	242			231
Total Noncurrent Assets	7,542			7,502
TOTAL ASSETS	$	39,045		$	37,535

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	June 30, 2016			December 31, 2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	662		$	734
Commercial Paper and Loans	—			364
Accounts Payable	1,308			1,369
Derivative Contracts	20			76
Accrued Interest	103			96
Accrued Taxes	107			42
Clean Energy Program	200			142
Obligation to Return Cash Collateral	128			128
Regulatory Liabilities	74			123
Regulatory Liabilities of VIEs	22			42
Other	496			459
Total Current Liabilities	3,120			3,575
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,545			8,166
Regulatory Liabilities	165			175
Asset Retirement Obligations	693			679
OPEB Costs	1,199			1,228
OPEB Costs of Servco	389			375
Accrued Pension Costs	429			487
Accrued Pension Costs of Servco	118			114
Clean Energy Program	27			—
Environmental Costs	402			415
Derivative Contracts	14			27
Long-Term Accrued Taxes	171			212
Other	181			181
Total Noncurrent Liabilities	12,333			12,059
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT	10,273			8,834
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2016 and 2015—534 shares	4,919			4,915
Treasury Stock, at cost, 2016—29 shares; 2015—28 shares	(709		)	(671		)
Retained Earnings	9,360			9,117
Accumulated Other Comprehensive Loss	(252		)	(295		)
Total Common Stockholders’ Equity	13,318			13,066
Noncontrolling Interest	1			1
Total Stockholders’ Equity	13,319			13,067
Total Capitalization	23,592			21,901
TOTAL LIABILITIES AND CAPITALIZATION	$	39,045		$	37,535

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	658		$	931
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	448			647
Amortization of Nuclear Fuel	105			106
Provision for Deferred Income Taxes (Other than Leases) and ITC	334			170
Non-Cash Employee Benefit Plan Costs	63			81
Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes	(30		)	(22		)
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	153			(9		)
Change in Accrued Storm Costs	(1		)	15
Net Change in Other Regulatory Assets and Liabilities	(124		)	(53		)
Cost of Removal	(74		)	(58		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(2		)	(21		)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	301			188
Accrued Taxes	94			71
Margin Deposit	(46		)	69
Other Current Assets and Liabilities	(120		)	98
Employee Benefit Plan Funding and Related Payments	(78		)	(67		)
Other	41			88
Net Cash Provided By (Used In) Operating Activities	1,722			2,234
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,971		)	(1,743		)
Proceeds from Sales of Available-for-Sale Securities	392			885
Investments in Available-for-Sale Securities	(407		)	(918		)
Other	(18		)	3
Net Cash Provided By (Used In) Investing Activities	(2,004		)	(1,773		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(364		)	—
Issuance of Long-Term Debt	1,550			600
Redemption of Long-Term Debt	(171		)	(300		)
Redemption of Securitization Debt	—			(125		)
Cash Dividends Paid on Common Stock	(415		)	(394		)
Other	(64		)	(47		)
Net Cash Provided By (Used In) Financing Activities	536			(266		)
Net Increase (Decrease) in Cash and Cash Equivalents	254			195
Cash and Cash Equivalents at Beginning of Period	394			402
Cash and Cash Equivalents at End of Period	$	648		$	597
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(276	)	$	184
Interest Paid, Net of Amounts Capitalized	$	176		$	195
Accrued Property, Plant and Equipment Expenditures	$	513		$	324

See Notes to Condensed Consolidated Financial Statements.

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,
	2016			2015			2016			2015
OPERATING REVENUES	$	1,350		$	1,466		$	3,062		$	3,468
OPERATING EXPENSES
Energy Costs	529			544			1,258			1,436
Operation and Maintenance	352			368			734			780
Depreciation and Amortization	136			234			275			481
Total Operating Expenses	1,017			1,146			2,267			2,697
OPERATING INCOME	333			320			795			771
Other Income	19			19			39			37
Other Deductions	(1		)	(1		)	(2		)	(2		)
Interest Expense	(74		)	(67		)	(142		)	(136		)
INCOME BEFORE INCOME TAXES	277			271			690			670
Income Tax Expense	(98		)	(104		)	(249		)	(261		)
NET INCOME	$	179		$	167		$	441		$	409

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,
	2016		2015			2016		2015
NET INCOME	$	179	$	167		$	441	$	409
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 and $0 for the three and six months ended 2016 and 2015, respectively	1		(1		)	1		(1		)
COMPREHENSIVE INCOME	$	180	$	166		$	442	$	408

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, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	168		$	198
Accounts Receivable, net of allowances of $65 and $67 in 2016 and 2015, respectively	736			787
Accounts Receivable—Affiliated Companies	—			222
Unbilled Revenues	202			197
Materials and Supplies	162			148
Prepayments	196			31
Regulatory Assets	310			164
Derivative Contracts	—			13
Other	8			9
Total Current Assets	1,782			1,769
PROPERTY, PLANT AND EQUIPMENT	24,976			23,732
Less: Accumulated Depreciation and Amortization	(5,627		)	(5,504		)
Net Property, Plant and Equipment	19,349			18,228
NONCURRENT ASSETS
Regulatory Assets	3,120			3,196
Long-Term Investments	316			330
Other Special Funds	57			49
Other	113			105
Total Noncurrent Assets	3,606			3,680
TOTAL ASSETS	$	24,737		$	23,677

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, 2016		December 31, 2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	100	$	171
Commercial Paper and Loans	—		153
Accounts Payable	680		724
Accounts Payable—Affiliated Companies	179		292
Accrued Interest	73		70
Clean Energy Program	200		142
Derivative Contracts	2		—
Obligation to Return Cash Collateral	127		128
Regulatory Liabilities	74		123
Regulatory Liabilities of VIEs	22		42
Other	339		297
Total Current Liabilities	1,796		2,142
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	5,503		5,181
OPEB Costs	904		937
Accrued Pension Costs	165		202
Regulatory Liabilities	165		175
Clean Energy Program	27		—
Environmental Costs	336		365
Asset Retirement Obligations	220		218
Derivative Contracts	—		11
Long-Term Accrued Taxes	99		109
Other	113		114
Total Noncurrent Liabilities	7,532		7,312
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT	7,394		6,650
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2016 and 2015—132 shares	892		892
Contributed Capital	695		695
Basis Adjustment	986		986
Retained Earnings	5,440		4,999
Accumulated Other Comprehensive Income	2		1
Total Stockholder’s Equity	8,015		7,573
Total Capitalization	15,409		14,223
TOTAL LIABILITIES AND CAPITALIZATION	$	24,737	$	23,677

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	441		$	409
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	275			481
Provision for Deferred Income Taxes and ITC	290			79
Non-Cash Employee Benefit Plan Costs	36			48
Cost of Removal	(74		)	(58		)
Change in Accrued Storm Costs	(1		)	15
Net Change in Other Regulatory Assets and Liabilities	(124		)	(53		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	50			53
Materials and Supplies	(14		)	(10		)
Prepayments	(165		)	(162		)
Accounts Payable	(29		)	48
Accounts Receivable/Payable—Affiliated Companies, net	181			154
Other Current Assets and Liabilities	17			(27		)
Employee Benefit Plan Funding and Related Payments	(62		)	(55		)
Other	(13		)	(13		)
Net Cash Provided By (Used In) Operating Activities	808			909
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,355		)	(1,230		)
Proceeds from Sales of Available-for-Sale Securities	12			12
Investments in Available-for-Sale Securities	(13		)	(14		)
Other	2			12
Net Cash Provided By (Used In) Investing Activities	(1,354		)	(1,220		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	(153		)	—
Issuance of Long-Term Debt	850			600
Redemption of Long-Term Debt	(171		)	(300		)
Redemption of Securitization Debt	—			(125		)
Other	(10		)	(8		)
Net Cash Provided By (Used In) Financing Activities	516			167
Net Increase (Decrease) In Cash and Cash Equivalents	(30		)	(144		)
Cash and Cash Equivalents at Beginning of Period	198			310
Cash and Cash Equivalents at End of Period	$	168		$	166
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(255	)	$	(74	)
Interest Paid, Net of Amounts Capitalized	$	134		$	131
Accrued Property, Plant and Equipment Expenditures	$	381		$	282

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,
	2016			2015			2016			2015
OPERATING REVENUES	$	714		$	1,025		$	2,027		$	2,750
OPERATING EXPENSES
Energy Costs	381			409			1,019			1,302
Operation and Maintenance	265			313			518			485
Depreciation and Amortization	80			75			159			151
Total Operating Expenses	726			797			1,696			1,938
OPERATING INCOME (LOSS)	(12		)	228			331			812
Income from Equity Method Investments	4			5			6			8
Other Income	25			55			51			84
Other Deductions	(9		)	(7		)	(27		)	(18		)
Other-Than-Temporary Impairments	(10		)	(10		)	(20		)	(15		)
Interest Expense	(20		)	(33		)	(42		)	(64		)
INCOME (LOSS) BEFORE INCOME TAXES	(22		)	238			299			807
Income Tax Benefit (Expense)	11			(72		)	(118		)	(306		)
NET INCOME (LOSS)	$	(11	)	$	166		$	181		$	501

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

Millions

(Unaudited)




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016		2015
NET INCOME (LOSS)	$	(11	)	$	166		$	181	$	501
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(9), $14, $(25) and $1 for the three and six months ended 2016 and 2015, respectively	9			(14		)	25		—
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0, $0 and $7 for the three and six months ended 2016 and 2015, respectively	—			—			—		(9		)
Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(5), $(10) and $(10) for the three and six months ended 2016 and 2015, respectively	7			7			14		14
Other Comprehensive Income (Loss), net of tax	16			(7		)	39		5
COMPREHENSIVE INCOME	$	5		$	159		$	220	$	506

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, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	16		$	12
Accounts Receivable	202			217
Accounts Receivable—Affiliated Companies	94			276
Short-Term Loan to Affiliate	1,335			363
Fuel	351			463
Materials and Supplies, net	389			363
Derivative Contracts	150			223
Prepayments	7			25
Other	4			7
Total Current Assets	2,548			1,949
PROPERTY, PLANT AND EQUIPMENT	11,969			11,354
Less: Accumulated Depreciation and Amortization	(3,491		)	(3,227		)
Net Property, Plant and Equipment	8,478			8,127
NONCURRENT ASSETS
NDT Fund	1,797			1,754
Long-Term Investments	112			119
Goodwill	16			16
Other Intangibles	131			102
Other Special Funds	60			55
Derivative Contracts	76			77
Other	60			51
Total Noncurrent Assets	2,252			2,174
TOTAL ASSETS	$	13,278		$	12,250

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, 2016			December 31, 2015
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	553		$	553
Accounts Payable	466			432
Accounts Payable—Affiliated Companies	102			33
Derivative Contracts	17			76
Accrued Interest	29			25
Other	96			107
Total Current Liabilities	1,263			1,226
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	2,418			2,347
Asset Retirement Obligations	470			457
OPEB Costs	234			230
Derivative Contracts	14			16
Accrued Pension Costs	151			166
Long-Term Accrued Taxes	22			35
Other	104			87
Total Noncurrent Liabilities	3,413			3,338
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT	2,380			1,684
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	5,195			5,014
Accumulated Other Comprehensive Loss	(201		)	(240		)
Total Member’s Equity	6,222			6,002
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	13,278		$	12,250

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,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	181		$	501
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	159			151
Amortization of Nuclear Fuel	105			106
Provision for Deferred Income Taxes and ITC	37			64
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	153			(9		)
Non-Cash Employee Benefit Plan Costs	19			24
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	(2		)	(21		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	86			209
Margin Deposit	(46		)	69
Accounts Receivable	(12		)	76
Accounts Payable	(10		)	(62		)
Accounts Receivable/Payable—Affiliated Companies, net	179			123
Other Current Assets and Liabilities	11			(21		)
Employee Benefit Plan Funding and Related Payments	(10		)	(7		)
Other	67			89
Net Cash Provided By (Used In) Operating Activities	917			1,292
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(598		)	(487		)
Proceeds from Sales of Available-for-Sale Securities	346			837
Investments in Available-for-Sale Securities	(359		)	(854		)
Short-Term Loan—Affiliated Company, net	(972		)	(366		)
Other	(24		)	(17		)
Net Cash Provided By (Used In) Investing Activities	(1,607		)	(887		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	700			—
Cash Dividend Paid	—			(400		)
Other	(6		)	(2		)
Net Cash Provided By (Used In) Financing Activities	694			(402		)
Net Increase (Decrease) in Cash and Cash Equivalents	4			3
Cash and Cash Equivalents at Beginning of Period	12			9
Cash and Cash Equivalents at End of Period	$	16		$	12
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(53	)	$	218
Interest Paid, Net of Amounts Capitalized	$	38		$	62
Accrued Property, Plant and Equipment Expenditures	$	132		$	42

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Note 1. Organization and Basis of Presentation

Organization

PSEG is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are:

PSE&G—which is ~~an operating~~a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU.

Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy ~~trading~~transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by ~~the~~ FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG's other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; 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 (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The ~~respective~~ financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, the Annual Report on Form 10-K for the year ended December 31, ~~2014.~~2015.

The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. All intercompany accounts and transactions are eliminated in consolidation. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, ~~2014.~~2015.

Note 2. Recent Accounting Standards

New Standards Issued But Not Yet Adopted

Revenue from Contracts with Customers

This accounting standard ~~was issued to clarify~~clarifies the principles for recognizing revenue and ~~to develop a common standard that would remove~~removes inconsistencies in revenue recognition requirements; ~~improve~~improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and ~~provide~~provides improved disclosures.

The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.

The ~~update~~standard was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board ~~has voted~~issued new guidance deferring the effective date by one year to ~~proceed with a one-year deferral with an effective date~~periods beginning after December 31, 2017. Early application will be permitted as of the original effective ~~date of December 31, 2016. We are~~date. PSEG is currently analyzing the impact of this standard on ~~our~~its financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

~~Amendments to the Consolidation Analysis~~Recognition and Measurement of Financial Assets and Financial Liabilities

This accounting standard ~~was issued to respond to concerns regarding~~will change how entities measure equity investments that are not consolidated or accounted for under the ~~current accounting for consolidation of certain legal entities.~~equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard all legal entities are subject to reevaluation under a revised consolidation model which will determine whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities; eliminate the presumption that a general partner should consolidate a limited partnership; affect the consolidation analysis of reporting entities that are involved with VIEs and provide a scope exception from consolidation guidance for reporting entities with interests inalso changes certain ~~legal entities who must comply with other requirements.~~disclosures.

The ~~update~~standard is effective for annual and interim reporting periods beginning after December 15, ~~2015. We are~~2017. PSEG is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the Nuclear Decommissioning Trust (NDT) and Rabbi Trust Funds.

Leases

This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements.

~~Simplifying~~The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the ~~Presentation~~impact of ~~Debt Issuance Costs~~this standard on its financial statements.

Stock Compensation-Improvements to Employee Share-Based Payment Accounting

This accounting standard was issued to simplify ~~presentation~~aspects of ~~debt issuance costs. The standard~~the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows.

Under the new guidance, all excess tax benefits and tax deficiencies will ~~require that debt issuance costs related~~be recognized in income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to ~~a recognized debt liability be presented in~~facilitate equity classification of the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard.award.

The ~~update~~standard is effective for annual and interim reporting periods beginning after December 15, ~~2015. We do not expect~~2017. Early adoption is permitted for an entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. PSEG is currently analyzing the impact of ~~adoption~~this standard on its financial statements.

Measurement of Credit Losses on Financial Instruments

This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination.

The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard ~~to be material to our Condensed Consolidated Balance Sheets.~~on its financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Note 3. Variable Interest Entities (VIEs)

~~Variable Interest Entities~~VIEs for which PSE&G is the Primary Beneficiary

PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which iswas pledged as collateral to a trustee. PSE&G ~~acts~~acted as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds ~~are~~were remitted to Transition Funding and Transition Funding II and ~~are~~were used for interest and principal payments on the transition bonds and related costs.

~~The assets and liabilities of~~ During 2015, Transition Funding and Transition Funding II ~~are presented separately on~~paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained with these VIEs. Effective January 1, 2016, PSE&G commenced refunding the ~~face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the assets of~~overcollections from customers associated with these VIEs ~~are restricted~~ and ~~can only be used~~expects to ~~settle their respective obligations. No Transition Funding or Transition Funding II creditor has any recourse to the general credit of PSE&G~~fully refund these liabilities in ~~the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding or Transition Funding II.~~2016.

~~PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was~~ ~~$16 million~~ ~~as of~~ ~~June 30, 2015~~ ~~and~~ ~~December 31, 2014. The risk of actual loss to PSE&G is considered remote. PSE&G did not provide any financial support to Transition Funding or Transition Funding II during the first~~ ~~six months~~ of ~~2015~~ ~~or in 2014. PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.~~

~~Variable Interest Entity~~VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA's T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco's economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.

Pursuant to the OSA, Servco's operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI's risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco's annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.

PSEG recognized a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and other postretirement benefit (OPEB) liabilities. This receivable is presented separately on the Condensed Consolidated Balance Sheet

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

~~of PSEG as a noncurrent asset because it is restricted. See Note 7. Pension and Other Postretirement Benefits for additional information.~~

For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operation and Maintenance (O&M) Expense, respectively. Servco recorded ~~$84~~$101 million and ~~$111~~$84 million for the three months and ~~$166~~$199 million and ~~$200~~$166 million for the six months ended June 30, ~~2015~~2016 and ~~2014,~~2015, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG's Condensed Consolidated Statement of Operations.

Note 4. Rate Filings

~~The following information discusses significant updates regarding orders and pending rate filings.~~ This Note should be read in conjunction with Note 5. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, ~~2014~~2015.

In addition to items previously reported in the Annual Report on Form 10-K, significant ~~2015~~ regulatory orders received and currently pending rate filings with ~~the~~ FERC and the BPU by PSE&G are as follows:

Remediation Adjustment Charge (RAC)—In April 2016, the BPU approved PSE&G's filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015.

Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June ~~2015,~~2016, PSE&G updated its ~~Energy Strong~~March cost recovery petition ~~seeking BPU approval~~ to ~~recover in base rates estimated annual increases in electric revenues of $6 million and gas revenues of $17 million. These increases represent recovery of~~include Energy Strong ~~investment costs~~investments in service as of May 31, ~~2015.~~2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million, respectively. The petition requests rates to be effective September 1, ~~2015,~~2016, consistent with the BPU Order of approval of the Energy Strong program. This matter is pending.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

In early 2014, NRG REMA LLC, an indirect subsidiary of NRG Energy, Inc. (NRG) had disclosed its plan to place the Shawville generating facility in a “long-term protective layup” by April 2015 as it evaluated its alternatives under the lease. However, NRG has since notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the summer of 2016 with the ability to use natural gas.

Note 6. Available-for-Sale Securities

~~Nuclear Decommissioning Trust (NDT)~~NDT Fund

Power maintains an external master ~~nuclear decommissioning trust~~NDT to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisers who operate under investment guidelines developed by Power.

Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.

As of June 30, 2015
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 697
$ 234
$ (10 ) $ 921

Debt Securities
Government Obligations 451
7
(3 ) 455

Other Debt Securities 388
4
(6 ) 386

Total Debt Securities 839
11
(9 ) 841

Other Securities 30
—
—
30

Total NDT Available-for-Sale Securities $ 1,566
$ 245
$ (19 ) $ 1,792




	As of June 30, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	679	$	198	$	(12	)	$	865
Debt Securities
Government Obligations	503		23		—			526
Other	348		12		(3		)	357
Total Debt Securities	851		35		(3		)	883
Other Securities	49		—		—			49
Total NDT Available-for-Sale Securities	$	1,579	$	233	$	(15	)	$	1,797

As of December 31, 2014
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 685
$ 220
$ (8 ) $ 897

Debt Securities
Government Obligations 430
9
(1 ) 438

Other Debt Securities 333
9
(3 ) 339

Total Debt Securities 763
18
(4 ) 777

Other Securities 106
—
—
106

Total NDT Available-for-Sale Securities $ 1,554
$ 238
$ (12 ) $ 1,780

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)




	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	693	$	185	$	(13	)	$	865
Debt Securities
Government Obligations	483		8		(3		)	488
Other	366		3		(10		)	359
Total Debt Securities	849		11		(13		)	847
Other Securities	42		—		—			42
Total NDT Available-for-Sale Securities	$	1,584	$	196	$	(26	)	$	1,754

The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.

As of As of
June 30,
2015 December 31,
2014
Millions
Accounts Receivable $ 42
$ 10

Accounts Payable $ 32
$ 2




	As of		As of
	June 30, 2016		December 31, 2015
	Millions
Accounts Receivable	$	18	$	17
Accounts Payable	$	10	$	10

The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months.

As of June 30, 2015 As of December 31, 2014

Less Than 12
Months

Greater Than 12
Months

Less Than 12
Months

Greater Than 12
Months

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Millions
Equity Securities (A) $ 114
$ (10 ) $ 3
$ —
$ 162
$ (8 ) $ 1
$ —

Debt Securities
Government Obligations (B) 156
(3 ) 22
—
95
—
28
(1 )
Other Debt Securities (C) 199
(4 ) 22
(2 ) 99
(1 ) 30
(2 )
Total Debt Securities 355
(7 ) 44
(2 ) 194
(1 ) 58
(3 )
NDT Available-for-Sale Securities $ 469
$ (17 ) $ 47
$ (2 ) $ 356
$ (9 ) $ 59
$ (3 )




	As of June 30, 2016										As of December 31, 2015
	Less Than 12 Months					Greater Than 12 Months					Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	108	$	(12	)	$	5	$	—		$	151	$	(13	)	$	1	$	—
Debt Securities
Government Obligations (B)	12		—			6		—			245		(2		)	19		(1		)
Other (C)	12		—			43		(3		)	222		(7		)	36		(3		)
Total Debt Securities	24		—			49		(3		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	132	$	(12	)	$	54	$	(3	)	$	618	$	(22	)	$	56	$	(4	)


(A)	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of June 30, ~~2015~~. 2016.

(B)

Debt Securities ~~(Government)~~(Government Obligations)—Unrealized losses on Power’s NDT investments in ~~United States~~U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the ~~United States~~U.S. government or an agency of the ~~United States~~U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be ~~more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of~~ ~~June 30, 2015~~.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of June 30, 2016.

(C)

Debt Securities (Other)—Power’s investments in corporate bonds ~~collateralized mortgage obligations, asset-backed securities and municipal government obligations~~ are ~~limited to~~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 June 30, ~~2015~~.

2016.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

The proceeds from the sales of and the net realized gains on securities in the NDT Fund were:

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
Millions
Proceeds from NDT Fund Sales (A) $ 232
$ 313
$ 822
$ 558

Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains 14
33
33
56

Gross Realized Losses (4 ) (5 ) (13 ) (9 )
Net Realized Gains (Losses) on NDT Fund $ 10
$ 28
$ 20
$ 47




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	Millions
Proceeds from NDT Fund Sales (A)	$	154		$	232		$	331		$	822
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	10			14			25			33
Gross Realized Losses	(6		)	(4		)	(22		)	(13		)
Net Realized Gains (Losses) on NDT Fund	$	4		$	10		$	3		$	20


(A)	~~Includes~~2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers.

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $~~111~~110 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of June 30, ~~2015~~2016.

The NDT available-for-sale debt securities held as of June 30, ~~2015~~2016 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ 9

1 - 5 years 229

6 - 10 years 197

11 - 15 years 53

16 - 20 years 47

Over 20 years 306

Total NDT Available-for-Sale Debt Securities $ 841




Time Frame	Fair Value
	Millions
Less than one year	$	19
1 - 5 years	216
6 - 10 years	220
11 - 15 years	54
16 - 20 years	61
Over 20 years	313
Total NDT Available-for-Sale Debt Securities	$	883

The cost of these securities was determined on the basis of specific identification.

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the six months ended June 30, ~~2015,~~2016, other-than-temporary impairments of $1520 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

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~~

~~table of contents~~ ~~(UNAUDITED)~~

PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.

As of June 30, 2015
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 12
$ 10
$ —
$ 22

Debt Securities
Government Obligations 99
1
—
100

Other Debt Securities 90
1
(1 ) 90

Total Debt Securities 189
2
(1 ) 190

Other Securities —
—
—
—

Total Rabbi Trust Available-for-Sale Securities $ 201
$ 12
$ (1 ) $ 212




	As of June 30, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	10	$	—		$	21
Debt Securities
Government Obligations	104		2		—			106
Other	90		1		(1		)	90
Total Debt Securities	194		3		(1		)	196
Other Securities	5		—		—			5
Total Rabbi Trust Available-for-Sale Securities	$	210	$	13	$	(1	)	$	222

As of December 31, 2014
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 12
$ 11
$ —
$ 23

Debt Securities
Government Obligations 89
2
—
91

Other Debt Securities 74
1
—
75

Total Debt Securities 163
3
—
166

Other Securities 2
—
—
2

Total Rabbi Trust Available-for-Sale Securities $ 177
$ 14
$ —
$ 191




	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	10	$	—		$	22
Debt Securities
Government Obligations	108		1		(1		)	108
Other	82		—		(1		)	81
Total Debt Securities	190		1		(2		)	189
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	204	$	11	$	(2	)	$	213

The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets as shown in the following table.

As of As of
June 30,
2015 December 31,
2014
Millions
Accounts Receivable $ 3
$ 1

Accounts Payable $ 2
$ —




	As of		As of
	June 30, 2016		December 31, 2015
	Millions
Accounts Receivable	$	2	$	1
Accounts Payable	$	4	$	—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than and greater than 12 months.

As of June 30, 2015 As of December 31, 2014

Less Than 12
Months

Greater Than 12
Months

Less Than 12
Months

Greater Than 12
Months

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Millions
Equity Securities (A) $ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —

Debt Securities
Government Obligations (B) 19
—
1
—
2
—
—
—

Other Debt Securities (C) 39
(1 ) 7
—
24
—
—
—

Total Debt Securities 58
(1 ) 8
—
26
—
—
—

Rabbi Trust Available-for-Sale Securities $ 58
$ (1 ) $ 8
$ —
$ 26
$ —
$ —
$ —




	As of June 30, 2016									As of December 31, 2015
	Less Than 12 Months				Greater Than 12 Months					Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—	$	—	$	—		$	—	$	—		$	—	$	—
Debt Securities
Government Obligations (B)	14		—		3		—			53		(1		)	2		—
Other (C)	14		—		11		(1		)	46		(1		)	9		—
Total Debt Securities	28		—		14		(1		)	99		(2		)	11		—
Rabbi Trust Available-for-Sale Securities	$	28	$	—	$	14	$	(1	)	$	99	$	(2	)	$	11	$	—


(A)	Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors.

(B)

Debt Securities ~~(Government)~~(Government Obligations)—Unrealized losses on PSEG’s Rabbi Trust investments in ~~United States~~U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the ~~United States~~U.S. government or an agency of the ~~United States~~U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of June 30, ~~2015.~~2016.

(C)

Debt Securities (Other)—PSEG’s investments in corporate bonds ~~collateralized mortgage obligations, asset-backed securities and municipal government obligations~~ are ~~limited to~~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 June 30, ~~2015.~~2016.

The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
Millions
Proceeds from Rabbi Trust Sales (A) $ 44
$ 14
$ 63
$ 26

Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains $ 2
$ —
$ 2
$ 2

Gross Realized Losses —
(1 ) —
(1 )
Net Realized Gains (Losses) on Rabbi Trust $ 2
$ (1 ) $ 2
$ 1




	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016			2015		2016			2015
	Millions
Proceeds from Rabbi Trust Sales (A)	$	36		$	44	$	61		$	63
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2	$	3		$	2
Gross Realized Losses	(1		)	—		(2		)	—
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	2	$	1		$	2


(A)	~~Includes~~2015 proceeds include activity in accounts related to the liquidation of funds being transitioned to new managers.

Gross realized gains disclosed in the preceding table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of $67 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of June 30, ~~2015~~2016.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

The Rabbi Trust available-for-sale debt securities held as of June 30, ~~2015~~2016 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ 1

1 - 5 years 56

6 - 10 years 37

11 - 15 years 9

16 - 20 years 8

Over 20 years 79

Total Rabbi Trust Available-for-Sale Debt Securities $ 190




Time Frame	Fair Value
	Millions
Less than one year	$	8
1 - 5 years	45
6 - 10 years	48
11 - 15 years	6
16 - 20 years	7
Over 20 years	82
Total Rabbi Trust Available-for-Sale Debt Securities	$	196

The cost of these securities was determined on the basis of specific identification.

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

The fair value of assets in the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows:

As of As of
June 30,
2015 December 31,
2014
Millions
PSE&G $ 42
$ 41

Power 52
45

Other 118
105

Total Rabbi Trust Available-for-Sale Securities $ 212
$ 191




	As of		As of
	June 30, 2016		December 31, 2015
	Millions
PSE&G	$	44	$	42
Power	54		52
Other	124		119
Total Rabbi Trust Available-for-Sale Securities	$	222	$	213

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

Note 7. Pension and Other Postretirement Benefits (OPEB)

PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria.

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

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Pension and OPEB costs for PSEG, except for Servco, are detailed as follows:

Pension Benefits OPEB Pension Benefits OPEB
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2015
2014 2015
2014 2015 2014 2015 2014
Millions
Components of Net Periodic Benefit Costs (Credit)
Service Cost $ 31
$ 26
$ 6
$ 4
$ 62
$ 52
$ 11
$ 9

Interest Cost 58
59
17
17
117
118
34
34

Expected Return on Plan Assets (104 ) (100 ) (8 ) (6 ) (207 ) (200 ) (15 ) (13 )
Amortization of Net
Prior Service Cost (Credit) (4 ) (4 ) (4 ) (3 ) (9 ) (9 ) (7 ) (7 )
Actuarial Loss 37
14
11
6
74
28
21
12

Total Benefit Costs (Credit) $ 18
$ (5 ) $ 22
$ 18
$ 37
$ (11 ) $ 44
$ 35




	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Six Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015			2016			2015
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	27		$	31		$	4		$	6		$	54		$	62		$	8		$	11
Interest Cost	51			58			14			17			101			117			29			34
Expected Return on Plan Assets	(99		)	(104		)	(7		)	(8		)	(197		)	(207		)	(15		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(4		)	(4		)	(4		)	(9		)	(9		)	(7		)	(7		)
Actuarial Loss	40			37			10			11			79			74			20			21
Total Benefit Costs	$	14		$	18		$	17		$	22		$	28		$	37		$	35		$	44

Pension and OPEB costs for PSE&G, Power and PSEG’s other subsidiaries, except for Servco, are detailed as follows:

Pension Benefits OPEB Pension Benefits OPEB
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2015 2014 2015 2014 2015 2014 2015 2014
Millions
PSE&G $ 10
$ (5 ) $ 14
$ 12
$ 20
$ (10 ) $ 28
$ 23

Power 5
(1 ) 6
5
11
(3 ) 13
10

Other 3
1
2
1
6
2
3
2

Total Benefit Costs (Credit) $ 18
$ (5 ) $ 22
$ 18
$ 37
$ (11 ) $ 44
$ 35




	Pension Benefits				OPEB				Pension Benefits				OPEB
	Three Months Ended				Three Months Ended				Six Months Ended				Six Months Ended
	June 30,				June 30,				June 30,				June 30,
	2016		2015		2016		2015		2016		2015		2016		2015
	Millions
PSE&G	$	7	$	10	$	11	$	14	$	14	$	20	$	22	$	28
Power	4		5		5		6		8		11		11		13
Other	3		3		1		2		6		6		2		3
Total Benefit Costs	$	14	$	18	$	17	$	22	$	28	$	37	$	35	$	44

During the three months ended March 31, ~~2015,~~2016, PSEG contributed its entire planned contributions for the year ~~2015~~2016 of ~~$15~~$21 million into its pension plans and $14 million into its OPEB ~~plan for 2015.~~plan.

Servco Pension and OPEB

At the direction of LIPA, ~~effective January 1, 2014,~~ Servco ~~established~~sponsors benefit plans that ~~provide substantially the same benefits to~~cover its current and former employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco's employees had worked under NGES' T&D operations services arrangement with LIPA, Servco's plans providewho meet certain ~~of those employees with pension and OPEB vested credit for prior years' services earned while working for NGES. The benefit plans cover all employees of Servco for current service.~~eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 3. Variable Interest Entities. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco ~~may~~plans to contribute ~~up to $30~~$28 million into its pension plan ~~trusts~~ during ~~2015. The~~2016. Servco's pension-related revenues and costs were $7$6 million and ~~$23~~$7 million for the three months ended June 30, ~~2015~~2016 and ~~2014,~~2015, respectively, and ~~were $13~~$12 million and ~~$46~~$13 million for the six months ended June 30, ~~2015~~2016 and ~~2014,~~2015, respectively. The OPEB-related revenues earned orand costs incurred for each of the three months and six months ended June 30, ~~2015~~2016 and ~~2014~~2015 were immaterial.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Note 8. Commitments and Contingent Liabilities

Guaranteed Obligations

Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.

Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to

support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and

obtain credit.

Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.

In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to

fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and

all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).

Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Power is subject to

counterparty collateral calls related to commodity contracts, and

certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.

In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

The following table shows the face value of Power's outstanding guarantees, current exposure and margin positions as of June 30, ~~2015~~2016 and December 31, ~~2014~~ ~~are shown as follows:~~2015.

As of As of
June 30,
2015 December 31,
2014
Millions
Face Value of Outstanding Guarantees $ 1,775
$ 1,814

Exposure under Current Guarantees $ 196
$ 273

Letters of Credit Margin Posted $ 161
$ 159

Letters of Credit Margin Received $ 74
$ 40

Cash Deposited and Received:
Counterparty Cash Margin Deposited $ —
$ —

Counterparty Cash Margin Received $ (9 ) $ (13 )
Net Broker Balance Deposited (Received) $ 42
$ 115

In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required $ 907
$ 945

Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral $ 3,494
$ 3,495

Additional Amounts Posted:
Other Letters of Credit $ 45
$ 45




	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Face Value of Outstanding Guarantees	$	1,809		$	1,734
Exposure under Current Guarantees	$	136		$	172

Letters of Credit Margin Posted	$	160		$	122
Letters of Credit Margin Received	$	130		$	192

Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(4	)	$	(15	)
Net Broker Balance Deposited (Received)	$	30		$	(5	)

Additional Amounts Posted:
Other Letters of Credit	$	51		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. In accordance with PSEG's accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power had posted letters of credit to support Power's various other non-energy contractual and environmental obligations. See preceding table. PSEG ~~had~~ also issued a $106 million guarantee to support Power's payment obligations related to its equity interest in the PennEast natural gas pipeline and a ~~$23~~$21 million guarantee to support Power's payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit.

Environmental Matters

Passaic River

Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)

In 2002, the U.S. Environmental Protection Agency (EPA) determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA.

The EPA ~~further~~ determined that there was a need to perform a comprehensive study of the entire ~~17-miles~~17 miles of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites.

In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.

In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G. This agreement and the work undertaken pursuant to the action agreement will not affect the ultimate remedy that the EPA will select for the remediation of the 17-mile stretch of the lower Passaic River.

In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than inwith respect ofto their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. ~~PSEG’s~~Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power's combined share of the cost of that effort is approximately three percent. The remaining CPG members have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal.

On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which ~~contemplates~~contemplated the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS ~~sets~~set forth various alternatives for remediating this portion of the Passaic River. The EPA’s estimated costs to remediate the lower eight miles of the Passaic River range from $365 million for a targeted remedy to $3.25 billion for a deep dredge of this portion of the Passaic River. The EPA also identified in the revised draft FFS its preferred alternative, which would involve dredging the river bank to bank and installing an engineered cap. The estimated cost in the revised draft FFS for its preferred alternative is $1.7 billion. No provisional cost allocation has been made by the CPG for the work contemplated by the revised draft FFS, and the work contemplated by the revised draft FFS is not subject to the CPG’s cost sharing allocation agreed to in connection with the removal work for River Mile 10.9 or in connection with the conduct of the RI/FS.

The revised draft FFS was subject to a public comment period, and remains subject to the EPA’s response to comments submitted, a design phase and at least an estimated five years for completion of the work. The public comment period on the revised draft FFS closed on August 21, 2014. Over 300 comments were submitted by a variety of entities potentially impacted by the revised draft FFS, including the CPG, individual companies, municipalities, public officials, citizens groups, Amtrak, NJ Transit and others.

The CPG, which consisted of 6153 members as of June 30, ~~2015,~~2016, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost for the preparation of the RI/FS is approximately ~~$150~~$163 million, which the CPG continues to incur. Of the estimated ~~$150~~$163 million, as of June 30, ~~2015,~~2016, the CPG had spent approximately ~~$132~~$150 million, of which ~~PSEG's total~~PSE&G's and Power's combined share was approximately $9$11 million.

The CPG's draft FS ~~sets~~set forth various alternatives for remediating ~~that portion of~~ the lower Passaic River. ~~The draft FS sets~~It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 ~~billion.~~billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ~~ranges~~ranged from approximately $518 million to $772 million. ~~No provisional cost allocation has been made by the CPG for the work contemplated by the draft FS. However, based~~Based on (i) the low end of the range of the

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current estimates of costs to remediate, (ii) PSE&G's and Power's ~~estimates of their~~estimated share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015.

~~The~~In March 2016, the EPA ~~will consider the comments received on~~released its ~~revised draft FFS and will consider the CPG’s RI/FS prior to issuing a~~ Record of Decision (ROD) for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7 and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation.

Based upon the estimated cost of the ROD Remedy, PSEG's estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of June 30, 2016, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemicals Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, will voluntarily perform the remedial design for the ROD Remedy. If the EPA secures a commitment to perform the

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Remedial Design from OCC, the EPA plans to begin negotiation of a ~~selected remedy~~remedial action consent decree, under which, OCC and the other “major” PRPs will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. "Major PRP" is undefined in the letter.

On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic ~~River.~~ River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG's share of the costs.

The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G's 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) ~~a final remedy is determined~~an agreement by the ~~EPA~~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 ~~our~~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 ~~United States~~U.S. Department of Commerce and the ~~United States~~U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between ~~$445~~$426 million and ~~$517~~$491 million through 2021, including its ~~$10~~$46 million share for the Passaic River accrued as of June 30, 2016, as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of ~~$445~~$426 million as of June 30, ~~2015.~~2016. Of this amount, ~~$84~~$99 million was recorded in Other Current Liabilities and ~~$361~~$327 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a ~~$445~~$426 millionRegulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.

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Prevention of Significant Deterioration (PSD)/New Source Review (NSR)

The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.

In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The ~~New Jersey Department of Environmental Protection (NJDEP)~~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 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. On June 30, 2015, the NJDEP issued a draft Salem permit. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The draft permit is subject to a public notice and comment period after which the NJDEP may make revisions before issuing the final permit expected during the first half of 2016.

On May 19, 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule.

On June 10, 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. On July 8, 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP's issuance of the final permit for Salem. The Riverkeeper's filing does not change the effective date of the permit.

State permitting decisions could have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants, including ~~Salem,~~ Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these ~~facilities.~~facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1$1.0 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power's future capital requirements, financial condition or results of operations.

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing

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intake structure and retire BH3 in 2021, which is four years earlier than the current estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in late 2016.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power will seek to operate BH3 through the current estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. Operations are expected to begin in mid-2019.

Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance

In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station's NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the ~~Connecticut Department~~CTDEEP of ~~Energy and Environmental Protection of~~ the

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issues and has taken actions to investigate and resolve the potential non-compliance. ~~At this early stage~~ Power cannot predict the impact of this matter.

Steam Electric Effluent Guidelines

On September 30, 2015, the EPA issued a new Effluent Guidelines Limitation Rule for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power's Mercer and Bridgeport Harbor stations and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

Coal Combustion Residuals (CCRs)

On December 19, 2014, the EPA issued a final rule which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power's Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October ~~14,~~19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows.

Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)

PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third party suppliers. The first category, which represents about 80% of PSE&G's load requirement, ~~are~~is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category ~~are~~is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, ~~2015~~2016 is ~~$272.78~~$335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, ~~2015~~2016 of ~~$282.04~~$272.78 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

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PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:

Auction Year
2012 2013 2014 2015
36-Month Terms Ending May 2015
May 2016
May 2017
May 2018
(A)
Load (MW) 2,900
2,800
2,800
2,900

$ per MWh $83.88 $92.18 $97.39 $99.54




	Auction Year
	2013	2014	2015	2016
36-Month Terms Ending	May 2016	May 2017	May 2018	May 2019	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$92.18	$97.39	$99.54	$96.38


(A)	Prices set ~~for~~in the ~~2015~~2016 BGS auction year became effective on June 1, ~~2015~~2016 when the ~~2012~~2013 BGS auction agreements expired.

Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.

PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 17. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium,

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enrichment and fabrication requirements through 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom.

Power ~~has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations.~~

~~Power also~~ has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its 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.

Power also has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations.

As of June 30, ~~2015~~2016, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type Power's Share of Commitments through 2019
Millions
Nuclear Fuel
Uranium $ 443

Enrichment $ 342

Fabrication $ 185

Natural Gas $ 1,072

Coal $ 360




Fuel Type	Power's Share of Commitments through 2020
	Millions
Nuclear Fuel
Uranium	$	454
Enrichment	$	358
Fabrication	$	180
Natural Gas	$	972
Coal	$	265

Regulatory Proceedings

FERC Compliance

In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the ~~matter.~~matter and self-reported the errors. As the internal investigation proceeded, additional

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pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed ~~the~~ FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for ~~its~~Power’s peaking units. Power continues to implement procedures to help mitigate the risk of similar issues occurring in the future. On September 2, 2014, the FERC Staff initiated a preliminary, non-public staff investigation into the matter. This investigation, which is ongoing, could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies.

During the three ~~months~~month period ended March 31, 2014, based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. ItNo additional charges to income have been recorded for this matter since that time.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ~~not possible at this~~ongoing. Since that time, Power has responded to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.

PSEG is unable to reasonably estimate the ~~potential~~ range of possible loss ~~or full impact or predict~~for this matter; however, the amounts of potential disgorgement and other potential penalties that Power may incur span a wide range depending on the success of PSEG's legal arguments. These arguments include that Power’s energy market bids in a substantial majority of the hours were below the allowed rate under the Tariff and therefore any ~~resulting penalties or other costs associated with this matter, or the applicability of mitigating factors. As new information becomes available or future developments occur~~errors in ~~this investigation,~~those hours were immaterial and that it is ~~possible~~unclear whether the quantity of the bids violated any legal requirement. If PSEG's legal arguments do not prevail in whole or in part with FERC or in ajudicial challenge that PSEG may choose to pursue, it is likely that Power ~~will~~would record additional ~~estimated~~ losses and that such additional losses ~~may~~would be ~~material.~~material to PSEG’s and Power’s Consolidated Statements of Operations in the quarterly and annual periods in which they are recorded.

~~New Jersey Clean Energy Program~~Nuclear Insurance Coverages

The following should be read in conjunction with Note 12. Commitments and Contingent Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

~~In June 2015, the BPU established the funding level for fiscal year 2016 applicable~~Based upon a review of its nuclear insurance, Power made changes to its ~~Renewable Energy and Energy Efficiency programs. The fiscal year 2016 aggregate funding for all EDCs is~~ ~~$345 million~~ ~~with PSE&G's share~~Nuclear Electric Insurance Limited (NEIL) insurance coverage of the ~~funding~~excess layer for property damage which became effective on April 1, 2016. The excess layer provides coverage above the primary layer of NEIL insurance coverage for property damage of $1.5 billion. For the excess layer at ~~$200~~the Salem/Hope Creek site, Power purchased coverage for property damage of $300 million~~. PSE&G has~~ due to a ~~current liability of~~ ~~$200~~nuclear event and $300 million ~~and~~ due to a ~~noncurrent liability of $27 million as of~~ ~~June 30, 2015~~non-nuclear event. For the excess layer at the Peach Bottom site, Power purchased coverage for its ~~outstanding share~~ownership interest for property damage of $300 million due to a nuclear event. For the ~~fiscal year 2016 and remaining fiscal year 2015 funding, respectively. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since~~excess layer at the ~~costs associated with this program are recovered from PSE&G ratepayers through~~Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ~~Societal Benefits Charge (SBC).~~ownership interest of Power.

~~Superstorm Sandy~~

In late October 2012, Superstorm Sandy caused severe damage to PSE&G's T&D system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds and the resulting storm surge caused damage to switching stations, substations and generating infrastructure.

PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. In June 2013, PSEG,

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PSE&G and Power filed suit in New Jersey state court (NJ Court) against its insurance carriers seeking an interpretation that the insurance policies cover their losses resulting from damage caused by Superstorm Sandy's storm surge.

As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its infrastructure and return it to pre-storm conditions. Of the costs incurred, approximately $40 million was recognized in O&M Expense, $75 million was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. Of the $295 million, $36 million related to insured property. In 2012, PSE&G recognized $6 million of insurance recoveries, which were deferred. There were no significant additional costs incurred since 2012.

PSE&G made a filing with the BPU to review the prudency of unreimbursed incremental storm restoration costs, including O&M and capital expenditures associated with Superstorm Sandy and certain other extreme weather events, for recovery in its next base rate case or sooner through a BPU-approved cost recovery mechanism. In September 2014, the BPU approved its filing.

Power had incurred a total of $193 million of storm-related costs from 2012 through 2014, primarily for repairs at certain generating stations in Power's fossil fleet. These costs were recognized primarily in O&M Expense, offset by $44 million of insurance recoveries in 2013 and 2012. Power incurred an additional $2 million of storm-related costs in 2015 which were recognized primarily in O&M Expense.

In the first half of 2015, PSEG reached settlements with its insurers with respect to claims for coverage of its Superstorm Sandy-related losses. PSEG received an additional $214 million under these settlements (consisting of $159 million and $55 million recognized in the three months ended March 31, 2015 and June 30, 2015, respectively), bringing cumulative insurance proceeds to $264 million. Of the $214 million recognized in 2015, PSE&G and Power recorded $35 million and $179 million, respectively. In addition to the $35 million recognized in 2015, PSE&G recognized the aforementioned $6 million of previously deferred insurance recoveries, resulting in reductions in Regulatory Assets of $20 million, O&M Expense of $10 million and Property, Plant and Equipment of $11 million. Power recorded reductions in both O&M Expense of $145 million and Property, Plant and Equipment of $6 million and an increase in Other Income of $28 million.

~~The claim filed by PSEG, PSE&G and Power related to Superstorm Sandy insurance coverage is now fully resolved.~~

Note 9. ~~Changes in Capitalization~~Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following ~~capital~~long-term debt transactions occurred in the six months ended June 30, ~~2015~~2016:

PSE&G

issued ~~$350~~$300 million of ~~3.00%~~1.90% Secured Medium-Term Notes, Series K due ~~May 2025,~~March 2021,

issued ~~$250~~$550 million of ~~4.05%~~3.80% Secured Medium-Term Notes, Series K due ~~May 2045,~~March 2046, and

~~paid~~ ~~$300 million~~ of ~~2.70%~~ ~~Secured Medium-Term Notes at maturity,~~

~~paid $117~~retired $171 million of ~~Transition Funding's securitization debt,~~6.75% Secured First and Refunding Mortgage Bonds, Series VV at maturity.

~~paid the final $8~~Power

issued $700 million of ~~Transition Funding II's securitization debt.~~3.00% Senior Notes due June 2021.

~~Power~~PSE&G

On July 1, 2016, PSE&G repurchased at par $100 million aggregate principal amount of Pollution Control Financing Authority of Salem County Bonds (Salem Bonds) and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds.

~~paid cash dividends~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents ~~$400 million~~ ~~to PSEG.~~(UNAUDITED)

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.

The commitments under PSEG's $4.2 billion credit facilities are provided by a diverse bank group with no single institution representing more than 7% of the total commitments in PSEG's credit facilities. As of June 30, 2016, PSEG's total available credit capacity of $3.9 billion was in excess of its anticipated maximum liquidity requirements.

Each of PSEG's credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries' liquidity needs. PSEG's total credit facilities and available liquidity as of June 30, 2016 were as follows:




	As of June 30, 2016
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	10	$	490	Apr 2019	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—		500		Apr 2020	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	10	$	990
PSE&G
5-year Credit Facility (B)	$	600	$	14	$	586	Apr 2020	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	14	$	586
Power
5-year Credit Facility	$	1,600	$	189	$	1,411	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	953		13		940		Apr 2020	Funding/Letters of Credit
Total Power	$	2,553	$	202	$	2,351
Total	$	4,153	$	226	$	3,927


(A)	PSEG facility will be reduced by $12 million in March 2018.


(B)	PSE&G facility will be reduced by $14 million in March 2018.

(C)Power facility will be reduced by $24 million in March 2018.


(D)	The primary use of PSEG's and PSE&G's credit facilities is to support their respective CP Programs. PSEG and PSE&G had no amounts outstanding under their respective CP Programs as of June 30, 2016.

Note 10. Financial Risk Management Activities

The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchase normal sale (NPNS), cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. Power and PSE&G enter into additional contracts that are derivatives, but ~~do not qualify for or~~ are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and ~~changes in the fair value of these contracts~~ are recorded ~~in earnings each period.~~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 to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists.

~~Cash Flow Hedges~~

PSEG ~~and Power use forward sale and purchase contracts, swaps and futures contracts to hedge certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G. These~~had no commodity derivative transactions ~~qualify and are~~ designated as cash flow ~~hedges.~~

~~As of~~ ~~June 30, 2015~~ ~~and~~ ~~December 31, 2014, the~~or fair value ~~and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity were as follows:~~

As of As of
June 30,
2015 December 31,
2014
Millions
Fair Value of Cash Flow Hedges $ 1
$ 18

Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ 1
$ 10

~~The expiration date of the longest-dated cash flow hedge at Power is in December 2015. Power’s remaining~~ ~~$1 million~~ ~~of after-tax unrealized gains on these derivatives is expected to be reclassified to earnings during the next 12 months. There was no ineffectiveness associated with qualifying~~ hedges as of June 30, ~~2015~~.2016 and December 31, 2015.

Economic Hedges

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

Interest Rates

PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of June 30, ~~2015,~~2016, PSEG had interest rate swaps outstanding totaling ~~$850~~$550 million. These swaps convert ~~Power’s $300 million of 5.5% Senior Notes due December 2015,~~ $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of June 30, ~~2015~~2016 and December 31, ~~2014,~~2015, the fair value of all the underlying hedges was ~~$15~~$2 million and ~~$22~~$6 million,, respectively. The effect of these hedges reduced interest expense by $2 million and $5 million for the three months ended June 30, 2016 and 2015, respectively, and $4 million and $10 million for the six months ended June 30, 2016 and 2015, respectively.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of June 30, 2016, PSEG had interest rate hedges outstanding totaling $500 million. The hedge ineffectiveness associated with these hedges was immaterial. The total fair value of these interest rate hedges was $(1) million as of June 30, 2016. PSEG interest rate hedges totaling $400 million were terminated during the second quarter and a gain of $2 million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power's $700 million of 3% Senior Notes due June 2021. For additional information see Note 9. Debt and Credit Facilities. There were no outstanding interest rate cash flow hedges as of December 31, 2015. The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $1 million as of June 30, 2016 and was immaterial as of ~~June 30, 2015~~ ~~and~~ December 31, ~~2014, respectively.~~2015. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months are immaterial. The expiration date of the longest-dated interest rate hedge is in May 2021.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with ~~our~~PSEG's accounting policy, these positions have been offset on the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG.

The following tabular disclosure does not include the offsetting of trade receivables and payables.

As of June 30, 2015
Power (A) PSE&G (A) PSEG (A) Consolidated

Cash Flow
Hedges
Not Designated Not Designated
Fair Value
Hedges

Balance Sheet Location
Energy-
Related
Contracts

Energy-
Related
Contracts

Netting
(B)

Total
Power

Energy-
Related
Contracts

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 1
$ 483
$ (345 ) $ 139
$ 5
$ 11
$ 155

Noncurrent Assets —
220
(117 ) 103
—
4
107

Total Mark-to-Market Derivative Assets $ 1
$ 703
$ (462 ) $ 242
$ 5
$ 15
$ 262

Derivative Contracts
Current Liabilities $ —
$ (421 ) $ 349
$ (72 ) $ —
$ —
$ (72 )
Noncurrent Liabilities —
(145 ) 121
(24 ) —
—
(24 )
Total Mark-to-Market Derivative (Liabilities) $ —
$ (566 ) $ 470
$ (96 ) $ —
$ —
$ (96 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 1
$ 137
$ 8
$ 146
$ 5
$ 15
$ 166




	As of June 30, 2016 (A)
	Power									PSE&G			PSEG			Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	460		$	(310	)	$	150		$	—		$	2		$	152
Noncurrent Assets	264			(188		)	76			—			—			76
Total Mark-to-Market Derivative Assets	$	724		$	(498	)	$	226		$	—		$	2		$	228
Derivative Contracts
Current Liabilities	$	(334	)	$	317		$	(17	)	$	(2	)	$	(1	)	$	(20	)
Noncurrent Liabilities	(203		)	189			(14		)	—			—			(14		)
Total Mark-to-Market Derivative (Liabilities)	$	(537	)	$	506		$	(31	)	$	(2	)	$	(1	)	$	(34	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	187		$	8		$	195		$	(2	)	$	1		$	194

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

As of December 31, 2014
Power (A) PSE&G (A) PSEG (A) Consolidated

Cash Flow
Hedges
Not Designated Not Designated
Fair Value
Hedges

Balance Sheet Location
Energy-
Related
Contracts

Energy-
Related
Contracts

Netting
(B)

Total
Power

Energy-
Related
Contracts

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 18
$ 597
$ (408 ) $ 207
$ 18
$ 15
$ 240

Noncurrent Assets —
171
(109 ) 62
8
7
77

Total Mark-to-Market Derivative Assets $ 18
$ 768
$ (517 ) $ 269
$ 26
$ 22
$ 317

Derivative Contracts
Current Liabilities $ —
$ (568 ) $ 436
$ (132 ) $ —
$ —
$ (132 )
Noncurrent Liabilities —
(138 ) 105
(33 ) —
—
(33 )
Total Mark-to-Market Derivative (Liabilities) $ —
$ (706 ) $ 541
$ (165 ) $ —
$ —
$ (165 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 18
$ 62
$ 24
$ 104
$ 26
$ 22
$ 152




	As of December 31, 2015 (A)
	Power									PSE&G			PSEG		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	700		$	(477	)	$	223		$	13		$	6	$	242
Noncurrent Assets	208			(131		)	77			—			—		77
Total Mark-to-Market Derivative Assets	$	908		$	(608	)	$	300		$	13		$	6	$	319
Derivative Contracts
Current Liabilities	$	(513	)	$	437		$	(76	)	$	—		$	—	$	(76	)
Noncurrent Liabilities	(132		)	116			(16		)	(11		)	—		(27		)
Total Mark-to-Market Derivative (Liabilities)	$	(645	)	$	553		$	(92	)	$	(11	)	$	—	$	(103	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	263		$	(55	)	$	208		$	2		$	6	$	216


(A)	Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of June 30, ~~2015~~2016 and December 31, ~~2014~~.2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

(B)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Condensed Consolidated Balance Sheets. As of June 30, ~~2015~~2016 and December 31, ~~2014~~,2015, net cash collateral (received) paid of $8$8 million and ~~$24~~$(55) million,, respectively, were netted against the corresponding net derivative contract positions. Of the $8$8 million as of June 30, ~~2015~~, ~~$(4) million~~ ~~and $(4)~~2016, $(2) million of cash collateral ~~were~~was netted against current assets, and ~~noncurrent assets, respectively, and~~ $7$10 million ~~and $9 million were~~ was netted against current ~~liabilities and noncurrent liabilities, respectively.~~liabilities. Of the ~~$24~~$(55) million as of December 31, ~~2014, $(4)~~2015, $(53) million and ~~$(8)~~$(16) million were netted against current assets and noncurrent assets, respectively, and ~~$32~~$12 million and $4$2 million were netted against current liabilities and noncurrent liabilities, respectively.

Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P and Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully ~~collateralized)~~collateralized, and contracts designated as NPNS) was ~~$82~~$26 million and ~~$127~~$78 million as of June 30, ~~2015~~2016 and December 31, ~~2014~~,2015, respectively. As of June 30, ~~2015~~2016 and December 31, ~~2014~~,2015, Power had the contractual right of offset of ~~$18~~$18 million and $12 million, respectively, related to derivative instruments that are assets with the same counterparty under agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of ~~$64~~$8 million and ~~$109~~$66 million as of June 30, ~~2015~~2016 and December 31, ~~2014~~,2015, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. ~~This~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

~~potential additional collateral is included in the~~ ~~$907 million~~ ~~and~~ ~~$945 million~~ ~~as of~~ ~~June 30, 2015~~ ~~and~~ ~~December 31, 2014, respectively, discussed in Note 8. Commitments and Contingent Liabilities.~~

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended June 30, ~~2015~~2016 and ~~2014.~~2015.

Derivatives in
Cash Flow Hedging
Relationships

Amount of
Pre-Tax
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective
Portion)

Location
of Pre-Tax Gain
(Loss) Reclassified
from AOCI into
Income

Amount of
Pre-Tax
Gain (Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)

Location of
Pre-Tax Gain
(Loss) Recognized in
Income on
Derivatives
(Ineffective Portion)

Amount of
Pre-Tax
Gain (Loss)
Recognized in
Income on
Derivatives
(Ineffective
Portion)

Three Months Ended Three Months Ended Three Months Ended
June 30, June 30, June 30,
2015 2014 2015 2014 2015 2014
Millions
PSEG
Energy-Related Contracts $ —
$ 1
Operating Revenues $ —
$ —
Operating Revenues $ —
$ —

Total PSEG $ —
$ 1
$ —
$ —
$ —
$ —

Power
Energy-Related Contracts $ —
$ 1
Operating Revenues $ —
$ —
Operating Revenues $ —
$ —

Total Power $ —
$ 1
$ —
$ —
$ —
$ —




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Three Months Ended						Three Months Ended					Three Months Ended
	June 30,						June 30,					June 30,
	2016			2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Interest Rate Swaps	(1		)	—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	(1	)	$	—		$	—	$	—		$	—	$	—
Power
Energy-Related Contracts	$	—		$	—	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total Power	$	—		$	—		$	—	$	—		$	—	$	—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the six months ended June 30, ~~2015~~2016 and ~~2014.~~2015.




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Six Months Ended					Six Months Ended					Six Months Ended
	June 30,					June 30,					June 30,
	2016		2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Interest Rate Swaps	2		—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	2	$	1		$	—	$	17		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	17		$	—	$	—

Derivatives in
Cash Flow Hedging
Relationships

Amount of
Pre-Tax
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective
Portion)

Location
of Pre-Tax Gain
(Loss) Reclassified
from AOCI into
Income

Amount of
Pre-Tax
Gain (Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)

Location of
Pre-Tax Gain
(Loss) Recognized in
Income on
Derivatives
(Ineffective Portion)

Amount of
Pre-Tax
Gain (Loss)
Recognized in
Income on
Derivatives
(Ineffective
Portion)

Six Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30,
2015 2014 2015 2014 2015 2014
Millions
PSEG
Energy-Related Contracts $ 1
$ (7 ) Operating Revenues $ 17
$ (12 ) Operating Revenues $ —
$ —

Total PSEG $ 1
$ (7 ) $ 17
$ (12 ) $ —
$ —

Power
Energy-Related Contracts $ 1
$ (7 ) Operating Revenues $ 17
$ (12 ) Operating Revenues $ —
$ —

Total Power $ 1
$ (7 ) $ 17
$ (12 ) $ —
$ —

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

The following reconciles the Accumulated Other Comprehensive Income for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis.

Accumulated Other Comprehensive Income Pre-Tax After-Tax
Millions
Balance as of December 31, 2014 $ 17
$ 10

Gain Recognized in AOCI 1
1

Less: Gain Reclassified into Income (17 ) (10 )
Balance as of March 31, 2015 $ 1
$ 1

Gain Recognized in AOCI —
—

Less: Gain Reclassified into Income —
—

Balance as of June 30, 2015 $ 1
$ 1




Accumulated Other Comprehensive Income	Pre-Tax				After-Tax
	Millions
Balance as of December 31, 2014	$	17			$	10
Gain Recognized in AOCI	3				2
Less: Gain Reclassified into Income	(20		)		(12		)
Balance as of December 31, 2015	$	—			$	—
Gain Recognized in AOCI	3			—	2
Less: Gain Reclassified into Income	—				—
Balance as of March 31, 2016	$	3			$	2
Loss Recognized in AOCI	(1		)		(1		)
Less: Gain Reclassified into Income	—				—
Balance as of June 30, 2016	$	2			$	1

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as ~~normal purchases~~NPNS, such as its BGS contracts and ~~sales~~certain other energy supply contracts, for the three months and six months ended June 30, ~~2015~~2016 and ~~2014.~~

Derivatives Not Designated as Hedges
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives
Pre-Tax Gain (Loss) Recognized in Income on Derivatives
Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
Millions
PSEG and Power
Energy-Related Contracts Operating Revenues $ 124
$ (58 ) $ 48
$ (852 )
Energy-Related Contracts Energy Costs (10 ) (36 ) —
77

Total PSEG and Power $ 114
$ (94 ) $ 48
$ (775 )

~~Power’s~~2015. Power's derivative contracts reflected in ~~the preceding~~these tables include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of these contracts are marked to market. The tables above do not include contracts for which Power has elected the NPNS exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $5 million for each of the three months and $10 million for each of the six months ended June 30, 2015 and 2014, respectively.




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2016			2015			2016		2015
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues	$	(86	)	$	124		$	130	$	48
Energy-Related Contracts	Energy Costs	6			(10		)	8		—
Total PSEG and Power		$	(80	)	$	114		$	138	$	48

The following reflects the gross volume, on an absolute value basis, of derivatives as of June 30, ~~2015~~2016 and December 31, ~~2014~~. 2015.

Type Notional Total PSEG Power PSE&G
Millions
As of June 30, 2015
Natural Gas Dth 259
—
214
45

Electricity MWh 299
—
299
—

Financial Transmission Rights (FTRs) MWh 30
—
30
—

Interest Rate Swaps U.S. Dollars 850
850
—
—

As of December 31, 2014
Natural Gas Dth 274
—
216
58

Electricity MWh 310
—
310
—

FTRs MWh 15
—
15
—

Interest Rate Swaps U.S. Dollars 850
850
—
—




Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of June 30, 2016
Natural Gas	Dekatherm (Dth)	347	—	327	20
Electricity	MWh	326	—	326	—
Financial Transmission Rights (FTRs)	MWh	21	—	21	—
Interest Rate Swaps	U.S. Dollars	1,050	1,050	—	—
As of December 31, 2015
Natural Gas	Dth	201	—	168	33
Electricity	MWh	299	—	299	—
FTRs	MWh	23	—	23	—
Interest Rate Swaps	U.S. Dollars	550	550	—	—

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of June 30, ~~2015~~, ~~99.3%~~2016, 90% of the credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

The following table provides information on Power’s credit risk from others, net of ~~cash~~ collateral, as of June 30, ~~2015~~.2016. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.

Rating
Current
Exposure

Securities
Held as
Collateral

Net
Exposure

Number of
Counterparties
>10%

Net Exposure of
Counterparties
>10%

Millions Millions
Investment Grade—External Rating $ 310
$ 82
$ 302
2
$ 119
(A)
Non-Investment Grade—External Rating 2
—
2
—
—

Investment Grade—No External Rating 10
—
10
—
—

Non-Investment Grade—No External Rating —
—
—
—
—

Total $ 322
$ 82
$ 314
2
$ 119




Rating	Current Exposure		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade—External Rating	$	334	$	129	$	205	2	$	125	(A)
Non-Investment Grade—External Rating	20		—		20		—	—
Investment Grade—No External Rating	8		1		7		—	—
Non-Investment Grade—No External Rating	3		—		3		—	—
Total	$	365	$	130	$	235	2	$	125


(A)	Represents net exposure of ~~$82~~$94 million with PSE&G. The remaining net exposure of ~~$37~~$31 million is with a ~~non- affiliated~~non-affiliated power purchaser which is an investment grade counterparty.

~~The net~~As of June 30, 2016, collateral held from counterparties where Power had credit exposure ~~listed above,~~included $3 million in ~~some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more~~ cash collateral ~~than the outstanding exposure,~~and $127 million in ~~which case there would be no exposure. When~~ letters of ~~credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank.~~ credit.

As of June 30, ~~2015~~2016, Power had ~~138~~140 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 June 30, ~~2015,~~2016, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G's suppliers’ credit exposure is calculated each business day. As of June 30, ~~2015,~~2016, PSE&G had no net credit exposure with suppliers, including Power.

PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Note 11. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and Power have the ability to access. These consist primarily of listed equity ~~securities.~~securities and money market mutual funds.

Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of June 30, ~~2015,~~2016, these consisted primarily of long-term gas supply contracts and certain electric load contracts.

The following tables present information about PSEG’s, PSE&G’s and Power's respective assets and (liabilities) measured at fair value on a recurring basis as of June 30, ~~2015~~2016 and December 31, ~~2014,~~2015, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Recurring Fair Value Measurements as of June 30, 2015
Description Total

Netting (E)

Quoted Market Prices for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs
(Level 3)

Millions
PSEG
Assets:
Cash Equivalents (A) $ 547
$ —
$ 547
$ —
$ —

�� Derivative Contracts:
Energy-Related Contracts (B) $ 247
$ (462 ) $ —
$ 701
$ 8

Interest Rate Swaps (C) $ 15
$ —
$ —
$ 15
$ —

NDT Fund (D)
Equity Securities $ 921
$ —
$ 920
$ 1
$ —

Debt Securities—Govt Obligations $ 455
$ —
$ —
$ 455
$ —

Debt Securities—Other $ 386
$ —
$ —
$ 386
$ —

Other Securities $ 30
$ —
$ 30
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 22
$ —
$ 22
$ —
$ —

Debt Securities—Govt Obligations $ 100
$ —
$ —
$ 100
$ —

Debt Securities—Other $ 90
$ —
$ —
$ 90
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (96 ) $ 470
$ —
$ (566 ) $ —

PSE&G
Assets:
Cash Equivalents (A) $ 151
$ —
$ 151
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 5
$ —
$ —
$ —
$ 5

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 4
$ —
$ 4
$ —
$ —

Debt Securities—Govt Obligations $ 20
$ —
$ —
$ 20
$ —

Debt Securities—Other $ 18
$ —
$ —
$ 18
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Power

Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 242
$ (462 ) $ —
$ 701
$ 3

NDT Fund (D)
Equity Securities $ 921
$ —
$ 920
$ 1
$ —

Debt Securities—Govt Obligations $ 455
$ —
$ —
$ 455
$ —

Debt Securities—Other $ 386
$ —
$ —
$ 386
$ —

Other Securities $ 30
$ —
$ 30
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—Govt Obligations $ 25
$ —
$ —
$ 25
$ —

Debt Securities—Other $ 22
$ —
$ —
$ 22
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (96 ) $ 470
$ —
$ (566 ) $ —




	Recurring Fair Value Measurements as of June 30, 2016
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	570		$	—		$	570	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
Interest Rate Swaps (C)	$	2		$	—		$	—	$	2		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	21		$	—		$	21	$	—		$	—
Debt Securities—Govt Obligations	$	106		$	—		$	—	$	106		$	—
Debt Securities—Other	$	90		$	—		$	—	$	90		$	—
Other Securities	$	5		$	—		$	5	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(33	)	$	506		$	—	$	(537	)	$	(2	)
Interest Rate Swaps (C)	$	(1	)	$	—		$	—	$	(1	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	125		$	—		$	125	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	4		$	—		$	4	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	18		$	—		$	—	$	18		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(2	)	$	—		$	—	$	—		$	(2	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	226		$	(498	)	$	—	$	717		$	7
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	526		$	—		$	—	$	526		$	—
Debt Securities—Other	$	357		$	—		$	—	$	357		$	—
Other Securities	$	49		$	—		$	49	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	22		$	—		$	—	$	22		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(31	)	$	506		$	—	$	(537	)	$	—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Recurring Fair Value Measurements as of December 31, 2014
Description Total Netting (E)
Quoted Market Prices for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs
(Level 3)

Millions
PSEG
Assets:
Cash Equivalents (A) $ 365
$ —
$ 365
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 295
$ (517 ) $ —
$ 774
$ 38

Interest Rate Swaps (C) $ 22
$ —
$ —
$ 22
$ —

NDT Fund (D)
Equity Securities $ 897
$ —
$ 896
$ 1
$ —

Debt Securities—Govt Obligations $ 438
$ —
$ —
$ 438
$ —

Debt Securities—Other $ 339
$ —
$ —
$ 339
$ —

Other Securities $ 106
$ —
$ 106
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 23
$ —
$ 23
$ —
$ —

Debt Securities—Govt Obligations $ 91
$ —
$ —
$ 91
$ —

Debt Securities—Other $ 75
$ —
$ —
$ 75
$ —

Other Securities $ 2
$ —
$ —
$ 2
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (165 ) $ 541
$ —
$ (705 ) $ (1 )
PSE&G
Assets:
Cash Equivalents (A) $ 294
$ —
$ 294
$ —
$ —

Derivative Contracts:
Energy Related Contracts (B) $ 26
$ —
$ —
$ —
$ 26

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—Govt Obligations $ 20
$ —
$ —
$ 20
$ —

Debt Securities—Other $ 16
$ —
$ —
$ 16
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 269
$ (517 ) $ —
$ 774
$ 12

NDT Fund (D)
Equity Securities $ 897
$ —
$ 896
$ 1
$ —

Debt Securities—Govt Obligations $ 438
$ —
$ —
$ 438
$ —

Debt Securities—Other $ 339
$ —
$ —
$ 339
$ —

Other Securities $ 106
$ —
$ 106
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—Govt Obligations $ 21
$ —
$ —
$ 21
$ —

Debt Securities—Other $ 18
$ —
$ —
$ 18
$ —

Other Securities $ 1
$ —
$ —
$ 1
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (165 ) $ 541
$ —
$ (705 ) $ (1 )




	Recurring Fair Value Measurements as of December 31, 2015
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	326		$	—		$	326	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	313		$	(608	)	$	—	$	896		$	25
Interest Rate Swaps (C)	$	6		$	—		$	—	$	6		$	—
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22	$	—		$	—
Debt Securities—Govt Obligations	$	108		$	—		$	—	$	108		$	—
Debt Securities—Other	$	81		$	—		$	—	$	81		$	—
Other Securities	$	2		$	—		$	2	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(103	)	$	553		$	—	$	(644	)	$	(12	)
PSE&G
Assets:
Cash Equivalents (A)	$	160		$	—		$	160	$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	13		$	—		$	—	$	—		$	13
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	21		$	—		$	—	$	21		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	—		$	—		$	—	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	—		$	—	$	—		$	(11	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	300		$	(608	)	$	—	$	896		$	12
NDT Fund (D)
Equity Securities	$	865		$	—		$	865	$	—		$	—
Debt Securities—Govt Obligations	$	488		$	—		$	—	$	488		$	—
Debt Securities—Other	$	359		$	—		$	—	$	359		$	—
Other Securities	$	42		$	—		$	42	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	26		$	—		$	—	$	26		$	—
Debt Securities—Other	$	20		$	—		$	—	$	20		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(92	)	$	553		$	—	$	(644	)	$	(1	)


(A)	Represents money market mutual ~~funds~~funds.

(B)

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.


(C)	Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(D)

The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of June 30, ~~2015,~~2016, net cash collateral (received) paid of $8 million was netted against the corresponding net derivative contract positions. Of the $8 million as of June 30, ~~2015, $(8)~~2016, $(2) million of cash collateral was netted against assets, and ~~$16~~$10 million was netted against liabilities. As of December 31, ~~2014,~~2015, net cash collateral (received) paid of ~~$24~~$(55) million was netted against the corresponding net derivative contract positions. Of the ~~$24~~$(55) million of cash collateral as of December 31, ~~2014, $(12)~~2015, $(69) million ~~of cash collateral~~ was netted against assets, and ~~$36~~$14 million was netted against liabilities.

Additional Information Regarding Level 3 Measurements

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

For PSE&G, ~~and Power,~~ natural gas supply contracts are measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power's electric load contracts in

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. For Power, long-term electric capacity contracts are measured using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of June 30, ~~2015~~2016 and December 31, ~~2014~~.2015.

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position June 30, 2015 Technique(s) Input Range
Assets (Liabilities)
Millions
PSE&G
Gas Natural Gas Supply Contracts $ 5
$ —
Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm
Total PSE&G $ 5
$ —

Power
Electricity Electric Load Contracts $ 3
$ —
Discounted Cash flow Historic Load Variability 0% to +10%
Other Various (A) —
—

Total Power $ 3
$ —

Total PSEG $ 8
$ —




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	June 30, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	—	$	(2	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(2	)
Power
Electricity	Electric Load Contracts	$	7	$	—		Discounted Cash flow	Historic Load Variability	0% to +10%
Total Power		$	7	$	—
Total PSEG		$	7	$	(2	)

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position December 31, 2014 Technique(s) Input Range
Assets (Liabilities)
Millions
PSE&G
Gas Natural Gas Supply Contracts $ 26
$ —
Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm
Total PSE&G $ 26
$ —

Power
Electricity Electric Load Contracts $ 12
$ (1 ) Discounted Cash Flow Historic Load Variability 0% to +10%
Other Various (B) —
—

Total Power $ 12
$ (1 )
Total PSEG $ 38
$ (1 )




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2015					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	13	$	(11	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	13	$	(11	)
Power
Electricity	Electric Load Contracts	$	11	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Electricity	Other	1		—
Total Power		$	12	$	(1	)
Total PSEG		$	25	$	(12	)

~~(A)Includes long-term electric positions which were immaterial as of June 30, 2015.~~


~~(B)~~	~~Includes gas supply positions and long-term electric capacity positions which were immaterial as of December 31, 2014.~~

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and six months ended June 30, ~~2015~~2016 and June 30, ~~2014,~~2015, respectively, follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Three Months andSix Months EndedJune 30, ~~2015~~2016

Three Months Ended June 30, 2015

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of April 1, 2015
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
Balance as of June 30, 2015
Millions
PSEG
Net Derivative Assets (Liabilities) $ 9
$ 5
$ (2 ) $ —
$ (4 ) $ —
$ 8

PSE&G
Net Derivative Assets (Liabilities) $ 7
$ —
$ (2 ) $ —
$ —
$ —
$ 5

Power
Net Derivative Assets (Liabilities) $ 2
$ 5
$ —
$ —
$ (4 ) $ —
$ 3

Six Months Ended June 30, 2015

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of January 1, 2015
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
Balance as of June 30, 2015
Millions
PSEG
Net Derivative Assets (Liabilities) $ 37
$ 8
$ (21 ) $ —
$ (16 ) $ —
$ 8

PSE&G
Net Derivative Assets (Liabilities) $ 26
$ —
$ (21 ) $ —
$ —
$ —
$ 5

Power
Net Derivative Assets (Liabilities) $ 11
$ 8
$ —
$ —
$ (16 ) $ —
$ 3




	Three Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2016		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	21	$	1	$	(12	)	$	—	$	(5	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	10	$	—	$	(12	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	1	$	—		$	—	$	(5	)	$	—	$	7

	Six Months Ended June 30, 2016
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	13	$	16	$	(4	)	$	—	$	(20	)	$	—	$	5
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	(4	)	$	—	$	—		$	—	$	(2	)
Power
Net Derivative Assets (Liabilities)	$	11	$	16	$	—		$	—	$	(20	)	$	—	$	7

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Three Months and Six Months EndedJune 30, ~~2014~~2015

Three Months Ended June 30, 2014

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of April 1, 2014
Included in
Income (E)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
(D)
Balance as of June 30, 2014
Millions
PSEG
Net Derivative Assets (Liabilities) $ 1
$ 6
$ 10
$ —
$ (1 ) $ (3 ) $ 13

PSE&G
Net Derivative Assets (Liabilities) $ 12
$ —
$ 10
$ —
$ —
$ —
$ 22

Power
Net Derivative Assets (Liabilities) $ (11 ) $ 6
$ —
$ —
$ (1 ) $ (3 ) $ (9 )

Six Months Ended June 30, 2014

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of January 1, 2014
Included in
Income (E)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of June 30, 2014
Millions
PSEG
Net Derivative Assets (Liabilities) $ 88
$ (58 ) $ (72 ) $ —
$ 58
$ (3 ) $ 13

PSE&G
Net Derivative Assets (Liabilities) $ 94
$ —
$ (72 ) $ —
$ —
$ —
$ 22

Power
Net Derivative Assets (Liabilities) $ (6 ) $ (58 ) $ —
$ —
$ 58
$ (3 ) $ (9 )




	Three Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	9	$	5	$	(2	)	$	—	$	(4	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	7	$	—	$	(2	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	2	$	5	$	—		$	—	$	(4	)	$	—	$	3

	Six Months Ended June 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of June 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	8	$	(21	)	$	—	$	(16	)	$	—	$	8
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(21	)	$	—	$	—		$	—	$	5
Power
Net Derivative Assets (Liabilities)	$	11	$	8	$	—		$	—	$	(16	)	$	—	$	3


(A)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $1 million and $16 million in Operating Income for the three months and six months ended June 30, 2016, respectively. Of the $1 million in Operating Income, $(4) million is unrealized. Of the $16 million in Operating Income, $(4) million is unrealized.


(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

Table of Contents (UNAUDITED)


(C)	Represents $(5) million and $(20) million in settlements for the three months and six months ended June 30, 2016, respectively. Represents $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015, respectively.


(D)	There were no transfers among levels during the three months and six months ended June 30, 2016 and 2015.


(E)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $5 million and $8 million in Operating Income for the three months and six months ended June 30, 2015, respectively. The $5 million in Operating Income is realized. Of the $8 million in Operating Income, $(9) million is unrealized.


~~(B)~~	Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.


~~(C)~~	Represents $(4) million and $(16) million in settlements for the three months and six months ended June 30, 2015. Includes $(1) million and $58 million in settlements for the three months and six months ended June 30, 2014.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~


~~(D)~~	During the three months and six months ended June 30, 2014, $(3) million of net derivative assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters in which the transfers first occurred as per PSEG's policy.


~~(E)~~	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $6 million and $(58) million in Operating Income for the three months and six months ended June 30, 2014, respectively. The $6 million in Operating Income is unrealized. Of the $(58) million in Operating Income, $1 million is unrealized.

As of June 30, ~~2015,~~2016, PSEG carried ~~$2.7~~$2.8 billion of net assets that are measured at fair value on a recurring basis, of which $8$5 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of June 30, ~~2014~~2015, PSEG carried $~~2.5~~2.7 billion of net assets that are measured at fair value on a recurring basis, of which $138 million of net ~~assets~~liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of June 30, ~~2015~~2016 and December 31, ~~2014~~2015.

As of As of
June 30, 2015 December 31, 2014

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Millions
Long-Term Debt:
PSEG (Parent) (A) $ 9
$ 15
$ 14
$ 22

PSE&G (B) 6,611
6,899
6,312
6,912

Transition Funding (PSE&G) (B) 134
137
251
261

Transition Funding II (PSE&G) (B) —
—
8
8

Power -Recourse Debt (B) 2,544
2,885
2,543
2,930

Energy Holdings:
Project Level, Non-Recourse Debt (C) 16
16
16
16

Total Long-Term Debt $ 9,314
$ 9,952
$ 9,144
$ 10,149




	As of				As of
	June 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	501	$	502	$	503	$	506
PSE&G (B)	7,494		8,624		6,821		7,235
Power - Recourse Debt (B)	2,933		3,274		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	7		7		7		7
Total Long-Term Debt	$	10,935	$	12,407	$	9,568	$	10,256

(A)

Fair value ~~represents~~includes a $500 million floating rate term loan and net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. Carrying amount ~~represents~~includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(B)

~~The~~Given that most bonds do not trade, the fair value amounts of taxable debt ~~fair~~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 ~~present value of each bond’s future cash flows. The~~credit risk into the discount rates, ~~used in the present value analysis are~~pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on ~~an estimate of~~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 ~~yields across the treasury curve. When a bond has embedded options, an interest rate model is used to reflect the impact of interest rate volatility into the analysis (primarily Level 2 measurements).~~or note.


(C)	Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Note 12. Other Income and Deductions

Other Income PSE&G Power Other (A) Consolidated
Millions
Three Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 25
$ —
$ 25

Allowance for Funds Used During Construction 12
—
—
12

Solar Loan Interest 6
—
—
6

     Gain on Insurance Recovery —
28
—
28

Other 1
2
2
5

Total Other Income $ 19
$ 55
$ 2
$ 76

Six Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 54
$ —
$ 54

Allowance for Funds Used During Construction 22
—
—
22

Solar Loan Interest 12
—
—
12

     Gain on Insurance Recovery —
28
—
28

Other 3
2
3
8

  Total Other Income $ 37
$ 84
$ 3
$ 124

Three Months Ended June 30, 2014
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 46
$ —
$ 46

Allowance for Funds Used During Construction 7
—
—
7

Solar Loan Interest 6
—
—
6

Other 1
—
2
3

Total Other Income $ 14
$ 46
$ 2
$ 62

Six Months Ended June 30, 2014
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 78
$ —
$ 78

Allowance for Funds Used During Construction 13
—
—
13

Solar Loan Interest 12
—
—
12

Other 3
1
3
7

Total Other Income $ 28
$ 79
$ 3
$ 110




Other Income	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	23	$	—	$	23
Allowance for Funds Used During Construction	10		—		—		10
Solar Loan Interest	5		—		—		5
Other	4		2		—		6
Total Other Income	$	19	$	25	$	—	$	44
Six Months Ended June 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	48	$	—	$	48
Allowance for Funds Used During Construction	21		—		—		21
Solar Loan Interest	11		—		—		11
Other	7		3		2		12
Total Other Income	$	39	$	51	$	2	$	92
Three Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	12		—		—		12
Solar Loan Interest	6		—		—		6
Gain on Insurance Recovery	—		28		—		28
Other	1		2		2		5
Total Other Income	$	19	$	55	$	2	$	76
Six Months Ended June 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	54	$	—	$	54
Allowance for Funds Used During Construction	22		—		—		22
Solar Loan Interest	12		—		—		12
Gain on Insurance Recovery	—		28		—		28
Other	3		2		3		8
Total Other Income	$	37	$	84	$	3	$	124

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of contents~~ ~~(UNAUDITED)~~

Other Deductions PSE&G Power Other (A) Consolidated
Millions
Three Months Ended June 30, 2015
  NDT Fund Realized Losses and Expenses $ —
$ 6
$ —
$ 6

  Other 1
1
2
4

    Total Other Deductions $ 1
$ 7
$ 2
$ 10

Six Months Ended June 30, 2015
  NDT Fund Realized Losses and Expenses $ —
$ 17
$ —
$ 17

  Other 2
1
2
5

    Total Other Deductions $ 2
$ 18
$ 2
$ 22

Three Months Ended June 30, 2014
  NDT Fund Realized Losses and Expenses $ —
$ 8
$ —
$ 8

  Other 1
1
—
2

  Total Other Deductions $ 1
$ 9
$ —
$ 10

Six Months Ended June 30, 2014
  NDT Fund Realized Losses and Expenses $ —
$ 14
$ —
$ 14

  Other 1
5
2
8

  Total Other Deductions $ 1
$ 19
$ 2
$ 22




Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	8	$	—	$	8
Other	1		1		—		2
Total Other Deductions	$	1	$	9	$	—	$	10
Six Months Ended June 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	26	$	—	$	26
Other	2		1		2		5
Total Other Deductions	$	2	$	27	$	2	$	31
Three Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	6	$	—	$	6
Other	1		1		2		4
Total Other Deductions	$	1	$	7	$	2	$	10
Six Months Ended June 30, 2015
NDT Fund Realized Losses and Expenses	$	—	$	17	$	—	$	17
Other	2		1		2		5
Total Other Deductions	$	2	$	18	$	2	$	22


(A)	Other ~~primarily~~ consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Note 13. Income Taxes

PSEG’s, PSE&G’s and Power's effective tax rates for the three months and six months ended June 30, ~~2015~~2016 and ~~2014~~2015 were as follows:

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
PSEG 35.0% 34.8% 38.5% 38.4%
PSE&G 38.4% 36.5% 39.0% 38.6%
Power 30.3% 28.9% 37.9% 37.8%

~~An explanation of the material changes in the effective tax rates is as follows:~~




	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
PSEG	32.7%	35.0%	36.2%	38.5%
PSE&G	35.4%	38.4%	36.1%	39.0%
Power	50.0%	30.3%	39.5%	37.9%

For the three months and six months ended June 30, ~~2015, PSE&G's~~2016, the overall decreases in PSEG's effective tax ~~rate was lower than~~rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions, plant and other flow through items, offset by the ~~beneficial impact~~absence of the benefit recorded in 2015 associated with the Nuclear Decommissioning Tax Carryback.

For the three months and six months ended June 30, 2016, the overall decreases in PSE&G's effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions and plant ~~related flow-through~~and other flow through items.

For the three months ended June 30, ~~2015, Power’s~~2016, the increase in Power's effective tax rate was lower than the statutory tax rate of 40.85% due primarily to the beneficial impact of the manufacturing deduction under Section 199 of the Internal Revenue Code (IRC) and the benefit associated with the income tax rate differential of carrying back federal net operating tax losses under section 172(f) of the IRC.

~~For the three months ended June 30, 2015,~~ as compared to the same period in the prior year ~~PSE&G's increase~~as well as to the statutory tax rate of 40.85%, was due primarily to the absence of the ~~2014 tax flow-through~~ benefit ~~associated with injuries and damages and an unfavorable increase~~recorded in ~~the flow-through of bad debt expense for 2015.~~

~~For the three months ended June 30,~~ 2015 as compared to the same period in the prior year, Power's increase was due primarily to the net reduction in the manufacturing deduction under Section 199 of the Internal Revenue Code and a reduction in purchased state income tax credits, partially offset by the tax benefit associated with the ~~income tax~~Nuclear Decommissioning Tax Carryback.

The Tax Increase Prevention Act of 2014 extended the 50% bonus depreciation rules for qualified property placed in service before January 1, 2015 and for long production property placed in service in 2015.

The Protecting Americans from Tax Hikes Act of 2015 (Tax Act) extended the 50% bonus depreciation rules for qualified property placed in service from January 1, 2015 through December 31, 2017. The rate ~~differential of carrying back federal net operating tax losses under section 172(f)~~is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. The Tax Act also extended the 30% ITC for qualified property placed in service starting January 1, 2016 through December 31, 2019 but reduces the ITC rate to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the ~~IRC.~~extensions of the ITC rate will depend upon future transactions.

These provisions have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax

PSEG Other Comprehensive Income (Loss)
Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of March 31, 2015 $ 1
$ (403 ) $ 132
$ (270 )
Other Comprehensive Income before Reclassifications —
—
(14 ) (14 )
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
8
(1 ) 7

Net Current Period Other Comprehensive Income (Loss) —
8
(15 ) (7 )
Balance as of June 30, 2015 $ 1
$ (395 ) $ 117
$ (277 )

PSEG Other Comprehensive Income (Loss)
Three Months Ended June 30, 2014
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of March 31, 2014 $ —
$ (234 ) $ 147
$ (87 )
Other Comprehensive Income before Reclassifications 1
—
23
24

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
2
(12 ) (10 )
Net Current Period Other Comprehensive Income (Loss) 1
2
11
14

Balance as of June 30, 2014 $ 1
$ (232 ) $ 158
$ (73 )

Other Comprehensive Income (Loss)
PSEG Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2014 $ 10
$ (411 ) $ 118
$ (283 )
Other Comprehensive Income before Reclassifications 1
—
2
3

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (10 ) 16
(3 ) 3

Net Current Period Other Comprehensive Income (Loss) (9 ) 16
(1 ) 6

Balance as of June 30, 2015 $ 1
$ (395 ) $ 117
$ (277 )

PSEG Other Comprehensive Income (Loss)
Six Months Ended June 30, 2014
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2013 $ (2 ) $ (238 ) $ 145
$ (95 )
Other Comprehensive Income before Reclassifications (4 ) —
34
30

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 7
6
(21 ) (8 )
Net Current Period Other Comprehensive Income (Loss) 3
6
13
22

Balance as of June 30, 2014 $ 1
$ (232 ) $ 158
$ (73 )




PSEG	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2016	$	2		$	(378	)	$	107		$	(269	)
Other Comprehensive Income before Reclassifications	(1		)	—			8			7
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			2			10
Net Current Period Other Comprehensive Income (Loss)	(1		)	8			10			17
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)

PSEG	Other Comprehensive Income (Loss)
	Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of March 31, 2015	$	1		$	(403	)	$	132		$	(270	)
Other Comprehensive Income before Reclassifications	—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			(1		)	7
Net Current Period Other Comprehensive Income (Loss)	—			8			(15		)	(7		)
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)

PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	1			—			18			19
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			16			8			24
Net Current Period Other Comprehensive Income (Loss)	1			16			26			43
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)

PSEG	Other Comprehensive Income (Loss)
	Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2014	$	10		$	(411	)	$	118		$	(283	)
Other Comprehensive Income before Reclassifications	1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	16			(3		)	3
Net Current Period Other Comprehensive Income (Loss)	(9		)	16			(1		)	6
Balance as of June 30, 2015	$	1		$	(395	)	$	117		$	(277	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Power Other Comprehensive Income (Loss)
Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of March 31, 2015 $ 2
$ (344 ) $ 126
$ (216 )
Other Comprehensive Income before Reclassifications —
—
(14 ) (14 )
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
7
—
7

Net Current Period Other Comprehensive Income (Loss) —
7
(14 ) (7 )
Balance as of June 30, 2015 $ 2
$ (337 ) $ 112
$ (223 )

Power Other Comprehensive Income (Loss)
Three Months Ended June 30, 2014
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of March 31, 2014 $ —
$ (201 ) $ 144
$ (57 )
Other Comprehensive Income before Reclassifications 2
—
21
23

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
2
(12 ) (10 )
Net Current Period Other Comprehensive Income (Loss) 2
2
9
13

Balance as of June 30, 2014 $ 2
$ (199 ) $ 153
$ (44 )

Power Other Comprehensive Income (Loss)
Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2014 $ 11
$ (351 ) $ 112
$ (228 )
Other Comprehensive Income before Reclassifications 1
—
2
3

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (10 ) 14
(2 ) 2

Net Current Period Other Comprehensive Income (Loss) (9 ) 14
—
5

Balance as of June 30, 2015 $ 2
$ (337 ) $ 112
$ (223 )

Power Other Comprehensive Income (Loss)
Six Months Ended June 30, 2014
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2013 $ (1 ) $ (204 ) $ 142
$ (63 )
Other Comprehensive Income before Reclassifications (4 ) —
31
27

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 7
5
(20 ) (8 )
Net Current Period Other Comprehensive Income (Loss) 3
5
11
19

Balance as of June 30, 2014 $ 2
$ (199 ) $ 153
$ (44 )




Power		Other Comprehensive Income (Loss)
		Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)		Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
		Millions
Balance as of March 31, 2016		$	—		$	(320	)	$	103		$	(217	)
Other Comprehensive Income before Reclassifications		—			—			6			6
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		—			7			3			10
Net Current Period Other Comprehensive Income (Loss)		—			7			9			16
Balance as of June 30, 2016		$	—		$	(313	)	$	112		$	(201	)

Power		Other Comprehensive Income (Loss)
		Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)		Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
		Millions
Balance as of March 31, 2015		$	2		$	(344	)	$	126		$	(216	)
Other Comprehensive Income before Reclassifications		—			—			(14		)	(14		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		—			7			—			7
Net Current Period Other Comprehensive Income (Loss)		—			7			(14		)	(7		)
Balance as of June 30, 2015		$	2		$	(337	)	$	112		$	(223	)

Power		Other Comprehensive Income (Loss)
		Six Months Ended June 30, 2016
Accumulated Other Comprehensive Income (Loss)		Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
		Millions
Balance as of December 31, 2015		$	—		$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications		—			—			16			16
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		—			14			9			23
Net Current Period Other Comprehensive Income (Loss)		—			14			25			39
Balance as of June 30, 2016		$	—		$	(313	)	$	112		$	(201	)
	��
Power		Other Comprehensive Income (Loss)
		Six Months Ended June 30, 2015
Accumulated Other Comprehensive Income (Loss)		Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
		Millions
Balance as of December 31, 2014		$	11		$	(351	)	$	112		$	(228	)
Other Comprehensive Income before Reclassifications		1			—			2			3
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		(10		)	14			(2		)	2
Net Current Period Other Comprehensive Income (Loss)		(9		)	14			—			5
Balance as of June 30, 2015		$	2		$	(337	)	$	112		$	(223	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations June 30, 2015 June 30, 2015
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Energy-Related Contracts Operating Revenues $ —
$ —
$ —
$ 17
$ (7 ) $ 10

Total Cash Flow Hedges —
—
—
17
(7 ) 10

Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2
6
(2 ) 4

Amortization of Actuarial Loss O&M Expense (17 ) 7
(10 ) (34 ) 14
(20 )
Total Pension and OPEB Plans (14 ) 6
(8 ) (28 ) 12
(16 )
Available-for-Sale Securities
Realized Gains Other Income 16
(8 ) 8
35
(18 ) 17

Realized Losses Other Deductions (4 ) 2
(2 ) (13 ) 7
(6 )
Other-Than-Temporary Impairments (OTTI) OTTI (10 ) 5
(5 ) (15 ) 7
(8 )
Total Available-for-Sale Securities 2
(1 ) 1
7
(4 ) 3

Total $ (12 ) $ 5
$ (7 ) $ (4 ) $ 1
$ (3 )

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations June 30, 2014 June 30, 2014
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Energy-Related Contracts Operating Revenues $ —
$ —
$ —
$ (12 ) $ 5
$ (7 )
Total Cash Flow Hedges —
—
—
(12 ) 5
(7 )
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2
5
(2 ) 3

Amortization of Actuarial Loss O&M Expense (6 ) 2
(4 ) (14 ) 5
(9 )
Total Pension and OPEB Plans (3 ) 1
(2 ) (9 ) 3
(6 )
Available-for-Sale Securities
Realized Gains Other Income 33
(17 ) 16
58
(30 ) 28

Realized Losses Other Deductions (6 ) 3
(3 ) (10 ) 5
(5 )
OTTI OTTI (2 ) 1
(1 ) (4 ) 2
(2 )
Total Available-for-Sale Securities 25
(13 ) 12
44
(23 ) 21

Total $ 22
$ (12 ) $ 10
$ 23
$ (15 ) $ 8




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	3			(1		)	2			6			(2		)	4
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)	(34		)	14			(20		)
Total Pension and OPEB Plans		(14		)	6			(8		)	(28		)	12			(16		)
Available-for-Sale Securities
Realized Gains	Other Income	12			(6		)	6			28			(14		)	14
Realized Losses	Other Deductions	(7		)	4			(3		)	(24		)	12			(12		)
Other-Than-Temporary Impairments (OTTI)	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(5		)	3			(2		)	(16		)	8			(8		)
Total		$	(19	)	$	9		$	(10	)	$	(44	)	$	20		$	(24	)




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2015									June 30, 2015
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	3			(1		)	2			6			(2		)	4
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)	(34		)	14			(20		)
Total Pension and OPEB Plans		(14		)	6			(8		)	(28		)	12			(16		)
Available-for-Sale Securities
Realized Gains	Other Income	16			(8		)	8			35			(18		)	17
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		2			(1		)	1			7			(4		)	3
Total		$	(12	)	$	5		$	(7	)	$	(4	)	$	1		$	(3	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)




Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2016									June 30, 2016
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	2		$	(1	)	$	1		$	5		$	(2	)	$	3
Amortization of Actuarial Loss	O&M Expense	(14		)	6			(8		)	(29		)	12			(17		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	10			(5		)	5			25			(13		)	12
Realized Losses	Other Deductions	(6		)	3			(3		)	(22		)	11			(11		)
OTTI	OTTI	(10		)	5			(5		)	(20		)	10			(10		)
Total Available-for-Sale Securities		(6		)	3			(3		)	(17		)	8			(9		)
Total		$	(18	)	$	8		$	(10	)	$	(41	)	$	18		$	(23	)




Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	June 30, 2015									June 30, 2015
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	3			(1		)	2			6			(2		)	4
Amortization of Actuarial Loss	O&M Expense	(15		)	6			(9		)	(30		)	12			(18		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(24		)	10			(14		)
Available-for-Sale Securities
Realized Gains	Other Income	14			(7		)	7			33			(17		)	16
Realized Losses	Other Deductions	(4		)	2			(2		)	(13		)	7			(6		)
OTTI	OTTI	(10		)	5			(5		)	(15		)	7			(8		)
Total Available-for-Sale Securities		—			—			—			5			(3		)	2
Total		$	(12	)	$	5		$	(7	)	$	(2	)	$	—		$	(2	)

Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Six Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations June 30, 2014 June 30, 2014
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Energy-Related Contracts Operating Revenues $ —
$ —
$ —
$ (12 ) $ 5
$ (7 )
Total Cash Flow Hedges —
—
—
(12 ) 5
(7 )
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 2
(1 ) 1
4
(2 ) 2

Amortization of Actuarial Loss O&M Expense (6 ) 3
(3 ) (12 ) 5
(7 )
Total Pension and OPEB Plans (4 ) 2
(2 ) (8 ) 3
(5 )
Available-for-Sale Securities
Realized Gains Other Income 33
(17 ) 16
56
(29 ) 27

Realized Losses Other Deductions (6 ) 3
(3 ) (10 ) 5
(5 )
OTTI OTTI (2 ) 1
(1 ) (4 ) 2
(2 )
Total Available-for-Sale Securities 25
(13 ) 12
42
(22 ) 20

Total $ 21
$ (11 ) $ 10
$ 22
$ (14 ) $ 8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Note 15. Earnings Per Share (EPS) and Dividends

Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under ~~our~~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.~~EPS:

Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014
Basic Diluted Basic Diluted Basic Diluted Basic Diluted

EPS Numerator (Millions)

Net Income $ 345
$ 345
$ 212
$ 212
$ 931
$ 931
$ 598
$ 598

EPS Denominator (Millions)

Weighted Average Common Shares Outstanding 506
506
506
506
506
506
506
506

Effect of Stock Based Compensation Awards —
2
—
2
—
2
—
2

Total Shares 506
508
506
508
506
508
506
508

EPS
Net Income $ 0.68
$ 0.68
$ 0.42
$ 0.42
$ 1.84
$ 1.83
$ 1.18
$ 1.18




	Three Months Ended June 30,								Six Months Ended June 30,
	2016				2015				2016				2015
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	187	$	187	$	345	$	345	$	658	$	658	$	931	$	931
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		506		506		505		505		506		506
Effect of Stock Based Compensation Awards	—		3		—		2		—		3		—		2
Total Shares	505		508		506		508		505		508		506		508

EPS
Net Income	$	0.37	$	0.37	$	0.68	$	0.68	$	1.30	$	1.30	$	1.84	$	1.83

There were approximately 0.3 million and 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months and six months ended June 30, 2016 and 2015, respectively.

Three Months Ended Six Months Ended
June 30, June 30,
Dividend Payments on Common Stock 2015 2014 2015 2014
Per Share $ 0.39
$ 0.37
$ 0.78
$ 0.74

In Millions $ 197
$ 187
$ 394
$ 374




	Three Months Ended				Six Months Ended
	June 30,				June 30,
Dividend Payments on Common Stock	2016		2015		2016		2015
Per Share	$	0.41	$	0.39	$	0.82	$	0.78
In Millions	$	208	$	197	$	415	$	394

On July 19, 2016, PSEG's Board of Directors approved a $0.41 per share common stock dividend for the third quarter of 2016.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Note 16. Financial Information by Business ~~Segments~~Segment

PSE&G Power Other (A) Eliminations (B) Consolidated
Millions
Three Months Ended June 30, 2015
Total Operating Revenues $ 1,466
$ 1,025
$ 108
$ (285 ) $ 2,314

Net Income (Loss) 167
166
12
—
345

Gross Additions to Long-Lived Assets 631
348
17
—
996

Six Months Ended June 30, 2015
Total Operating Revenues $ 3,468
$ 2,750
$ 206
$ (975 ) $ 5,449

Net Income (Loss) 409
501
21
—
931

Gross Additions to Long-Lived Assets 1,230
487
26
—
1,743

Three Months Ended June 30, 2014
Total Operating Revenues $ 1,435
$ 986
$ 131
$ (303 ) $ 2,249

Net Income (Loss) 151
54
7
—
212

Gross Additions to Long-Lived Assets 515
100
5
—
620

Six Months Ended June 30, 2014
Total Operating Revenues $ 3,580
$ 2,686
$ 236
$ (1,030 ) $ 5,472

Net Income (Loss) 365
218
15
—
598

Gross Additions to Long-Lived Assets 996
226
7
—
1,229

As of June 30, 2015
Total Assets $ 22,721
$ 12,166
$ 3,017
$ (1,692 ) $ 36,212

Investments in Equity Method Subsidiaries $ —
$ 116
$ 2
$ —
$ 118

As of December 31, 2014
Total Assets $ 22,223
$ 12,046
$ 2,799
$ (1,735 ) $ 35,333

Investments in Equity Method Subsidiaries $ —
$ 121
$ 2
$ —
$ 123




	PSE&G		Power			Other (A)		Eliminations (B)			Consolidated
	Millions
Three Months Ended June 30, 2016
Total Operating Revenues	$	1,350	$	714		$	127	$	(286	)	$	1,905
Net Income (Loss)	179		(11		)	19		—			187
Gross Additions to Long-Lived Assets	631		265			10		—			906
Six Months Ended June 30, 2016
Operating Revenues	$	3,062	$	2,027		$	249	$	(817	)	$	4,521
Net Income (Loss)	441		181			36		—			658
Gross Additions to Long-Lived Assets	1,355		598			18		—			1,971
Three Months Ended June 30, 2015
Total Operating Revenues	$	1,466	$	1,025		$	108	$	(285	)	$	2,314
Net Income (Loss)	167		166			12		—			345
Gross Additions to Long-Lived Assets	631		348			17		—			996
Six Months Ended June 30, 2015
Operating Revenues	$	3,468	$	2,750		$	206	$	(975	)	$	5,449
Net Income (Loss)	409		501			21		—			931
Gross Additions to Long-Lived Assets	1,230		487			26		—			1,743
As of June 30, 2016
Total Assets	$	24,737	$	13,278		$	2,873	$	(1,843	)	$	39,045
Investments in Equity Method Subsidiaries	$	—	$	112		$	—	$	—		$	112
As of December 31, 2015
Total Assets	$	23,677	$	12,250		$	2,810	$	(1,202	)	$	37,535
Investments in Equity Method Subsidiaries	$	—	$	119		$	—	$	—		$	119


(A)	Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.

(B)

Intercompany eliminations primarily ~~related~~relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 17. Related-Party Transactions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Note 17. Related-Party Transactions

The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

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 Transactions 2015 2014 2015 2014
Millions
Billings from Affiliates:
Billings from Power primarily through BGS and BGSS (A) $ 297
$ 297
$ 993
$ 1,028

Administrative Billings from Services (B) 65
64
131
124

Total Billings from Affiliates $ 362
$ 361
$ 1,124
$ 1,152




	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2016		2015		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Administrative Billings from Services (B)	82		65		151		131
Total Billings from Affiliates	$	379	$	362	$	993	$	1,124

As of As of
Related-Party Transactions June 30, 2015 December 31, 2014
Millions
Receivable from PSEG (C) $ 52
$ 274

Payable to Power (A) $ 158
$ 313

Payable to Services (B) 57
66

Accounts Payable—Affiliated Companies $ 215
$ 379

Working Capital Advances to Services (D) $ 33
$ 33

Long-Term Accrued Taxes Payable
$ 161
$ 116




	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSEG (C)	$	—	$	222
Payable to Power (A)	$	94	$	212
Payable to Services (B)	79		80
Payable to PSEG (C)	6		—
Accounts Payable—Affiliated Companies	$	179	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	99	$	109

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 Transactions 2015 2014 2015 2014
Millions
Billings to Affiliates:
Billings to PSE&G primarily through BGS and BGSS Contracts (A) $ 297
$ 297
$ 993
$ 1,028

Billings from Affiliates:
Administrative Billings from Services (B) $ 46
$ 46
$ 91
$ 88




	Three Months Ended				Six Months Ended
	June 30,				June 30,
Related-Party Transactions	2016		2015		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	297	$	297	$	842	$	993
Billings from Affiliates:
Administrative Billings from Services (B)	$	45	$	46	$	90	$	91

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

As of As of
Related-Party Transactions June 30, 2015 December 31, 2014
Millions
Receivables from PSE&G (A) $ 158
$ 313

Payable to Services (B) $ 27
$ 23

Payable to PSEG (C) 101
95

Accounts Payable—Affiliated Companies $ 128
$ 118

Short-Term Loan (to) from Affiliate (Demand Note (to) PSEG) (E) $ 950
$ 584

Working Capital Advances to Services (D) $ 17
$ 17

Long-Term Accrued Taxes Payable
$ 56
$ 41




	As of		As of
Related-Party Transactions	June 30, 2016		December 31, 2015
	Millions
Receivables from PSE&G (A)	$	94	$	212
Receivables from PSEG (C)	—		64
Accounts Receivable—Affiliated Companies	$	94	$	276
Payable to Services (B)	$	28	$	33
Payable to PSEG (C)	74		—
Accounts Payable—Affiliated Companies	$	102	$	33
Short-Term Loan Due (to) from Affiliate (E)	$	1,335	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	22	$	35

(A)

PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other in compliance with FERC and BPU affiliate rules.


(B)	Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.

(C)

PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.


(D)	PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Condensed Consolidated Balance Sheets.


(E)	Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Note 18. Guarantees of Debt

Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor ~~subsidiaries.~~subsidiaries, as of June 30, 2016 and December 31, 2015 and for the three months and six months ended June 30, 2016 and 2015.

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
Three Months Ended June 30, 2015
Operating Revenues $ —
$ 1,012
$ 39
$ (26 ) $ 1,025

Operating Expenses (1 ) 787
37
(26 ) 797

Operating Income (Loss) 1
225
2
—
228

Equity Earnings (Losses) of Subsidiaries 186
(1 ) 5
(185 ) 5

Other Income 12
55
—
(12 ) 55

Other Deductions (1 ) (6 ) —
—
(7 )
Other-Than-Temporary Impairments —
(10 ) —
—
(10 )
Interest Expense (33 ) (7 ) (5 ) 12
(33 )
Income Tax Benefit (Expense) 1
(73 ) —
—
(72 )
Net Income (Loss) $ 166
$ 183
$ 2
$ (185 ) $ 166

Comprehensive Income (Loss) $ 159
$ 169
$ 2
$ (171 ) $ 159

Six Months Ended June 30, 2015
Operating Revenues $ —
$ 2,727
$ 107
$ (84 ) $ 2,750

Operating Expenses 4
1,918
100
(84 ) 1,938

Operating Income (Loss) (4 ) 809
7
—
812

Equity Earnings (Losses) of Subsidiaries 535
(2 ) 8
(533 ) 8

Other Income 23
85
—
(24 ) 84

Other Deductions (1 ) (17 ) —
—
(18 )
Other-Than-Temporary Impairments —
(15 ) —
—
(15 )
Interest Expense (62 ) (16 ) (10 ) 24
(64 )
Income Tax Benefit (Expense) 10
(315 ) (1 ) —
(306 )
Net Income (Loss) $ 501
$ 529
$ 4
$ (533 ) $ 501

Comprehensive Income (Loss) $ 506
$ 520
$ 4
$ (524 ) $ 506

Six Months Ended June 30, 2015

Net Cash Provided By (Used In)
   Operating Activities
$ 410
$ 1,508
$ 61
$ (687 ) $ 1,292

Net Cash Provided By (Used In)
   Investing Activities
$ (480 ) $ (963 ) $ (210 ) $ 766
$ (887 )

Net Cash Provided By (Used In)
   Financing Activities
$ 70
$ (543 ) $ 150
$ (79 ) $ (402 )




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2016
Operating Revenues	$	—		$	700		$	46		$	(32	)	$	714
Operating Expenses	2			716			40			(32		)	726
Operating Income (Loss)	(2		)	(16		)	6			—			(12		)
Equity Earnings (Losses) of Subsidiaries	(1		)	1			4			—			4
Other Income	17			30			—			(22		)	25
Other Deductions	—			(9		)	—			—			(9		)
Other-Than-Temporary Impairments	—			(10		)	—			—			(10		)
Interest Expense	(31		)	(7		)	(4		)	22			(20		)
Income Tax Benefit (Expense)	6			3			2			—			11
Net Income (Loss)	$	(11	)	$	(8	)	$	8		$	—		$	(11	)
Comprehensive Income (Loss)	$	5		$	1		$	8		$	(9	)	$	5
Six Months Ended June 30, 2016
Operating Revenues	$	—		$	2,002		$	88		$	(63	)	$	2,027
Operating Expenses	12			1,668			79			(63		)	1,696
Operating Income (Loss)	(12		)	334			9			—			331
Equity Earnings (Losses) of Subsidiaries	204			—			6			(204		)	6
Other Income	34			62			—			(45		)	51
Other Deductions	—			(27		)	—			—			(27		)
Other-Than-Temporary Impairments	—			(20		)	—			—			(20		)
Interest Expense	(61		)	(17		)	(9		)	45			(42		)
Income Tax Benefit (Expense)	16			(137		)	3			—			(118		)
Net Income (Loss)	$	181		$	195		$	9		$	(204	)	$	181
Comprehensive Income (Loss)	$	220		$	220		$	9		$	(229	)	$	220
Six Months Ended June 30, 2016
Net Cash Provided By (Used In) Operating Activities	$	337		$	777		$	159		$	(356	)	$	917
Net Cash Provided By (Used In) Investing Activities	$	(1,287	)	$	(504	)	$	(395	)	$	579		$	(1,607	)
Net Cash Provided By (Used In) Financing Activities	$	951		$	(273	)	$	239		$	(223	)	$	694

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
Three Months Ended June 30, 2014
Operating Revenues $ —
$ 972
$ 42
$ (28 ) $ 986

Operating Expenses 5
903
40
(29 ) 919

Operating Income (Loss) (5 ) 69
2
1
67

Equity Earnings (Losses) of Subsidiaries 57
(3 ) 3
(54 ) 3

Other Income 8
47
—
(9 ) 46

Other Deductions —
(8 ) —
(1 ) (9 )

Other-Than-Temporary
   Impairments
—
(2 ) —
—
(2 )
Interest Expense (27 ) (6 ) (5 ) 9
(29 )
Income Tax Benefit (Expense) 21
(43 ) —
—
(22 )
Net Income (Loss) $ 54
$ 54
$ —
$ (54 ) $ 54

Comprehensive Income (Loss) $ 67
$ 66
$ —
$ (66 ) $ 67

Six Months Ended June 30, 2014
Operating Revenues $ —
$ 2,656
$ 82
$ (52 ) $ 2,686

Operating Expenses 9
2,307
74
(53 ) 2,337

Operating Income (Loss) (9 ) 349
8
1
349

Equity Earnings (Losses) of Subsidiaries 234
(3 ) 7
(231 ) 7

Other Income 16
80
—
(17 ) 79

Other Deductions (4 ) (14 ) —
(1 ) (19 )
Other-Than-Temporary Impairments —
(4 ) —
—
(4 )
Interest Expense (55 ) (13 ) (10 ) 17
(61 )
Income Tax Benefit (Expense) 36
(168 ) (1 ) —
(133 )
Net Income (Loss) $ 218
$ 227
$ 4
$ (231 ) $ 218

Comprehensive Income (Loss) $ 237
$ 242
$ 4
$ (246 ) $ 237

Six Months Ended June 30, 2014

Net Cash Provided By (Used In)
   Operating Activities
$ 292
$ 950
$ 32
$ (460 ) $ 814

Net Cash Provided By (Used In)
   Investing Activities
$ 138
$ (415 ) $ (16 ) $ 57
$ (236 )

Net Cash Provided By (Used In)
   Financing Activities
$ (430 ) $ (534 ) $ (17 ) $ 403
$ (578 )




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended June 30, 2015
Operating Revenues	$	—		$	1,012		$	39		$	(26	)	$	1,025
Operating Expenses	(1		)	787			37			(26		)	797
Operating Income (Loss)	1			225			2			—			228
Equity Earnings (Losses) of Subsidiaries	186			(1		)	5			(185		)	5
Other Income	12			55			—			(12		)	55
Other Deductions	(1		)	(6		)	—			—			(7		)
Other-Than-Temporary Impairments	—			(10		)	—			—			(10		)
Interest Expense	(33		)	(7		)	(5		)	12			(33		)
Income Tax Benefit (Expense)	1			(73		)	—			—			(72		)
Net Income (Loss)	$	166		$	183		$	2		$	(185	)	$	166
Comprehensive Income (Loss)	$	159		$	169		$	2		$	(171	)	$	159
Six Months Ended June 30, 2015
Operating Revenues	$	—		$	2,727		$	107		$	(84	)	$	2,750
Operating Expenses	4			1,918			100			(84		)	1,938
Operating Income (Loss)	(4		)	809			7			—			812
Equity Earnings (Losses) of Subsidiaries	535			(2		)	8			(533		)	8
Other Income	23			85			—			(24		)	84
Other Deductions	(1		)	(17		)	—			—			(18		)
Other-Than-Temporary Impairments	—			(15		)	—			—			(15		)
Interest Expense	(62		)	(16		)	(10		)	24			(64		)
Income Tax Benefit (Expense)	10			(315		)	(1		)	—			(306		)
Net Income (Loss)	$	501		$	529		$	4		$	(533	)	$	501
Comprehensive Income (Loss)	$	506		$	520		$	4		$	(524	)	$	506
Six Months Ended June 30, 2015
Net Cash Provided By (Used In) Operating Activities	$	410		$	1,508		$	61		$	(687	)	$	1,292
Net Cash Provided By (Used In) Investing Activities	$	(480	)	$	(963	)	$	(210	)	$	766		$	(887	)
Net Cash Provided By (Used In) Financing Activities	$	70		$	(543	)	$	150		$	(79	)	$	(402	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~table~~Table of ~~contents~~Contents (UNAUDITED)

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
As of June 30, 2015
Current Assets $ 4,613
$ 1,678
$ 136
$ (4,216 ) $ 2,211

Property, Plant and Equipment, net 80
6,290
1,337
—
7,707

Investment in Subsidiaries 4,409
289
—
(4,698 ) —

Noncurrent Assets 258
2,026
132
(168 ) 2,248

Total Assets $ 9,360
$ 10,283
$ 1,605
$ (9,082 ) $ 12,166

Current Liabilities $ 987
$ 3,532
$ 774
$ (4,216 ) $ 1,077

Noncurrent Liabilities 465
2,534
350
(168 ) 3,181

Long-Term Debt 2,244
—
—
—
2,244

Member's Equity 5,664
4,217
481
(4,698 ) 5,664

Total Liabilities and Member's Equity $ 9,360
$ 10,283
$ 1,605
$ (9,082 ) $ 12,166

As of December 31, 2014
Current Assets $ 4,263
$ 2,037
$ 150
$ (4,091 ) $ 2,359

Property, Plant and Equipment, net 81
6,265
1,169
—
7,515

Investment in Subsidiaries 4,516
120
—
(4,636 ) —

Noncurrent Assets 278
1,952
137
(195 ) 2,172

Total Assets $ 9,138
$ 10,374
$ 1,456
$ (8,922 ) $ 12,046

Current Liabilities $ 883
$ 3,606
$ 786
$ (4,091 ) $ 1,184

Noncurrent Liabilities 454
2,442
360
(195 ) 3,061

Long-Term Debt 2,243
—
—
—
2,243

Member's Equity 5,558
4,326
310
(4,636 ) 5,558

Total Liabilities and Member's Equity $ 9,138
$ 10,374
$ 1,456
$ (8,922 ) $ 12,046




	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of June 30, 2016
Current Assets	$	5,490	$	1,655	$	231	$	(4,828	)	$	2,548
Property, Plant and Equipment, net	58		6,476		1,944		—			8,478
Investment in Subsidiaries	4,419		345		—		(4,764		)	—
Noncurrent Assets	134		2,041		128		(51		)	2,252
Total Assets	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
Current Liabilities	$	1,079	$	3,719	$	1,293	$	(4,828	)	$	1,263
Noncurrent Liabilities	420		2,652		392		(51		)	3,413
Long-Term Debt	2,380		—		—		—			2,380
Member's Equity	6,222		4,146		618		(4,764		)	6,222
Total Liabilities and Member's Equity	$	10,101	$	10,517	$	2,303	$	(9,643	)	$	13,278
As of December 31, 2015
Current Assets	$	4,501	$	1,912	$	364	$	(4,828	)	$	1,949
Property, Plant and Equipment, net	83		6,502		1,542		—			8,127
Investment in Subsidiaries	4,501		346		—		(4,847		)	—
Noncurrent Assets	155		1,959		136		(76		)	2,174
Total Assets	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250
Current Liabilities	$	1,112	$	3,866	$	1,076	$	(4,828	)	$	1,226
Noncurrent Liabilities	442		2,597		375		(76		)	3,338
Long-Term Debt	1,684		—		—		—			1,684
Member's Equity	6,002		4,256		591		(4,847		)	6,002
Total Liabilities and Member's Equity	$	9,240	$	10,719	$	2,042	$	(9,751	)	$	12,250

~~table~~Table of ~~contents~~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, our public utility company which ~~primarily provides electric~~is engaged principally in the transmission ~~services~~of electricity and distribution of ~~electric energy~~electricity and natural gas ~~implements demand response~~in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and ~~energy efficiency programs and~~the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU, and

Power, our multi-regional, wholesale energy supply company that integrates its ~~nuclear, fossil and renewable~~ generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy ~~trading and marketing and risk management activities~~transacting functions primarily in the Northeast and Mid-Atlantic United ~~States.~~States through its principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA), and the states in which they operate.

PSEG's other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority's (LIPA) transmission and distribution (T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and these operating subsidiaries with certain management, administrative and general services at cost.

Our business discussion in Part I, Item 1. Business of our ~~2014~~2015 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part I, Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of ~~2014~~2015 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during ~~2015~~2016 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the ~~2014~~2015 Form 10-K.

EXECUTIVE OVERVIEW OF ~~2015~~2016 AND FUTURE OUTLOOK

Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:

~~Growing our~~

improving utility operations through ~~continued~~growth in investment in T&D and other infrastructure projects ~~with greater diversity of regulatory oversight,~~designed to enhance resiliency, and

~~Maintaining~~maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.

~~table~~Table of ~~contents~~Contents

Financial Results

The results for PSEG, PSE&G and Power for the three months and six months ended June 30, ~~2015~~2016 and ~~2014~~2015 are presented as follows:

Three Months Ended Six Months Ended
June 30, June 30,
Earnings 2015 2014 2015 2014
Millions
PSE&G $ 167
$ 151
$ 409
$ 365

Power (A) 166
54
501
218

Other (B) 12
7
21
15

PSEG Net Income $ 345
$ 212
$ 931
$ 598

PSEG Net Income Per Share (Diluted) $ 0.68
$ 0.42
$ 1.83
$ 1.18




	Three Months Ended					Six Months Ended
	June 30,					June 30,
Earnings	2016			2015		2016		2015
	Millions
PSE&G	$	179		$	167	$	441	$	409
Power (A)	(11		)	166		181		501
Other (B)	19			12		36		21
PSEG Net Income	$	187		$	345	$	658	$	931

PSEG Net Income Per Share (Diluted)	$	0.37		$	0.68	$	1.30	$	1.83


(A)	Includes an after-tax insurance recovery for Superstorm Sandy of $27 million and $102 million in the three months and six months ended June 30, 2015, respectively. ~~See Note 8. Commitments and Contingent Liabilities.~~


(B)	Other includes activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations.

Power’s results above include the realized gains, losses and earnings on the Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity and the impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with ~~forward~~future delivery dates.

The variances in our Net Income include the changes related to NDT and MTM shown in the following table:

Three Months Ended Six Months Ended
June 30, June 30,
2015 2014 2015 2014
Millions, after tax
NDT Fund Income (Expense) (A) $ 1
$ 14
$ 3
$ 23

Non-Trading MTM Gains (Losses) $ 28
$ (42 ) $ 8
$ (174 )




	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016			2015		2016			2015
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	(1	)	$	1	$	(6	)	$	3
Non-Trading MTM Gains (Losses) (C)	$	(101	)	$	28	$	(88	)	8

(A)

NDT Fund Income (Expense) includes the realized gains and losses, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions, and impairments on certain NDT securities recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization Expense.


(B)	Net of tax (expense) benefit of $(1) million, $(2) million, $2 million and $(7) million for the three and six months ended June 30, 2016 and 2015, respectively.


(C)	Net of tax (expense) benefit of $70 million, $(20) million, $61 million and $(6) million for the three and six months ended June 30, 2016 and 2015, respectively.

Our ~~$133~~$158 million ~~and $333 million increases~~decrease in Net Income for the three months ~~and six months~~ ended June 30, ~~2015 were~~2016 was driven primarily ~~by:~~by

MTM ~~gains~~losses in ~~2015~~2016 as compared to MTM ~~losses~~gains in ~~2014,~~2015,

lower ~~generation~~volumes of energy sold at lower average realized prices primarily in the PJM Interconnection, L.L.C. (PJM) region,

higher congestion costs in PJM resulting from credits received in 2015 due to ~~lower fuel costs,~~the colder than normal weather, and

insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy.

These decreases were partially offset by

higher revenues due to increased investments in transmission projects,

lower generation costs driven by lower natural gas prices and reduced generation output, and

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lower O&M expense at Power due to higher costs incurred in 2015 for planned major outages.

Our $273 million decrease in Net Income for the six months ended June 30, 2016 was driven primarily by

MTM losses in 2016 as compared to MTM gains in 2015,

lower volumes of energy sold at lower average realized sales primarily in the PJM region and lower volumes of energy sold under wholesale load contracts,

lower operating reserve revenues and capacity revenues in PJM,

lower volumes of gas sold at lower average prices under the Basic Gas Supply Service (BGSS) contract, and

insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy.

These decreases were partially offset by

•lower generation costs driven by lower fuel costs and reduced generation output at Power,

•a decrease in O&M expense at Power due to higher costs incurred for planned outages in 2015, and

higher revenues due to increased investments in transmission projects.

During the first half of ~~Superstorm Sandy costs, primarily~~2016, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at ~~Power.~~

At PSE&G, our regulated utility, ~~we continued~~in recent years has yielded strong results and allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our multi-year, long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our ~~customers. Effective January 1, 2015,~~customers and bolstering our system resiliency. At Power, our merchant generator, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.

At PSE&G, in 2016 we continued to make investments and seek recovery on such investments made to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014. We also commenced modernizing PSE&G's ~~formula rate increased~~gas distribution systems as part of our ~~annual transmission revenues~~Gas System Modernization Program (GSMP) that was approved by approximately $182 million. Each year, transmission revenues are filed based on estimated data and subject to true up with actual current year data. The true-up adjustment for 2015 will primarily include the ~~impact on rate base due to the extension of bonus depreciation, which was enacted after the filing was made, and is estimated to reduce our 2015 annual revenue increase by approximately $21 million.~~BPU in late 2015. Over the past few years, these types of investments have altered ~~the~~our business mix ~~of our overall results of operations~~ to reflect a higher percentage of earnings contribution by PSE&G.

~~table~~Despite the unseasonable weather patterns during the first six months of ~~contents~~

2016, Power’s results benefited from access to natural gas supplies through its existing firm pipeline transportation ~~contracts during the cold weather experienced in the first quarter of 2015.~~contracts. Power manages these contracts for the benefit of PSE&G’s customers through the ~~basic gas supply service (BGSS)~~BGSS arrangement. The contracts are sized to ~~ensure~~provide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third party sales and supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s strategic hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business.

Our recent investments in the latter half of 2015 and early 2016 in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.

Since 2013, eight nuclear generating stations in the United States totaling over 8,300 MW of capacity have closed or announced early retirement due to economic reasons. Four additional stations totaling nearly 5,300 MW of capacity have been announced as being at risk for early retirement. This situation is generally due to low natural gas prices resulting from the growth of shale gas production since 2007, the continuing cost of regulatory compliance for nuclear facilities and both federal and state-level policies that provide credits to renewable energy such as wind and solar, but do not apply to nuclear generating stations. These trends have significantly reduced the revenues to nuclear generating stations while simultaneously raising the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating greater reliance on natural gas pipelines for delivery and less diversity of the generation fleet. Additionally, we believe that the early retirement of nuclear plants will lead to an increase in replacement energy and environmental costs.

While our nuclear generating units are not currently at risk of early retirement, we continue to advocate for sound policies that recognize nuclear power as a source of clean energy and an important part of a diverse and reliable energy portfolio.

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Regulatory, Legislative and Other Developments

In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.

Transmission ~~Planning~~

The FERC’s rule under Order 1000 altered the right of first refusal (ROFR) previously held by incumbent utilities to build transmission within their respective service territories, creating the potential that new transmission projects in our service territory could be assigned to third parties rather than PSE&G. Order 1000 also presents opportunities for us to construct transmission outside of our service territory. In April 2013, PJM ~~Interconnection, L.L.C. (PJM)~~ initiated aits first "open window" solicitation process to allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues in ~~which we participated~~New Jersey. In April 2016, PSE&G accepted construction responsibility for the three components of the Artificial Island project that PJM assigned to ~~review technical solutions~~it, based on having reached agreement with PJM regarding an estimate for the project base cost of $273 million, plus risk and contingency for a total project cost of up to $340 million. PSE&G continues to work with PJM to optimize the scope and cost of the project.

In April 2016, PJM filed at FERC to incorporate a voltage threshold into PJM’s Regional Transmission Expansion Plan (RTEP) process to exempt, except under certain circumstances, reliability violations on facilities below 200 kV from PJM’s proposal window process. We generally support this reform as a measure to improve the ~~operational performance~~efficiency of the open window procedure that will permit transmission developers to focus on the projects most likely to benefit from a competitive process.

There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G's ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey and may cause increased scrutiny regarding PSE&G's future capital investments. In addition, as a basic generation service (BGS) supplier, Power provides services that include specified transmission costs. If the ~~Artificial Island area, consisting~~allocation of ~~our Salem and Hope Creek nuclear generation facilities. On April 28, 2015,~~ the PJM staff advised stakeholders that it intended to recommend a transmission project that would primarily be awarded to another entity, but that a portion at an estimated construction cost of between $100 million and $130 million would be assigned to PSE&G. We subsequently filed commentscosts associated with the ~~PJM Board~~transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to an adjustment, subject to BPU approval. We do not believe that these matters will have a material effect on Power's business or results of ~~Managers (PJM Board) identifying what~~operations.

Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners' base ROEs. While we ~~believed were deficiencies~~are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, the ~~PJM staff recommendation. On July 29, 2015, the PJM Board approved the PJM staff's recommendation. See Part II. Item 5. Other Information—Transmission Regulation—Transmission Policy Developments~~results of these other proceedings could set precedents for ~~additional information.~~other transmission owners with formula rates in place, including PSE&G.

Wholesale Power Market Design

In an important development in the proceedings concerning the actions that had been taken by the states of New Jersey and Maryland to subsidize new generation that is above market cost, in April 2016, the United States Supreme Court affirmed the decision of the lower courts that had held the action in Maryland to be unconstitutional. The Supreme Court’s ruling upholds FERC’s authority to foster competitive wholesale electricity markets and provides guidance to states in balancing their interests to encourage and support the development of renewables and other generating facilities.

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. In ~~May 2014,~~June 2015, FERC conditionally accepted a federal court issued a rule that vacated a FERC Order in which the FERC had determined that demand response (DR) providers should receive full market compensation for power and held that the FERC has no jurisdiction over DR. The U.S. Supreme Court has accepted this case for review. The U.S. Supreme Court's decision could have a material impact on capacity market outcomes in which DR currently participates as a supply resource under FERC jurisdiction.

~~In a separate development of significance to the wholesale capacity market, in December 2014~~proposal from PJM ~~filed at the FERC its proposal~~ for a capacity performance (CP) product to include generators, DRDemand Response and energy efficiency providers, ~~who would need~~which will be required to ~~certify their availability~~perform during emergency conditions, as a supplement to the base ~~capacity.~~capacity product. The proposal ~~includes~~included enhanced performance-based incentives and penalties. ~~On June 9, 2015,~~We believe that the ~~FERC conditionally accepted~~auction pricing adequately reflects the ~~proposal. The~~increased costs that could result from operating under more stringent rules for generation availability. Based on the auction results, the CP mechanism appears to have provided the opportunity for enhanced capacity market revenue streams for Power, but future impacts cannot be assured. Further, there may be requirements for additional investment and there are additional performance ~~market design will be implemented~~and financial risks. Appeals of FERC's CP orders are pending.

In May 2016, PJM announced the results of the RPM capacity auction for the ~~2015 base residual~~2019-2020 delivery year. Power cleared 8,895 MW of its generating capacity at an average price of $116 per MW-day for the 2019-2020 delivery period. Of the cleared capacity, Power believes that nearly all is compliant with PJM's CP requirements. In the two prior capacity auctions covering the 2017-2018 and 2018-2019 delivery years, Power cleared approximately 8,700 MW at average prices of $177 per MW-day and $215 per MW-day, respectively. Prices in the most recent auction ~~which is scheduled~~reflect PJM’s downwardly-revised demand forecast, changes in the emergency transfer limits due to ~~begin~~transmission expansion and the effects of both the new generation and uncleared generation from the prior year’s auction.

An emerging issue in PJM involves the impact of subsidized existing generation on ~~August 10, 2015. It further provides generation owners with greater flexibility in submitting~~RPM market outcomes. These subsidies would likely enable the affected generators to submit bids into PJM capacity markets that are not reflective of their actual costs of operation and may prevent uneconomic generating facilities from retiring. Either of these conditions could artificially

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suppress capacity market ~~bids~~prices, especially given that ~~reflect~~PJM’s currently effective “minimum offer price rule” (MOPR) which applies only to new gas-fired units, would not apply to these plants. Given the ~~additional costs~~uncertainty surrounding these possible subsidies, we cannot predict the effects this might have on capacity prices and ~~risks of~~ the ~~more rigorous performance requirements.~~corresponding impact on our business. See ~~Part II,~~ Item 5. Other Information—Federal Regulation—Capacity Market Issues—PJM for additional information.

Environmental Regulation

We continue to advocate for the development and implementation of fair and reasonable rules by the ~~U.S. Environmental Protection Agency (EPA)~~EPA and state environmental regulators. In particular, section 316(b) of the ~~EPA’s 316(b) rule on~~Federal Water Pollution Control Act (FWPCA) requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs. As adopted by the EPA, the rule requires that cooling water intake structures reflect the best technology available for minimizing environmental impacts. Under this standard, power facilities have the flexibility to select one of several options as their method of compliance. However, the EPA has structured the rule so that each state will continue to consider renewal permits for power facilities on a case by case basis. On June 30, 2015, the New Jersey Department of Environmental Protection (NJDEP) issued a draft New Jersey Pollutant Discharge Elimination Systems (NJPDES) permit governing cooling water intake structures for Salem. The draft permit does not require installation of cooling towersSee Item 1. Note 8. Commitments and allows Salem to continue to operate utilizing the existing once-through cooling water system. The draft permit is subject to a public notice and comment period after which the NJDEP may make revisions before issuing the final permit expected during the first half of 2016. See Part II, Item 5. Other Information—Water Pollution Control—Cooling Water Intake Structure RegulationContingent Liabilities for further information.

~~The EPA’s proposed~~In October 2015, the EPA published the Clean Power Plan (CPP), a greenhouse gas emissions ~~regulations are also~~regulation under the Clean Air Act (CAA) for existing power plants. The regulation establishes state-specific emission targets based on implementation of ~~potential consequence to our results.~~the best systems of emission reduction. We continue to work with ~~the~~ FERC and other federal and state regulators, as well as industry partners, to determine the potential impact of these regulations. ~~Clean Air Act (CAA) regulations governing~~

The U.S. Supreme Court’s February 2016 decision to stay the implementation of the CPP will delay deadlines for submission of state requests for extensions and final plans. If the CPP is upheld, new deadlines will need to be established and the effective date of the compliance period may be impacted.

We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous ~~air pollutants under~~substances that we generated. In particular, the ~~EPA's Maximum Achievable Control Technology rules~~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 variousstatutes. We are also currently involved in a number of ~~significance; however, we believe our generation business remains well-positioned for~~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 ~~air pollution control regulations if and when they are implemented.For additional information, see Part II, Item 5. Other~~

~~table of contents~~

~~Information—Air Pollution Control—Hazardous Air Pollutants Control.~~In addition, state environmental regulations governing emissions from power plants also have a significant impact on our operations. In the second quarter of 2015, we retired 1,545 MW of fully depreciated combustion turbine capacity that would notremediation efforts could be able to comply with the more stringent emission standards for high electric demand day units (HEDD) under the New Jersey HEDD regulations for nitrous oxide, which will reduce capacity revenues for this year.material.

~~Other Developments~~For further information regarding the matters described above as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 8. Commitments and Contingent Liabilities.

In the first half of 2015, we continued to make investments and seek recovery on such investments made to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the New Jersey Board of Public Utilities (BPU) in 2014. As approved, the Energy Strong program provides for $1.22 billion of investment, with cost recovery atFERC Compliance

Since September 2014, FERC Staff has been conducting a 9.75% rate of return on equity on the first $1.0 billion of the investment, plus associated allowance for funds used during construction, through an accelerated recovery mechanism. We will seek recovery of the remaining $220 million of investment in PSE&G's next base rate case, which is to be filed no later than November 1, 2017.

In February 2015, we filed a petition with the BPU seeking approval of a Gas System Modernization Program (GSMP) through which we propose to invest approximately $1.6 billion over the next five years, or about $320 million per year, to modernize PSE&G’s gas systems. The matter is pending.

In June 2015, we acquired a development project to construct a 755 MW gas-fired combined cycle generating station (Keys Energy Center) in Maryland with completion expected in 2018 at an estimated investment of $825 million - $875 million.

~~The~~ preliminary non-public ~~staff~~ investigation ~~initiated by~~regarding errors in the ~~FERC into Power's discovery and investigation~~calculation of ~~(i) incorrect calculations for~~ certain components of ~~its~~Power's cost-based bids for its New Jersey fossil generating units in the PJM energy market and ~~(ii) differences in~~ the quantity of energy that Power offered into the energy market for its fossil peaking units ~~from~~compared to the ~~amount~~amounts for which Power was compensated in the capacity market for those ~~units continues.~~units. This investigation is ongoing. The amounts of potential disgorgement and other potential penalties that we may incur span a wide range depending on the success of our legal arguments. If our legal arguments do not prevail, in whole or in part with FERC or in a judicial challenge that we may choose to pursue, it is likely that Power ~~has an ongoing process~~would record losses that would be material to PSEG's and Power's results of ~~implementing improved procedures to help mitigate the risk of similar issues occurring~~operations in the ~~future. This investigation could result~~quarterly and annual periods in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies. It is not possible at this time to reasonably estimate the ultimate impact or predict any resulting penalties, other costs associated with this matter, or the applicability of mitigating factors.which they are recorded. For ~~more detailed~~additional information, ~~refer to~~see Item 1. Note 8. Commitments and Contingent ~~Liabilities—FERC Compliance.~~Liabilities.

Salem Operations

In April 2016, during a scheduled refueling outage at Salem Unit 1, a visual inspection revealed degradation to a number of bolts inside the reactor vessel. The bolt replacement has been completed and the unit is in the process of returning to service. We expect to continue to inspect and replace degraded bolts at both Salem units over the next several refueling outage cycles and a strategic solution to maintain the long-term health of both reactor vessel internals is under review. Production and margin effects for the second quarter of 2016 were largely offset by the increased production at Peach Bottom as a result of the Extended Power Uprates made in 2015 being fully operational. Extension of the Salem Unit 1 outage into July and an unplanned outage at Salem Unit 2 will have a continuing effect on third quarter performance.

Operational Excellence

We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of market opportunities presented during the year as we remain diligent in managing costs. InFor the first six months of ~~2015,~~2016, our

total nuclear fleet achieved an average capacity factor of ~~91%~~91.2%,

~~nuclear output increased by 2.6%~~ and ~~combined cycle output by 20.8% as compared to the first half of 2014,~~

diverse fuel mix and dispatch flexibility allowed us to generate approximately ~~28 TWh~~26 terra-watt hours while addressing unit outages and balancing fuel availability and price ~~volatility, and~~volatility.

~~construction~~

Table of ~~transmission projects proceeded on schedule and within budget.~~Contents

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 ~~2015~~2016 as we

had cash ~~flow from operations~~on hand of ~~$2.2 billion~~$648 million as of June 30, ~~2015,~~2016,

maintained solid investment grade credit ratings,

~~extended the expiration dates for approximately $2.0 billion of five-year credit facilities for PSEG, PSE&G and Power from 2018 to 2020,~~ and

increased our ~~indicated~~indicative annual dividend for ~~2015~~2016 to ~~$1.56~~$1.64 per share.

We expect to be able to fund our ~~transmission projects required under PJM's reliability program, our Energy Strong program, Keys Energy Center~~planned capital requirements, as described in Liquidity and ~~other planned projects, as well as our proposed GSMP,~~Capital Resources, without the issuance of new equity.

~~table of contents~~

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~~half of ~~2015, in addition to our acquisition of the Keys Energy Center,~~2016, we

made additional investments in transmission infrastructure projects,

~~secured approval to extend three~~began executing our GSMP and continued executing Energy ~~Efficiency Economic Stimulus subprograms to allow for $95 million of additional capital expenditures~~Strong and ~~$12 million of additional administrative expenses to provide energy efficiency assistance to hospitals, healthcare facilities and residential multi-family housing units,~~

~~continued to execute our~~other existing BPU-approved utility programs,

~~completed the power ascension~~commenced construction of our Keys and Sewaren 7 generation projects for ~~the extended power uprate at~~targeted commercial operation in 2018 and announced our ~~co-owned Peach Bottom 2 nuclear station,~~plan to construct BH5 and commence operations in mid-2019, and

~~completed installation of equipment~~acquired three solar energy projects totaling 100 MW-direct current in North Carolina and Colorado expected to ~~increase output and improve efficiency at our Bergen 2 combined cycle gas unit similar to our 2014 installation at our Linden plant.~~go into service during 2016.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a ~~slow-moving~~slow-growing economy and a cost-constrained environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue toto:

focus on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,

successfully manage our energy obligations and re-contract our open supply positions,

execute our utility capital investment program, including our Energy Strong program, ~~proposed~~ GSMP and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,

effectively manage construction of our Keys, ~~Energy Center~~Sewaren 7, BH5 and other generation projects,

advocate for measures to ensure the implementation by PJM and ~~the~~ FERC of market design and transmission planning rules that continue to promote fair and efficient electricity markets,

engage multiple stakeholders, including regulators, government officials, customers and investors, and

successfully operate the LIPA T&D system and manage LIPA's fuel supply and generation dispatch obligations.

For ~~2015~~2016 and beyond, the key issues and challenges we expect our business to confront include:

regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,

fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our base rate case which must be filed with the BPU no later than November 1, 2017,

uncertainty in the slowly improving national and regional economic recovery, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,

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the potential for continued reductions in demand and sustained lower natural gas and electricity prices, both at market hubs and the locations where we operate, ~~and~~

delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory ~~approvals.~~approvals, and

FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.

Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:

67the acquisition, construction or disposition of transmission and distribution facilities and/or generation units,

the disposition or reorganization of our merchant generation business or other existing businesses or the acquisition or development of new businesses, such as retail energy marketing,

the expansion of our geographic footprint,

continued or expanded participation in solar, demand response and energy efficiency programs, and

investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency and modernizing existing infrastructure.

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 17. Related-Party Transactions.

Three Months Ended
Increase/
(Decrease)
Six Months Ended
Increase/
(Decrease)

June 30, June 30,
2015 2014 2015 vs. 2014 2015 2014 2015 vs. 2014
Millions Millions % Millions Millions %
Operating Revenues $ 2,314
$ 2,249
$ 65
3
$ 5,449
$ 5,472
$ (23 ) —

Energy Costs 668
789
(121 ) (15 ) 1,762
2,145
(383 ) (18 )
Operation and Maintenance 761
800
(39 ) (5 ) 1,424
1,656
(232 ) (14 )
Depreciation and Amortization 317
295
22
7
647
601
46
8

Income from Equity Method Investments 4
3
1
33
7
7
—
—

Other Income and (Deductions) 66
52
14
27
102
88
14
16

Other-Than-Temporary Impairments 10
2
8
N/A
15
4
11
N/A

Interest Expense 97
94
3
3
195
191
4
2

Income Tax Expense 186
112
74
66
584
372
212
57




	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,				Increase/ (Decrease)					June 30,				Increase/ (Decrease)
	2016		2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,905	$	2,314	$	(409	)	(18	)	$	4,521	$	5,449	$	(928	)	(17	)
Energy Costs	624		668		(44		)	(7	)	1,460		1,762		(302		)	(17	)
Operation and Maintenance	710		761		(51		)	(7	)	1,439		1,424		15			1
Depreciation and Amortization	224		317		(93		)	(29	)	448		647		(199		)	(31	)
Income from Equity Method Investments	4		4		—			—		6		7		(1		)	(14	)
Other Income (Deductions)	34		66		(32		)	(48	)	61		102		(41		)	(40	)
Other-Than-Temporary Impairments	10		10		—			—		20		15		5			33
Interest Expense	97		97		—			—		189		195		(6		)	(3	)
Income Tax Expense	91		186		(95		)	(51	)	374		584		(210		)	(36	)

The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.

Table of Contents

PSE&G

Three Months Ended
Increase/
(Decrease)
Six Months Ended
Increase/
(Decrease)

June 30, June 30,
2015 2014 2015 vs. 2014 2015 2014 2015 vs. 2014
Millions Millions % Millions Millions %
Operating Revenues $ 1,466
$ 1,435
$ 31
2
$ 3,468
$ 3,580
$ (112 ) (3 )
Energy Costs 544
565
(21 ) (4 ) 1,436
1,610
(174 ) (11 )
Operation and Maintenance 368
362
6
2
780
824
(44 ) (5 )
Depreciation and Amortization 234
217
17
8
481
444
37
8

Other Income (Deductions) 18
13
5
38
35
27
8
30

Interest Expense 67
67
—
—
136
135
1
1

Income Tax Expense 104
86
18
21
261
229
32
14




	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,				Increase/ (Decrease)					June 30,				Increase/ (Decrease)
	2016		2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,350	$	1,466	$	(116	)	(8	)	$	3,062	$	3,468	$	(406	)	(12	)
Energy Costs	529		544		(15		)	(3	)	1,258		1,436		(178		)	(12	)
Operation and Maintenance	352		368		(16		)	(4	)	734		780		(46		)	(6	)
Depreciation and Amortization	136		234		(98		)	(42	)	275		481		(206		)	(43	)
Other Income (Deductions)	18		18		—			—		37		35		2			6
Interest Expense	74		67		7			10		142		136		6			4
Income Tax Expense	98		104		(6		)	(6	)	249		261		(12		)	(5	)

Three Months Ended June 30, ~~2015~~2016 as Compared to ~~2014~~2015

Operating Revenues ~~increased $31~~decreased $116 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased ~~$69~~$28 million due primarily to an increase in transmission revenues.

Transmission revenues were ~~$49~~$48 million higher due to ~~net rate increases resulting primarily from~~ increased capital investments.

Electric distribution revenues ~~increased $13~~decreased $19 million due primarily to ~~higher sales volumes~~lower Green Program Recovery Charges (GPRC) of $9$14 million and ~~higher CIP II related revenues of $3~~$5 million ~~due to the inclusion~~ in ~~base rates beginning in July 2014.~~lower sales volumes.

~~table of contents~~

~~Gas distribution revenues increased $7 million due primarily to higher Weather Normalization Clause (WNC) revenue of $6~~Commodity Revenue decreased $15 million as a result of ~~warmer than normal weather in the second quarter of 2015.~~

~~Commodity Revenue~~ ~~decreased $21~~$30 million ~~as a result~~ of lower ~~Gas~~Electric revenues, partially offset by $15 million in higher ~~Electric~~Gas revenues. Commodity revenue for both electric and gas is entirely offset with ~~decreased~~the change in Energy Costs. PSE&G earns no margin on the provision of ~~basic generation service (BGS)~~BGS and BGSS to retail customers.

~~Gas~~Electric revenues decreased ~~$51 million due primarily to lower BGSS prices.~~

~~Electric revenues increased~~ $30 million due primarily to $15 million of lower revenues from collections of Non-Utility Generation Charges (NGC), a ~~$41~~$7 million or ~~11% increase~~2% decrease in BGS revenues due to ~~higher~~lower sales ~~volumes. This increase was partially offset by an $11~~volumes, and a decrease of $8 million ~~reduction in revenues~~ due to ~~lower collections of Non-Utility Generation Charges (NGC) and~~ lower volumes of Non-Utility Generation (NUG) energy ~~sold at lower prices.~~sold.

Gas revenues increased $15 million due to higher BGSS sales volumes.

Clause Revenues decreased ~~$18~~$128 million due primarily to lower Securitization Transition Charges (STC) of $122 million and lower Societal Benefit Charges (SBC) of ~~$12 million, lower Margin Adjustment Clause (MAC) revenue~~$5 million. The STC reduction is a result of ~~$6 million and lower Solar Pilot Recovery Charges (SPRC)~~rate reductions due to the completion of ~~$2 million, partially offset by higher Securitization Transition Charges (STC) of $2 million.~~securitization collections in 2015. The changes in the STC and SBC ~~MAC, SPRC and STC~~ amounts ~~were~~are entirely offset by decreases in the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC or SBC ~~MAC, SPRC or STC~~ collections.

~~Other Operating Revenues~~ ~~experienced no material change.~~

Operating Expenses

Energy Costs decreased ~~$21 million due to lower Gas costs partially offset by higher Electric costs.~~$15 million. This is entirely offset by ~~decreased~~the change in Commodity Revenue.

~~Gas costs decreased $51 million or 34% due to lower prices.~~

Electric costs increased by $30 million or 7% due to $11 million of higher BGS and NUG prices and $37 million in higher BGS volumes. BGS volumes increased 10% due primarily to reverse customer migration. These increases were partially offset by $14 million of lower NUG volumes and $4 million of decreased deferred cost recovery.

Operation and Maintenance ~~increased $6~~decreased $16 million, of which the most significant components were

a $9$28 million ~~increase~~net reduction in ~~pension~~costs related to various clause mechanisms and ~~OPEB expenses,~~

~~increased gas bad debt expense of $5 million, and~~

~~$12 million in operating expenses, including increases of $3 million in storm damages, $3 million of higher wages, $2 million in appliance service costs and $1 million for injuries and damages,~~GPRC,

partially offset by a ~~$20~~$7 million ~~decrease~~increase in ~~costs related~~distribution maintenance, due to ~~a net decrease in SBC, MAC, GPRC, SPRC~~increases of $4 million for vegetation management and ~~STC. Due to the nature of the SBC, MAC, SPRC and STC clause mechanisms, these are entirely offset in revenues.~~$3 million for corrective maintenance.

Depreciation and Amortization ~~increased $17~~decreased $98 million due ~~primarily~~ to a ~~$13 million increase in depreciation~~decrease of ~~additional plant in service related to increased investments in various transmission and distribution projects and an increase of $4~~$116 million in amortization of Regulatory ~~Assets.~~Assets primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by a $17 million increase in depreciation due to additional plant in service.

~~Other Income and (Deductions)~~Interest Expense increased $5$7 million due primarily to an increase of $8 million due to net debt issuances in ~~Allowance for Funds used During Construction (AFUDC).~~2015 and 2016.

Income Tax Expense ~~increased $18~~decreased $6 million due primarily to plant and other flow through items and uncertain tax positions, partially offset by higher pre-tax income.

Table of Contents

Six Months Ended June 30, ~~2015~~2016 as Compared to ~~2014~~2015

Operating Revenues decreased ~~$112~~$406 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased ~~$109~~$57 million due primarily to an increase in transmission revenues.

Transmission revenues were ~~$82~~$102 million higher due to ~~net rate increases resulting primarily from~~ increased capital investments.

Electric distribution revenues ~~increased $14~~decreased $42 million due primarily to ~~higher~~lower GPRC of $26 million and $16 million in lower sales volumes.

Gas distribution revenues decreased $3 million due primarily to $68 million of lower delivery volumes and lower GPRC of $7 million due to lower sales volumes ~~of $9~~from warmer winter weather. These decreases were almost entirely offset by $62 million in higher Weather Normalization Clause revenue and an

~~increase in CIP revenues of $4~~$10 million due to the ~~inclusion~~roll in of ~~CIP II in~~Energy Strong into base rates ~~beginning in July 2014.~~effective September 1, 2015.

Gas distribution revenues increased $13 million due primarily to $20 million from higher sales volumes outside the WNC clause, partially offset by lower WNC revenue of $9 million due to colder weather in 2015 compared to 2014.

~~table of contents~~

Commodity Revenue decreased ~~$174~~$178 million ~~due to~~as a result of lower Gas ~~revenues offset partially by higher~~and Electric revenues. Commodity revenue for both ~~electric~~gas and ~~gas~~electric is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of ~~BGS~~BGSS and ~~BGSS~~BGS to retail customers.

Gas revenues decreased ~~$200~~$94 million due primarily to lower BGSS prices of $278 million, of which $207 million was due to lower residential rates resulting from $133 million in residential bill credits and $74 million of lower commodity prices, partially offset by higher BGSS volumes of $78 million due to colder weather in 2015.sales volumes.

Electric revenues ~~increased $26~~decreased $84 million due primarily to ~~$58~~a $42 million or 5% decrease in BGS revenues due to lower sales volumes, $26 million of ~~higher net BGS revenues. BGS~~lower revenues ~~increased by $87 million or 11%, due to higher sales volumes, which were partially offset by $29~~from collections of NGC and a decrease of $16 million due to lower ~~BGS prices. The increase from BGS was partially offset by $32 million in lower revenues from lower collection of NGC and lower sales prices and~~ volumes of NUG ~~energy.~~energy sold at lower prices.

Clause Revenues decreased ~~$47~~$282 million due primarily to lower ~~SBC~~STC of ~~$25 million, lower MAC revenue of $24~~$251 million and lower ~~SPRC~~SBC of $1$38 million, partially offset by higher Margin Adjustment Clause (MAC) revenue of $14 million. The STC reduction is a result of ~~$3 million.~~rate reductions due to the completion of securitization collections in 2015. The changes in the STC, SBC and MAC ~~SPRC and STC~~ amounts ~~were~~are entirely offset by decreases in the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SBC or MAC ~~SPRC or STC~~ collections.

~~Other Operating Revenues~~ ~~experienced no material change.~~

Operating Expenses

Energy Costs decreased ~~$174 million due to lower Gas costs partially offset by higher Electric costs.~~$178 million. This is entirely offset by ~~decreased~~the change in Commodity Revenue.

~~Gas costs decreased $200 million or 28% due to a $278 million or 39% decline in prices, partially offset by $78 million or 11% in higher sales volumes due to colder than normal weather.~~

Electric costs increased $26 million or 3% due to a $72 million or 9% increase in BGS volumes, primarily reflecting reverse customer migration and a $23 million increase due to higher BGS and NUG prices, partially offset by $50 million of decreased deferred cost recovery and $19 million in lower NUG sales volumes.

Operation and Maintenance decreased ~~$44~~$46 million, of which the most significant components were

a ~~$60~~$72 million ~~decrease~~net reduction in costs related ~~primarily~~ to ~~a net decrease in SBC, MAC, GPRC, CIP, SPRC and STC. Due to the nature of the SBC, MAC, SPRC and STC~~various clause mechanisms ~~these are entirely~~and GPRC,

partially offset by an $11 million increase in ~~revenues.~~distribution maintenance, due to increases of $6 million for corrective maintenance and $5 million for vegetation management and

$10 million of storm insurance recovery proceeds ~~of $10 million,~~

•~~partially offset by an $18 million increase~~received in ~~pension and OPEB expenses, and~~

~~increased gas bad debt expense of $5 million.~~2015.

Depreciation and Amortization~~increased$37 million~~ decreased $206 million due ~~primarily~~ to a ~~$28 millionincrease~~ ~~in depreciation~~decrease of ~~additional plant in service related to increased investments in various transmission and distribution projects and an increase of $10~~$239 million in amortization of Regulatory ~~Assets.~~Assets primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by a $32 million increase in depreciation due to additional plant in service.

~~Other Income and (Deductions)~~Interest Expense increased $8$6 million due primarily to an increase ~~in AFUDC.~~

~~Interest Expense~~ ~~increased $1~~of $13 million due ~~primarily to~~ net debt issuances ~~of Medium Term Notes~~ in ~~the first half~~ 2015 and ~~latter half of 2014,~~2016, partially offset by ~~partial~~an $8 million decrease due to the redemption of securitization ~~debt.~~debt in 2015.

Income Tax Expense~~increased$32~~ decreased $12 million due primarily to plant and other flow through items and uncertain tax positions offset by higher pre-tax income.

~~table~~Table of ~~contents~~Contents

Power

Three Months Ended
Increase/
(Decrease)
Six Months Ended
Increase/
(Decrease)

June 30, June 30,
2015 2014
2015 vs. 2014 2015 2014 2015 vs. 2014
Millions Millions % Millions Millions %
Operating Revenues $ 1,025
$ 986
$ 39
4
$ 2,750
$ 2,686
$ 64
2

Energy Costs 409
520
(111 ) (21 ) 1,302
1,564
(262 ) (17 )
Operation and Maintenance 313
327
(14 ) (4 ) 485
629
(144 ) (23 )
Depreciation and Amortization 75
72
3
4
151
144
7
5

Income from Equity Method Investments 5
3
2
67
8
7
1
14

Other Income (Deductions) 48
37
11
30
66
60
6
10

Other-Than-Temporary Impairments 10
2
8
N/A
15
4
11
N/A

Interest Expense 33
29
4
14
64
61
3
5

Income Tax Expense 72
22
50
N/A
306
133
173
N/A




	Three Months Ended					Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,					Increase/ (Decrease)					June 30,				Increase/ (Decrease)
	2016			2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions					Millions			%		Millions				Millions			%
Operating Revenues	$	714		$	1,025	$	(311	)	(30	)	$	2,027	$	2,750	$	(723	)	(26	)
Energy Costs	381			409		(28		)	(7	)	1,019		1,302		(283		)	(22	)
Operation and Maintenance	265			313		(48		)	(15	)	518		485		33			7
Depreciation and Amortization	80			75		5			7		159		151		8			5
Income from Equity Method Investments	4			5		(1		)	(20	)	6		8		(2		)	(25	)
Other Income (Deductions)	16			48		(32		)	(67	)	24		66		(42		)	(64	)
Other-Than-Temporary Impairments	10			10		—			—		20		15		5			33
Interest Expense	20			33		(13		)	(39	)	42		64		(22		)	(34	)
Income Tax Expense	(11		)	72		(83		)	N/A		118		306		(188		)	(61	)

Three Months Ended June 30, ~~2015~~2016 as Compared to ~~2014~~2015

Operating Revenues ~~increased $39~~decreased $311 million due to changes in generation, gas supply and other ~~operating~~ revenues.

Generation Revenues~~increased $92~~ decreased $300 million due primarily to

~~higher net revenues~~

a decrease of ~~$112~~$212 million due ~~primarily~~to MTM losses in 2016 as compared to MTM gains in ~~2015~~2015. Of this amount, $187 million was due to changes in forward power prices, which increased in the current period and decreased during the comparable period in 2015. Also contributing to the decrease was $25 million from higher gains on positions reclassified to realized upon settlement this year compared to ~~MTM losses~~last year,

a decrease of $66 million in ~~2014, coupled with higher generation volumes at higher average realized~~energy sales ~~prices~~primarily in the PJM region due to lower volumes and lower average realized prices,

~~an increase~~a decrease of ~~$24~~$14 million ~~due~~in capacity revenue primarily ~~to higher volumes of electricity sold under wholesale load contracts~~ in the PJM ~~and New England (NE) regions,~~region due to the retirement of older peaking units in June 2015, and

~~an increase~~a net decrease of ~~$10~~$8 million ~~due to higher volumes of~~in electricity sold under our BGS ~~contract,~~

~~partially offset by a decrease of $54 million~~contracts due primarily to lower ~~capacity revenues resulting from lower average auction prices coupled with a decrease in operating reserve revenue in the PJM region in 2015.~~volumes.

Gas Supply Revenues decreased ~~$55~~$11 million due primarily to

a net decrease of ~~$24~~$15 million in sales under the BGSS contract ~~substantially comprised~~primarily due to lower average sales prices and MTM losses, and

a net increase of $4 million on sales to third party customers, of which $8 million was due to higher volumes sold partially offset by $4 million of lower average sales ~~prices, and~~

~~a decrease of $31 million due to lower sales volumes at lower average sales prices to third party customers.~~

~~Operating Revenues~~ ~~increased$2 milliondue tohigher fees received from fuel management and power supply management contracts with LIPA.~~

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 ~~$111~~$28 million due to

Generation costs decreased ~~$55~~$37 million due primarily to lower natural gas and coal fuel costs of $30 million reflecting lower average realized ~~natural gas~~ prices ~~coupled with a 2014 unfavorable MTM impact from lower average unrealized natural gas prices on forward purchases. These decreased costs were partially offset by~~and the utilization of ~~higher volumes of natural gas and higher congestion costs in the PJM region.~~lower volumes.

Gas costs ~~decreased $56~~increased $9 million mainly related to ~~lower average gas inventory costs on both obligations under the BGSS contract and sales to third parties, coupled with lower~~higher volumes sold to third parties.

~~table of contents~~

Operation and Maintenance decreased ~~$14~~$48 million due primarily to

~~a decrease of $17 million due to insurance recovery related to Superstorm Sandy, and~~

a net decrease of ~~$17~~$35 millionrelated to our fossil plants, ~~largely~~primarily due to higher costs incurred in ~~2014~~2015 for ~~planned outages and maintenance and~~the installation of upgraded technology ~~at our Linden combined cycle gas generating plant, partly offset by installation of upgraded technology in 2015~~ at our combined cycle Bergen generating plant, and

~~partially offset by an increase~~

Table of ~~$23~~Contents

a net decrease of $33 million atrelated to our nuclear facilities, ~~primarily~~largely due to a planned outage at our 100%-owned Hope Creek ~~nuclear~~ plant in 2015, ~~as compared to a planned~~partly offset in 2016 by an extended refueling outage at our 57%-owned Salem ~~nuclear unit 2~~Unit 1 plant,

partially offset by $17 million of insurance recoveries received in ~~2014.~~2015 related to Superstorm Sandy,

Depreciation and Amortizationincreased $3$5 million due primarily to a higher depreciable ~~fossil and~~ nuclear asset base.

~~Income from Equity Method Investments~~ ~~experienced no material change.~~

Other Income ~~and~~ (Deductions) ~~increased $11~~decreased $32 million due primarily to a $28 million of insurance ~~recovery~~recoveries received in 2015 related to Superstorm Sandy ~~partly offset by lower~~and higher net realized gains from the NDT ~~Fund.~~

~~Other-Than-Temporary Impairments~~ ~~increased $8 million due to an increase~~Fund in ~~impairments of the NDT Fund.~~2015.

Interest Expense~~experienced no material change.~~ decreased $13 million due primarily to the maturity of $300 million of 5.50% Senior Notes in December 2015 and higher capitalized interest in 2016.

Income Tax Expense ~~increased $50~~decreased $83 million in ~~2015~~2016 due primarily to ~~higher~~lower pre-tax ~~income.~~income, partially offset by a benefit related to a Nuclear Decommissioning Tax Carryback transaction that was recorded in 2015.

Six Months EndedJune 30, ~~2015~~2016 as Compared to ~~2014~~2015

Operating Revenues ~~increased~~decreased $64723 million due to changes in generation and gas supply ~~and other operating~~ revenues.

Generation Revenues ~~increased $200~~decreased $474 million due primarily to

~~higher net revenues~~a decrease of ~~$239~~$173 million due ~~primarily~~to MTM losses in 2016 as compared to MTM gains in ~~2015~~2015. Of this amount, $103 million was due to higher gains on positions reclassified to realized upon settlement this year compared to ~~MTM losses~~last year. Also contributing to the decrease was $70 million from a decrease in ~~2014, partially offset by lower~~forward power prices in 2015,

a decrease of $140 million in energy sales volumes ~~sold~~ in the ~~NE region at~~PJM and New England (NE) regions due primarily to milder weather and lower average realized ~~sales~~ prices in the PJM and New York regions,

a net decrease of $87 million primarily in the PJM region due to lower operating reserve revenues coupled with lower capacity revenues resulting from the retirement of older peaking units in June 2015, and

~~an increase~~a decrease of ~~$105~~$40 million ~~due primarily to higher volumes of~~in electricity sold under wholesale load contracts in the PJM and NE regions

~~partially offset by a net decrease of $153 million~~ due primarily to lower ~~capacity revenues resulting from~~volumes and lower average ~~auction prices coupled with lower ancillary and operating reserve revenues in the PJM region.~~prices.

Gas Supply Revenues decreased ~~$138~~$249 million due primarily to

a net decrease of ~~$71~~$234 million in sales under the BGSS contract, substantially comprised of lower sales volumes due to warmer average temperatures in the 2016 winter heating season, coupled with lower average sales prices, and

a net decrease of $15 million on sales to third party customers, of which $47 million was due to lower average sales prices, partially offset by $32 million of higher ~~sales~~ volumes ~~due to colder average temperatures in the 2015 winter heating season, and~~

~~a decrease of $67 million due to lower average sales prices and volumes to third party customers.~~

~~Other Operating Revenues~~ ~~increased$2 million due to higher fees received from fuel management and power supply management contracts with LIPA.~~sold.

Operating Expenses

Generation costs decreased ~~$90~~$160 million due primarily to

lower fuel costs of $267 million reflecting lower average realized prices for natural gas ~~prices~~ and the utilization of lower volumes of ~~oil, coupled with~~ fuel, and

a ~~2014 unfavorable~~decrease of $18 million due to MTM ~~impact from lower average unrealized~~gains in 2016 as compared to MTM losses in 2015. The 2016 MTM gains were primarily due to favorable forward price movements on natural gas, ~~prices~~while the 2015 MTM losses were primarily due to higher gains on ~~forward purchases. These decreased costs were~~ positions reclassified to realized upon settlement on transmission products,

partially offset by ~~the utilization of higher volumes of natural gas and~~ higher congestion costs in PJM of $142 million, mainly as a result of credits received in the ~~PJM region.~~prior year due to extremely cold weather.

Gas costs decreased ~~$172~~$123 million mainly related to

a decrease of $136 million related to ~~lower average gas inventory costs on both obligations under the BGSS contract and~~ sales ~~to third parties. This was partially offset by higher volumes sold~~ under the BGSS contract due primarily to ~~colder~~lower volumes sold due to warmer average temperatures during the ~~2015~~2016 winter heating ~~season.~~season and lower average gas costs,

partially offset by a net increase of $13 million related to sales to third parties due primarily to an increase in volumes sold.

Table of Contents

Operation and Maintenance~~decreased$144~~ increased $33 million due primarily to

~~a decrease~~$145 million of ~~$145 million due to~~ insurance recoveries received in 2015 related to Superstorm Sandy, ~~and~~

~~table of contents~~

partially offset by a net decrease of ~~$36~~$85 million related to our fossil plants, largely due to higher costs incurred in ~~2014~~2015 for our planned ~~outage costs, including maintenance and installation of upgraded technology~~major outages at ~~our Linden combined cycle gas generating plant, partly offset by planned outage costs in 2015 at our~~the Bethlehem Energy Center and Bergen generating ~~plant~~plants, and ~~installation~~

a net decrease of ~~upgraded technology at our combined cycle Bergen plant,~~

~~partially offset by an increase of $37~~$38 million atrelated to our nuclear ~~facilities,~~plants due primarily ~~due~~ to ~~higher planned outage costs at our Hope Creek nuclear plant in 2015 as compared to our Salem nuclear unit 2 in 2014.~~the aforementioned reasons provided for the second quarter variance.

Depreciation and Amortizationincreased $78 milliondue primarily to a higher depreciable ~~fossil and~~ nuclear asset base.

~~Income from Equity Method Investments~~ ~~experienced no material change.~~

Other Income ~~and~~ (Deductions) ~~increased $6~~decreased $42 million due primarily to a $28 million of insurance ~~recovery~~recoveries received in 2015 related to Superstorm Sandy ~~offset by lower~~and higher net realized gains from the NDT ~~Fund.~~Fund in 2015.

Other-Than-Temporary Impairments increased ~~$11~~$5 million due to an increase in impairments of equity securities in the NDT ~~Fund.~~Fund in 2016.

Interest Expense ~~experienced no material change.~~decreased $22 million due primarily to the maturity of $300 million of 5.50% Senior Notes in December 2015 and higher capitalized interest in 2016.

Income Tax Expense~~increased$173 million~~ decreased $188 million in ~~2015~~2016 due primarily to ~~higher~~lower pre-tax income.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.

Operating Cash Flows

~~Our~~We expect operating cash flows combined with cash on hand and financing activities ~~are expected~~ to be sufficient to fund planned capital expenditures and shareholder dividend payments.

For the six months ended June 30, ~~2015~~2016, our operating cash flow ~~increased~~decreased $~~786~~512 million as compared to the same period in ~~2014.~~2015. The net change was due primarily to ~~higher tax payments in 2014 at the parent company and Energy Holdings and~~ the net changes from PSE&G and Power as discussed below.

PSE&G

PSE&G’s operating cash flow ~~increased~~decreased $~~172~~101 million from $~~737~~909 million to $~~909~~808 million for the six months ended June 30, ~~2015~~2016, as compared to the same period in ~~2014~~2015, due primarily to ~~higher earnings, a $176 million reduction in tax payments and increased customer collections of $9 million. These amounts were partially offset by~~ a decrease of ~~$227~~$87 million due to a change in regulatory deferrals primarily driven by ~~the return of prior year overcollections~~lower volumes due to ~~customers for BGSS gas costs,~~warmer weather impacting our Gas Weather Normalization, ~~charges~~SBC, GPRC and ~~Non-Utility Generation charges.~~BGSS clauses and a $77 million decrease due to higher vendor payments. These amounts were partially offset by higher earnings and higher tax refunds in 2016.

Power

Power’s operating cash flow ~~increased~~decreased $~~478~~375 million from $~~814~~1,292 million to $~~1,292~~917 million for the six months ended June 30, ~~2015~~2016, as compared to the same period in ~~2014,~~2015, primarily due to ~~higher~~lower earnings, a $123 million decrease from fuels, materials and supplies, and a ~~reduction~~$115 million increase in margin deposit requirements, partially offset by ~~an increase of $171 million~~a reduction in tax payments.

Short-Term Liquidity

~~The commitments under~~

Table of Contents

We continually monitor our ~~$4.3 billion credit facilities are provided by a diverse bank group. As of~~ ~~June 30, 2015~~,liquidity and seek to add capacity as needed to meet our ~~total available credit capacity was $4.1 billion.~~

~~As of~~ ~~June 30, 2015, no single institution represented more than~~ 8% ~~of the total commitments in our credit facilities.~~

~~As of~~ ~~June 30, 2015, our total credit capacity was in excess of our anticipated maximum~~ liquidity requirements.

Each of our credit facilities is restricted as to availability and use to the specific companies as listed ~~in the following table;~~below; however, if necessary, the PSEG facilities can also be used to support our ~~subsidiaries'~~subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of June 30, ~~2015~~2016 were as follows:

~~table of contents~~

As of June 30, 2015
Company/Facility
Total
Facility
Usage
Available
Liquidity

Expiration
Date
Primary Purpose
Millions
PSEG
  5-year Credit Facility $ 500
$ 8
$ 492
Apr 2019 Commercial Paper (CP) Support/Funding/Letters of Credit
  5-year Credit Facility (A) 500
—
500
Apr 2020 CP Support/Funding/Letters of Credit
Total PSEG $ 1,000
$ 8
$ 992

PSE&G
5-year Credit Facility (B) $ 600
$ 14
$ 586
Apr 2020 CP Support/Funding/Letters of Credit
Total PSE&G $ 600
$ 14
$ 586

Power
  5-year Credit Facility $ 1,600
$ 198
$ 1,402
Apr 2019 Funding/Letters of Credit
  5-year Credit Facility (C) 1,000
—
1,000
Apr 2020 Funding/Letters of Credit
  Bilateral Credit Facility 100
—
100
Sept 2015 Letters of Credit
Total Power $ 2,700
$ 198
$ 2,502

Total $ 4,300
$ 220
$ 4,080




Company/Facility	As of June 30, 2016
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,000	$	10	$	990
PSE&G	600		14		586
Power	2,553		202		2,351
Total	$	4,153	$	226	$	3,927

~~(A)~~As of June 30, 2016, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the ~~PSEG facility will~~potential impact of Power losing its investment grade credit rating, which would represent a three level downgrade from its current S&P and Moody’s ratings. In the event of a deterioration of Power’s credit rating certain of Power's agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be ~~reduced by $23~~required to post under these agreements if Power were to lose its investment grade credit rating was approximately $748 million ~~in April~~and $864 million as of June 30, 2016 and ~~$12 million~~December 31, 2015, respectively.

As of June 30, PSEG’s credit facilities are available to back-stop its Commercial Paper Program and issue letters of credit. As of June 30, 2016, no Commercial Paper was outstanding. PSE&G's credit facility primary use is to support its Commercial Paper Program under which as of June 30, 2016, no amounts were outstanding. Most of our credit facilities expire in ~~March 2018.~~2019 and 2020.

~~(B)PSE&G facility will be reduced by $29 million in April 2016~~For additional information, see Item 1.Note 9. Debt and ~~$14 million in March 2018.~~

~~(C)Power facility will be reduced by $48 million in April 2016 and $24 million in March 2018.~~Credit Facilities.

Long-Term Debt Financing

~~PSE&G~~Power has ~~$171~~$303 million of ~~6.75% Mortgage Bonds maturing in January 2016. Power has $300~~5.32% Senior Notes and $250 million of ~~5.50%~~2.75% Senior Notes maturing in ~~December 2015.~~September 2016.

For a discussion of our long-term debt transactions during ~~2015,~~2016, see Item 1. Note 9. ~~Changes in Capitalization.~~Debt and Credit Facilities.

Common Stock Dividends

On ~~July 21, 2015,~~April 19, 2016, our Board of Directors approved a ~~$0.39~~$0.41 per share of common stock dividend for the second quarter of 2016. On July 19, 2016, our Board of Directors declared a quarterly dividend of $0.41 per share of common stock for the third quarter of ~~2015.~~2016. This reflects an ~~indicated~~indicative annual dividend rate of ~~$1.56~~$1.64 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. Note 15. 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 Fitch)~~(Moody’s) and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies' ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

In ~~May 2015, Moody’s~~January 2016, S&P published updated research reports on PSEG and PSE&G ~~and Power~~ and the existing ratings and outlooks were unchanged. In ~~May 2015,~~June 2016, Moody's published credit opinions on Power and PSE&G and the existing ratings and outlooks were unchanged. In June 2016, S&P published an updated research ~~reports and revised the outlook to stable from positive for PSEG’s Corporate Credit Rating and Power’s Senior Notes. S&P also affirmed the senior unsecured rating of BBB+ at~~report on Power and the ~~mortgage bond~~existing rating ~~of A at PSE&G.~~and outlook were unchanged.

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	Moody’s (A)			S&P (B)	~~Fitch (C)~~
PSEG
Outlook	Positive		Stable
Commercial Paper	P2		A2
PSE&G
Outlook	Stable			Stable
~~Stable~~Mortgage Bonds	Aa3		A
Commercial Paper	P2	P1		A2	F2
~~PSE&G~~			Power
Outlook	Stable			~~Stable~~	~~Stable~~
~~Mortgage Bonds~~	~~Aa3~~			A	A+
~~Commercial Paper~~	P1			A2	F2
~~Power~~
~~Outlook~~	~~Stable~~			~~Stable~~	Stable
Senior Notes	Baa1			~~BBB+~~	BBB+


(A)	Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.


(B)	S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. The Corporate Credit Rating outlook does not apply to PSEG's or PSE&G's Commercial Paper Rating or PSE&G's Mortgage Bond rating.


~~(C)~~	~~Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities.~~

CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing.

~~In February 2015, we filed a petition with the BPU seeking authority to invest $1.6 billion over the next 5 years, or about $320 million per year, to modernize PSE&G’s gas systems.~~

In June 2015, we acquired a development project to construct a 755 MW gas-fired combined cycle generating station in Maryland (Keys Energy Center). We plan to start constructing this year with expected completion in 2018 at an estimated investment of $825 million - $875 million.

The estimated project expenditures related to the gas system modernization program at PSE&G and the Maryland project at Power are not included in the $8.7 billion three-year capital forecast table in our 2014 Form 10-K. There were no material changes to our projected capital expenditures at Power and Services as compared to amounts disclosed in our ~~2014~~2015 Form 10-K.

PSEG

In July 2016, PSEG partnered with Vectren Corporation on a FERC 1000 proposal to construct, own and operate a twenty mile, 345 kilovolt transmission line in the midwest region served by the Midcontinent Independent System Operator (MISO). MISO estimated the project would cost approximately $60 million and would go in service in 2021. MISO is expected to select a proposal in December 2016. This project is not included in PSEG's projected capital expenditures.

PSE&G

PSE&G increased its estimate of its capital expenditure program as reported in our 2015 Form 10-K by approximately $300 million from $8.3 billion to $8.6 billion primarily to address new business requests and to replace aging equipment and infrastructure.

In May 2016, PSE&G filed a petition with the BPU requesting an extension of its existing landfill/brownfield solar program to construct 100 MW of grid-connected solar facilities with projected capital expenditures of up to $240 million through approximately 2021. This is not included in PSE&G's projected capital expenditures.

During the six months ended June 30, ~~2015,~~2016, PSE&G made capital expenditures of ~~$1,230~~$1,355 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$58~~$74 million, which are included in operating cash flows.

Power

During the six months ended June 30, ~~2015,~~2016, Power made capital expenditures of ~~$360~~$505 million, excluding $~~127~~93 million for nuclear fuel, primarily related to ~~various projects at its fossil~~our Keys, Sewaren 7, BH5 and ~~nuclear~~other generation ~~stations, including the new Maryland generating station noted above.~~projects.

ACCOUNTING MATTERS

For information related to recent accounting matters, see Item 1. Note 2. Recent Accounting Standards.

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ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.

Commodity Contracts

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

Value-at-Risk (VaR) Models

VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities.

The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.

From April through June ~~2015,~~2016, MTM VaR remained relatively ~~stable.~~stable between low of $10 million to high of $18 million at 95% confidence level. The range of VaR was narrower for the three months ended June 30, ~~2015~~2016 as compared with the year ended December 31, ~~2014.~~2015.

MTM VaR
Three Months Ended June 30, 2015 Year Ended December 31, 2014
Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End $ 15
$ 36

Average for the Period $ 18
$ 30

High $ 23
$ 195

Low $ 12
$ 14

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 23
$ 56

Average for the Period $ 28
$ 46

High $ 36
$ 306

Low $ 18
$ 22




	MTM VaR
	Three Months Ended June 30, 2016		Year Ended December 31, 2015
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	16	$	24
Average for the Period	$	15	$	17
High	$	18	$	40
Low	$	10	$	8
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	25	$	38
Average for the Period	$	23	$	26
High	$	27	$	63
Low	$	16	$	12

See Item 1. Note 10. Financial Risk Management Activities for a discussion of credit risk.

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ITEM 4.	CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of Public Service Enterprise Group Incorporated, Public Service Electric and Gas Company and PSEG Power LLC. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of Public Service Enterprise Group Incorporated, Public Service Electric and Gas Company and PSEG Power LLC have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

There have been no changes in internal control over financial reporting that occurred during the second quarter of ~~2015~~2016 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

We are party to various lawsuits and regulatory matters in the ordinary course of business. For additional information regarding material legal proceedings, including updates to information reported in Item 3 of Part I of the ~~2014~~2015 Annual Report on Form 10-K, see Part I, Item 1. Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.


ITEM 1A.	RISK FACTORS

There are no additional Risk Factors to be added to those disclosed in Part I, Item 1A of our ~~2014~~2015 Annual Report on Form 10-K.


ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the second quarter of ~~2015~~2016.

Three Months Ended June 30, 2015
Total Number
of Shares
Purchased

Average
Price Paid
per Share

April 1 - April 30 —
$ —

May 1- May 31 49,360
$ 42.70

June 1- June 30 —
$ —




Three Months Ended June 30, 2016	Total Number of Shares Purchased	Average Price Paid per Share
April 1 - April 30	—	$	—
May 1 - May 31	228,639	$	46.23
June 1- June 30	50,000	$	44.50

ITEM 5. OTHER INFORMATION

Certain information reported in the ~~2014~~2015 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the ~~2014~~2015 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, ~~2015.~~2016. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.

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~~Federal Regulation~~

~~FERC~~

~~Regulation of Wholesale Sales—Generation/Market Issues~~

~~Capacity Market Issues~~—~~PJM~~Employee Relations

December 31, ~~2014~~2015 Form 10-K page 16 and March 31, ~~2015~~2016 Form 10-Q page 6970. Since the beginning of 2016, six of our eight labor unions ratified extensions of their collective bargaining agreements with us, with expiration dates from 2019 to

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2021. The collective bargaining agreements for the remaining two unions expire in 2017 and 2018. We believe we maintain satisfactory relationships with our employees.

Federal Regulation

FERC

Capacity Market Issues—PJM

December 31, 2015 Form 10-K page 17 and March 31, 2016 Form 10-Q page 70. An emerging issue in PJM involves the impact of subsidized generation on RPM market outcomes. In particular, FirstEnergy Corp. (FE) and American Electric Power (AEP) have proposed to enter into power purchase agreements (PPAs) with their non-utility generation affiliates providing for above-market purchases from certain coal plants and a nuclear plant (in FE's case). The Ohio Public Utility Commission (PUCO) approved the PPAs on terms similar to the terms sought by those companies. The Dayton Power and Light Company has recently also filed for comparable arrangements covering generating plants that it owns. On April 27, 2016, FERC issued orders finding that the PPAs should be reviewed to determine whether they comport with the Commission’s standards for contracts. FE subsequently submitted a modified arrangement to PUCO arguing that it is within PUCO’s exclusive jurisdiction. This modified proposal is currently the subject of contested proceedings at both the PUCO and at FERC. In another proceeding at FERC, certain parties are claiming that PJM should be directed to expand the MOPR to apply to existing contracts, including the FE and AEP PPAs.

We are unable to predict the results of these pending proceedings or any future related proceedings or to calculate the potential impacts on our business.

Capacity Market Issues—ISO-New England

December 31, 2015 Form 10-K page 18 and March 31, 2016 Form 10-Q page 71. ~~The RPM is the locational installed capacity market design~~In March 2015, in conjunction with other companies, we filed a petition for ~~the PJM region, including a forward auction for installed capacity. There is currently significant activity concerning two topics: (i) the future role of DR in the RPM market in light of a decision by~~review with the D.C. Circuit Court of Appeals (D.C. Court) ~~holding that DR is not~~of FERC's ruling accepting the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources. On December 1, 2015, following a ~~FERC-jurisdictional product, and (ii) PJM’s development~~request by FERC for a voluntary remand of ~~a new capacity product called a Capacity Performance (CP) product.~~

~~In May 2014,~~the order, the D.C. Court ~~held that DR is not a FERC-jurisdictional product, thereby calling into question DR resources’ ability~~remanded the case to ~~participate in either the energy or capacity markets in the future. The U.S. Supreme Court has agreed to hear this case. A decision~~FERC for additional consideration. However, on April 8, 2016, FERC issued an order upholding the ~~lower court decision would be expected~~exemption. We and other companies continue to ~~have a significant impact on~~contest the amount and manner of participation by DR in PJM's markets. However, until the U.S. Supreme Court rules on the case, DR will be allowed to participate in RPM for the upcoming base residual auction and capacity performance transitional auctions as supply resources under the recently accepted capacity performance rules described below.

On December 12, 2014, PJM filed a proposal at the FERC to implement a CP mechanism. Under this mechanism, PJM created a more robust capacity product definition with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. On June 9, 2015, the FERC conditionally accepted the CP mechanism which will be phased in over the next few years, with the participation of both the CP product and a base product that has less rigorous performance obligations. The CP mechanism will be implemented for the 2015 base residual auction which will begin on August 10, 2015. The CP product will be implemented fully for the 2020-2021 Delivery Year. The CP mechanism may provide the opportunity for enhanced capacity market revenue streams for Power. However, there may be requirements for additional investment and there are additional performance risks, as well as risks associated with our ability to bid in a manner that would ensure recovery of any required capital investment.

On June 30, 2015, a consumer coalition filed a complaint requesting that the load forecast that PJM is currently analyzing and updating to determine the amount of capacity it will procure in the 2016 base residual auction be implemented immediately for the upcoming 2015 transition auctions and base residual auction. If granted, usereasonableness of the ~~forecast values would likely decrease the amount of capacity to be procured and have an adverse impact on clearing prices in the 2015 base residual auction.~~exemption.

~~Capacity Market Issues~~—~~NYISO~~Reactive Power Rates

December 31, ~~2014~~2015 Form 10-K page 1719 and March 31, ~~2015~~2016 Form 10-Q page ~~70.~~71. ~~Matters are pending before~~In June 2015, Power submitted a tariff filing with FERC to increase Power’s rates for reactive supply and voltage control service from approximately $27 million per year to about $39 million per year. Following settlement discussions with FERC Trial Staff, Power agreed to accept an overall rate of $34 million per year on the condition that we will refile in six years, which FERC approved in February 2016. FERC had earlier referred the filing to the FERC ~~concerning~~Office of Enforcement for its evaluation, which remains pending. More broadly, FERC has begun to review regulations relating to reactive power compensation. We cannot predict the impact of potential changes to ~~the NYISO capacity markets, including rules~~reactive power compensation regulations on our business and results of operations.

Transmission Regulation

December 31, 2015 Form 10-K page 19. Each year, transmission revenues are adjusted to govern payments and bidding requirements for generators proposing to exit the market but required to remain in service for reliability reasons. On March 19, 2015, the FERC issued an order which held that units receiving special reliability payments could properly take those payments into account in formulating capacity market bids. We believe that this ruling could have impacts on efficient price formationreflect items such as updating estimates used in the ~~capacity market and could artificially suppress capacity market outcomes. On April 20,~~filing with actual data. In June 2016, PSE&G filed its 2015 ~~a trade association~~true-up adjustment pertaining to its transmission formula rates in effect for 2015, which resulted in an adjustment of ~~which we are a member~~$34 million less than the 2015 originally filed for rehearing by the FERC of this ruling. On May 8, 2015, the New York Public Service Commission and other New York agencies filed a complaint at the FERC requesting certain exemptions from the NYISO rules that prevent capacity suppliers from submitting bids that are not market competitive. If the exemptions are granted, market prices could be suppressed.revenues. For additional information about our transmission formula rate, see Part I, Item 1. Financial Information—Note 4. Rate Filings.

Transmission Regulation—Transmission Policy Developments

December 31, ~~2014~~2015 Form 10-K page 1819 and March 31, ~~2015~~2016 Form 10-Q page ~~70.~~71. ~~The~~ FERC concluded in Order 1000 that the incumbent transmission owner should not always have a Right of First Refusal (ROFR) to construct and own transmission projects in its service territory. We and other companies appealed Order 1000 but this appeal was denied ~~last year.~~in 2014 by the D.C. Court. The current PJM rules retain carve-outs for projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing ~~right-of-way~~rights-of-way and whose construction would interfere with incumbents’ use of their ~~right-of-way.~~rights-of-way. While these carve-outs ameliorate the impacts of the Order 1000 ruling on incumbents, we and several other companies appealed various aspects of the FERC order approving PJM’s implementation of Order 1000, onincluding the ~~grounds that the FERC had not met the requisite legal burden in eliminating~~elimination of the ROFR from the PJM Tariff. ~~This appeal remains~~On July 1, 2016, the D.C. Court dismissed the case, thus upholding FERC’s determination. We are currently analyzing the impact of the D.C. Court’s decision on our operations and whether further action is appropriate.

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There are several matters pending ~~in federal court.~~

~~In April 2013, PJM initiated its first "open window" solicitation process~~before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G contending that insufficient levels of costs are being allocated to ~~allow both incumbents and non-incumbents~~PSE&G. Projects involved include the ~~opportunity to submit transmission project proposals to address identified high voltage issues at~~ Artificial Island ~~off~~project, the ~~shore of~~Bergen-Linden project in New Jersey and a smaller project in Sewaren, New Jersey. On April ~~28, 2015,~~22, 2016, FERC issued orders denying the ~~PJM staff advised stakeholders that it intended~~complaints and leaving the current cost allocation in effect as to recommend a transmission project to the PJM Board of Managers consisting of various components to be constructed by LS Power, PSE&G and Potomac Holding Company. Based on PJM’s presentation, the total construction cost of the project components that would be assigned to PSE&G

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ranged between $100 million and $130 million. Interested parties were allowed to submit comments to the PJM Board of Managers (PJM Board) until May 29, 2015. We filed timely comments identifying what we believed were deficiencies in the PJM staff recommendation. On July 29, 2015, the PJM Board approved the PJM staff's recommendation. In a related matter, the FERC denied a complaint filed by PSE&G contending that PJM had failed to follow its rules during the Artificial Island ~~solicitation process.~~

~~There have also been developments on two additional matters. In November 2014, Con Edison had brought a complaint against PJM at~~and Bergen-Linden projects. Due to an intervening FERC order concerning the ~~FERC challenging PJM's~~ allocation of costs for ~~two~~projects constructed to meet local reliability requirements, FERC directed that all of the Sewaren costs be allocated to PSE&G. It is anticipated that additional proceedings are likely to occur. It is anticipated that these various proceedings will not be resolved for several years.

Another proceeding is a matter remanded from a federal appellate court concerning the appropriate cost allocation for certain 500 kV projects in PJM that either have been built or are in the process of being built, including the Susquehanna-Roseland project. A proposed settlement was filed with FERC on June 15, 2016. The settlement, if adopted by FERC, will result in increased annual cost allocations to customers in the PSE&G ~~projects~~Transmission Zone. Under this settlement, Power, as a BGS supplier could 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.

Con Edison Wheeling Agreement

In April 2016, Con Edison informed PJM that it would allow its Wheeling Agreement to expire effective as of May 1, 2017. The Wheeling Agreement enables Con Edison to move 1,000 MW of energy from southeast New York across the PSE&G system for delivery into New York City. Discussions are currently ongoing among PJM and NYISO stakeholders regarding future operational procedures and transmission planning assumptions associated with the affected transmission lines. Depending on the outcome of these discussions, which may require FERC to approve tariff revisions, there could be impacts on capacity and energy prices in ~~northern New Jersey, including~~ the ~~Bergen-Linden Corridor Project.~~region as well as impacts on transmission planning. In addition, Regional Transmission Expansion Plan costs that would have been allocated to Con Edison under the Wheeling Agreement will be reallocated elsewhere, which will include some reallocations to the customers within the PSE&G Transmission Zone.

Nuclear Regulatory Commission (NRC)

December 31, 2015 Form 10-K page 21. As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in 2011, the NRC began performing additional operational and safety reviews of nuclear facilities in the United States. We ~~had opposed Con Edison's complaint~~believe that our nuclear plants currently meet the stringent applicable design and safety specifications of the NRC.

Among other things, the NRC advised the staff to give the highest priority to those activities that can achieve the greatest safety benefit and/or have the broadest applicability (Tier 1).

The NRC issued letters and orders to licensees implementing the Tier 1 recommendations in March 2012. In June ~~2015,~~2013, the ~~FERC~~NRC issued an order ~~upholding~~requiring Mark I and Mark II licensees to upgrade or replace their reliable hardened vents with containment venting systems designed and installed to remain functional during severe accident conditions. We are implementing the diverse and flexible strategies and spent fuel pool level indication modifications in accordance with the regulatory requirements at the Salem, Hope Creek and Peach Bottom nuclear units. For our ~~position. Con Edison has sought judicial review of certain aspects of FERC’s order~~Hope Creek and ~~has the right to seek rehearing of other aspects~~Peach Bottom units, final installation of the ~~order. Also, in June 2015,~~required modifications is expected to be completed by 2018.

In March 2013, the NRC initiated a ~~transmission developer filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent~~rulemaking process for ~~evaluating transmission network upgrade requests that~~filtering strategies with drywell filtration and severe accident management for U.S. Boiling Water Reactors with Mark I and Mark II containments. The NRC subsequently disapproved the ~~transmission developer had submitted~~staff plan to ~~PJM. According~~pursue rulemaking, based in part on the upgrades required by the June 2013 order. The NRC continues to evaluate potential revisions to its requirements in connection with its operational and safety reviews of nuclear facilities in the complaint, PJM and certain transmission owners wrongfully inflated the scope and associated costs of mitigation work needed to accommodate the developer’s proposal in order to prevent it from pursuing its projects. Although not namedUnited States as a ~~respondent in the complaint, PSE&G is identified as one~~result of the ~~companies claimed~~Fukushima Daiichi incident.

We are unable to ~~have been involved. On July 10, 2015, PJM filed a response, which included a supporting affidavit from PSE&G, contesting~~predict the ~~allegations.~~ final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to our Salem, Hope Creek and Peach Bottom facilities, but such cost could be material.

State Regulation

~~Energy Efficiency Economic Stimulus Extension II (EEE Ext II)~~

~~December 31, 2014 Form 10-K page 22 and March 31, 2015 Form 10-Q page 71~~. On April 15, 2015, the BPU approved our petition for an EEE Ext II Program to extend three EEE subprograms (multi-family, direct install and hospital efficiency). The Order allows us to extend the subprogram offerings under the same clause recovery process as our existing EEE Program and allows for $95 million of additional capital expenditures over the next three years and $12 million of additional administrative expenses over the next 15 years. The EEE Ext II Program was added as a ninth component of the Green Program Recovery Charges rate effective May 1, 2015.

Connecticut Rate Filing

InDecember 31, 2015 Form 10-K page 23. On June ~~2015,~~30, 2016, Power’s subsidiary, PSEG New Haven LLC, filed a mandatory annual rate case with the Connecticut Public Utilities Regulatory Authority for recovery of its costs and investment in its Connecticut-based peaking unit. Power requested ~~2016~~2017 revenues of ~~$22~~$20 million. This matter is pending.

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Solar 4 All Program Extension II

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

Environmental Matters

Air Pollution Control

Hazardous Air Pollutants Regulation

December 31, ~~2014~~2015 Form 10-K page ~~22.~~24 and March 31, 2016 Form 10-Q page 72. In February 2012, the ~~Environmental Protection Agency~~ (~~EPA)~~(EPA) published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources under the National Emission Standard for Hazardous Air Pollutants (NESHAP) provisions of the ~~Clean Air Act.~~CAA. The MATS established allowable levels for mercury as well as other hazardous air pollutants and went into effect in April 2015. OnIn June ~~29,~~ 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plants. ~~The case has been remanded back~~On April 15, 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to the ~~D.C. Circuit Court of Appeals (D.C. Court)~~U.S. Supreme Court's ruling. Industry participants and ~~as a result the future of MATS remains unclear. If~~various state authorities have filed petitions with the D.C. Court ~~decides~~challenging the EPA’s Supplemental Finding. We do not expect this Supplemental Finding to remand the rule to the EPA with a stay or vacate the rule in its entirety, power plants located in states with less stringent air pollution control requirements may choose to cease operating their newly installed controls. In addition, such a decision could impact ~~decisions by other generators on plant retirements. Such uncertainty puts a downward pressure on power prices in the region. While the outcome~~operation of ~~MATS remains uncertain,~~ our ~~power generation plants are already in compliance with MATS.~~ facilities.

Demand Response (DR) Reciprocating Internal Combustion Engines (RICE) Litigation

December 31, ~~2014~~2015 Form 10-K page ~~23.~~24. In March 2013, Power filed a petition at the EPA challenging the National Emission Standards for Hazardous Air Pollutants (NESHAP) for RICE issued in January 2013. Among other things, the ~~final EPA rule includes~~NESHAP include two exemptions that allow owners and operators of stationery emergency RICE to operate their engines without the installation and operation of emission controls (1) as part of an emergency DR program for 100 hours per year (100 hour exemption) or (2) as part of a financial arrangement with another entity per specified restrictions in non-emergency situations for 50 hours per year (50 hour exemption). ~~This~~We believe this waiver of NESHAP standards results in disparate treatment of different generation technology types. In its appeal, Power sought more stringent emission control standards for RICE to support more competitive markets, particularly the PJM capacity market. In August 2014, the EPA denied the March 2013 petition and in October 2014, Power appealed the EPA's denial to the D.C. Court. On ~~May 1,~~September 23, 2015, the D.C. Court granted the EPA's motion for voluntary remand of the 50 hour exemption provision to the EPA. On May 4, 2016, the D.C. Court vacated the 100 hour

~~table of contents~~

~~exemption. The~~ exemption which removes that provision from the rule. We believe that the impact of ~~this ruling will~~the D.C. Court's rulings would likely benefit Power's and its competitors' operations of their power generation peaking units. ~~The D.C. Court's decision on the 50 hour exemption remains pending.~~

~~Climate Change~~

CO₂~~Regulation Under the Clean Air Act (CAA)~~

~~December 31, 2014 Form 10-K page 23 and March 31, 2015 Form 10-Q page 72.~~ In June 2014, the EPA issued a proposed greenhouse gas (GHG) emissions regulation under the CAA for existing power plants. The regulation establishes state-specific emission rate targets based on implementation of the best system of emission reduction (BSER). The BSER consists of four components: (i) heat rate improvements at existing coal-fired power plants, (ii) increased use of existing natural gas combined cycle capacity, (iii) operation of zero-emitting generation (renewables and nuclear), and (iv) increased use of demand-side energy efficiency. States may choose these or other methodologies to achieve the necessary reductions of CO₂ ~~emissions.~~

Since the EPA has requested comments on many aspects of the proposal, the final rule may look considerably different than the proposal. We continue to work with state and federal regulators, as well as industry partners, to determine the potential impact. A final rule is expected in August 2015.

The FERC held a series of technical conferences ending in early April 2015 to discuss the implications of compliance approaches to the EPA’s proposed GHG regulation for existing power plants. The conferences focused on issues related to electric reliability, wholesale electric markets and operations and energy infrastructure. The FERC also solicited and received written comments. On May 15, 2015, the FERC issued a letter to the EPA expressing its willingness to work with the EPA to address reliability concerns as the EPA moves toward finalizing the rule.

~~Water Pollution Control~~

Cooling Water Intake Structure Regulation

December 31, ~~2014 Form 10-K~~2015 Form10-K page ~~25.~~ 26.On June ~~30, 2015,~~10, 2016, the ~~NJDEP~~New Jersey Department of Environmental Protection (NJDEP) issued ~~a draft~~the final New Jersey Pollutant Discharge Elimination System (NJPDES) permit for ~~Salem.~~Salem, with an effective date of August 1, 2016. The ~~draft~~final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The ~~draft permit is subject to a sixty-day public notice and comment period after which the NJDEP may make revisions before issuing the~~ final permit ~~expected in the first half of 2016. We are reviewing the details~~does not mandate specific service water system modifications, but consistent with Section 316 (b) of the ~~draft, evaluating its potential impact~~Clean Water Act, it requires additional studies and ~~will participate in~~ the ~~comment process.~~selection of technology to address impingement for the service water system. On July 8, 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP's issuance of a final NJPDES renewal permit for Salem. The Riverkeeper's filing does not change the effective date of the permit. For additional information, see Part I, Item 1. Note 8. Commitments and Contingent Liabilities.

~~Waters of the United States~~

~~December 31, 2014 Form 10-K page 25.~~ In April 2014, the EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published a proposed rule to clarify the definition of waters of the U.S. under the Clean Water Act (CWA) programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. On November 14, 2014, we participated with other energy companies in submitting comments on the proposed rule. The final rule was published on June 29, 2015 and we are reviewing it to determine the materiality of the impacts that might result from the final rule.

~~Endangered Species Act~~

On June 16, 2015, the Sierra Club and another environmental group submitted to the NJDEP a sixty-day notice of intent to sue alleging the agency has caused violations of the Endangered Species Act by allowing our Mercer generation station to operate in a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a permit renewal action for Mercer which addresses the alleged Endangered Species Act violations. We cannot predict the outcome of this action.

~~Fuel and Waste Disposal~~

~~Coal Combustion Residuals (CCRs)~~

~~December 31, 2014 Form 10-K page 26 and March 31, 2015 Form 10-Q page 72~~. On December 19, 2014, the EPA issued a final rule which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Our Hudson and Mercer generating stations, along with our co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 14, 2015. The impacts of this final rule were not material to our results of operations, financial condition or cash flows. See Part I, Item 1. Note 8. Commitments and Contingent Liabilities for additional information.

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ITEM 6.	EXHIBITS

A listing of exhibits being filed with this document is as follows:



a. PSEG:
Exhibit 10a(10):		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016
Exhibit 12:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:		Certification by ~~Caroline Dorsa~~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 ~~Caroline Dorsa~~Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

b. PSE&G:
Exhibit 10a(9):		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016 ⁽¹⁾
Exhibit 12.1:		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.2:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

c. ~~PSE&G:~~
~~Exhibit 4 (a) (23)~~		~~Supplemental Indenture dated May 1, 2015~~
~~Exhibit 12.1:~~		~~Computation of Ratios of Earnings to Fixed Charges~~
~~Exhibit 12.2:~~		~~Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements~~
~~Exhibit 31.2:~~		~~Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act~~
~~Exhibit 31.3:~~		~~Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act~~
~~Exhibit 32.2:~~		~~Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code~~
~~Exhibit 32.3:~~		~~Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code~~
~~Exhibit 101.INS:~~		~~XBRL Instance Document~~
~~Exhibit 101.SCH:~~		~~XBRL Taxonomy Extension Schema~~
~~Exhibit 101.CAL:~~		~~XBRL Taxonomy Extension Calculation Linkbase~~
~~Exhibit 101.LAB:~~		~~XBRL Taxonomy Extension Labels Linkbase~~
~~Exhibit 101.PRE:~~		~~XBRL Taxonomy Extension Presentation Linkbase~~
~~Exhibit 101.DEF:~~		~~XBRL Taxonomy Extension Definition Document~~

b. Power:
Exhibit ~~12.3:~~10a(8):		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 19, 2016 ⁽¹⁾
Exhibit 12.2:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.4:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5:		Certification by ~~Caroline Dorsa~~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 ~~Caroline Dorsa~~Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

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

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.



PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: July ~~31, 2015~~29, 2016

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SIGNATURE



PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: July ~~31, 2015~~29, 2016

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SIGNATURE



PSEG POWER LLC
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: July ~~31, 2015~~29, 2016

8486



Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza ~~P.O. Box 1171~~ Newark, New Jersey ~~07101-1171~~07102 973 430-7000 http://www.pseg.com	22-2625848
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza ~~P.O. Box 570~~ Newark, New Jersey ~~07101-0570~~07102 973 430-7000 http://www.pseg.com	22-1212800
001-34232	PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza Newark, New Jersey ~~07102-4194~~07102 973 430-7000 http://www.pseg.com	22-3663480



Public Service Enterprise Group Incorporated	Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

Public Service Electric and Gas Company	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o

PSEG Power LLC	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o




	As of			As of
	June 30, 2015			December 31, 2014
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	661		$	691
Estimated Residual Value of Leased Assets	519			525
Unearned and Deferred Income	(372		)	(380		)
Gross Investment in Leases	808			836
Deferred Tax Liabilities	(695		)	(738		)
Net Investment in Leases	$	113		$	98




	As of			As of
	June 30, 2016			December 31, 2015
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	630		$	631
Estimated Residual Value of Leased Assets	519			519
Total Investment in Rental Receivables	1,149			1,150
Unearned and Deferred Income	(359		)	(366		)
Gross Investment in Leases	790			784
Deferred Tax Liabilities	(694		)	(724		)
Net Investment in Leases	$	96		$	60




Credit Risk Profile Based on Payment Activity
	As of		As of
Consumer Loans	June 30, 2015		December 31, 2014
	Millions
Commercial/Industrial	$	186	$	188
Residential	13		13
Total	$	199	$	201




Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	June 30, 2016		December 31, 2015
	Millions
Commercial/Industrial	$	174	$	177
Residential	12		12
Total	$	186	$	189




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating (Standard & Poor's (S&P))	As of
As of June 30, 2015	June 30, 2015
	Millions
AA	$	17
AA-	29
BBB+ — BBB-	316
BB-	134
B-	165
Total	$	661




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor's (S&P) as of June 30, 2016
	As of June 30, 2016
	Millions
AA	$	16
BBB+ — BBB-	316
BB-	134
CCC	164
Total	$	630




Asset	Location	Gross Investment		% Owned		Total	Fuel Type	Counter-parties’ S&P Credit Ratings	Counterparty
		Millions				MW
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	84	64	%	1,044	Coal	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	B-	NRG REMA LLC
Conemaugh Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	B-	NRG REMA LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	113	100	%	603	Coal	B-	NRG REMA LLC


(A)	The Joliet facility is currently in the process of converting to natural gas.


(B)	NRG REMA, LLC (NRG REMA) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the fall of 2016 with the ability to use natural gas.


(C)	On May 24, 2016, S&P lowered its corporate credit rating on GenOn Energy Inc. and affiliates (including NRG REMA) to "CCC" from "CCC+" due to a weaker forward power curve, milder weather patterns and weakening financial measures. PSEG continues to monitor any changes to GenOn's status and potential impacts on Energy Holdings' lease investments.




	As of December 31, 2014
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	685	$	220	$	(8	)	$	897
Debt Securities
Government Obligations	430		9		(1		)	438
Other Debt Securities	333		9		(3		)	339
Total Debt Securities	763		18		(4		)	777
Other Securities	106		—		—			106
Total NDT Available-for-Sale Securities	$	1,554	$	238	$	(12	)	$	1,780




	Auction Year
	2012	2013	2014	2015
36-Month Terms Ending	May 2015	May 2016	May 2017	May 2018	(A)
Load (MW)	2,900	2,800	2,800	2,900
$ per MWh	$83.88	$92.18	$97.39	$99.54




Fuel Type	Power's Share of Commitments through 2019
	Millions
Nuclear Fuel
Uranium	$	443
Enrichment	$	342
Fabrication	$	185
Natural Gas	$	1,072
Coal	$	360




	As of June 30, 2015
	Power (A)											PSE&G (A)		PSEG (A)		Consolidated
	Cash Flow Hedges		Not Designated									Not Designated		Fair Value Hedges
Balance Sheet Location	Energy- Related Contracts		Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts		Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	1	$	483		$	(345	)	$	139		$	5	$	11	$	155
Noncurrent Assets	—		220			(117		)	103			—		4		107
Total Mark-to-Market Derivative Assets	$	1	$	703		$	(462	)	$	242		$	5	$	15	$	262
Derivative Contracts
Current Liabilities	$	—	$	(421	)	$	349		$	(72	)	$	—	$	—	$	(72	)
Noncurrent Liabilities	—		(145		)	121			(24		)	—		—		(24		)
Total Mark-to-Market Derivative (Liabilities)	$	—	$	(566	)	$	470		$	(96	)	$	—	$	—	$	(96	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	1	$	137		$	8		$	146		$	5	$	15	$	166




	Three Months Ended June 30, 2014
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of April 1, 2014			Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2014
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	6		$	10		$	—	$	(1	)	$	(3	)	$	13
PSE&G
Net Derivative Assets (Liabilities)	$	12		$	—		$	10		$	—	$	—		$	—		$	22
Power
Net Derivative Assets (Liabilities)	$	(11	)	$	6		$	—		$	—	$	(1	)	$	(3	)	$	(9	)

	Six Months Ended June 30, 2014
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2014			Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of June 30, 2014
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	88		$	(58	)	$	(72	)	$	—	$	58		$	(3	)	$	13
PSE&G
Net Derivative Assets (Liabilities)	$	94		$	—		$	(72	)	$	—	$	—		$	—		$	22
Power
Net Derivative Assets (Liabilities)	$	(6	)	$	(58	)	$	—		$	—	$	58		$	(3	)	$	(9	)




	MTM VaR
	Three Months Ended June 30, 2015		Year Ended December 31, 2014
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	15	$	36
Average for the Period	$	18	$	30
High	$	23	$	195
Low	$	12	$	14
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	23	$	56
Average for the Period	$	28	$	46
High	$	36	$	306
Low	$	18	$	22