~~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)	17
	Note 4. Rate Filings	18
	Note 5. Financing Receivables	1918
	Note 6. Available-for-Sale Securities	2120
	Note 7. Pension and Other Postretirement Benefits (OPEB)	2726
	Note 8. Commitments and Contingent Liabilities	2827
	Note 9. Changes in Capitalization	35
	Note 10. Financial Risk Management Activities	3635
	Note 11. Fair Value Measurements	4340
	Note 12. Other Income and Deductions	5147
	Note 13. Income Taxes	5247
	Note 14. Accumulated Other Comprehensive Income (Loss), Net of Tax	5348
	Note 15. Earnings Per Share (EPS) and Dividends	5751
	Note 16. Financial Information by Business Segments	5852
	Note 17. Related-Party Transactions	5953
	Note 18. Guarantees of Debt	6155
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6457
	Executive Overview of ~~2015~~2016 and Future Outlook	6457
	Results of Operations	7063
	Liquidity and Capital Resources	7565
	Capital Requirements	7768
	Accounting Matters	7768
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	7868
Item 4.	Controls and Procedures	7969

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	7969
Item 1A.	Risk Factors	7970
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	7970
Item 5.	Other Information	8070
Item 6.	Exhibits	8473
	Signatures	8574

~~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 and disallowances,

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 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 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

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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 Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
OPERATING REVENUES $ 2,688
$ 2,641
$ 8,137
$ 8,113

OPERATING EXPENSES
Energy Costs 815
863
2,577
3,008

Operation and Maintenance 746
714
2,170
2,370

Depreciation and Amortization 313
318
960
919

Total Operating Expenses 1,874
1,895
5,707
6,297

OPERATING INCOME 814
746
2,430
1,816

Income from Equity Method Investments 3
3
10
10

Other Income 47
75
171
185

Other Deductions (14 ) (9 ) (36 ) (31 )
Other-Than-Temporary Impairments (30 ) (10 ) (45 ) (14 )
Interest Expense (96 ) (100 ) (291 ) (291 )
INCOME BEFORE INCOME TAXES 724
705
2,239
1,675

Income Tax Expense (285 ) (261 ) (869 ) (633 )
NET INCOME $ 439
$ 444
$ 1,370
$ 1,042

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC 505
506
505
506

DILUTED 508
507
508
507

NET INCOME PER SHARE:
BASIC $ 0.87
$ 0.88
$ 2.71
$ 2.06

DILUTED $ 0.87
$ 0.87
$ 2.70
$ 2.05

DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.39
$ 0.37
$ 1.17
$ 1.11

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

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~~PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED~~

~~CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~Millions~~

~~(Unaudited)~~

Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
NET INCOME $ 439
$ 444
$ 1,370
$ 1,042

Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $33, $33, $35 and $21 for the three and nine months ended 2015 and 2014, respectively (31 ) (30 ) (32 ) (17 )
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1), $(1), $6 and $(3) for the three and nine months ended 2015 and 2014, respectively —
1
(9 ) 4

Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(5), $(2), $(17) and $(5) for three and nine months ended 2015 and 2014, respectively 9
3
25
9

Other Comprehensive Income (Loss), net of tax (22 ) (26 ) (16 ) (4 )
COMPREHENSIVE INCOME $ 417
$ 418
$ 1,354
$ 1,038

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

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~~PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~Millions~~

~~(Unaudited)~~

September 30,
2015 December 31,
2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 271
$ 402

Accounts Receivable, net of allowances of $59 and $52 in 2015 and 2014, respectively 1,199
1,254

Tax Receivable 5
211

Unbilled Revenues 203
284

Fuel 451
538

Materials and Supplies, net 472
484

Prepayments 180
108

Derivative Contracts 162
240

Deferred Income Taxes 23
11

Regulatory Assets 189
323

Regulatory Assets of Variable Interest Entities (VIEs) —
249

Restricted Cash of VIEs 26
—

Other 23
15

Total Current Assets 3,204
4,119

PROPERTY, PLANT AND EQUIPMENT 34,625
32,196

Less: Accumulated Depreciation and Amortization (9,020 ) (8,607 )
Net Property, Plant and Equipment 25,605
23,589

NONCURRENT ASSETS
Regulatory Assets 3,161
3,192

Long-Term Investments 1,235
1,307

Nuclear Decommissioning Trust (NDT) Fund 1,715
1,780

Long-Term Tax Receivable 165
64

Long-Term Receivable of VIE 601
580

Other Special Funds 230
212

Goodwill 16
16

Other Intangibles 122
84

Derivative Contracts 91
77

Restricted Cash of VIEs —
24

Other 279
289

Total Noncurrent Assets 7,615
7,625

TOTAL ASSETS $ 36,424
$ 35,333

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

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~~PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED~~

~~CONDENSED CONSOLIDATED BALANCE SHEETS~~

~~Millions~~

~~(Unaudited)~~

September 30,
2015 December 31,
2014
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 1,038
$ 624

Securitization Debt of VIEs Due Within One Year 68
259

Commercial Paper and Loans 20
—

Accounts Payable 1,046
1,178

Derivative Contracts 70
132

Accrued Interest 123
95

Accrued Taxes 204
21

Deferred Income Taxes —
173

Clean Energy Program 185
142

Obligation to Return Cash Collateral 126
121

Regulatory Liabilities 208
186

Regulatory Liabilities of VIEs 3
—

Other 513
547

Total Current Liabilities 3,604
3,478

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC) 7,672
7,303

Regulatory Liabilities 181
258

Regulatory Liabilities of VIEs —
39

Asset Retirement Obligations 776
743

Other Postretirement Benefit (OPEB) Costs 1,250
1,277

OPEB Costs of Servco 480
452

Accrued Pension Costs 373
440

Accrued Pension Costs of Servco 118
126

Environmental Costs 438
417

Derivative Contracts 23
33

Long-Term Accrued Taxes 287
208

Other 156
112

Total Noncurrent Liabilities 11,754
11,408

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

CAPITALIZATION

LONG-TERM DEBT
Total Long-Term Debt 8,132
8,261

STOCKHOLDERS’ EQUITY

Common Stock, no par, authorized 1,000,000,000 shares; issued, 2015 and 2014—533,556,660 shares 4,894
4,876

Treasury Stock, at cost, 2015— 28,238,912 shares; 2014— 27,720,068 shares (667 ) (635 )
Retained Earnings 9,005
8,227

Accumulated Other Comprehensive Loss (299 ) (283 )
Total Common Stockholders’ Equity 12,933
12,185

Noncontrolling Interest 1
1

Total Stockholders’ Equity 12,934
12,186

Total Capitalization 21,066
20,447

TOTAL LIABILITIES AND CAPITALIZATION $ 36,424
$ 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)~~

Nine Months Ended
September 30,
2015 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 1,370
$ 1,042

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 960
919

Amortization of Nuclear Fuel 162
151

Provision for Deferred Income Taxes (Other than Leases) and ITC 230
103

Non-Cash Employee Benefit Plan Costs 121
36

Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes 6
(30 )
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives (87 ) 237

Change in Accrued Storm Costs 15
(3 )
Net Change in Other Regulatory Assets and Liabilities 26
276

Cost of Removal (82 ) (68 )
Net Realized (Gains) Losses and (Income) Expense from NDT Fund (2 ) (99 )
Net Change in Certain Current Assets and Liabilities:
          Tax Receivable 206
95

          Accrued Taxes 127
127

          Margin Deposit 142
(173 )
          Other Current Assets and Liabilities 15
(103 )
Employee Benefit Plan Funding and Related Payments (87 ) (76 )
Other 106
102

Net Cash Provided By (Used In) Operating Activities 3,228
2,536

CASH FLOWS FROM INVESTING ACTIVITIES

Additions to Property, Plant and Equipment (2,782 ) (1,922 )
Proceeds from Sales of Capital Leases and Investments 12
11

Proceeds from Sales of Available-for-Sale Securities 1,120
1,224

Investments in Available-for-Sale Securities (1,163 ) (1,241 )
Other (28 ) (60 )
Net Cash Provided By (Used In) Investing Activities (2,841 ) (1,988 )
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans 20
(60 )
Issuance of Long-Term Debt 600
1,000

Redemption of Long-Term Debt (300 ) (500 )
Redemption of Securitization Debt (191 ) (170 )
Cash Dividends Paid on Common Stock (592 ) (561 )
Other (55 ) (47 )
Net Cash Provided By (Used In) Financing Activities (518 ) (338 )
Net Increase (Decrease) in Cash and Cash Equivalents (131 ) 210

Cash and Cash Equivalents at Beginning of Period 402
493

Cash and Cash Equivalents at End of Period $ 271
$ 703

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 292
$ 284

Interest Paid, Net of Amounts Capitalized $ 265
$ 269

Accrued Property, Plant and Equipment Expenditures $ 321
$ 286

~~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 Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
OPERATING REVENUES $ 1,766
$ 1,655
$ 5,234
$ 5,235

OPERATING EXPENSES
Energy Costs 740
668
2,176
2,278

Operation and Maintenance 391
366
1,171
1,190

Depreciation and Amortization 231
238
712
682

Total Operating Expenses 1,362
1,272
4,059
4,150

OPERATING INCOME 404
383
1,175
1,085

Other Income 22
16
59
44

Other Deductions —
(2 ) (2 ) (3 )
Interest Expense (67 ) (71 ) (203 ) (206 )
INCOME BEFORE INCOME TAXES 359
326
1,029
920

Income Tax Expense (137 ) (126 ) (398 ) (355 )
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 222
$ 200
$ 631
$ 565

~~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 Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
NET INCOME $ 222
$ 200
$ 631
$ 565

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

COMPREHENSIVE INCOME $ 222
$ 201
$ 630
$ 566

~~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)~~

September 30,
2015 December 31,
2014
ASSETS
CURRENT ASSETS

Cash and Cash Equivalents $ 14
$ 310

Accounts Receivable, net of allowances of $59 and $52 in 2015 and 2014, respectively 938
864

Accounts Receivable-Affiliated Companies 7
274

Unbilled Revenues 203
284

Materials and Supplies 146
133

Prepayments 109
42

Regulatory Assets 189
323

Regulatory Assets of VIEs —
249

Derivative Contracts 4
18

Deferred Income Taxes 47
24

Restricted Cash of VIEs 26
—

Other 17
7

Total Current Assets 1,700
2,528

PROPERTY, PLANT AND EQUIPMENT 22,940
21,103

Less: Accumulated Depreciation and Amortization (5,419 ) (5,183 )
Net Property, Plant and Equipment 17,521
15,920

NONCURRENT ASSETS
Regulatory Assets 3,161
3,192

Long-Term Investments 335
348

Other Special Funds 52
53

Derivative Contracts —
8

Restricted Cash of VIEs —
24

Other 140
150

Total Noncurrent Assets 3,688
3,775

TOTAL ASSETS $ 22,909
$ 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)~~

September 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 68
259

Commercial Paper and Loans 20
—

Accounts Payable 567
574

Accounts Payable—Affiliated Companies 208
379

Accrued Interest 80
68

Clean Energy Program 185
142

Deferred Income Taxes —
165

Obligation to Return Cash Collateral 126
121

Regulatory Liabilities 208
186

Regulatory Liabilities of VIEs 3
—

Other 357
381

Total Current Liabilities 1,993
2,575

NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 4,896
4,575

Other Postretirement Benefit (OPEB) Costs 929
967

Accrued Pension Costs 131
173

Regulatory Liabilities 181
258

Regulatory Liabilities of VIEs —
39

Environmental Costs 387
364

Asset Retirement Obligations 304
290

Long-Term Accrued Taxes 165
116

Derivative Contracts 7
—

Other 58
67

Total Noncurrent Liabilities 7,058
6,849

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

CAPITALIZATION
LONG-TERM DEBT

Total Long-Term Debt 6,441
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 4,843
4,212

Accumulated Other Comprehensive Income 1
2

Total Stockholder’s Equity 7,417
6,787

Total Capitalization 13,858
12,799

TOTAL LIABILITIES AND CAPITALIZATION $ 22,909
$ 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)~~

Nine Months Ended
September 30,
2015 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 631
$ 565

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 712
682

Provision for Deferred Income Taxes and ITC 96
93

Non-Cash Employee Benefit Plan Costs 71
21

Cost of Removal (82 ) (68 )
Change in Accrued Storm Costs 15
(3 )
Net Change in Other Regulatory Assets and Liabilities 26
276

Net Change in Certain Current Assets and Liabilities:

Accounts Receivable and Unbilled Revenues 30
71

Materials and Supplies (13 ) (15 )
Prepayments (67 ) (92 )
Accounts Payable 34
(3 )
Accounts Receivable/Payable—Affiliated Companies, net 190
(113 )
Other Current Assets and Liabilities (18 ) (6 )
Employee Benefit Plan Funding and Related Payments (72 ) (67 )
Other (35 ) 2

Net Cash Provided By (Used In) Operating Activities 1,518
1,343

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (1,946 ) (1,493 )
Proceeds from Sales of Available-for-Sale Securities 16
98

Investments in Available-for-Sale Securities (18 ) (96 )
Other 13
1

Net Cash Provided By (Used In) Investing Activities (1,935 ) (1,490 )
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt 20
(60 )
Issuance of Long-Term Debt 600
1,000

Redemption of Long-Term Debt (300 ) (500 )
Redemption of Securitization Debt (191 ) (170 )
Contributed Capital —
175

Other (8 ) (11 )
Net Cash Provided By (Used In) Financing Activities 121
434

Net Increase (Decrease) In Cash and Cash Equivalents (296 ) 287

Cash and Cash Equivalents at Beginning of Period 310
18

Cash and Cash Equivalents at End of Period $ 14
$ 305

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ (29 ) $ 174

Interest Paid, Net of Amounts Capitalized $ 186
$ 188

Accrued Property, Plant and Equipment Expenditures $ 251
$ 238

~~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 Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
OPERATING REVENUES $ 1,096
$ 1,138
$ 3,846
$ 3,824

OPERATING EXPENSES
Energy Costs 367
472
1,669
2,036

Operation and Maintenance 263
242
748
871

Depreciation and Amortization 75
71
226
215

Total Operating Expenses 705
785
2,643
3,122

OPERATING INCOME 391
353
1,203
702

Income from Equity Method Investments 3
4
11
11

Other Income 25
56
109
135

Other Deductions (14 ) (6 ) (32 ) (25 )
Other-Than-Temporary Impairments (30 ) (10 ) (45 ) (14 )
Interest Expense (30 ) (31 ) (94 ) (92 )
INCOME BEFORE INCOME TAXES 345
366
1,152
717

Income Tax Expense (139 ) (144 ) (445 ) (277 )
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 206
$ 222
$ 707
$ 440

~~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 Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
NET INCOME $ 206
$ 222
$ 707
$ 440

Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $32, $34, $33 and $23 for the three and nine months ended 2015 and 2014, respectively (29 ) (30 ) (29 ) (19 )
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1), $0, $6 and $(2) for the three and nine months ended 2015 and 2014, respectively —
1
(9 ) 4

Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(1), $(15) and $(4) for the three and nine months ended 2015 and 2014, respectively 7
2
21
7

Other Comprehensive Income (Loss), net of tax (22 ) (27 ) (17 ) (8 )
COMPREHENSIVE INCOME $ 184
$ 195
$ 690
$ 432

~~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)~~

September 30,
2015 December 31,
2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 15
$ 9

Accounts Receivable 218
334

Accounts Receivable—Affiliated Companies 158
313

Tax Receivable 3
3

Short-Term Loan to Affiliate 865
584

Fuel 451
538

Materials and Supplies, net 324
350

Derivative Contracts 147
207

Prepayments 36
17

Other 7
4

Total Current Assets 2,224
2,359

PROPERTY, PLANT AND EQUIPMENT 11,273
10,732

Less: Accumulated Depreciation and Amortization (3,366 ) (3,217 )
Net Property, Plant and Equipment 7,907
7,515

NONCURRENT ASSETS
Nuclear Decommissioning Trust (NDT) Fund 1,715
1,780

Long-Term Investments 116
121

Goodwill 16
16

Other Intangibles 122
84

Other Special Funds 56
49

Derivative Contracts 91
62

Other 67
60

Total Noncurrent Assets 2,183
2,172

TOTAL ASSETS $ 12,314
$ 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)~~

September 30,
2015 December 31,
2014
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 853
$ 300

Accounts Payable 315
424

Accounts Payable-Affiliated Companies 117
118

Derivative Contracts 70
132

Deferred Income Taxes 44
43

Accrued Interest 43
27

Other 132
140

Total Current Liabilities 1,574
1,184

NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC) 2,148
2,065

Asset Retirement Obligations 469
450

Other Postretirement Benefit (OPEB) Costs 258
248

Derivative Contracts 16
33

Accrued Pension Costs 134
153

Long-Term Accrued Taxes 54
41

Other 121
71

Total Noncurrent Liabilities 3,200
3,061

COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)

LONG-TERM DEBT
Total Long-Term Debt 1,691
2,243

MEMBER’S EQUITY
Contributed Capital 2,215
2,214

Basis Adjustment (986 ) (986 )
Retained Earnings 4,865
4,558

Accumulated Other Comprehensive Loss (245 ) (228 )
Total Member’s Equity 5,849
5,558

TOTAL LIABILITIES AND MEMBER’S EQUITY $ 12,314
$ 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)~~

Nine Months Ended
September 30,
2015 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 707
$ 440

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 226
215

Amortization of Nuclear Fuel 162
151

Provision for Deferred Income Taxes and ITC 109
5

Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives (87 ) 237

Non-Cash Employee Benefit Plan Costs 36
10

Net Realized (Gains) Losses and (Income) Expense from NDT Fund (2 ) (99 )
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies 113
17

Margin Deposit 142
(173 )
Accounts Receivable 54
49

Accounts Payable (99 ) (135 )
Accounts Receivable/Payable—Affiliated Companies, net 115
299

Other Current Assets and Liabilities (26 ) 28

Employee Benefit Plan Funding and Related Payments (9 ) (5 )
Other 117
71

Net Cash Provided By (Used In) Operating Activities 1,558
1,110

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (797 ) (414 )
Proceeds from Sales of Available-for-Sale Securities 1,057
882

Investments in Available-for-Sale Securities (1,083 ) (898 )
Short-Term Loan—Affiliated Company, net (281 ) 167

Other (46 ) (63 )
Net Cash Provided By (Used In) Investing Activities (1,150 ) (326 )
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid (400 ) (775 )
Other (2 ) (3 )
Net Cash Provided By (Used In) Financing Activities (402 ) (778 )
Net Increase (Decrease) in Cash and Cash Equivalents 6
6

Cash and Cash Equivalents at Beginning of Period 9
6

Cash and Cash Equivalents at End of Period $ 15
$ 12

Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 284
$ 87

Interest Paid, Net of Amounts Capitalized $ 76
$ 78

Accrued Property, Plant and Equipment Expenditures $ 70
$ 66

~~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
	March 31,
	2016			2015
OPERATING REVENUES	$	2,616		$	3,135
OPERATING EXPENSES
Energy Costs	836			1,094
Operation and Maintenance	729			663
Depreciation and Amortization	224			330
Total Operating Expenses	1,789			2,087
OPERATING INCOME	827			1,048
Income from Equity Method Investments	2			3
Other Income	48			48
Other Deductions	(21		)	(12		)
Other-Than-Temporary Impairments	(10		)	(5		)
Interest Expense	(92		)	(98		)
INCOME BEFORE INCOME TAXES	754			984
Income Tax Expense	(283		)	(398		)
NET INCOME	$	471		$	586
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			506
DILUTED	508			508
NET INCOME PER SHARE:
BASIC	$	0.93		$	1.16
DILUTED	$	0.93		$	1.15
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.41		$	0.39

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
	March 31,
	2016		2015
NET INCOME	$	471	$	586
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(16) and $(13) for 2016 and 2015, respectively	16		14
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1) and $7 for 2016 and 2015, respectively	2		(9		)
Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(6) and $(6) for 2016 and 2015, respectively	8		8
Other Comprehensive Income (Loss), net of tax	26		13
COMPREHENSIVE INCOME	$	497	$	599

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	March 31, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	592		$	394
Accounts Receivable, net of allowances of $66 and $67 in 2016 and 2015, respectively	1,107			1,068
Tax Receivable	4			305
Unbilled Revenues	178			197
Fuel	306			463
Materials and Supplies, net	533			513
Prepayments	89			135
Derivative Contracts	230			242
Regulatory Assets	217			164
Other	7			13
Total Current Assets	3,263			3,494
PROPERTY, PLANT AND EQUIPMENT	36,393			35,494
Less: Accumulated Depreciation and Amortization	(9,119		)	(8,955		)
Net Property, Plant and Equipment	27,274			26,539
NONCURRENT ASSETS
Regulatory Assets	3,150			3,196
Long-Term Investments	1,234			1,233
Nuclear Decommissioning Trust (NDT) Fund	1,778			1,754
Long-Term Tax Receivable	184			171
Long-Term Receivable of Variable Interest Entity (VIE)	506			495
Other Special Funds	246			227
Goodwill	16			16
Other Intangibles	112			102
Derivative Contracts	133			77
Other	230			231
Total Noncurrent Assets	7,589			7,502
TOTAL ASSETS	$	38,126		$	37,535

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	March 31, 2016			December 31, 2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	562		$	734
Commercial Paper and Loans	12			364
Accounts Payable	1,192			1,369
Derivative Contracts	53			76
Accrued Interest	123			96
Accrued Taxes	155			42
Clean Energy Program	86			142
Obligation to Return Cash Collateral	130			128
Regulatory Liabilities	115			123
Regulatory Liabilities of VIEs	32			42
Other	482			459
Total Current Liabilities	2,942			3,575
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,377			8,166
Regulatory Liabilities	177			175
Asset Retirement Obligations	686			679
OPEB Costs	1,205			1,228
OPEB Costs of Servco	382			375
Accrued Pension Costs	458			487
Accrued Pension Costs of Servco	117			114
Environmental Costs	423			415
Derivative Contracts	14			27
Long-Term Accrued Taxes	176			212
Other	174			181
Total Noncurrent Liabilities	12,189			12,059
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT	9,676			8,834
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2016 and 2015—534 shares	4,908			4,915
Treasury Stock, at cost, 2016 - 29 shares; 2015— 28 shares	(702		)	(671		)
Retained Earnings	9,381			9,117
Accumulated Other Comprehensive Loss	(269		)	(295		)
Total Common Stockholders’ Equity	13,318			13,066
Noncontrolling Interest	1			1
Total Stockholders’ Equity	13,319			13,067
Total Capitalization	22,995			21,901
TOTAL LIABILITIES AND CAPITALIZATION	$	38,126		$	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)




	Three Months Ended
	March 31,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	471		$	586
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	224			330
Amortization of Nuclear Fuel	58			55
Provision for Deferred Income Taxes (Other than Leases) and ITC	182			63
Non-Cash Employee Benefit Plan Costs	32			41
Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes	(15		)	4
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(21		)	37
Change in Accrued Storm Costs	(1		)	7
Net Change in Other Regulatory Assets and Liabilities	(104		)	(29		)
Cost of Removal	(35		)	(26		)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	3			(12		)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	301			180
Accrued Taxes	144			322
Margin Deposit	(4		)	14
Other Current Assets and Liabilities	27			109
Employee Benefit Plan Funding and Related Payments	(56		)	(47		)
Other	8			45
Net Cash Provided By (Used In) Operating Activities	1,214			1,679
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(1,065		)	(747		)
Proceeds from Sales of Available-for-Sale Securities	202			609
Investments in Available-for-Sale Securities	(207		)	(638		)
Other	(11		)	(3		)
Net Cash Provided By (Used In) Investing Activities	(1,081		)	(779		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(352		)	—
Issuance of Long-Term Debt	850			—
Redemption of Long-Term Debt	(171		)	—
Redemption of Securitization Debt	—			(58		)
Cash Dividends Paid on Common Stock	(207		)	(197		)
Other	(55		)	(39		)
Net Cash Provided By (Used In) Financing Activities	65			(294		)
Net Increase (Decrease) in Cash and Cash Equivalents	198			606
Cash and Cash Equivalents at Beginning of Period	394			402
Cash and Cash Equivalents at End of Period	$	592		$	1,008
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(299	)	$	(175	)
Interest Paid, Net of Amounts Capitalized	$	66		$	74
Accrued Property, Plant and Equipment Expenditures	$	434		$	276

See Notes to Condensed Consolidated Financial Statements.

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended
	March 31,
	2016			2015
OPERATING REVENUES	$	1,712		$	2,002
OPERATING EXPENSES
Energy Costs	729			892
Operation and Maintenance	382			412
Depreciation and Amortization	139			247
Total Operating Expenses	1,250			1,551
OPERATING INCOME	462			451
Other Income	20			18
Other Deductions	(1		)	(1		)
Interest Expense	(68		)	(69		)
INCOME BEFORE INCOME TAXES	413			399
Income Tax Expense	(151		)	(157		)
NET INCOME	$	262		$	242

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions

(Unaudited)




	Three Months Ended
	March 31,
	2016		2015
NET INCOME	$	262	$	242
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0 and $0 for 2016 and 2015, respectively	—		—
COMPREHENSIVE INCOME	$	262	$	242

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

Table of Contents

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	March 31, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	558		$	198
Accounts Receivable, net of allowances of $66 and $67 in 2016 and 2015, respectively	831			787
Accounts Receivable—Affiliated Companies	3			222
Unbilled Revenues	178			197
Materials and Supplies	154			148
Prepayments	5			31
Regulatory Assets	217			164
Derivative Contracts	8			13
Other	5			9
Total Current Assets	1,959			1,769
PROPERTY, PLANT AND EQUIPMENT	24,347			23,732
Less: Accumulated Depreciation and Amortization	(5,584		)	(5,504		)
Net Property, Plant and Equipment	18,763			18,228
NONCURRENT ASSETS
Regulatory Assets	3,150			3,196
Long-Term Investments	331			330
Other Special Funds	59			49
Derivative Contracts	2			—
Other	108			105
Total Noncurrent Assets	3,650			3,680
TOTAL ASSETS	$	24,372		$	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)




	March 31, 2016		December 31, 2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	—	$	171
Commercial Paper and Loans	—		153
Accounts Payable	621		724
Accounts Payable—Affiliated Companies	258		292
Accrued Interest	83		70
Clean Energy Program	86		142
Obligation to Return Cash Collateral	130		128
Regulatory Liabilities	115		123
Regulatory Liabilities of VIEs	32		42
Other	329		297
Total Current Liabilities	1,654		2,142
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	5,341		5,181
OPEB Costs	912		937
Accrued Pension Costs	183		202
Regulatory Liabilities	177		175
Environmental Costs	354		365
Asset Retirement Obligations	219		218
Derivative Contracts	—		11
Long-Term Accrued Taxes	89		109
Other	116		114
Total Noncurrent Liabilities	7,391		7,312
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
CAPITALIZATION
LONG-TERM DEBT	7,492		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	5,261		4,999
Accumulated Other Comprehensive Income	1		1
Total Stockholder’s Equity	7,835		7,573
Total Capitalization	15,327		14,223
TOTAL LIABILITIES AND CAPITALIZATION	$	24,372	$	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)




	Three Months Ended
	March 31,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	262		$	242
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	139			247
Provision for Deferred Income Taxes and ITC	147			29
Non-Cash Employee Benefit Plan Costs	18			24
Cost of Removal	(35		)	(26		)
Change in Accrued Storm Costs	(1		)	7
Net Change in Other Regulatory Assets and Liabilities	(104		)	(29		)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	(26		)	(142		)
Materials and Supplies	(6		)	(9		)
Prepayments	26			37
Accounts Payable	(24		)	16
Accounts Receivable/Payable—Affiliated Companies, net	197			253
Other Current Assets and Liabilities	35			77
Employee Benefit Plan Funding and Related Payments	(44		)	(37		)
Other	(16		)	(12		)
Net Cash Provided By (Used In) Operating Activities	568			677
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(724		)	(599		)
Proceeds from Sales of Available-for-Sale Securities	5			4
Investments in Available-for-Sale Securities	(5		)	(5		)
Solar Loan Investments	—			(2		)
Other	—			9
Net Cash Provided By (Used In) Investing Activities	(724		)	(593		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt	(153		)	—
Issuance of Long-Term Debt	850			—
Redemption of Long-Term Debt	(171		)	—
Redemption of Securitization Debt	—			(58		)
Other	(10		)	—
Net Cash Provided By (Used In) Financing Activities	516			(58		)
Net Increase (Decrease) In Cash and Cash Equivalents	360			26
Cash and Cash Equivalents at Beginning of Period	198			310
Cash and Cash Equivalents at End of Period	$	558		$	336
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(200	)	$	(180	)
Interest Paid, Net of Amounts Capitalized	$	53		$	58
Accrued Property, Plant and Equipment Expenditures	$	318		$	226

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

Table of Contents

PSEG POWER LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Millions

(Unaudited)




	Three Months Ended
	March 31,
	2016			2015
OPERATING REVENUES	$	1,313		$	1,725
OPERATING EXPENSES
Energy Costs	638			893
Operation and Maintenance	253			172
Depreciation and Amortization	79			76
Total Operating Expenses	970			1,141
OPERATING INCOME	343			584
Income from Equity Method Investments	2			3
Other Income	26			29
Other Deductions	(18		)	(11		)
Other-Than-Temporary Impairments	(10		)	(5		)
Interest Expense	(22		)	(31		)
INCOME BEFORE INCOME TAXES	321			569
Income Tax Expense	(129		)	(234		)
NET INCOME	$	192		$	335

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
	March 31,
	2016		2015
NET INCOME	$	192	$	335
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(16) and $(13) for 2016 and 2015, respectively	16		14
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0 and $7 for 2016 and 2015, respectively	—		(9		)
Pension/OPEB adjustment, net of tax (expense) benefit of $(5) and $(5) for 2016 and 2015, respectively	7		7
Other Comprehensive Income (Loss), net of tax	23		12
COMPREHENSIVE INCOME	$	215	$	347

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

Table of Contents

PSEG POWER LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

Millions

(Unaudited)




	March 31, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	16		$	12
Accounts Receivable	227			217
Accounts Receivable—Affiliated Companies	184			276
Short-Term Loan to Affiliate	672			363
Fuel	306			463
Materials and Supplies, net	377			363
Derivative Contracts	218			223
Prepayments	27			25
Other	4			7
Total Current Assets	2,031			1,949
PROPERTY, PLANT AND EQUIPMENT	11,690			11,354
Less: Accumulated Depreciation and Amortization	(3,364		)	(3,227		)
Net Property, Plant and Equipment	8,326			8,127
NONCURRENT ASSETS
NDT Fund	1,778			1,754
Long-Term Investments	116			119
Goodwill	16			16
Other Intangibles	112			102
Other Special Funds	61			55
Derivative Contracts	127			77
Other	50			51
Total Noncurrent Assets	2,260			2,174
TOTAL ASSETS	$	12,617		$	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)




	March 31, 2016			December 31, 2015
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	553		$	553
Accounts Payable	418			432
Accounts Payable—Affiliated Companies	152			33
Derivative Contracts	52			76
Accrued Interest	39			25
Other	98			107
Total Current Liabilities	1,312			1,226
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	2,402			2,347
Asset Retirement Obligations	463			457
OPEB Costs	232			230
Derivative Contracts	14			16
Accrued Pension Costs	158			166
Long-Term Accrued Taxes	38			35
Other	96			87
Total Noncurrent Liabilities	3,403			3,338
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8)
LONG-TERM DEBT	1,685			1,684
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	5,206			5,014
Accumulated Other Comprehensive Loss	(217		)	(240		)
Total Member’s Equity	6,217			6,002
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	12,617		$	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)




	Three Months Ended
	March 31,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	192		$	335
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	79			76
Amortization of Nuclear Fuel	58			55
Provision for Deferred Income Taxes and ITC	34			37
Net Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(21		)	37
Non-Cash Employee Benefit Plan Costs	10			13
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	3			(12		)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	143			284
Margin Deposit	(4		)	14
Accounts Receivable	(41		)	(16		)
Accounts Payable	(34		)	(55		)
Accounts Receivable/Payable—Affiliated Companies, net	184			86
Accrued Interest Payable	14			16
Other Current Assets and Liabilities	1			(56		)
Employee Benefit Plan Funding and Related Payments	(8		)	(6		)
Other	53			42
Net Cash Provided By (Used In) Operating Activities	663			850
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(333		)	(139		)
Proceeds from Sales of Available-for-Sale Securities	183			594
Investments in Available-for-Sale Securities	(188		)	(608		)
Short-Term Loan—Affiliated Company, net	(309		)	(471		)
Other	(12		)	(11		)
Net Cash Provided By (Used In) Investing Activities	(659		)	(635		)
CASH FLOWS FROM FINANCING ACTIVITIES
Cash Dividend Paid	—			(200		)
Net Cash Provided By (Used In) Financing Activities	—			(200		)
Net Increase (Decrease) in Cash and Cash Equivalents	4			15
Cash and Cash Equivalents at Beginning of Period	12			9
Cash and Cash Equivalents at End of Period	$	16		$	24
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(100	)	$	5
Interest Paid, Net of Amounts Capitalized	$	11		$	16
Accrued Property, Plant and Equipment Expenditures	$	116		$	50

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 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 the principles for recognizing revenue and to develop a common standard that would remove inconsistencies in revenue requirements; improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provide 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 was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. ~~We are~~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~~will change how entities measure equity investments that are not consolidated or accounted for under the equity method and how they will present changes in the fair value of financial liabilities measured under the fair value option that are attributable to ~~respond to concerns regarding the current accounting for consolidation of certain legal entities.~~their own credit. Under the new guidance, equity investments (other than those accounted for using the equity method) will now have to be measured at fair value through Net Income instead of 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~~accounting 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 would recognize a lease asset and corresponding lease obligation. A lessee would 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 would 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 accounting 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 will require that debt issuance costs related~~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 should be recognized as income tax expense rather than recognized in additional paid in capital. In the statement of cash flows, excess tax benefits should 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~~accounting 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 of~~ this standard ~~to be material to our Condensed Consolidated Balance Sheets.~~on its financial statements.

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 the face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the assets of these VIEs are restricted and can only be used to settle~~paid their respective obligations. No Transition Funding or Transition Funding II creditor has any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding or Transition Funding II.

PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of September 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 nine 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. In June 2015, Transition Funding II paid its final securitization bond ~~payment~~payments and ~~Transition Funding I is scheduled~~as of December 31, 2015, no further debt or related costs remained with these VIEs. Effective January 1, 2016, PSE&G commenced refunding the overcollections from customers associated with these VIEs and expects to ~~make its final securitization bond payment~~fully refund these liabilities in ~~December 2015.~~2016.

~~Variable Interest Entity~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

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.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

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 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 ~~$96~~$98 million and ~~$107~~$82 million for the three months ended March 31, 2016 and ~~$262 million and $307 million for the nine months ended September 30,~~ 2015, ~~and 2014,~~ 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 FERC and the BPU by PSE&G are as follows:

~~Energy Strong Recovery Filing~~—In June 2015, PSE&G updated its Energy Strong electric and gas cost recovery petition filed in March 2015 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 a return on investment and recovery of Energy Strong capitalized investment costs placed in service from December 1, 2014 through May 31, 2015 for electric and from June 1, 2014 through May 31, 2015 for gas. In August 2015, the BPU provisionally approved PSE&G's request effective September 1, 2015.

In September 2015, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2015 through November 30, 2015. The annualized requested increase in electric revenue requirements is $14 million. The petition requests rates to be effective March 1, 2016, consistent with the BPU Order of approval of the Energy Strong Program. This matter is pending.

~~Basic Gas Supply Service (BGSS)~~—In March 2015, PSE&G filed a letter with the BPU to extend the 28 cents per therm residential rate reduction via a bill credit for one additional month through April 30, 2015, which provided an additional approximate $31 million credit to customers.

~~In April 2015, the BPU issued an Order approving PSE&G’s provisional BGSS rate of 45 cents per therm which had been implemented on October 1, 2014.~~

In June 2015, PSE&G made its Annual BGSS Filing with the BPU requesting a reduction of $70 million in annual BGSS revenues. In September 2015, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 45 cents to 40 cents per therm effective October 1, 2015.

~~Weather Normalization Clause~~—On April 15, 2015, the BPU approved PSE&G's final filing with respect to excess revenues collected during the colder than normal 2013-2014 Winter Period (October 1, 2013 through May 31, 2014). Effective October 1, 2014, PSEG commenced returning $45 million in revenues to its customers during the 2014-2015 Winter Period (October 1, 2014 through May 31, 2015).

In September 2015, the BPU approved PSE&G's filing on a provisional basis with respect to excess revenues collected during the colder than normal 2014-2015 Winter Period. Effective October 1, 2015, PSE&G commenced returning $40 million in revenues to its customers during the 2015-2016 Winter Period (October 1, 2015 through May 31, 2016).

~~Solar and Energy Efficiency - Green Program Recovery Charges (GPRC) and Solar Pilot Recovery Charge~~

~~(SPRC)~~—In April 2015, the BPU approved PSE&G’s petition for an Energy Efficiency Economic Stimulus Extension II Program (EEE Ext II) to extend three EEE subprograms (multi-family, direct install and hospital efficiency). The Order allows PSE&G to extend the subprogram offerings under the same clause recovery process as its existing EEE Program and allows for $95 million of additional capital expenditures over the next three years and an allowance for

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

~~$12 million of additional administrative expenses over the next 15 years. The EEE Ext II program was added as a ninth component of the GPRC rate effective May 1, 2015.~~

In July of each year, PSE&G files for annual recovery for its Green Program investments which include a return on its investment and recovery of expenses. In May 2015, the BPU approved PSE&G’s July 2014 filing requesting recovery of costs and investments in the first eight combined components of the electric and gas GPRC for the period October 1, 2014 through September 30, 2015. In July 2015, PSE&G filed its annual GPRC and SPRC cost recovery petitions with the BPU, requesting recovery of costs and investments for the first eight combined components of the electric and gas GPRC, as well as the electric SPRC. The filings proposed rates for the period October 1, 2015 through September 30, 2016 designed to recover approximately $66 million and $10 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU approved programs. In September 2015, the BPU approved the July 2015 filings on a provisional basis, with new rates effective October 1, 2015.

~~Transmission Formula Rate Filings~~—In June 2015, PSE&G filed its 2014 true-up adjustment pertaining to its formula rates in effect for 2014, which resulted in an adjustment of $19 million less than the 2014 filed revenues. The adjustment was primarily due to the impact of bonus depreciation and lower interest rates which PSE&G had recognized in its Consolidated Statement of Operations for the year ended December 31, 2014.

~~The 2016 Annual Formula Rate Update was filed with FERC in October 2015 and provides for approximately $146 million in increased annual transmission revenues effective January 1, 2016.~~

Remediation Adjustment Charge (RAC)—~~In August 2015,~~On April 27, 2016, the BPU approved PSE&G's filing with respect to its RAC 2223 petition allowing recovery of ~~$85~~$54 million effective ~~September 1, 2015~~May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, ~~2013~~2014 through July 31, ~~2014.~~2015.

~~Universal Service Fund (USF)/Lifeline~~—In September 2015, the BPU approved rates set to recover costs incurred under the USF/Lifeline energy assistance programs effective October 1, 2015. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.

Note 5. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with ~~Solar Renewable Energy Certificates~~solar renewable energy certificates generated from the installed solar electric system. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG's and PSE&G's Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which are considered “non-performing.”

Credit Risk Profile Based on Payment Activity
As of As of
Consumer Loans September 30,
2015 December 31,
2014
Millions
Commercial/Industrial $ 180
$ 188

Residential 13
13

Total $ 193
$ 201




Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	March 31, 2016		December 31, 2015
	Millions
Commercial/Industrial	$	178	$	177
Residential	12		12
Total	$	190	$	189

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Energy Holdings

Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings’ investments in the leases are comprised of the total expected lease receivables on its investments over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Condensed Consolidated Balance Sheets.

The following table shows Energy Holdings’ gross and net lease investment as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015, respectively.

As of As of
September 30,
2015 December 31,
2014
Millions
Lease Receivables (net of Non-Recourse Debt) $ 631
$ 691

Estimated Residual Value of Leased Assets 519
525

Unearned and Deferred Income (368 ) (380 )
Gross Investment in Leases 782
836

Deferred Tax Liabilities (706 ) (738 )
Net Investment in Leases $ 76
$ 98




	As of			As of
	March 31, 2016			December 31, 2015
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	631		$	631
Estimated Residual Value of Leased Assets	519			519
Unearned and Deferred Income	(363		)	(366		)
Gross Investment in Leases	787			784
Deferred Tax Liabilities	(709		)	(724		)
Net Investment in Leases	$	78		$	60

The corresponding receivables associated with the lease portfolio are reflected in the following table, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings.

Lease Receivables, Net of
Non-Recourse Debt

Counterparties’ Credit Rating (Standard & Poor's (S&P)) As of
As of September 30, 2015 September 30, 2015
Millions
AA $ 17

BBB+ — BBB- 316

BB- 134

B- 164

Total $ 631




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor's (S&P) as of March 31, 2016
	As of March 31, 2016
	Millions
AA	$	17
BBB+ — BBB-	316
BB-	134
CCC+	164
Total	$	631

The “BB-” and the ~~"B-~~"CCC+" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of ~~September 30, 2015~~March 31, 2016, the gross investment in the leases of such assets, net of non-recourse debt, was $573 million ($~~(13)~~(18) million, net of deferred taxes). A more detailed description of such assets under lease, as of ~~September 30, 2015,~~March 31, 2016, is presented in the following table.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Asset Location
Gross
Investment

%
Owned
Total
Fuel
Type

Counter-parties’
S&P Credit
Ratings As of September 30, 2015 (A)
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




Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	84	64	%	1,044	Coal	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC+	NRG REMA, LLC
Conemaugh Station Units 1 and 2	PA	$	121	17	%	1,711	Coal	CCC+	NRG REMA, LLC
Shawville Station Units 1, 2, 3 and 4	PA	$	113	100	%	603	Coal	CCC+	NRG REMA, LLC


~~(A)~~	On October 2, 2015, S&P lowered the B- rating for NRG REMA, LLC, an indirect subsidiary of NRG Energy, Inc., to CCC+. Potential adverse consequences relevant to the downgrade are discussed in the following paragraph.

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and attempt to seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital investments and trigger certain material tax obligations. A bankruptcy of a lessee would likely delay any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities to the Internal Revenue Service (IRS).

Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and the quality and condition of assets under lease.

~~In early 2014,~~ NRG REMA, LLC ~~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~~(NRG) 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~~fall 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

As of September 30, 2015
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 667
$ 176
$ (18 ) $ 825

Debt Securities
Government Obligations 445
10
(1 ) 454

Other Debt Securities 402
6
(7 ) 401

Total Debt Securities 847
16
(8 ) 855

Other Securities 35
—
—
35

Total NDT Available-for-Sale Securities $ 1,549
$ 192
$ (26 ) $ 1,715




	As of March 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	690	$	195	$	(13	)	$	872
Debt Securities
Government Obligations	487		15		—			502
Other	369		9		(6		)	372
Total Debt Securities	856		24		(6		)	874
Other Securities	32		—		—			32
Total NDT Available-for-Sale Securities	$	1,578	$	219	$	(19	)	$	1,778

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




	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
September 30,
2015 December 31,
2014
Millions
Accounts Receivable $ 10
$ 10

Accounts Payable $ 4
$ 2




	As of		As of
	March 31, 2016		December 31, 2015
	Millions
Accounts Receivable	$	16	$	17
Accounts Payable	$	9	$	10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

As of September 30, 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) $ 143
$ (18 ) $ 1
$ —
$ 162
$ (8 ) $ 1
$ —

Debt Securities
Government Obligations (B) 90
(1 ) 15
—
95
—
28
(1 )
Other Debt Securities (C) 164
(5 ) 29
(2 ) 99
(1 ) 30
(2 )
Total Debt Securities 254
(6 ) 44
(2 ) 194
(1 ) 58
(3 )
NDT Available-for-Sale Securities $ 397
$ (24 ) $ 45
$ (2 ) $ 356
$ (9 ) $ 59
$ (3 )




	As of March 31, 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)	$	123	$	(13	)	$	1	$	—		$	151	$	(13	)	$	1	$	—
Debt Securities
Government Obligations (B)	29		—			19		—			245		(2		)	19		(1		)
Other (C)	61		(2		)	48		(4		)	222		(7		)	36		(3		)
Total Debt Securities	90		(2		)	67		(4		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	213	$	(15	)	$	68	$	(4	)	$	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 ~~September 30, 2015~~. March 31, 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 ~~September 30, 2015~~.

March 31, 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 ~~September 30, 2015~~.

March 31, 2016.

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

Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
Millions
Proceeds from NDT Fund Sales (A) $ 215
$ 221
$ 1,037
$ 779

Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains 14
45
47
101

Gross Realized Losses (11 ) (3 ) (24 ) (12 )
Net Realized Gains (Losses) on NDT Fund $ 3
$ 42
$ 23
$ 89




		Three Months Ended
		March 31,
		2016			2015
	Millions
Proceeds from NDT Fund Sales (A)		$	177		$	590
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains		15			19
Gross Realized Losses		(16		)	(9		)
Net Realized Gains (Losses) on NDT Fund		$	(1	)	$	10


(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 $82101 million (after-tax) were a component of Accumulated Other Comprehensive Loss on PSEG's and Power’s Condensed Consolidated Balance Sheets as of ~~September 30, 2015~~March 31, 2016.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

The NDT available-for-sale debt securities held as of ~~September 30, 2015~~March 31, 2016 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ 8

1 - 5 years 236

6 - 10 years 201

11 - 15 years 51

16 - 20 years 51

Over 20 years 308

Total NDT Available-for-Sale Debt Securities $ 855




Time Frame	Fair Value
	Millions
Less than one year	$	24
1 - 5 years	215
6 - 10 years	209
11 - 15 years	57
16 - 20 years	53
Over 20 years	316
Total NDT Available-for-Sale Debt Securities	$	874

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 ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, other-than-temporary impairments of $4510 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

Rabbi Trust

PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”

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

As of September 30, 2015
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 11
$ 9
$ —
$ 20

Debt Securities
Government Obligations 106
1
(1 ) 106

Other Debt Securities 86
—
(2 ) 84

Total Debt Securities 192
1
(3 ) 190

Other Securities 1
—
—
1

Total Rabbi Trust Available-for-Sale Securities $ 204
$ 10
$ (3 ) $ 211




	As of March 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	12	$	8	$	—		$	20
Debt Securities
Government Obligations	107		2		—			109
Other	84		1		(2		)	83
Total Debt Securities	191		3		(2		)	192
Other Securities	5		—		—			5
Total Rabbi Trust Available-for-Sale Securities	$	208	$	11	$	(2	)	$	217

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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
September 30,
2015 December 31,
2014
Millions
Accounts Receivable $ 1
$ 1

Accounts Payable $ 1
$ —




	As of		As of
	March 31, 2016		December 31, 2015
	Millions
Accounts Receivable	$	3	$	1
Accounts Payable	$	5	$	—

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 September 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) 47
(2 ) 2
—
2
—
—
—

Other Debt Securities (C) 41
(1 ) 9
—
24
—
—
—

Total Debt Securities 88
(3 ) 11
—
26
—
—
—

Rabbi Trust Available-for-Sale Securities $ 88
$ (3 ) $ 11
$ —
$ 26
$ —
$ —
$ —




	As of March 31, 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)	10		—			2		—			53		(1		)	2		—
Other (C)	30		(1		)	11		(1		)	46		(1		)	9		—
Total Debt Securities	40		(1		)	13		(1		)	99		(2		)	11		—
Rabbi Trust Available-for-Sale Securities	$	40	$	(1	)	$	13	$	(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 ~~September 30, 2015.~~March 31, 2016.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

(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 ~~September 30, 2015.~~March 31, 2016.

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

Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
Millions
Proceeds from Rabbi Trust Sales (A) $ 20
$ 419
$ 83
$ 445

Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains $ —
$ 2
$ 2
$ 4

Gross Realized Losses (1 ) (2 ) (1 ) (3 )
Net Realized Gains (Losses) on Rabbi Trust $ (1 ) $ —
$ 1
$ 1




		Three Months Ended
		March 31,
		2016			2015
	Millions
Proceeds from Rabbi Trust Sales (A)		$	25		$	19
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains		$	1		$	—
Gross Realized Losses		(1		)	—
Net Realized Gains (Losses) on Rabbi Trust		$	—		$	—


(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 $46 million (after-tax) were a component of Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of ~~September 30, 2015~~March 31, 2016.

The Rabbi Trust available-for-sale debt securities held as of ~~September 30, 2015~~March 31, 2016 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ 5

1 - 5 years 49

6 - 10 years 39

11 - 15 years 8

16 - 20 years 9

Over 20 years 80

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




Time Frame	Fair Value
	Millions
Less than one year	$	9
1 - 5 years	42
6 - 10 years	47
11 - 15 years	5
16 - 20 years	9
Over 20 years	80
Total Rabbi Trust Available-for-Sale Debt Securities	$	192

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

Power 52
45

Other 117
105

Total Rabbi Trust Available-for-Sale Securities $ 211
$ 191




	As of		As of
	March 31, 2016		December 31, 2015
	Millions
PSE&G	$	43	$	42
Power	53		52
Other	121		119
Total Rabbi Trust Available-for-Sale Securities	$	217	$	213

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. For the three months ended March 31, 2016, pension and OPEB costs, net of amounts capitalized, were reduced by $9 million and $3 million, 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.

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 Nine Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2015
2014 2015
2014 2015 2014 2015 2014
Millions
Components of Net Periodic Benefit Costs (Credit)
Service Cost $ 30
$ 26
$ 5
$ 5
$ 92
$ 78
$ 16
$ 14

Interest Cost 59
58
16
18
176
176
50
52

Expected Return on Plan Assets (103 ) (99 ) (7 ) (7 ) (310 ) (299 ) (22 ) (20 )
Amortization of Net
Prior Service Cost (Credit) (5 ) (5 ) (4 ) (4 ) (14 ) (14 ) (11 ) (11 )
Actuarial Loss 38
14
11
6
112
42
32
18

Total Benefit Costs (Credit) $ 19
$ (6 ) $ 21
$ 18
$ 56
$ (17 ) $ 65
$ 53




		Pension Benefits						OPEB
		Three Months Ended						Three Months Ended
		March 31,						March 31,
		2016			2015			2016			2015
	Millions
Components of Net Periodic Benefit Costs
Service Cost		$	27		$	31		$	4		$	5
Interest Cost		50			59			15			17
Expected Return on Plan Assets		(98		)	(103		)	(8		)	(7		)
Amortization of Net
Prior Service Cost (Credit)		(4		)	(5		)	(3		)	(3		)
Actuarial Loss		39			37			10			10
Total Benefit Costs		$	14		$	19		$	18		$	22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

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 Nine Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2015 2014 2015 2014 2015 2014 2015 2014
Millions
PSE&G $ 10
$ (4 ) $ 13
$ 12
$ 30
$ (14 ) $ 41
$ 35

Power 5
(2 ) 7
5
16
(5 ) 20
15

Other 4
—
1
1
10
2
4
3

Total Benefit Costs (Credit) $ 19
$ (6 ) $ 21
$ 18
$ 56
$ (17 ) $ 65
$ 53




		Pension Benefits				OPEB
		Three Months Ended				Three Months Ended
		March 31,				March 31,
		2016		2015		2016		2015
	Millions
PSE&G		$	7	$	10	$	11	$	14
Power		4		6		6		7
Other		3		3		1		1
Total Benefit Costs		$	14	$	19	$	18	$	22

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

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 for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco plans to contribute $28 million into its pension plan during 2016. Servco's pension-related revenues and costs were ~~$17~~$6 million ~~and $30 million~~ for each of the three months ended March 31, 2016 and ~~nine months ended September 30, 2015, respectively, completing its entire planned contribution for the year~~ 2015. ~~Servco's pension-related revenues and costs were $21 million and $67 million for the three months and nine months ended September 30, 2014, respectively.~~ The OPEB-related revenues earned and costs incurred for each of the three months ended March 31, 2016 and ~~nine months ended September 30,~~ 2015 ~~and 2014~~ were immaterial.

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

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~~

The following table ~~of contents~~ ~~(UNAUDITED)~~

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

As of As of
September 30,
2015 December 31,
2014
Millions
Face Value of Outstanding Guarantees $ 1,733
$ 1,814

Exposure under Current Guarantees $ 184
$ 273

Letters of Credit Margin Posted $ 178
$ 159

Letters of Credit Margin Received $ 80
$ 40

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

Counterparty Cash Margin Received $ (44 ) $ (13 )
Net Broker Balance Deposited (Received) $ 4
$ 115

In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required $ 796
$ 945

Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral $ 3,375
$ 3,495

Additional Amounts Posted:
Other Letters of Credit $ 47
$ 45




	As of			As of
	March 31, 2016			December 31, 2015
	Millions
Face Value of Outstanding Guarantees	$	1,786		$	1,734
Exposure under Current Guarantees	$	183		$	172

Letters of Credit Margin Posted	$	169		$	122
Letters of Credit Margin Received	$	220		$	192

Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(17	)	$	(15	)
Net Broker Balance Deposited (Received)	$	1		$	(5	)

In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required	$	851		$	864
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,391		$	3,215

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 and Moody’s 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 $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.

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As of March 31, 2016, PSE&G had posted $14 million in letters of credit to support various environmental obligations. PSE&G had $615 million of liquidity available under its credit facility as of March 31, 2016.

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.

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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 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 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 with respect to their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. ~~PSEG’s~~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 $3.3 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 lower eight miles of the river bank-to-bank and installing an engineered cap. The estimated cost in the revised draft FFS for the EPA's 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 for 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 6053 members as of ~~September 30, 2015,~~March 31, 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 ~~$151~~$156 million, which the CPG continues to incur. Of the estimated ~~$151~~$156 million, as of ~~August~~March 31, ~~2015,~~2016, the CPG had spent approximately ~~$141~~$146 million, of which ~~PSEG's total~~PSE&G's and Power's combined share was approximately $9 million.

The CPG's draft FS ~~sets~~set forth various alternatives for remediating 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~~

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~~by the CPG for the work contemplated by the draft FS. However, based~~Based on (i) the low end of the range of the 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

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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 is expected to 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 March 31, 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 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 ~~Passaic River.~~ 8.3 miles. "Major PRP" is undefined in the letter.

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.

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MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between ~~$450~~$434 million and ~~$518~~$500 million through 2021, including its ~~$10~~$46 million share for the Passaic River accrued as of March 31, 2016, as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of ~~$450~~$434 million as of ~~September 30, 2015.~~March 31, 2016. Of this amount, ~~$73~~$90 million was recorded in Other Current Liabilities and ~~$377~~$344 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a ~~$450~~$434 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.

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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.~~permit for Salem. 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 with certain required system modifications. The draft permit was subject to a public notice and comment period. The NJDEP may make revisions before issuing the final permit expected during the first half of 2016. Power participated in the NJDEP’s August 5, 2015 public hearing and submitted comments on the draft permit on September 18, 2015.

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.

State permitting decisions could have a material impact on Power’s ability to renew permits at its 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

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Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1.0 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power'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 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 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 ~~these new standards~~this rule will have a material impact on ~~Power's~~its future capital requirements, financial condition orand 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 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 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

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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.

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~~will become effective on June 1, ~~2015~~2016 when the ~~2012~~2013 BGS auction agreements ~~expired.~~expire.

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

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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, 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.

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As of ~~September 30, 2015~~March 31, 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 $ 440

Enrichment $ 345

Fabrication $ 179

Natural Gas $ 1,001

Coal $ 331




Fuel Type	Power's Share of Commitments through 2020
	Millions
Nuclear Fuel
Uranium	$	467
Enrichment	$	348
Fabrication	$	193
Natural Gas	$	1,002
Coal	$	277

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 pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for ~~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, FERC Staff initiated a preliminary, non-public staff investigation into the matter. This investigation, which is ongoing, could result in 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.

In September 2014, FERC Staff initiated 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~~ ~~$185~~nuclear event and $300 million ~~as of~~ ~~September 30, 2015~~ due to a 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~~excess layer at the Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ownership interest of Power.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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 the costs associated with this program are recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

~~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, 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

The following capital transactions occurred in the ~~nine~~three months ended ~~September 30, 2015~~March 31, 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 $183~~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 million of Transition Funding II's securitization debt.~~

~~Power~~

~~paid cash dividends of~~ ~~$400 million~~ ~~to PSEG.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

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

Asor fair value hedges as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity were as follows:~~2015.

As of As of
September 30,
2015 December 31,
2014
Millions
Fair Value of Cash Flow Hedges $ 2
$ 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~~ ~~September 30, 2015~~.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Interest Rates

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

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. As of ~~September 30, 2015,~~March 31, 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 ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014,~~2015, the fair value of all the underlying hedges was ~~$11~~$4 million and ~~$22~~$6 million,, respectively. The effect of these hedges was to reduce interest expense by $2 million and $5 million for the three months ended March 31, 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 March 31, 2016, PSEG had interest rate hedges outstanding totaling $900 million. The hedge ineffectiveness associated with these hedges was immaterial. The total fair value of these interest rate hedges was $3 million as of March 31, 2016. There were no outstanding interest rate hedges as of December 31, 2015. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $2 million as of March 31, 2016 and was immaterial as of ~~September 30, 2015~~ ~~and~~ December 31, ~~2014, respectively.~~2015.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with ~~our~~PSEG's accounting policy, these positions have been offset on the Condensed Consolidated Balance Sheets of Power, PSE&G and PSEG.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

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

As of September 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 $ 2
$ 413
$ (268 ) $ 147
$ 4
$ 11
$ 162

Noncurrent Assets —
284
(193 ) 91
—
—
91

Total Mark-to-Market Derivative Assets $ 2
$ 697
$ (461 ) $ 238
$ 4
$ 11
$ 253

Derivative Contracts
Current Liabilities $ —
$ (311 ) $ 241
$ (70 ) $ —
$ —
$ (70 )
Noncurrent Liabilities —
(178 ) 162
(16 ) (7 ) —
(23 )
Total Mark-to-Market Derivative (Liabilities) $ —
$ (489 ) $ 403
$ (86 ) $ (7 ) $ —
$ (93 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 2
$ 208
$ (58 ) $ 152
$ (3 ) $ 11
$ 160




	As of March 31, 2016
	Power (A)									PSE&G (A)		PSEG (A)			Consolidated
	Not Designated									Not Designated		Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts		Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	718		$	(500	)	$	218		$	8	$	4		$	230
Noncurrent Assets	346			(219		)	127			2		4			133
Total Mark-to-Market Derivative Assets	$	1,064		$	(719	)	$	345		$	10	$	8		$	363
Derivative Contracts
Current Liabilities	$	(533	)	$	481		$	(52	)	$	—	$	(1	)	$	(53	)
Noncurrent Liabilities	(218		)	204			(14		)	—		—			(14		)
Total Mark-to-Market Derivative (Liabilities)	$	(751	)	$	685		$	(66	)	$	—	$	(1	)	$	(67	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	313		$	(34	)	$	279		$	10	$	7		$	296

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
	Power (A)									PSE&G (A)			PSEG (A)		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	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 ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~.2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

(B)

$(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $(34) million as of March 31, 2016, $(37) million and $(16) million of cash collateral were netted against current assets and noncurrent assets, respectively, and $19 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

~~December 31, 2014, net cash collateral (received) paid of~~ ~~$(58) million~~ ~~and~~ ~~$24 million, respectively, were netted against the corresponding net derivative contract positions. Of the~~ ~~$(58) million~~ ~~as of~~ ~~September 30, 2015~~, ~~$(32) million~~ ~~and $(38) million of cash collateral were netted against current assets and noncurrent assets, respectively, and~~ ~~$5 million~~ ~~and $7 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $24 million as of~~ ~~December 31, 2014, $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and~~ ~~$32 million~~ ~~and $4 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. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was ~~$78~~$62 million and ~~$127~~$78 million as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~,2015, respectively. As of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014,~~2015, Power had the contractual right of offset of ~~$12~~$16 million and ~~$18~~$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 ~~$66~~$46 million and ~~$109~~$66 million as of ~~September 30, 2015~~March 31, 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 potential additional collateral is included in the ~~$796~~$851 million and ~~$945~~$864 million as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~,2015, 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 September 30, 2015 and 2014.

Derivatives in
Cash Flow Hedging
Relationships

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

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

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

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

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

Three Months Ended Three Months Ended Three Months Ended
September 30, September 30, September 30,
2015 2014 2015 2014 2015 2014
Millions
PSEG
Energy-Related Contracts $ 1
$ 3
Operating Revenues $ —
$ 1
Operating Revenues $ —
$ —

Total PSEG $ 1
$ 3
$ —
$ 1
$ —
$ —

Power
Energy-Related Contracts $ 1
$ 3
Operating Revenues $ —
$ 1
Operating Revenues $ —
$ —

Total Power $ 1
$ 3
$ —
$ 1
$ —
$ —

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Derivatives in
Cash Flow Hedging
Relationships

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

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

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

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

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

Nine Months Ended Nine Months Ended Nine Months Ended
September 30, September 30, September 30,
2015 2014 2015 2014 2015 2014
Millions
PSEG
Energy-Related Contracts $ 2
$ (4 ) Operating Revenues $ 17
$ (11 ) Operating Revenues $ —
$ —

Total PSEG $ 2
$ (4 ) $ 17
$ (11 ) $ —
$ —

Power
Energy-Related Contracts $ 2
$ (4 ) Operating Revenues $ 17
$ (11 ) Operating Revenues $ —
$ —

Total Power $ 2
$ (4 ) $ 17
$ (11 ) $ —
$ —




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
	March 31,					March 31,					March 31,
	2016		2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Interest Rate Swaps	3		—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	3	$	1		$	—	$	17		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	17	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	17		$	—	$	—

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 June 30, 2015 $ 1
$ 1

Gain Recognized in AOCI 1
—
—

Less: Gain Reclassified into Income —
—

Balance as of September 30, 2015 $ 2
$ 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

~~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 and sales~~NPNS for the three months ended March 31, 2016 and ~~nine months ended September 30, 2015 and 2014.~~2015.

Derivatives Not Designated as Hedges
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives
Pre-Tax Gain (Loss) Recognized in Income on Derivatives
Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
Millions
PSEG and Power
Energy-Related Contracts Operating Revenues $ 154
$ 93
$ 202
$ (759 )
Energy-Related Contracts Energy Costs (4 ) (12 ) (4 ) 65

Total PSEG and Power $ 150
$ 81
$ 198
$ (694 )




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
			Three Months Ended
			March 31,
			2016		2015
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues		$	216	$	(76	)
Energy-Related Contracts	Energy Costs		2		10
Total PSEG and Power			$	218	$	(66	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

Power’s derivative contracts reflected in the preceding 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 $15 million for each of the nine months ended September 30, 2015 and 2014, respectively.

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

Type Notional Total PSEG Power PSE&G
Millions
As of September 30, 2015
Natural Gas Dth 193
—
154
39

Electricity MWh 291
—
291
—

Financial Transmission Rights (FTRs) MWh 21
—
21
—

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 March 31, 2016
Natural Gas	Dekatherm (Dth)	298	—	272	26
Electricity	MWh	303	—	303	—
Financial Transmission Rights (FTRs)	MWh	14	—	14	—
Interest Rate Swaps	U.S. Dollars	1,450	1,450	—	—
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	—	—

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 ~~September 30, 2015~~, ~~98%~~March 31, 2016, 91% of the credit 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 ~~September 30, 2015~~.March 31, 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 $ 348
$ 118
$ 230
2
$ 127
(A)
Non-Investment Grade—External Rating 1
—
1
—
—

Investment Grade—No External Rating 11
—
11
—
—

Non-Investment Grade—No External Rating 4
—
4
—
—

Total $ 364
$ 118
$ 246
2
$ 127




Rating	Current Exposure		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade—External Rating	$	542	$	230	$	312	1	$	178	(A)
Non-Investment Grade—External Rating	30		—		30		—	—
Investment Grade—No External Rating	10		1		9		—	—
Non-Investment Grade—No External Rating	—		—		—		—	—
Total	$	582	$	231	$	351	1	$	178


(A)	Represents net exposure ~~of $87 million~~ with PSE&G. ~~The remaining net exposure of $40 million is with a non- affiliated power purchaser which is an investment grade counterparty.~~

As of ~~September 30, 2015,~~March 31, 2016, collateral held from counterparties where Power had credit exposure included ~~$43~~$16 million in cash collateral and ~~$75~~$215 million in letters of credit.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)

As of ~~September 30, 2015~~March 31, 2016, Power had ~~133~~137 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 ~~September 30, 2015,~~March 31, 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 ~~September 30, 2015,~~March 31, 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 of 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 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 ~~September 30, 2015,~~March 31, 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 ~~September 30, 2015~~March 31, 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 September 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) $ 226
$ —
$ 226
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 242
$ (461 ) $ —
$ 694
$ 9

Interest Rate Swaps (C) $ 11
$ —
$ —
$ 11
$ —

NDT Fund (D)
Equity Securities $ 825
$ —
$ 824
$ 1
$ —

Debt Securities—Govt Obligations $ 454
$ —
$ —
$ 454
$ —

Debt Securities—Other $ 401
$ —
$ —
$ 401
$ —

Other Securities $ 35
$ —
$ 35
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 20
$ —
$ 20
$ —
$ —

Debt Securities—Govt Obligations $ 106
$ —
$ —
$ 106
$ —

Debt Securities—Other $ 84
$ —
$ —
$ 84
$ —

Other Securities $ 1
$ —
$ 1
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (93 ) $ 403
$ —
$ (489 ) $ (7 )
PSE&G
Assets:
Cash Equivalents (A) $ —
$ —
$ —
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 4
$ —
$ —
$ —
$ 4

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

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

Debt Securities—Other $ 17
$ ��
$ —
$ 17
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (7 ) $ —
$ —
$ —
$ (7 )
Power

Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 238
$ (461 ) $ —
$ 694
$ 5

NDT Fund (D)
Equity Securities $ 825
$ —
$ 824
$ 1
$ —

Debt Securities—Govt Obligations $ 454
$ —
$ —
$ 454
$ —

Debt Securities—Other $ 401
$ —
$ —
$ 401
$ —

Other Securities $ 35
$ —
$ 35
$ —
$ —

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

Debt Securities—Govt Obligations $ 26
$ —
$ —
$ 26
$ —

Debt Securities—Other $ 21
$ —
$ —
$ 21
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (86 ) $ 403
$ —
$ (489 ) $ —




	Recurring Fair Value Measurements as of March 31, 2016
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	521		$	—		$	521	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	355		$	(719	)	$	—	$	1,053		$	21
Interest Rate Swaps (C)	$	8		$	—		$	—	$	8		$	—
NDT Fund (D)
Equity Securities	$	872		$	—		$	872	$	—		$	—
Debt Securities—Govt Obligations	$	502		$	—		$	—	$	502		$	—
Debt Securities—Other	$	372		$	—		$	—	$	372		$	—
Other Securities	$	32		$	—		$	32	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	20		$	—		$	20	$	—		$	—
Debt Securities—Govt Obligations	$	109		$	—		$	—	$	109		$	—
Debt Securities—Other	$	83		$	—		$	—	$	83		$	—
Other Securities	$	5		$	—		$	5	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(66	)	$	685		$	—	$	(751	)	$	—
Interest Rate Swaps (C)	$	(1	)	$	—		$	—	$	(1	)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	521		$	—		$	521	$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	10		$	—		$	—	$	—		$	10
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	4		$	—		$	4	$	—		$	—
Debt Securities—Govt Obligations	$	22		$	—		$	—	$	22		$	—
Debt Securities—Other	$	16		$	—		$	—	$	16		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—	$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	345		$	(719	)	$	—	$	1,053		$	11
NDT Fund (D)
Equity Securities	$	872		$	—		$	872	$	—		$	—
Debt Securities—Govt Obligations	$	502		$	—		$	—	$	502		$	—
Debt Securities—Other	$	372		$	—		$	—	$	372		$	—
Other Securities	$	32		$	—		$	32	$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5	$	—		$	—
Debt Securities—Govt Obligations	$	27		$	—		$	—	$	27		$	—
Debt Securities—Other	$	20		$	—		$	—	$	20		$	—
Other Securities	$	1		$	—		$	1	$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(66	)	$	685		$	—	$	(751	)	$	—

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.

(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

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 ~~September 30, 2015,~~March 31, 2016, net cash collateral (received) paid of ~~$(58)~~$(34) million was netted against the corresponding net derivative contract positions. Of the ~~$(58)~~$(34) million as of ~~September 30, 2015, $(70)~~March 31, 2016, $(53) million of cash collateral was netted against assets, and ~~$12~~$19 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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power's electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. 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 ~~September 30, 2015~~March 31, 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 September 30, 2015 Technique(s) Input Range
Assets (Liabilities)
Millions
PSE&G
Gas Natural Gas Supply Contracts $ 4
$ (7 ) Discounted Cash Flow Transportation Costs $0.60 to $0.90/dekatherm
Total PSE&G $ 4
$ (7 )
Power
Electricity Electric Load Contracts $ 4
$ —
Discounted Cash flow Historic Load Variability 0% to +10%
Other Various (A) 1
—

Total Power $ 5
$ —

Total PSEG $ 9
$ (7 )




	Quantitative Information About Level 3 Fair Value Measurements

							Significant
		Fair Value as of				Valuation	Unobservable
Commodity	Level 3 Position	March 31, 2016				Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contracts	$	10	$	—	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	10	$	—
Power
Electricity	Electric Load Contracts	$	11	$	—	Discounted Cash flow	Historic Load Variability	0% to +10%
Total Power		$	11	$	—
Total PSEG		$	21	$	—

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 September 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 nine months~~ ended ~~September 30, 2015~~March 31, 2016 and ~~September 30, 2014,~~March 31, 2015, respectively, follows:

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

for the ~~Three Months and~~ ~~Nine~~Three Months Ended ~~September 30, 2015~~March 31, 2016

Three Months Ended September 30, 2015

Total Gains or (Losses)
Realized/Unrealized

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

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

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

PSE&G
Net Derivative Assets (Liabilities) $ 5
$ —
$ (8 ) $ —
$ —
$ —
$ (3 )
Power
Net Derivative Assets (Liabilities) $ 3
$ 4
$ —
$ —
$ (2 ) $ —
$ 5

Nine Months Ended September 30, 2015

Total Gains or (Losses)
Realized/Unrealized

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

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
Balance as of September 30, 2015
Millions
PSEG
Net Derivative Assets (Liabilities) $ 37
$ 12
$ (29 ) $ —
$ (18 ) $ —
$ 2

PSE&G
Net Derivative Assets (Liabilities) $ 26
$ —
$ (29 ) $ —
$ —
$ —
$ (3 )
Power
Net Derivative Assets (Liabilities) $ 11
$ 12
$ —
$ —
$ (18 ) $ —
$ 5




			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of March 31, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	13	$	15	$	8	$	—	$	(15	)	$	—	$	21
PSE&G
Net Derivative Assets (Liabilities)	$	2	$	—	$	8	$	—	$	—		$	—	$	10
Power
Net Derivative Assets (Liabilities)	$	11	$	15	$	—	$	—	$	(15	)	$	—	$	11

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

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

for the ~~Three Months and~~ ~~Nine~~Three Months Ended ~~September 30, 2014~~March 31, 2015

Three Months Ended September 30, 2014

Total Gains or (Losses)
Realized/Unrealized

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

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
(D)
Balance as of September 30, 2014
Millions
PSEG
Net Derivative Assets (Liabilities) $ 13
$ (8 ) $ (9 ) $ —
$ (4 ) $ —
$ (8 )
PSE&G
Net Derivative Assets (Liabilities) $ 22
$ —
$ (9 ) $ —
$ —
$ —
$ 13

Power
Net Derivative Assets (Liabilities) $ (9 ) $ (8 ) $ —
$ —
$ (4 ) $ —
$ (21 )

Nine Months Ended September 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 September 30, 2014
Millions
PSEG
Net Derivative Assets (Liabilities) $ 88
$ (66 ) $ (81 ) $ —
$ 54
$ (3 ) $ (8 )
PSE&G
Net Derivative Assets (Liabilities) $ 94
$ —
$ (81 ) $ —
$ —
$ —
$ 13

Power
Net Derivative Assets (Liabilities) $ (6 ) $ (66 ) $ —
$ —
$ 54
$ (3 ) $ (21 )




			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 (D)		Balance as of March 31, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	3	$	(19	)	$	—	$	(12	)	$	—	$	9
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(19	)	$	—	$	—		$	—	$	7
Power
Net Derivative Assets (Liabilities)	$	11	$	3	$	—		$	—	$	(12	)	$	—	$	2

(A)

PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities ~~includes $4~~include $15 million and ~~$12~~$3 million in Operating Income ~~for the three months~~in 2016 and ~~nine months ended September 30,~~ 2015, respectively. ~~Of the $4~~The $15 million in Operating Income ~~$3 million~~in 2016 is ~~unrealized.~~realized. Of the ~~$12~~$3 million in Operating Income, ~~$(6)~~$(9) million is unrealized.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents (UNAUDITED)


(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 ~~$(2)~~$(15) million and ~~$(18)~~$(12) million in settlements for the three months ended March 31, 2016 and ~~nine months ended September 30,~~ 2015. ~~Includes $(4) million and $54 million in settlements for the three months and nine months ended September 30, 2014.~~

(D)

There were no transfers among levels during the three months ended ~~September 30, 2015~~March 31, 2016 and ~~2014 and the nine months ended September 30,~~ 2015. During the nine months ended September 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 $(8) million and $(66) million in Operating Income for the three months and nine months ended September 30, 2014, respectively. Of the $(8) million in Operating Income, $(12) million is unrealized. Of the $(66) million in Operating Income, $(11) million is unrealized.

As of ~~September 30, 2015,~~March 31, 2016, PSEG carried ~~$2.3~~$2.8 billion of net assets that are measured at fair value on a recurring basis, of which $2$21 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of ~~September 30, 2014~~March 31, 2015, PSEG carried $~~2.5~~3.1 billion of net assets that are measured at fair value on a recurring basis, of which $89 million of net 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 ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015.

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

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Millions
Long-Term Debt:
PSEG (Parent) (A) $ 7
$ 11
$ 14
$ 22

PSE&G (B) 6,612
�� 7,102
6,312
6,912

Transition Funding (PSE&G) (B) 68
69
251
261

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

Power - Recourse Debt (B) 2,544
2,856
2,543
2,930

Energy Holdings:
Project Level, Non-Recourse Debt (C) 7
7
16
16

Total Long-Term Debt $ 9,238
$ 10,045
$ 9,144
$ 10,149




	As of				As of
	March 31, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	501	$	504	$	503	$	506
PSE&G (B)	7,492		8,339		6,821		7,235
Power - Recourse Debt (B)	2,238		2,502		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	7		7		7		7
Total Long-Term Debt	$	10,238	$	11,352	$	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 September 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 24
$ —
$ 24

Allowance for Funds Used During Construction 14
—
—
14

Solar Loan Interest 6
—
—
6

Other 2
1
—
3

Total Other Income $ 22
$ 25
$ —
$ 47

Nine Months Ended September 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 78
$ —
$ 78

Allowance for Funds Used During Construction 36
—
—
36

Solar Loan Interest 18
—
—
18

Gain on Insurance Recovery —
28
—
28

Other 5
3
3
11

Total Other Income $ 59
$ 109
$ 3
$ 171

Three Months Ended September 30, 2014
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 55
$ —
$ 55

Allowance for Funds Used During Construction 8
—
—
8

Solar Loan Interest 6
—
—
6

Other 2
1
3
6

Total Other Income $ 16
$ 56
$ 3
$ 75

Nine Months Ended September 30, 2014
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 133
$ —
$ 133

Allowance for Funds Used During Construction 21
—
—
21

Solar Loan Interest 18
—
—
18

Other 5
2
6
13

Total Other Income $ 44
$ 135
$ 6
$ 185




Other Income	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended March 31, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	11		—		—		11
Solar Loan Interest	6		—		—		6
Other	3		1		2		6
Total Other Income	$	20	$	26	$	2	$	48
Three Months Ended March 31, 2015
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	29	$	—	$	29
Allowance for Funds Used During Construction	10		—		—		10
Solar Loan Interest	6		—		—		6
Other	2		—		1		3
Total Other Income	$	18	$	29	$	1	$	48

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

Other Deductions PSE&G Power Other (A) Consolidated
Millions
Three Months Ended September 30, 2015
  NDT Fund Realized Losses and Expenses $ —
$ 13
$ —
$ 13

  Other —
1
—
1

    Total Other Deductions $ —
$ 14
$ —
$ 14

Nine Months Ended September 30, 2015
  NDT Fund Realized Losses and Expenses $ —
$ 30
$ —
$ 30

  Other 2
2
2
6

    Total Other Deductions $ 2
$ 32
$ 2
$ 36

Three Months Ended September 30, 2014
  NDT Fund Realized Losses and Expenses $ —
$ 4
$ —
$ 4

  Other 2
2
1
5

  Total Other Deductions $ 2
$ 6
$ 1
$ 9

Nine Months Ended September 30, 2014
  NDT Fund Realized Losses and Expenses $ —
$ 18
$ —
$ 18

  Other 3
7
3
13

  Total Other Deductions $ 3
$ 25
$ 3
$ 31




Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended March 31, 2016
NDT Fund Realized Losses and Expenses	$	—	$	18	$	—	$	18
Other	1		��		2		3
Total Other Deductions	$	1	$	18	$	2	$	21
Three Months Ended March 31, 2015
NDT Fund Realized Losses and Expenses	$	—	$	11	$	—	$	11
Other	1		—		—		1
Total Other Deductions	$	1	$	11	$	—	$	12


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

Note 13. Income Taxes

PSEG’s, PSE&G’s and Power's effective tax rates for the three months ~~and nine months~~ ended ~~September 30, 2015~~March 31, 2016 and ~~2014~~2015 were as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
PSEG 39.4% 37.0% 38.8% 37.8%
PSE&G 38.2% 38.5% 38.7% 38.6%
Power 40.3% 39.4% 38.6% 38.6%




	Three Months Ended
	March 31,
	2016	2015
PSEG	37.5%	40.5%
PSE&G	36.6%	39.4%
Power	40.2%	41.1%

For the three months ended ~~September 30, 2015,~~March 31, 2016, the overall decreases in PSEG's and PSE&G's effective tax ~~rate was lower than the statutory tax rate of 40.85% due primarily to the beneficial impact of plant related flow-through items.~~

~~For the nine months ended September 30, 2015, PSEG's and Power’s effective tax~~ rates were lower than the statutory tax rate of 40.85% primarily due to a manufacturing deduction under Section 199 of the Internal Revenue Code (IRC) and the tax benefit associated with the income tax rate differential of carrying back federal net operating tax losses under section 172(f) of the IRC. PSE&G's effective tax rate was lower than the statutory tax rate due primarily to the beneficial impact of plant related flow-through items.

~~For the three months and nine months ended September 30, 2015,~~ as compared to the same periods in the prior year ~~PSEG's increase was~~as well as to the statutory tax rate of 40.85%, were due primarily to depreciation flow through items and changes in uncertain tax positions.

The Tax Increase Prevention Act of 2014 extended the ~~absence of the 2014 audit settlement.~~

In August 2014, PSEG received notice from the Internal Revenue Service (IRS) that the audit settlement covering tax years 2007 through 2010 had been approved by the Joint Committee on Taxation. This effectively settled all issues with the IRS through 2010. In September 2014, PSEG received refunds from the IRS totaling $121 million, representing the net settlement of all disputed amounts, including interest, through the tax year 2010. As a result of the settlement of this audit, PSEG recorded a $12 million reduction of tax expense50% bonus depreciation rules for qualified property placed in ~~the quarter ended September 30, 2014.~~service before January 1, 2015 and for long production property placed in service in 2015.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

PSEG Other Comprehensive Income (Loss)
Three Months Ended September 30, 2015
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2015 $ 1
$ (395 ) $ 117
$ (277 )
Other Comprehensive Income before Reclassifications —
—
(46 ) (46 )
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
9
15
24

Net Current Period Other Comprehensive Income (Loss) —
9
(31 ) (22 )
Balance as of September 30, 2015 $ 1
$ (386 ) $ 86
$ (299 )

Other Comprehensive Income (Loss)
Three Months Ended September 30, 2014
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2014 $ 1
$ (232 ) $ 158
$ (73 )
Other Comprehensive Income before Reclassifications 2
—
(15 ) (13 )
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1 ) 3
(15 ) (13 )
Net Current Period Other Comprehensive Income (Loss) 1
3
(30 ) (26 )
Balance as of September 30, 2014 $ 2
$ (229 ) $ 128
$ (99 )

Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2015
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2014 $ 10
$ (411 ) $ 118
$ (283 )
Other Comprehensive Income before Reclassifications 1
—
(44 ) (43 )
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (10 ) 25
12
27

Net Current Period Other Comprehensive Income (Loss) (9 ) 25
(32 ) (16 )
Balance as of September 30, 2015 $ 1
$ (386 ) $ 86
$ (299 )

Other Comprehensive Income (Loss)
Nine Months Ended September 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 (2 ) —
19
17

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 6
9
(36 ) (21 )
Net Current Period Other Comprehensive Income (Loss) 4
9
(17 ) (4 )
Balance as of September 30, 2014 $ 2
$ (229 ) $ 128
$ (99 )




PSEG	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	2			—			10			12
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			8			6			14
Net Current Period Other Comprehensive Income (Loss)	2			8			16			26
Balance as of March 31, 2016	$	2		$	(378	)	$	107		$	(269	)

	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 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			—			16			17
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	8			(2		)	(4		)
Net Current Period Other Comprehensive Income (Loss)	(9		)	8			14			13
Balance as of March 31, 2015	$	1		$	(403	)	$	132		$	(270	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Power Other Comprehensive Income (Loss)
Three Months Ended September 30, 2015
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2015 $ 2
$ (337 ) $ 112
$ (223 )
Other Comprehensive Income before Reclassifications —
—
(43 ) (43 )
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
7
14
21

Net Current Period Other Comprehensive Income (Loss) —
7
(29 ) (22 )
Balance as of September 30, 2015 $ 2
$ (330 ) $ 83
$ (245 )

Other Comprehensive Income (Loss)
Three Months Ended September 30, 2014
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2014 $ 2
$ (199 ) $ 153
$ (44 )
Other Comprehensive Income before Reclassifications 2
—
(14 ) (12 )
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1 ) 2
(16 ) (15 )
Net Current Period Other Comprehensive Income (Loss) 1
2
(30 ) (27 )
Balance as of September 30, 2014 $ 3
$ (197 ) $ 123
$ (71 )

Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2015
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2014 $ 11
$ (351 ) $ 112
$ (228 )
Other Comprehensive Income before Reclassifications 1
—
(41 ) (40 )
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (10 ) 21
12
23

Net Current Period Other Comprehensive Income (Loss) (9 ) 21
(29 ) (17 )
Balance as of September 30, 2015 $ 2
$ (330 ) $ 83
$ (245 )

Other Comprehensive Income (Loss)
Nine Months Ended September 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 (2 ) —
17
15

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 6
7
(36 ) (23 )
Net Current Period Other Comprehensive Income (Loss) 4
7
(19 ) (8 )
Balance as of September 30, 2014 $ 3
$ (197 ) $ 123
$ (71 )




Power	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications	—			—			10			10
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			7			6			13
Net Current Period Other Comprehensive Income (Loss)	—			7			16			23
Balance as of March 31, 2016	$	—		$	(320	)	$	103		$	(217	)

	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 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			—			16			17
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(10		)	7			(2		)	(5		)
Net Current Period Other Comprehensive Income (Loss)	(9		)	7			14			12
Balance as of March 31, 2015	$	2		$	(344	)	$	126		$	(216	)




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		March 31, 2016
	Location of Pre-Tax Amount In Statement of Operations		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense		3			(1		)	2
Amortization of Actuarial Loss	O&M Expense		(17		)	7			(10		)
Total Pension and OPEB Plans			(14		)	6			(8		)
Available-for-Sale Securities
Realized Gains	Other Income		16			(8		)	8
Realized Losses	Other Deductions		(17		)	8			(9		)
Other-Than-Temporary Impairments (OTTI)	OTTI		(10		)	5			(5		)
Total Available-for-Sale Securities			(11		)	5			(6		)
Total			$	(25	)	$	11		$	(14	)

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

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

Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2
9
(3 ) 6

Amortization of Actuarial Loss O&M Expense (17 ) 6
(11 ) (51 ) 20
(31 )
Total Pension and OPEB Plans (14 ) 5
(9 ) (42 ) 17
(25 )
Available-for-Sale Securities
Realized Gains Other Income 14
(7 ) 7
49
(25 ) 24

Realized Losses Other Deductions (12 ) 5
(7 ) (25 ) 12
(13 )
Other-Than-Temporary Impairments (OTTI) OTTI (30 ) 15
(15 ) (45 ) 22
(23 )
Total Available-for-Sale Securities (28 ) 13
(15 ) (21 ) 9
(12 )
Total $ (42 ) $ 18
$ (24 ) $ (46 ) $ 19
$ (27 )

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2014 September 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 $ 1
$ —
$ 1
$ (11 ) $ 5
$ (6 )
Total Cash Flow Hedges 1
—
1
(11 ) 5
(6 )
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2
8
(3 ) 5

Amortization of Actuarial Loss O&M Expense (8 ) 3
(5 ) (22 ) 8
(14 )
Total Pension and OPEB Plans (5 ) 2
(3 ) (14 ) 5
(9 )
Available-for-Sale Securities
Realized Gains Other Income 47
(24 ) 23
105
(54 ) 51

Realized Losses Other Deductions (5 ) 2
(3 ) (15 ) 7
(8 )
OTTI OTTI (10 ) 5
(5 ) (14 ) 7
(7 )
Total Available-for-Sale Securities 32
(17 ) 15
76
(40 ) 36

Total $ 28
$ (15 ) $ 13
$ 51
$ (30 ) $ 21




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	March 31, 2015
	Location of Pre-Tax Amount In Statement of Operations	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
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)
Total Pension and OPEB Plans		(14		)	6			(8		)
Available-for-Sale Securities
Realized Gains	Other Income	19			(10		)	9
Realized Losses	Other Deductions	(9		)	5			(4		)
OTTI	OTTI	(5		)	2			(3		)
Total Available-for-Sale Securities		5			(3		)	2
Total		$	8		$	(4	)	$	4




Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	March 31, 2016
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	3			(1		)	2
Amortization of Actuarial Loss	O&M Expense	(15		)	6			(9		)
Total Pension and OPEB Plans		(12		)	5			(7		)
Available-for-Sale Securities
Realized Gains	Other Income	15			(8		)	7
Realized Losses	Other Deductions	(16		)	8			(8		)
OTTI	OTTI	(10		)	5			(5		)
Total Available-for-Sale Securities		(11		)	5			(6		)
Total		$	(23	)	$	10		$	(13	)

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

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

Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2
9
(3 ) 6

Amortization of Actuarial Loss O&M Expense (15 ) 6
(9 ) (45 ) 18
(27 )
Total Pension and OPEB Plans (12 ) 5
(7 ) (36 ) 15
(21 )
Available-for-Sale Securities
Realized Gains Other Income 14
(7 ) 7
47
(24 ) 23

Realized Losses Other Deductions (11 ) 5
(6 ) (24 ) 12
(12 )
OTTI OTTI (30 ) 15
(15 ) (45 ) 22
(23 )
Total Available-for-Sale Securities (27 ) 13
(14 ) (22 ) 10
(12 )
Total $ (39 ) $ 18
$ (21 ) $ (41 ) $ 18
$ (23 )

Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2014 September 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 $ 1
$ —
$ 1
$ (11 ) $ 5
$ (6 )
Total Cash Flow Hedges 1
—
1
(11 ) 5
(6 )
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2
7
(3 ) 4

Amortization of Actuarial Loss O&M Expense (6 ) 2
(4 ) (18 ) 7
(11 )
Total Pension and OPEB Plans (3 ) 1
(2 ) (11 ) 4
(7 )
Available-for-Sale Securities
Realized Gains Other Income 45
(23 ) 22
101
(52 ) 49

Realized Losses Other Deductions (2 ) 1
(1 ) (12 ) 6
(6 )
OTTI OTTI (10 ) 5
(5 ) (14 ) 7
(7 )
Total Available-for-Sale Securities 33
(17 ) 16
75
(39 ) 36

Total $ 31
$ (16 ) $ 15
$ 53
$ (30 ) $ 23




Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	March 31, 2015
	Location of Pre-Tax Amount In Statement of Operations	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
Amortization of Actuarial Loss	O&M Expense	(15		)	6			(9		)
Total Pension and OPEB Plans		(12		)	5			(7		)
Available-for-Sale Securities
Realized Gains	Other Income	19			(10		)	9
Realized Losses	Other Deductions	(9		)	5			(4		)
OTTI	OTTI	(5		)	2			(3		)
Total Available-for-Sale Securities		5			(3		)	2
Total		$	10		$	(5	)	$	5

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~table of 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 September 30, Nine Months Ended September 30,
2015 2014 2015 2014
Basic Diluted Basic Diluted Basic Diluted Basic Diluted

EPS Numerator (Millions)

Net Income $ 439
$ 439
$ 444
$ 444
$ 1,370
$ 1,370
$ 1,042
$ 1,042

EPS Denominator (Millions)

Weighted Average Common Shares Outstanding 505
505
506
506
505
505
506
506

Effect of Stock Based Compensation Awards —
3
—
1
—
3
—
1

Total Shares 505
508
506
507
505
508
506
507

EPS
Net Income $ 0.87
$ 0.87
$ 0.88
$ 0.87
$ 2.71
$ 2.70
$ 2.06
$ 2.05




	Three Months Ended March 31,
	2016				2015
	Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	471	$	471	$	586	$	586
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		506		506
Effect of Stock Based Compensation Awards	—		3		—		2
Total Shares	505		508		506		508

EPS
Net Income	$	0.93	$	0.93	$	1.16	$	1.15

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 ended March 31, 2016 and 2015, respectively.

Three Months Ended Nine Months Ended
September 30, September 30,
Dividend Payments on Common Stock 2015 2014 2015 2014
Per Share $ 0.39
$ 0.37
$ 1.17
$ 1.11

In Millions $ 198
$ 187
$ 592
$ 561

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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




	Three Months Ended
	March 31,
Dividend Payments on Common Stock	2016		2015
Per Share	$	0.41	$	0.39
In Millions	$	207	$	197

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

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

PSE&G Power Other (A) Eliminations (B) Consolidated
Millions
Three Months Ended September 30, 2015
Total Operating Revenues $ 1,766
$ 1,096
$ 120
$ (294 ) $ 2,688

Net Income (Loss) 222
206
11
—
439

Gross Additions to Long-Lived Assets 716
310
13
—
1,039

Nine Months Ended September 30, 2015
Total Operating Revenues $ 5,234
$ 3,846
$ 326
$ (1,269 ) $ 8,137

Net Income (Loss) 631
707
32
—
1,370

Gross Additions to Long-Lived Assets 1,946
797
39
—
2,782

Three Months Ended September 30, 2014
Total Operating Revenues $ 1,655
$ 1,138
$ 123
$ (275 ) $ 2,641

Net Income (Loss) 200
222
22
—
444

Gross Additions to Long-Lived Assets 497
188
8
—
693

Nine Months Ended September 30, 2014
Total Operating Revenues $ 5,235
$ 3,824
$ 359
$ (1,305 ) $ 8,113

Net Income (Loss) 565
440
37
—
1,042

Gross Additions to Long-Lived Assets 1,493
414
15
—
1,922

As of September 30, 2015
Total Assets $ 22,909
$ 12,314
$ 2,775
$ (1,574 ) $ 36,424

Investments in Equity Method Subsidiaries $ —
$ 116
$ 1
$ —
$ 117

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 March 31, 2016
Operating Revenues	$	1,712	$	1,313	$	122	$	(531	)	$	2,616
Net Income (Loss)	262		192		17		—			471
Gross Additions to Long-Lived Assets	724		333		8		—			1,065
Three Months Ended March 31, 2015
Operating Revenues	$	2,002	$	1,725	$	98	$	(690	)	$	3,135
Net Income (Loss)	242		335		9		—			586
Gross Additions to Long-Lived Assets	599		139		9		—			747
As of March 31, 2016
Total Assets	$	24,372	$	12,617	$	2,462	$	(1,325	)	$	38,126
Investments in Equity Method Subsidiaries	$	—	$	116	$	—	$	—		$	116
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 Nine Months Ended
September 30, September 30,
Related-Party Transactions 2015 2014 2015 2014
Millions
Billings from Affiliates:
Billings from Power primarily through BGS and BGSS (A) $ 294
$ 280
$ 1,287
$ 1,308

Administrative Billings from Services (B) 66
59
197
183

Total Billings from Affiliates $ 360
$ 339
$ 1,484
$ 1,491




		Three Months Ended
		March 31,
Related-Party Transactions		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)		$	545	$	696
Administrative Billings from Services (B)		69		66
Total Billings from Affiliates		$	614	$	762

As of As of
Related-Party Transactions September 30, 2015 December 31, 2014
Millions
Receivable from PSEG (C) $ 7
$ 274

Payable to Power (A) $ 158
$ 313

Payable to Services (B) 50
66

Accounts Payable—Affiliated Companies $ 208
$ 379

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

Long-Term Accrued Taxes Payable
$ 165
$ 116




	As of		As of
Related-Party Transactions	March 31, 2016		December 31, 2015
	Millions
Receivables from PSEG (C)	$	3	$	222
Payable to Power (A)	$	184	$	212
Payable to Services (B)	74		80
Accounts Payable—Affiliated Companies	$	258	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	89	$	109

Power

The financial statements for Power include transactions with related parties ~~presented~~ as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
Related-Party Transactions 2015 2014 2015 2014
Millions
Billings to Affiliates:
Billings to PSE&G primarily through BGS and BGSS (A) $ 294
$ 280
$ 1,287
$ 1,308

Billings from Affiliates:
Administrative Billings from Services (B) $ 44
$ 41
$ 135
$ 129




		Three Months Ended
		March 31,
Related-Party Transactions		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)		$	545	$	696
Billings from Affiliates:
Administrative Billings from Services (B)		$	45	$	45

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

Payable to Services (B) $ 26
$ 23

Payable to PSEG (C) 91
95

Accounts Payable—Affiliated Companies $ 117
$ 118

Short-Term Loan Due (to) from Affiliate (E) $ 865
$ 584

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

Long-Term Accrued Taxes Payable
$ 54
$ 41




	As of		As of
Related-Party Transactions	March 31, 2016		December 31, 2015
	Millions
Receivables from PSE&G (A)	$	184	$	212
Receivables from PSEG (C)	—		64
Accounts Receivable—Affiliated Companies	$	184	$	276
Payable to Services (B)	$	34	$	33
Payable to PSEG (C)	118		—
Accounts Payable—Affiliated Companies	$	152	$	33
Short-Term Loan Due (to) from Affiliate (E)	$	672	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	38	$	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 March 31, 2016 and December 31, 2015 and for the three months ended March 31, 2016 and 2015.

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
Three Months Ended September 30, 2015
Operating Revenues $ —
$ 1,084
$ 37
$ (25 ) $ 1,096

Operating Expenses 3
692
35
(25 ) 705

Operating Income (Loss) (3 ) 392
2
—
391

Equity Earnings (Losses) of Subsidiaries 220
(2 ) 3
(218 ) 3

Other Income 10
26
—
(11 ) 25

Other Deductions —
(14 ) —
—
(14 )
Other-Than-Temporary Impairments —
(30 ) —
—
(30 )
Interest Expense (28 ) (8 ) (5 ) 11
(30 )
Income Tax Benefit (Expense) 7
(148 ) 2
—
(139 )
Net Income (Loss) $ 206
$ 216
$ 2
$ (218 ) $ 206

Comprehensive Income (Loss) $ 184
$ 187
$ 2
$ (189 ) $ 184

Nine Months Ended September 30, 2015
Operating Revenues $ —
$ 3,811
$ 144
$ (109 ) $ 3,846

Operating Expenses 7
2,610
135
(109 ) 2,643

Operating Income (Loss) (7 ) 1,201
9
—
1,203

Equity Earnings (Losses) of Subsidiaries 755
(4 ) 11
(751 ) 11

Other Income 33
111
—
(35 ) 109

Other Deductions (1 ) (31 ) —
—
(32 )
Other-Than-Temporary Impairments —
(45 ) —
—
(45 )
Interest Expense (90 ) (24 ) (15 ) 35
(94 )
Income Tax Benefit (Expense) 17
(463 ) 1
—
(445 )
Net Income (Loss) $ 707
$ 745
$ 6
$ (751 ) $ 707

Comprehensive Income (Loss) $ 690
$ 707
$ 6
$ (713 ) $ 690

Nine Months Ended September 30, 2015

Net Cash Provided By (Used In)
   Operating Activities
$ 435
$ 1,826
$ 66
$ (769 ) $ 1,558

Net Cash Provided By (Used In)
   Investing Activities
$ (656 ) $ (1,382 ) $ (303 ) $ 1,191
$ (1,150 )

Net Cash Provided By (Used In)
   Financing Activities
$ 221
$ (446 ) $ 245
$ (422 ) $ (402 )




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended March 31, 2016
Operating Revenues	$	—		$	1,302		$	42		$	(31	)	$	1,313
Operating Expenses	10			952			39			(31		)	970
Operating Income (Loss)	(10		)	350			3			—			343
Equity Earnings (Losses) of Subsidiaries	205			(1		)	2			(204		)	2
Other Income	17			32			—			(23		)	26
Other Deductions	—			(18		)	—			—			(18		)
Other-Than-Temporary Impairments	—			(10		)	—			—			(10		)
Interest Expense	(30		)	(10		)	(5		)	23			(22		)
Income Tax Benefit (Expense)	10			(140		)	1			—			(129		)
Net Income (Loss)	$	192		$	203		$	1		$	(204	)	$	192
Comprehensive Income (Loss)	$	215		$	219		$	1		$	(220	)	$	215
Three Months Ended March 31, 2016
Net Cash Provided By (Used In) Operating Activities	$	271		$	480		$	47		$	(135	)	$	663
Net Cash Provided By (Used In) Investing Activities	$	(598	)	$	(428	)	$	(246	)	$	613		$	(659	)
Net Cash Provided By (Used In) Financing Activities	$	326		$	(51	)	$	203		$	(478	)	$	—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
Three Months Ended September 30, 2014
Operating Revenues $ —
$ 1,125
$ 36
$ (23 ) $ 1,138

Operating Expenses 3
772
32
(22 ) 785

Operating Income (Loss) (3 ) 353
4
(1 ) 353

Equity Earnings (Losses) of Subsidiaries 225
(1 ) 4
(224 ) 4

Other Income 9
55
—
(8 ) 56

Other Deductions (3 ) (4 ) —
1
(6 )

Other-Than-Temporary
   Impairments
—
(10 ) —
—
(10 )
Interest Expense (24 ) (10 ) (4 ) 7
(31 )
Income Tax Benefit (Expense) 18
(161 ) (1 ) —
(144 )
Net Income (Loss) $ 222
$ 222
$ 3
$ (225 ) $ 222

Comprehensive Income (Loss) $ 195
$ 191
$ 3
$ (194 ) $ 195

Nine Months Ended September 30, 2014
Operating Revenues $ —
$ 3,781
$ 118
$ (75 ) $ 3,824

Operating Expenses 12
3,079
106
(75 ) 3,122

Operating Income (Loss) (12 ) 702
12
—
702

Equity Earnings (Losses) of Subsidiaries 459
(4 ) 11
(455 ) 11

Other Income 25
135
—
(25 ) 135

Other Deductions (7 ) (18 ) —
—
(25 )
Other-Than-Temporary Impairments —
(14 ) —
—
(14 )
Interest Expense (79 ) (23 ) (14 ) 24
(92 )
Income Tax Benefit (Expense) 54
(329 ) (2 ) —
(277 )
Net Income (Loss) $ 440
$ 449
$ 7
$ (456 ) $ 440

Comprehensive Income (Loss) $ 432
$ 433
$ 7
$ (440 ) $ 432

Nine Months Ended September 30, 2014

Net Cash Provided By (Used In)
   Operating Activities
$ 471
$ 1,252
$ 53
$ (666 ) $ 1,110

Net Cash Provided By (Used In)
   Investing Activities
$ 187
$ (559 ) $ (24 ) $ 70
$ (326 )

Net Cash Provided By (Used In)
   Financing Activities
$ (652 ) $ (693 ) $ (29 ) $ 596
$ (778 )




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended March 31, 2015
Operating Revenues	$	—		$	1,715		$	68		$	(58	)	$	1,725
Operating Expenses	5			1,131			63			(58		)	1,141
Operating Income (Loss)	(5		)	584			5			—			584
Equity Earnings (Losses) of Subsidiaries	349			(1		)	3			(348		)	3
Other Income	11			30			—			(12		)	29
Other Deductions	—			(11		)	—			—			(11		)
Other-Than-Temporary Impairments	—			(5		)	—			—			(5		)
Interest Expense	(29		)	(9		)	(5		)	12			(31		)
Income Tax Benefit (Expense)	9			(242		)	(1		)	—			(234		)
Net Income (Loss)	$	335		$	346		$	2		$	(348	)	$	335
Comprehensive Income (Loss)	$	347		$	351		$	2		$	(353	)	$	347
Three Months Ended March 31, 2015
Net Cash Provided By (Used In) Operating Activities	$	327		$	772		$	11		$	(260	)	$	850
Net Cash Provided By (Used In) Investing Activities	$	(537	)	$	(515	)	$	(13	)	$	430		$	(635	)
Net Cash Provided By (Used In) Financing Activities	$	210		$	(242	)	$	2		$	(170	)	$	(200	)

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Consolidated
Millions
As of September 30, 2015
Current Assets $ 4,678
$ 1,786
$ 134
$ (4,374 ) $ 2,224

Property, Plant and Equipment, net 82
6,390
1,435
—
7,907

Investment in Subsidiaries 4,555
349
—
(4,904 ) —

Noncurrent Assets 264
1,962
133
(176 ) 2,183

Total Assets $ 9,579
$ 10,487
$ 1,702
$ (9,454 ) $ 12,314

Current Liabilities $ 1,581
$ 3,595
$ 772
$ (4,374 ) $ 1,574

Noncurrent Liabilities 458
2,563
355
(176 ) 3,200

Long-Term Debt 1,691
—
—
—
1,691

Member's Equity 5,849
4,329
575
(4,904 ) 5,849

Total Liabilities and Member's Equity $ 9,579
$ 10,487
$ 1,702
$ (9,454 ) $ 12,314

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 March 31, 2016
Current Assets	$	4,819	$	1,934	$	283	$	(5,005	)	$	2,031
Property, Plant and Equipment, net	88		6,465		1,773		—			8,326
Investment in Subsidiaries	4,615		345		—		(4,960		)	—
Noncurrent Assets	138		2,046		133		(57		)	2,260
Total Assets	$	9,660	$	10,790	$	2,189	$	(10,022	)	$	12,617
Current Liabilities	$	1,316	$	3,809	$	1,192	$	(5,005	)	$	1,312
Noncurrent Liabilities	441		2,637		382		(57		)	3,403
Long-Term Debt	1,685		—		—		—			1,685
Member's Equity	6,218		4,344		615		(4,960		)	6,217
Total Liabilities and Member's Equity	$	9,660	$	10,790	$	2,189	$	(10,022	)	$	12,617
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~~growing our utility operations through continued investment in T&D and other infrastructure projects, 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~~ ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~ are presented as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
Earnings 2015 2014 2015 2014
Millions
PSE&G $ 222
$ 200
$ 631
$ 565

Power (A) 206
222
707
440

Other (B) 11
22
32
37

PSEG Net Income $ 439
$ 444
$ 1,370
$ 1,042

PSEG Net Income Per Share (Diluted) $ 0.87
$ 0.87
$ 2.70
$ 2.05




		Three Months Ended
		March 31,
Earnings		2016		2015
	Millions
PSE&G		$	262	$	242
Power (A)		192		335
Other (B)		17		9
PSEG Net Income		$	471	$	586

PSEG Net Income Per Share (Diluted)		$	0.93	$	1.15


(A)	Includes an after-tax insurance recovery for Superstorm Sandy of ~~$102~~$75 million in the ~~nine~~three months ended ~~September 30,~~March 31, 2015. ~~See Item 1. 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 delivery dates.

The variances in our Net Income include the changes related to NDT and MTM shown in the following table:

Three Months Ended Nine Months Ended
September 30, September 30,
2015 2014 2015 2014
Millions, after tax
NDT Fund Income (Expense) (A) $ (14 ) $ 17
$ (11 ) $ 40

Non-Trading MTM Gains (Losses) $ 50
$ 36
$ 58
$ (138 )




		Three Months Ended
		March 31,
		2016			2015
	Millions, after tax
NDT Fund Income (Expense) (A)		$	(5	)	$	2
Non-Trading MTM Gains (Losses)		$	13		$	(20	)

(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.

Our $5$115 million decrease in Net Income for the three months ended ~~September 30, 2015~~March 31, 2016 was driven primarily ~~by:~~by

reduced volumes of gas sold at lower average prices under the BGSS contract,

lower ~~net realized gains~~sales volumes of energy in the PJM and ~~higher other-than-temporary impairments~~New England regions resulting from unseasonably warm temperatures in 2016 as compared to unusually cold temperatures in 2015,

insurance recoveries received primarily by Power in 2015 related to ~~the NDT Fund,~~Superstorm Sandy, and

~~higher maintenance costs related to the earlier start~~lower operating reserve revenues and capacity revenues in ~~2015 of the planned annual outage of our Peach Bottom Unit 3 nuclear facility and higher pension and OPEB costs.~~PJM.

These decreases were ~~largely~~partially offset by

higher revenues due to increased investments in transmission projects, and

~~higher MTM gains.~~

~~Our $328 million increase in Net Income for the nine months ended September 30, 2015 was driven primarily by:~~

~~MTM gains in 2015 as compared to MTM losses in 2014,~~

~~higher volumes of electricity sold under wholesale load contracts and under the BGS contract, the latter at higher average prices,~~

lower generation costs ~~due to~~driven by lower ~~fuel costs,~~

~~table of contents~~

~~higher revenues due to increased investments in transmission projects, and~~

~~insurance recoveries of Superstorm Sandy costs, primarily~~natural gas prices at Power.

~~These year-to date increases were partially offset by~~

~~lower realized gains~~During the first quarter of 2016, we sustained 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 ~~higher other-than-temporary impairments related to the NDT Fund,~~

~~higher planned outage costs~~credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at ~~our nuclear plants and higher pension and OPEB costs, and~~

~~higher Depreciation Expense largely related to increased investments in transmission and distribution projects and a higher depreciable nuclear and fossil asset base.~~

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

Table of Contents

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 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, which will be filedthe BPU in the Spring of 2016, 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. In October 2015, we filed our 2016 Annual Formula Rate Update with the Federal Energy Regulatory Commission (FERC), which will provide $146 million in increased annual transmission revenues effective January 1, 2016.

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 contribution by PSE&G.

During the first quarter of 2016, Power continued to improve its performance for both nuclear and fossil operations, with continued upgrades in efficiency and output, while mitigating environmental impacts. 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) arrangement. The contracts are sized to ensure 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.

~~Gas prices have remained relatively low this year as a result of the expansion of shale gas production, primarily in the Marcellus/Utica regions. These low prices benefit PSE&G’s gas customers~~ Power’s strategic hedging practices and ~~provide a low cost fuel supply for Power’s combined cycle units. However, they have also resulted in a decline in power prices. Our contractual hedges currently in place have helped mitigate~~ability to use market conditions to its advantage help it to balance some of the ~~effects~~volatility of ~~low prices this year~~the merchant power business.

Our recent investments in the latter half of 2015 and ~~for 2016. However, as these arrangements expire~~early 2016 in Keys Energy Center (Keys), Sewaren 7 and ~~new hedges~~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 ~~set at lower price levels, our margins will be impacted. A sustained continuation~~expected to contribute to the overall efficiency of ~~low prices could have an adverse impact on the earnings from our nuclear and coal-fired units.~~ operations.

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

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 ~~in which we participated~~ to ~~review technical solutions~~allow both incumbents and non-incumbents the opportunity to ~~improve the operational performance in the~~submit transmission project proposals to address identified high voltage issues at Artificial Island ~~area, consisting of our Salem and Hope Creek nuclear generation facilities.~~in New Jersey. In April 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 would be assigned to PSE&G. We subsequently filed comments with the PJM Board of Managers (PJM Board) identifying what we believed were deficiencies in the PJM staff recommendation. In July 2015, the PJM Board approved the PJM staff's recommendation and in August 2015, PJM provided notice to2016, PSE&G ~~of its designation for~~accepted construction responsibility ~~with respect to~~for the three components of the project ~~estimated by~~that PJM assigned to ~~cost approximately $126 million. PSE&G is currently in discussions~~it, based on having reached agreement with PJM regarding an estimate for the ~~accuracy~~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 ~~estimate given~~reform as a measure to improve the ~~complexities~~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 ~~construction work at Artificial Island. See Part II. Item 5. Other Information—Transmission Regulation—Transmission Policy Developments for additional information.~~

~~table~~transmission projects being constructed by PSE&G. Regardless of ~~contents~~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 allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to an adjustment, subject to BPU approval. We do not believe that these matters will have a material effect on Power's business or results of operations.

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 above-market new generation, on April 19, 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. See Item 5. Other Information—Federal Regulation—Long-Term Capacity Agreement Pilot Program Act for additional information.

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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 FERC had determined that demand response (DR) providers should receive full market compensation for power and held that FERC has no jurisdiction over DR. In October 2015, the U.S. Supreme Court heard oral arguments on this case. Although a reversal by the U.S. Supreme Court of the federal court's decision regarding FERC's lack of jurisdiction is not expected to have significant impacts on capacity markets, a decision that upholds such decision could have a material impact on capacity market outcomes.

~~In a separate development of significance to the wholesale capacity market, in December 2014~~proposal from PJM ~~filed at 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 included enhanced performance-based incentives and penalties. In June 2015, FERC conditionally accepted the proposal. PJM commenced the auction on August 10, 2015 and announced the auction results on August 21, 2015. Power cleared 8,634 MW of its generating capacity at an average price of $214.72 MW-day for the 2018-2019 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 2016-2017 and 2017-2018 delivery years, Power cleared approximately 8,700 MW at average prices of $172 MW-day and $177 MW-day, respectively. The capacity that Power cleared for the 2018-2019 delivery year included Sewaren 7 and Keys Energy Center generation plants. See Other Developments below for additional details about our construction of these two new projects. We believe that ~~this~~the auction pricing adequately reflects the increased costs that could result from operating under more stringent rules for generation availability. ~~No assurances can~~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 ~~given that similar pricing will continue in future auctions.~~

assured. Further, there may be requirements for additional investment and there are additional performance risks. Applications for rehearing of FERC's ~~capacity performance~~CP order are pending.

An emerging issue in PJM involves the impact of subsidized existing generation on 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 suppress capacity market prices, especially given that PJM’s currently effective “minimum offer price rule” (MOPR) which applies only to new gas-fired units, would not apply to these plants. See ~~Part II,~~ Item 5. Other Information—Federal Regulation—Capacity Market ~~Issues—PJM for additional information.~~

We have also been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for setting prices for energy in the day-ahead and real-time markets administered by PJM and other system operators. A recent development which we view as positive involves a September 2015 FERC notice of proposed rulemaking on two issues: aligning settlements with dispatch intervals (more granular “5-minute pricing” in real-time markets) and improving real-time scarcity pricing. Comments made by FERC commissioners stressed these two items are intended to be the first of a series of steps FERC will take on energy price formation in the future. See Part II, Item 5. Other Information—Price Formation InitiativesIssues 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. In June 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 towers and allows Salem to continue to operate utilizing the existing once-through cooling water system with required system modifications. The draft permit was subject to a sixty-day public notice and comment period. The NJDEP may make revisions before issuing the final permit expected during the first half of 2016. We ~~participated in the NJDEP’s August 2015 public hearing and submitted comments on the draft permit in September 2015.~~ See Item 1. Note 8. Commitments and Contingent Liabilities for further information.

~~The EPA’s greenhouse gas (GHG) emissions regulations are also of potential consequence to our results.~~ In October 2015, the EPA published the Clean Power Plan (CPP), a ~~GHG~~greenhouse gas emissions regulation under the Clean Air Act (CAA) for existing power plants. The regulation establishes state-specific emission targets based on implementation of the best systems of emission reduction. ~~Each state must submit a compliance plan to the EPA by September 6, 2016 or seek a two-year extension to September 6, 2018.~~ We continue to work with FERC and other federal and state regulators, as well as industry partners, to determine the potential impact of these regulations.

The ~~EPA, FERC~~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 ~~U.S. Department~~effective date of ~~Energy~~the compliance period may be impacted.

We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have ~~announced that they plan to meet at least quarterly to evaluate states' plans and identify reliability concerns so adjustments can be made before~~discharged substantial contamination into the ~~final plans are submitted. The agencies are engaging~~Passaic River/Newark Bay Complex in violation of various stakeholders, including the Regional Transmission Operators/Independent System Operators. The agencies will continue to meet after the states' plans are in effect to assess if revisions are required. See Part II, Item 5. Other Information—CO₂ ~~Regulation Under the Clean Air Act.~~

~~CAA regulations governing hazardous air pollutants under the EPA's Maximum Achievable Control Technology rules~~statutes. We are also currently involved in a number of ~~significance; however, we believe our generation business remains well-positioned for such regulations if~~proceedings relating to sites where other hazardous substances may have been discharged and ~~when they are implemented. In addition, state environmental regulations governing emissions from power plants also have a significant~~

~~table of contents~~

~~impact on our operations. In~~may be subject to additional proceedings in the second quarter of 2015, we retired 1,545 MW of fully depreciated combustion turbine capacity that would not 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.

~~Other Developments~~

In the first nine months 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 $1.2 billion of investment, with cost recovery at 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 up to $220 million of investment in PSE&G's next base rate case, which is to be filed no later than November 1, 2017.

~~In September 2015, we reached a settlement in principle with the BPU Staff~~future, and the ~~New Jersey Division~~costs of ~~Rate Counsel~~any such remediation efforts could be material.

For further information regarding ~~PSE&G’s Gas System Modernization Program (GSMP) through which, if approved, we will invest $905 million over~~ the ~~next three years to modernize PSE&G's gas systems. The settlement in principle provides for cost recovery at a 9.75% rate~~matters described above as well as other matters that may impact our financial condition and results of return on equity on the first $650 million of the investment through an accelerated recovery mechanism. Under the settlement in principle, PSE&G will seek recovery of the remaining $255 million of investment in its next base rate case, which is to be filed no later than November 1, 2017. For additional information,operations, see ~~Part II,~~ Item ~~5. Other Information—Gas System Modernization Program.~~1. Note 8. Commitments and Contingent Liabilities.

In August 2015, we announced our plan to construct Sewaren 7, a new 540 MW duel-fueled combined cycle generating plant in Woodbridge, New Jersey scheduled to be in-service for the summer of 2018 at an estimated investment of $625 million - $675 million. The Sewaren 7 plant will replace Sewaren Units 1, 2, 3 and 4.

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.FERC Compliance

The FERC Staff has initiated a preliminary non-public ~~staff~~ investigation ~~initiated by FERC into Power's discovery and investigation~~regarding errors in the 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 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 Inspection

In April 2016, during a scheduled refueling outage at Salem Unit 1, a visual inspection revealed degradation to a series of bolts inside the reactor vessel. We have initiated further testing, which is ongoing and is expected to extend the refueling outage. The impact of the outage on Salem Unit 1’s output, margin and cost will depend on the timing and results of the inspection and necessary repairs.

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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 ~~nine months~~quarter of ~~2015,~~2016, our

total nuclear fleet achieved an average capacity factor of ~~92%~~99.7%,

nuclear output increased by ~~2.7% and combined cycle output by 14.9%~~7.5% as compared to the same period in ~~2014,~~2015, and

diverse fuel mix and dispatch flexibility allowed us to generate approximately ~~42.5 TWh~~13 terra-watt hours while addressing unit outages and balancing fuel availability and price volatility.

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 ~~2015~~the first quarter of 2016 as we

had cash ~~flow from operations~~on hand of ~~$3.2 billion~~$592 million as of ~~September 30, 2015,~~March 31, 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, Energy Strong distribution program, Keys Energy Center and other~~ planned ~~projects, as well as our GSMP,~~capital requirements without the issuance of new equity.

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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 ~~2015, in addition to our acquisition~~the first quarter of ~~the Keys Energy Center and clearance of Sewaren 7 in the 2018/2019 capacity auction, each of which is under construction,~~2016, we

~~placed into service the final phase of our 500 kV Susquehanna-Roseland and 230 kV Mickleton-Gloucester-Camden transmission projects,~~

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 additional capital expenditures~~Strong and ~~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,~~

~~completed installation of equipment~~plan to ~~increase output~~construct BH5 and ~~improve efficiency at our Bergen 2 combined cycle gas unit similar to our 2014 installation at our Linden plant,~~commence operations in mid-2019, and

~~placed~~acquired three solar energy projects totaling 100 MW-direct current in North Carolina and Colorado expected to go into service ~~a 13 MWdc solar energy facility near Waldorf, Maryland and acquired and placed into service a 25 MWdc solar energy facility near San Francisco, California.~~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 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 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.

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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,

FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market,

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,

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.

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:

69the 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 of new businesses,

the expansion of our geographic footprint,

continued or expanded participation in solar, demand response and energy efficiency programs, and

investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency 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~~Table of ~~contents~~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)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2015 2014 2015 vs. 2014 2015 2014 2015 vs. 2014
Millions Millions % Millions Millions %
Operating Revenues $ 2,688
$ 2,641
$ 47
2
$ 8,137
$ 8,113
$ 24
—

Energy Costs 815
863
(48 ) (6 ) 2,577
3,008
(431 ) (14 )
Operation and Maintenance 746
714
32
4
2,170
2,370
(200 ) (8 )
Depreciation and Amortization 313
318
(5 ) (2 ) 960
919
41
4

Income from Equity Method Investments 3
3
—
—
10
10
—
—

Other Income and (Deductions) 33
66
(33 ) (50 ) 135
154
(19 ) (12 )
Other-Than-Temporary Impairments 30
10
20
N/A
45
14
31
N/A

Interest Expense 96
100
(4 ) (4 ) 291
291
—
—

Income Tax Expense 285
261
24
9
869
633
236
37




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	2016		2015		2016 vs. 2015
	Millions				Millions			%
Operating Revenues	$	2,616	$	3,135	$	(519	)	(17	)
Energy Costs	836		1,094		(258		)	(24	)
Operation and Maintenance	729		663		66			10
Depreciation and Amortization	224		330		(106		)	(32	)
Income from Equity Method Investments	2		3		(1		)	(33	)
Other Income and (Deductions)	27		36		(9		)	(25	)
Other-Than-Temporary Impairments	10		5		5			N/A
Interest Expense	92		98		(6		)	(6	)
Income Tax Expense	283		398		(115		)	(29	)

The following discussions for PSE&G and Power provide a detailed explanation of their respective variances.

PSE&G

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2015 2014 2015 vs. 2014 2015 2014 2015 vs. 2014
Millions Millions % Millions Millions %
Operating Revenues $ 1,766
$ 1,655
$ 111
7
$ 5,234
$ 5,235
$ (1 ) —

Energy Costs 740
668
72
11
2,176
2,278
(102 ) (4 )
Operation and Maintenance 391
366
25
7
1,171
1,190
(19 ) (2 )
Depreciation and Amortization 231
238
(7 ) (3 ) 712
682
30
4

Other Income (Deductions) 22
14
8
57
57
41
16
39

Interest Expense 67
71
(4 ) (6 ) 203
206
(3 ) (1 )
Income Tax Expense 137
126
11
9
398
355
43
12




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	2016		2015		2016 vs. 2015
	Millions				Millions			%
Operating Revenues	$	1,712	$	2,002	$	(290	)	(14	)
Energy Costs	729		892		(163		)	(18	)
Operation and Maintenance	382		412		(30		)	(7	)
Depreciation and Amortization	139		247		(108		)	(44	)
Other Income (Deductions)	19		17		2			12
Interest Expense	68		69		(1		)	(1	)
Income Tax Expense	151		157		(6		)	(4	)

Three Months Ended ~~September 30, 2015~~March 31, 2016 as Compared to ~~2014~~2015

Operating Revenues ~~increased $111~~decreased $290 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased ~~$67~~$29 million due primarily to ~~increases~~an increase in transmission ~~and electric distribution~~ revenues.

Transmission revenues were ~~$41~~$53 million higher due to ~~increases resulting primarily from~~ increased capital investments.

Electric distribution revenues ~~increased $29~~decreased $23 million due primarily to ~~higher sales volumes of $24 million, higher~~lower Green Program Recovery Charges (GPRC) of $3$14 million and $2$10 million in lower sales volumes.

Gas distribution revenues decreased $1 million due primarily to $76 million lower delivery volume and lower GPRC of $6 million due to ~~the~~lower sales volumes from warmer winter weather. These decreases were almost entirely offset by $73 million in higher Weather Normalization Clause (WNC) revenue and $8 million due to roll in of Energy Strong into base rates effective September 1, 2015.

~~table~~Table of ~~contents~~Contents

~~Gas distribution revenues decreased $3 million due primarily to lower delivery volume.~~

Commodity Revenue ~~increased $72~~decreased $163 million as a result of ~~higher Electric revenues partially offset by~~ lower Gas and Electric revenues. Commodity revenue for both ~~electric~~gas and ~~gas~~electric is entirely offset with ~~increased~~decreased Energy Costs. PSE&G earns no margin on the provision of ~~basic generation service (BGS) and~~ Basic Gas Supply Service (BGSS) and basic generation service (BGS) to retail customers.

Gas revenues decreased $109 million due to lower BGSS volume.

Electric revenues ~~increased $81~~decreased $54 million due primarily to ~~an $83~~a $35 million or ~~16% increase~~8% decrease in BGS revenues due to ~~higher~~lower sales volumes, ~~and $2~~$11 million of ~~higher~~lower revenues from collections of Non-Utility Generation Charges (NGC)~~. These increases were partially offset by~~ and a $4decrease of $8 million ~~reduction in revenues~~ due to ~~lower~~higher volumes onof Non-Utility Generation (NUG) energy sold at lower prices.

~~Gas revenues decreased $9 million due primarily to $11 million in lower BGSS prices, partially offset by $2 million in higher prices.~~

Clause Revenues decreased ~~$28~~$155 million due primarily to lower Securitization Transition Charges (STC) of ~~$28 million, lower Solar Pilot Recovery Charges (SPRC) of $3~~$129 million and lower ~~Margin Adjustment Clause Revenue~~Societal Benefit Charges (SBC) of $1$33 million, partially offset by higher ~~Societal Benefit Charges (SBC)~~Margin Adjustment Clause Revenue (MAC) of $4$12 million. The STC reduction is a result of rate reductions due to the completion of securitization collections in 2015. The changes in the STC, ~~SPRC,~~SBC and MAC ~~and SBC~~ amounts are entirely offset by decreases in the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, ~~SPRC, MAC or SBC collections.~~

~~Other Operating Revenues~~ ~~experienced no material change.~~

~~Operating Expenses~~

~~Energy Costs~~ ~~increased $72 million due to higher Electric costs partially offset by lower Gas costs. This is entirely offset by decreased Commodity Revenue.~~

Electric costs increased $81 million or 14% due to $45 million of higher BGS and NUG prices and $68 million in higher BGS volumes. BGS volumes increased due to higher sales volumes due to warmer weather and reverse customer migration. These increases were partially offset by $19 million of decreased deferred cost recovery and $13 million of lower NUG volumes.

~~Gas costs decreased $9 million or 11% due to $11 million in lower prices, partially offset by $2 million in higher volumes.~~

~~Operation and Maintenance~~ ~~increased $25 million, of which the most significant components were~~

~~$10 million increase in pension and OPEB expenses,~~

~~$7 millionincrease~~ ~~in transmission operating expenses,~~

$8 million increase in other operating expenses, including $4 million in appliance service costs, $3 million in higher preventive maintenance and tree trimming and $1 million increase in general operating expenses,

partially offset by a $3 million decrease in costs related to a net decrease in SBC, MAC, GPRC, SPRC and STC. Due to the nature of the SBC, MAC, SPRC and STC clause mechanisms, these are entirely offset in revenue.

~~Depreciation and Amortization~~ decreased $7 million due primarily to a decrease of $22 million in amortization of Regulatory Assets, partially offset by a $13 million increase in depreciation of additional plant in service related to increased investments in various transmission and distribution projects.

~~Other Income and (Deductions)~~ ~~increased $8 million due primarily to an increase in Allowance for Funds used During Construction (AFUDC).~~

~~Interest Expense~~ ~~decreased $4 million due primarily to partial redemption of securitization debt and clause interest, partially offset by net issuances of Medium Term Notes during 2015 and the latter half of 2014.~~

~~Income Tax Expense~~ ~~increased $11 million due primarily to higher pre-tax income.~~

~~Nine Months Ended September 30, 2015 as Compared to 2014~~

~~Operating Revenues~~ ~~decreased $1 million due to changes in delivery, commodity, clause and other operating revenues.~~

~~Delivery Revenues~~ ~~increased $178 million due primarily to increases in transmission and electric distribution revenues.~~

~~Transmission revenues were $124 million higher due to increases resulting primarily from increased capital investments.~~

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~~Electric distribution revenues increased $45 million due primarily to higher sales volumes of $37 million, an~~

~~increase in Capital Stimulus Infrastructure Program (CIP) revenues of $5 million due to the inclusion of CIP II in base rates beginning in July 2014 and $3 million of higher revenues from GPRC.~~

Gas distribution revenues increased $9 million due primarily to $16 million from higher sales volumes and an increase in CIP revenues of $2 million, partially offset by lower Weather Normalization Charges (WNC) revenue of $9 million due to colder weather in 2015 compared to 2014.

~~Commodity Revenue~~ decreased $102 million due to lower Gas revenues offset partially by higher Electric revenues. Commodity revenue for both electric and gas is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

Gas revenues decreased $209 million due primarily to lower BGSS prices of $290 million, of which $215 million was due to lower residential rates resulting from $133 million in residential bill credits and $82 million of lower commodity prices, partially offset by higher BGSS volumes of $81 million due to colder weather in 2015.

Electric revenues increased $107 million due primarily to $140 million of higher net BGS revenues. BGS revenues increased $171 million or 13%, due to higher sales volumes, which were partially offset by $31 million due to lower BGS rates. The increase from BGS was partially offset by $33 million in lower revenues from lower collection of NGC and lower sales prices and volumes of NUG energy.

~~Clause Revenues~~ decreased $75 million due primarily to lower MAC revenue of $24 million, lower STC of $24 million, lower SBC of $23 million and lower SPRC of $4 million. The changes in the MAC, STC, SBC and SPRC amounts were entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on MAC, STC, SBC or ~~SPRC~~MAC collections.

Other Operating Revenues experienced no material change.

Operating Expenses

Energy Costs decreased ~~$102 million due to lower Gas costs partially offset by higher Electric costs.~~$163 million. This is entirely offset by ~~decreased~~ Commodity Revenue.

~~Gas costs decreased $209 million or 27% due to a $290 million or 37% decline in prices, partially offset by $81 million or 10% in higher sales volumes due to colder than normal weather.~~

Electric costs increased $107 million or 7% due to a $140 million or 11% increase in BGS volumes, due to reverse customer migration and higher sales volumes due to warmer weather and a $57 million increase due to higher BGS and NUG prices, partially offset by $69 million of decreased deferred cost recovery and $21 million in lower NUG sales volumes.

Operation and Maintenance decreased ~~$19~~$30 million, of which the most significant components were

a ~~$63~~$44 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 ~~in revenues,~~

by $15 million of storm insurance recovery proceeds ~~of $10 million, and~~

~~decreased injuries and damages of~~ ~~$6 million~~,

•~~partially offset by a $28 million increase~~received in ~~pension and OPEB expenses,~~

•~~increased transmission operating expenses of $10 million,~~

•~~$8 million~~ ~~of higher appliance service costs,~~

~~increased bad debt expense of $6 million, and~~

~~an $8 million increase in other general operating expenses.~~2015.

Depreciation and Amortization~~increased$30 million~~ decreased $108 million due ~~primarily~~ to a ~~$42 millionincrease~~ ~~in depreciation of additional plant in service related to increased investments in various transmission and distribution projects, offset by~~ a decrease of ~~$13~~$124 million in amortization of Regulatory Assets ~~which~~primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is ~~fully~~completely offset in ~~Clause Revenues.~~STC Revenues), partially offset by a $16 million increase in depreciation due to of additional plant in service.

~~Other~~ Income ~~and (Deductions)~~Tax Expense ~~increased $16~~decreased $6 million due primarily to ~~an increase in AFUDC.~~

~~Interest Expense~~ ~~decreased $3 million due primarily to partial redemption of securitization debt partially~~depreciation flow through items and uncertain tax positions offset by ~~net issuances of Medium Term Notes in 2015 and the latter half of 2014.~~

~~table of contents~~

~~Income Tax Expenseincreased$43 million~~ ~~due primarily to~~ higher pre-tax income.

Power

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2015 2014
2015 vs. 2014 2015 2014 2015 vs. 2014
Millions Millions % Millions Millions %
Operating Revenues $ 1,096
$ 1,138
$ (42 ) (4 ) $ 3,846
$ 3,824
$ 22
1

Energy Costs 367
472
(105 ) (22 ) 1,669
2,036
(367 ) (18 )
Operation and Maintenance 263
242
21
9
748
871
(123 ) (14 )
Depreciation and Amortization 75
71
4
6
226
215
11
5

Income from Equity Method Investments 3
4
(1 ) (25 ) 11
11
—
—

Other Income (Deductions) 11
50
(39 ) (78 ) 77
110
(33 ) (30 )
Other-Than-Temporary Impairments 30
10
20
N/A
45
14
31
N/A

Interest Expense 30
31
(1 ) (3 ) 94
92
2
2

Income Tax Expense 139
144
(5 ) (3 ) 445
277
168
61




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	2016		2015		2016 vs. 2015
	Millions				Millions			%
Operating Revenues	$	1,313	$	1,725	$	(412	)	(24	)
Energy Costs	638		893		(255		)	(29	)
Operation and Maintenance	253		172		81			47
Depreciation and Amortization	79		76		3			4
Income from Equity Method Investments	2		3		(1		)	(33	)
Other Income (Deductions)	8		18		(10		)	(56	)
Other-Than-Temporary Impairments	10		5		5			N/A
Interest Expense	22		31		(9		)	(29	)
Income Tax Expense	129		234		(105		)	(45	)

Three Months Ended ~~September 30, 2015~~ March 31, 2016 as Compared to ~~2014~~2015

Operating Revenuesdecreased ~~$42~~$412 million due to changes in generation and gas supply ~~and other operating~~ revenues.

~~Gas Supply~~Generation Revenues decreased ~~$44~~$174 million due primarily to

a decrease of ~~$14~~$75 million primarily in the PJM region due to lower operating reserve revenue coupled with lower capacity revenues resulting from the retirement of older peaking units in June 2015,

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lower net revenues of $75 million due primarily to milder weather which led to lower energy volumes sold in the PJM and NE regions and lower average realized prices,

a decrease of $38 million due primarily to lower volumes of electricity sold under fewer wholesale load contracts in the PJM and NE regions coupled with lower average prices,

a net decrease of $25 million due primarily to lower volumes of electricity sold under the BGS contracts as a result of milder weather partially offset by higher average prices, and

partially offset by an increase of $39 million due to MTM gains in 2016 as compared to MTM losses in 2015.

Gas Supply Revenuesdecreased $238 million due primarily to

a net decrease of $220 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 ~~$30~~$18 million ~~due to lower average~~on sales ~~prices and volumes~~ to third party ~~customers.~~

~~Generation Revenues~~ ~~increased $3~~customers, of which $47 million ~~due primarily to~~

~~an increase of $39 million~~was due to ~~higher volumes of electricity sold under our BGS contract at higher average prices,~~

~~partially offset by a decrease of $27 million due primarily to lower volumes sold under the wholesale load contracts in the PJM and New England (NE) regions.~~

~~Other Operating Revenues~~ ~~decreased$1 milliondue tolower fees received from fuel management and power supply management contracts with LIPA.~~

~~Operating Expenses~~

~~Energy Costs~~ represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $105 million due to

~~Generation costs~~ decreased $59 million due primarily to lower fuel costs, reflecting lower average realized natural gas prices and the utilization of lower coal volumes at lower average realized prices, coupled with higher MTM gains in 2015. These decreased costs were partially offset by higher congestion costs in the PJM region.

~~Gas costs~~ ~~decreased $46 million related to lower average gas inventory costs on both obligations under the BGSS contract and sales to third parties, coupled with lower volumes sold to third parties.~~

~~Operation and Maintenance~~ ~~increased $21 million due primarily to~~

~~a net increase of $24 million at our nuclear facilities, primarily due to the start of the 2015 fall outage one month sooner than in 2014 at our 50%-owned Peach Bottom nuclear unit 3,~~

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~~partially offset by a decrease of $5 million related to our fossil plants, largely due to higher costs incurred in 2014 for planned outages and maintenance.~~

~~Depreciation and Amortization~~ ~~increased $4 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)~~ ~~decreased $39 million due primarily to lower net realized gains from the NDT Fund.~~

~~Other-Than-Temporary Impairments~~ ~~increased $20 million due to an increase in impairments of the NDT Fund.~~

~~Interest Expense~~ ~~experienced no material change.~~

~~Income Tax Expense~~ ~~decreased $5 million in 2015 due primarily to lower pre-tax income.~~

~~Nine Months EndedSeptember 30, 2015~~ ~~as Compared to 2014~~

~~Operating Revenuesincreased$22 million~~ ~~due to changes in generation, gas supply and other operating revenues.~~

~~Generation Revenues~~ ~~increased $203 million due primarily to~~

higher net revenues of $232 million due primarily to MTM gains in 2015 compared to MTM losses in 2014, partially offset by lower energy volumes sold in the NE region and lower average realized prices in the NE and New York (NY) regions,

~~an increase of $78 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM and NE regions, and~~

~~an increase of $48 million due primarily to higher volumes of electricity sold under the BGS contract at higher average prices,~~

partially offset by a decrease of $155 million due primarily to lower capacity revenues resulting from lower average auction prices coupled with lower ancillary and operating reserve revenues in the PJM region.

~~Gas Supply Revenuesdecreased~~ ~~$182 million due primarily to~~

~~a net decrease of $86 million in sales under the BGSS contract, substantially comprised of~~ lower average sales prices, partially offset by $29 million of higher volumes ~~due to colder average temperatures in the 2015 winter heating season, and~~

~~a decrease of $96 million due to lower average sales prices and volumes to third party customers.~~

~~Other Operating Revenues~~ ~~increased$1 million due to higher fees received from fuel management and power supply management contracts with LIPA.~~sold.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $~~367~~255 million due to

Generation costs decreased ~~$149~~$123 million due primarily to lower fuel costs of $234 million reflecting lower average realized natural gas ~~and oil~~ prices and the utilization of lower volumes of coal, ~~coupled with MTM gains in 2015 as compared to MTM losses in 2014.~~oil and gas. These decreased costs were partially offset by ~~the utilization of higher volumes of natural gas, coupled with~~ higher congestion costs in the PJM ~~region.~~region of $145 million, mainly as a result of credits received in the prior year due to extremely cold weather. Also, lower MTM losses in 2016 resulted in a $20 million decrease.

Gas costs decreased ~~$218~~$132 million mainly related to ~~lower average gas inventory costs on both obligations under the BGSS contract and sales to third parties, coupled with lower volumes sold to third parties. This was partially offset by higher~~a decrease in volumes sold under the BGSS contract ~~due~~coupled with lower average gas costs. Gas costs on sales to ~~colder average temperatures during the 2015 winter heating season.~~third parties were flat.

Operation and Maintenance~~decreased$123~~ increased $81 million due primarily to

~~a decrease~~$128 million of ~~$145 million due to~~ insurance recoveries received in 2015 related to Superstorm Sandy, ~~and~~

partially offset by a net decrease of $48 million related to our fossil plants, largely due to higher costs incurred in ~~2014~~2015 for planned outage costs, including maintenance and installation of upgraded technology at our Linden combined cycle gas generating plant, partially offset by planned outage costs in 2015 at our Bethlehem Energy Center generating plant and installation of upgraded technology at our combined cycle Bergen plant,

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partially offset by an increase of $48 million at our nuclear facilities, primarily due to higher planned outage costs at our 100%-owned Hope Creek and 50%-owned Peach Bottom 3 nuclear plants in 2015 as compared to our 57%-owned Salem nuclear unit 2 in 2014, and

~~a $22 million increase due to higher pension and OPEB costs.~~

~~Depreciation and Amortizationincreased$11 million~~ ~~due primarily to a higher depreciable fossil and nuclear asset base.~~

~~Income from Equity Method Investments~~ ~~experienced no material change.~~major outages.

Other Income and (Deductions) decreased ~~$33~~$10 million due primarily to ~~lower~~higher net realized ~~gains~~losses from the NDT ~~Fund partially offset by a $28 million insurance recovery related to Superstorm Sandy.~~Fund.

Other-Than-Temporary Impairments increased ~~$31~~$5 million due primarily to an increase in impairments of equity securities in the NDT Fund.

Interest Expense ~~experienced no material change.~~decreased $9 million due primarily to the maturity of a $300 million 5.50% Senior Note in December 2015 and higher capitalized interest in 2016.

Income Tax Expense~~increased$168 million~~ decreased $105 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 ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016, our operating cash flow ~~increased~~decreased $~~692~~465 million as compared to the same period in ~~2014.~~2015. The net change was due primarily to the net changes from PSE&G and Power as discussed below.

PSE&G

PSE&G’s operating cash flow ~~increased~~decreased $~~175~~109 million from $~~1,343~~677 million to $~~1,518~~568 million for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016, as compared to the same period in ~~2014~~2015, due primarily to ~~higher earnings, a $203 million reduction in tax payments, $37 million reduction in vendor payments and a $25 million decrease in prepayments. These amounts were partially offset by~~ a decrease of ~~$232~~$83 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

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and ~~Non-Utility Generation charges.~~BGSS clauses, a $42 million decrease in other current assets and liabilities and a $40 million decrease due to vendor payments. These amounts were partially offset by higher earnings and a reduction in tax payments.

Power

Power’s operating cash flow ~~increased~~decreased $~~448~~187 million from $~~1,110~~850 million to $~~1,558~~663 million for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016, as compared to the same period in ~~2014,~~2015, primarily due to ~~higher~~lower earnings and a ~~reduction in margin deposit requirements,~~$141 million decrease for fuel, materials and supplies, partially offset by ~~an increase of $197 million~~a reduction in tax payments.

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 our ~~$4.2~~$4.3 billion credit facilities are provided by a diverse bank group. As of ~~September 30, 2015~~March 31, 2016, our total available credit capacity was ~~$3.9~~$4.0 billion.

As of ~~September 30, 2015~~March 31, 2016, no single institution represented more than 7% of the total commitments in our credit facilities.

As of ~~September 30, 2015~~March 31, 2016, 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; however, if necessary, the PSEG facilities can also be used to support our subsidiaries' liquidity needs. Our total credit facilities and available liquidity as of ~~September 30, 2015~~March 31, 2016 were as follows:

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As of September 30, 2015
Company/Facility
Total
Facility
Usage
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
$ 34
$ 566
Apr 2020 CP Support/Funding/Letters of Credit
Total PSE&G $ 600
$ 34
$ 566

Power
  5-year Credit Facility $ 1,600
$ 201
$ 1,399
Apr 2019 Funding/Letters of Credit
  5-year Credit Facility (C) 1,000
14
986
Apr 2020 Funding/Letters of Credit
Total Power $ 2,600
$ 215
$ 2,385

Total $ 4,200
$ 259
$ 3,941




	As of March 31, 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)	524		12		512		Apr 2020	CP Support/Funding/Letters of Credit
Total PSEG	$	1,024	$	22	$	1,002
PSE&G
5-year Credit Facility (B)	$	629	$	14	$	615	Apr 2020	CP Support/Funding/Letters of Credit
Total PSE&G	$	629	$	14	$	615
Power
5-year Credit Facility	$	1,600	$	202	$	1,398	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	1,000		9		991		Apr 2020	Funding/Letters of Credit
Total Power	$	2,600	$	211	$	2,389
Total	$	4,253	$	247	$	4,006

~~(A)PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018.~~

~~(B)PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018.~~


(A)	PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018; PSEG's 2020 credit facility was increased by $24 million in March 2016 in anticipation of the April expiration.


(B)	PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018; PSE&G's 2020 facility was increased by $29 million in March 2016 in anticipation of the April expiration.

(C)Power facility will be reduced by $48 million in April 2016 and $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 under which as of March 31, 2016, PSEG had $12 million outstanding at a weighted average interest rate of 0.65%. PSE&G had no amounts outstanding under its CP Program as of March 31, 2016.

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Long-Term Debt Financing

~~PSE&G has $171 million of 6.75% Mortgage Bonds maturing in January 2016.~~ Power has ~~$300 million of 5.50% Senior Notes maturing in December 2015 and~~ $303 million of 5.32% Senior Notes and $250 million of 2.75% Senior Notes maturing in September 2016.

For a discussion of our long-term debt transactions during ~~2015,~~2016, see Item 1. Note 9. Changes in Capitalization.

Common Stock Dividends

On ~~July 21, 2015,~~February 16, 2016, our Board of Directors approved a ~~$0.39~~$0.41 per share common stock dividend for the ~~third~~first quarter of ~~2015.~~2016. On April 19, 2016, our Board of Directors declared a quarterly dividend of $0.41 per share of common stock for the second quarter of 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 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, S&P published 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 Power and the mortgage bond rating of A at PSE&G. In September 2015,March 2016, Moody's published an updated research report on ~~PSEG~~Power and ~~revised~~ the existing rating and outlook ~~to positive from stable. In September and October 2015, Fitch published full rating reports on PSEG and Power leaving ratings and outlooks~~were unchanged. ~~As of October 2015, PSEG has ended a contractual agreement with Fitch to provide credit rating services for PSEG, PSE&G and Power.~~

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	Moody’s (A)	S&P (B)
PSEG
Outlook	Positive	Stable
Commercial Paper	P2	A2
PSE&G
Outlook	Stable	Stable
Mortgage Bonds	Aa3	A
Commercial Paper	P1	A2
Power
Outlook	Stable	Stable
Senior Notes	Baa1	BBB+


(A)	Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.


(B)	S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. The Corporate Credit Rating outlook does not apply to PSEG's or PSE&G's Commercial Paper Rating or PSE&G's Mortgage Bond rating.

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CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing.

In September 2015, we reached a settlement in principle with the BPU Staff and the New Jersey Division of Rate Counsel regarding our GSMP, through which, if approved, we will invest $905 million over the next three years 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 aforementioned estimated project expenditures related to the GSMP at PSE&G and the Maryland and Woodbridge, New Jersey projects 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 PSE&G, Power and Services as compared to amounts disclosed in our ~~2014~~2015 Form 10-K.

PSE&G

During the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, PSE&G made capital expenditures of ~~$1,946~~$724 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$82~~$35 million, which are included in operating cash flows.

Power

During the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016, Power made capital expenditures of ~~$597~~$283 million, excluding $~~200~~50 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 ~~July~~January through ~~September 2015,~~March 2016, MTM VaR remained relatively stable between low of $8$11 million to high of ~~$14~~$25 million at 95% confidence level. The range of VaR was narrower for the three months ended ~~September 30, 2015~~March 31, 2016 as compared with the year ended December 31, ~~2014.~~2015.

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MTM VaR
Three Months Ended September 30, 2015 Year Ended December 31, 2014
Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End $ 10
$ 36

Average for the Period $ 10
$ 30

High $ 14
$ 195

Low $ 8
$ 14

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 16
$ 56

Average for the Period $ 15
$ 46

High $ 23
$ 306

Low $ 12
$ 22




	MTM VaR
	Three Months Ended March 31, 2016		Year Ended December 31, 2015
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	11	$	24
Average for the Period	$	17	$	17
High	$	25	$	40
Low	$	11	$	8
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	17	$	38
Average for the Period	$	27	$	26
High	$	40	$	63
Low	$	17	$	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 ~~third~~first 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~~ see Part I, Item 1. Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.

Environmental Matters

The following updates information previously reported in Item 3 of Part I of the 2015 Annual Report on Form 10-K.

(1)

Claim by the EPA, Region III, under CERCLA with respect to the Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and the former and current site owners are alleged to be liable for contamination at the site and PSE&G has been named as a Potentially Responsible Party (PRP). The EPA approved the Final Revised Remedial Design for the Site in early 2008. This document presented the design details of the EPA’s selected remedy. PSE&G and other utility companies as members of a PRP group entered into a Consent Decree and agreed to implement

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the negotiated EPA selected remedy. The EPA settled its claims against the site owners who did not join the Consent Decree to implement the remedy. The PRP group’s implementation of the remedy was completed in 2010; however, an additional estimated cost of $200,000 will be incurred by PSE&G in 2016 to repair part of the remedy. Although the PRP Group has not received a formal Certification of Completion of the Remedy from the EPA, the PRP Group does not anticipate further significant costs at this time. Although subject to EPA approval and oversight, long-term monitoring, operations, and maintenance activities are anticipated through 2018 at a total estimated cost to PSE&G of $200,000.


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 ~~third~~first quarter of ~~2015~~2016.

Three Months Ended September 30, 2015
Total Number
of Shares
Purchased

Average
Price Paid
per Share

July 1 - July 31 —
$ —

August 1- August 31 189,018
$ 42.23

September 1- September 30 20,000
$ 38.97




Three Months Ended March 31, 2016	Total Number of Shares Purchased	Average Price Paid per Share
January 1 - January 31	—	$	—
February 1- February 29	621,983	$	43.62
March 1- March 31	493,764	$	42.92

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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 quarters ended March 31, 2015 and June 30, 2015.~~10-K. References are to the related pages on the ~~Forms~~Form 10-K ~~and 10-Q~~ as printed and distributed.

Employee Relations

December 31, 2015 Form 10-K page 16. During the first quarter of 2016, four of PSEG's eight labor unions ratified the extension of their respective collective bargaining agreements with PSEG for four years effective May 1, 2017. Collectively, these unions represent approximately 75 percent of PSEG's total union employees. Therefore, as of March 31, 2016, our collective bargaining agreements will expire in November 2016 with one union, in October 2017 with two unions, in May 2018 with one union and in April 2021 with four unions. We believe we maintain satisfactory relationships with our employees.

Federal Regulation

FERC

~~Regulation of Wholesale Sales—Generation/Market Issues~~

Capacity Market Issues—PJM

December 31, ~~2014~~2015 Form 10-K page ~~16, March~~17. 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) recently 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. The subsidies under these contracts 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 suppress capacity market prices, especially given that PJM’s currently effective “minimum offer price rule” (MOPR) which applies only to new gas-fired units would not apply to these plants. 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. 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.

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Capacity Market Issues—ISO-New England

December 31, 2015 Form ~~10-Q~~10-K page ~~69 and June 30,~~18. In March 2015, ~~Form 10-Q page 78~~. ~~The RPM is~~in conjunction with other companies, we filed a petition for review with the ~~locational installed~~D.C. Court of FERC's ruling accepting the exemption from the MOPR in the capacity market ~~design~~afforded for ~~the PJM region, including a forward auction for installed capacity.~~

up to 200 MW annually (600 MW cumulatively) of renewable resources. On December ~~12, 2014, PJM~~1, 2015, following a request by FERC for a voluntary remand of the order, the D.C. Court remanded the case to FERC for additional consideration. However, on April 8, 2016, FERC issued an order reinstating the exemption. We are currently in the process of analyzing this development.

In December 2015, ISO-NE filed a proposal atthat would allow resource owners to submit bids into the capacity auction reflecting their desire to retire a resource. In April 2016, FERC to implement a Capacity Performance (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, FERC conditionally accepted the ~~CP mechanism which will be phased in over~~proposal subject to a compliance filing by ISO-NE. We remain concerned that 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 was implemented for the 2015 base residual auction (covering the 2018-2019 Delivery Year) which concluded on August 21, 2015. The CP product will be implemented fully for the 2020-2021 Delivery Year. Based upon the August 2015 base residual 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, therenew rules may be ~~requirements for additional investment and there are additional performance risks.~~

~~On June 30, 2015, a consumer coalition filed a complaint requesting that the load forecast that PJM was currently analyzing and updating~~disruptive to determine the amount of capacity it would procure in the 2016 base residual auction be implemented immediately for the upcoming 2015 transition auctions and base residual auction. FERC did not address the complaint prior to the auctions, effectively denying it.

~~Price Formation Initiatives~~

Power has been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for setting prices for energy in the day-ahead and real-time markets administered by PJM and other system operators. A recent development which we consider positive involves a September 17, 2015 FERC notice of proposed rulemaking on two issues: aligning settlements with dispatch intervals (more granular “5-minute pricing” in real-time markets) and improving real-time scarcity pricing. Comments made by FERC commissioners stressed these two items are intended to be the first of a series of steps FERC will take on energyefficient price formation in the ~~future.~~capacity market.

Reactive Power Rates

December 31, 2015 Form 10-K page 19. 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. ~~The rates were last adjusted~~Following settlement discussions with FERC Trial Staff, Power agreed to accept an overall rate of $34 million per year, which FERC approved in ~~2008 and since that time various generating units have been de-activated, activated or improved with the net impact supportive of an upward rate adjustment.~~February 2016. FERC ~~accepted Power’s rate filing increase to become effective in January 2016, subject to refund, hearing and settlement procedures. FERC also~~had earlier referred the filing to the FERC Office of Enforcement for its ~~evaluation. Power has participated in two settlement conferences to date with the FERC trial staff.~~evaluation, which remains pending.

Long-Term Capacity Agreement Pilot Program Act (LCAPP)

December 31, ~~2014~~2015 Form 10-K page ~~18.~~21. In 2011, the State of New Jersey enacted the LCAPP to subsidize approximately 2,000 MW of new natural gas-fired generation. The LCAPP provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey EDCs.

In 2013, the U.S. District Court in New Jersey found that the LCAPP was unconstitutional and declared the LCAPP null and void. This federal court decision was subsequently challenged on appeal in the U.S. Third Circuit Court of ~~Appeals.~~Appeals (Third Circuit). The State of Maryland also took similar action to subsidize above-market new generation. This action was also determined to be unconstitutional in 2013 in the U.S. District Court in Maryland and such decision was challenged in the U.S. Fourth Circuit Court of ~~Appeals.~~Appeals (Fourth Circuit). Both appeals were denied, with the U.S. Fourth Circuit Court of Appeals (Fourth Circuit) denying the appeal regarding the State of Maryland’s action in June 2014 and the U.S. Third Circuit Court of Appeals denying the LCAPP appeal in September 2014.denied. These denials ~~have been~~were challenged on appeal to the U.S. Supreme Court. ~~In October 2015,~~On April 19, 2016, the U.S. Supreme Court ~~announced that it would consider~~issued its ruling upholding the Fourth Circuit decision. 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. On April 25, 2016, the U.S. Supreme Court denied the request to hear the appeal of the ~~Fourth Circuit's decision involving Maryland. The U.S. Supreme Court is expected to consider this case in 2016. We cannot predict the outcome of this appeal.~~

Third Circuit decision.

~~table of contents~~

Transmission ~~Regulation—~~Regulation—Transmission Policy Developments

December 31, ~~2014~~2015 Form 10-K page ~~18, March 31, 2015 Form 10-Q page 70 and June 30, 2015 Form 10-Q page 78.~~19.

In April 2013, PJM initiated its 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 at Artificial Island ~~off the shore of~~in New Jersey. In April ~~2015, the PJM staff advised stakeholders that it intended to recommend a transmission project to the PJM Board of Managers consisting of various components to be constructed by LS Power,~~2016, PSE&G ~~and Potomac Holding Company. On July 29, 2015,~~accepted construction responsibility for the ~~PJM Board approved the PJM staff's recommendation. In August 2015, PJM sent PSE&G a Construction Responsibility Letter (to which PSE&G will be responding on November 9) awarding PSE&G~~ three components of the project ~~estimated by~~that PJM assigned to ~~cost approximately $126 million. PSE&G is currently in discussions~~it, based on having reached agreement with PJM regarding an estimate for the ~~accuracy~~project base cost of ~~this estimate given the complexities associated with construction work at Artificial Island. In~~$273 million, plus risk and contingency for a ~~related matter, FERC denied a complaint filed by~~total project cost of up to $340 million. PSE&G ~~contending that PJM had failed to follow its rules during the Artificial Island solicitation process. PSE&G, however,~~ continues to work with ~~both~~ PJM to optimize the scope and ~~its stakeholders~~cost of the project.

On April 1, 2016, PJM filed at FERC to incorporate a voltage threshold into PJM’s 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 ~~rules governing~~efficiency of the open window ~~processes in PJM.~~

In November 2014, Con Edison had brought a complaint against PJM at FERC challenging PJM's allocation of costs for two PSE&G projects in northern New Jersey, including the Bergen-Linden Corridor Project (BLC). In June 2015, FERC issued an order dismissing the complaint. Con Edison and a merchant generator have sought judicial review of certain aspects of FERC’s order and Con Edison has filed a rehearing request with FERC.

There have been developments on several additional matters involving cost allocation issues. In May 2015 and as amended in July 2015, a merchant transmission operator filed a complaint against PJM challenging PJM’s allocation of costs for four PSE&G projects, including BLC. PSE&G filed opposition to the complaint and the matter is currently pending at FERC. In August 2015, the Delaware Public Service Commission and the Maryland Public Service Commission filed a complaint against PJM and certain transmission owners that have voting rights over cost allocation and rate design, including PSE&G, alleging that PJM tariff provisions allocate an excessive share of the Artificial Island project costs to them relative to the actual benefits of the project to residents of Delaware and Maryland. PSE&G intends to participate in a group filing of transmission ownersprocedure that will ~~oppose~~permit transmission developers to focus on the ~~complaint.~~projects most likely to benefit from a competitive process.

In June 2015, a transmission developer filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. According to 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 named as a respondent in the complaint, PSE&G is identified as one of the companies claimed to have been involved. ~~In July~~The developer subsequently amended its complaint to add additional claims. Motions are pending before FERC seeking to dismiss both the original and the amended complaint. We are unable to predict the outcome of these proceedings.

There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G contending that insufficient levels of costs are being allocated to PSE&G. Projects involved include the Artificial Island project, the Bergen-Linden project in New Jersey and a smaller project in Sewaren, New Jersey. On April 22, 2016, FERC issued orders denying the complaints and leaving the current cost allocation in effect as to the Artificial Island and Bergen-Linden projects. Due to an intervening FERC order concerning the allocation of costs for 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.

Table of Contents

Compliance—Reliability Standards

December 31, 2015 ~~PJM filed~~Form 10-K page 21. FERC is considering whether to direct the North American Electric Reliability Council (NERC) to develop a ~~response, which included a supporting affidavit from PSE&G, contesting~~new reliability standard to provide security controls for supply chain management associated with the ~~allegations. The matter is pending.~~procurement of industrial control system hardware, software, and services related to bulk electric system operations. If adopted, compliance with these new standards would be expected to impose additional obligations and costs on transmission providers.

State Regulation

~~Gas System Modernization Program (GSMP)~~BPU Cybersecurity Requirements for Regulated Entities

In March ~~31, 2015 Form 10-Q page 71.~~ ~~In September 2015,~~2016, the BPU issued an Order for the regulated electric, natural gas, and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The Order requires these regulated utilities, including PSE&G, ~~reached~~to implement a ~~settlement in principle with the BPU Staff~~cybersecurity program that defines and ~~the~~ implements organization accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems.

New Jersey ~~Division of Rate Counsel regarding PSE&G’s GSMP through which, if approved,~~utilities, including PSE&G, ~~will invest $905 million over~~are required to be compliant with these requirements by October 31, 2017. We are currently evaluating the ~~next three years to modernize its gas system. The settlement in principle will enable the utility to replace up to 510 miles of gas mains and 38,000 service lines over~~requirements. For a ~~three-year period, with cost recovery at a 9.75% rate of return on equity on the first $650 million~~discussion of the ~~investment through an accelerated recovery mechanism. Under the settlement~~risks associated with cyber threats, see Part I, Item 1A. Risk Factors—"Cyber security attacks or intrusions could adversely impact our businesses." in ~~principle, PSE&G will seek recovery of the remaining $255 million of investment in its next base rate case, which is to be filed no later than November 1, 2017.~~our 2015 Annual Report on

~~Connecticut Rate Filing~~

~~June 30, 2015~~ Form ~~10-Q page 79.~~ In June 2015, Power’s subsidiary PSEG New Haven LLC, filed a mandatory annual rate case with the Connecticut Public Utilities Regulatory Authority (PURA) for recovery of its costs and investment in its Connecticut-based peaking unit. Power requested 2016 revenues of $22 million. On October 22, 2015, PURA issued a Proposed Final Decision to approve the entirety of Power’s request. A Final Decision is expected to be issued on November 4, 2015.10-K.

~~table of contents~~

Environmental Matters

Air Pollution Control

~~Demand Response (DR) Reciprocating Internal Combustion Engines (RICE) Litigation~~Hazardous Air Pollutants Regulation

December 31, ~~2014~~2015 Form 10-K page 2324. In February 2012, theEnvironmental Protection Agency(EPA) published Mercury Air Toxics Standards (MATS) for both newly-built and ~~June 30, 2015 Form 10-Q page 79.~~ I~~n March 2013, Power filed a petition at the EPA challenging~~existing electric generating sources under the National Emission ~~Standards~~Standard for Hazardous Air Pollutants (NESHAP) provisions of the CAA. The MATS established allowable levels for ~~RICE issued~~mercury as well as other hazardous air pollutants and went into effect in ~~January 2013. Among other things,~~April 2015. In June 2015, the ~~final EPA rule includes two exemptions~~U.S. Supreme Court held 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~~it was unreasonable 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 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~~to refuse to consider the ~~March 2013 petition~~materiality of costs in determining whether to regulate hazardous air pollutants from power plants and ~~in October 2014, Power appealed~~remanded the ~~EPA's denial~~matter back to the D.C. Court. On ~~May 1,~~December 15, 2015, the D.C. Court ~~vacated~~remanded the 100 hour exemption but thereafter granted a stay until May 1, 2016. On September 23, 2015, the D.C. Court granted the EPA's motion for voluntary remand of the 50 hour exemption provision to the EPA. While both provisions remain in place, the EPA will undergo proceedings to address the D.C. Court's orders. We believe that the impact of the D.C. Court's rulings would likely benefit Power's and its competitors' operations of their power generation peaking units.

~~Ozone Standard~~

~~March 31, 2015 Form 10-Q page 71.~~ In December 2014, the EPA proposed a rule to lower the ambient air quality standard for the level of ozone in the atmosphere from 75 parts per billion (ppb) to a level in the range of 65-70 ppb. On October 1, 2015, the EPA finalized a standard of 70 ppb. To meet the new standard, the EPA and the states have to implement additional emission reduction strategies for NO_X and volatile organic compounds. Some portions of the Mid-Atlantic and New England states are not expected to be able to meet the new standard. Although the majority of our fossil generating units employ state-of-the-art NO_X emission controls, we cannot predict the outcome of this matter since new requirements of the EPA and the states are unknown at this time. A coal mining company has filed a petition for review with the D.C. Court to challenge the rule.

~~Climate Change~~

~~CO2 Regulation Under the Clean Air Act (CAA)~~

~~December 31, 2014 Form 10-K page 23, March 31, 2015 Form 10-Q page 72 and June 30, 2015 Form 10-Q page 80.~~ On October 23, 2015, the EPA published the Clean Power Plan (CPP), a 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 three components: (i) heat rate improvements at existing coal-fired power plants, (ii) increased use of existing natural gas combined cycle capacity, and (iii) operation of incremental zero-emitting generation (renewables and nuclear). States may choose these or other methodologies to achieve the necessary reductions of CO₂ ~~emissions.~~

~~Each state must submit a compliance plan~~MATS to the EPA ~~by September 6,~~without vacating the rule. On April 15, 2016, ~~or seek a two-year extension to September 6, 2018. States can comply using an emission rate-based plan (pounds CO~~₂~~/MWh) or a mass-based plan (tons). Compliance with~~the EPA released the final ~~rule is effective January 1, 2022.~~

~~The EPA, FERC and~~Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to the U.S. Department of Energy announced that they plan to meet at least quarterly to evaluate states' plans and identify reliability concerns so adjustments can be made before the final plans are submitted. The agencies are engaging various stakeholders, including the Regional Transmission Operators/Independent System Operators. The agencies will continue to meet after the states' plans are in effect to assess if revisions are required.

~~On October 23, 2015, the EPA also published proposed federal implementation requirements for states that~~Supreme Court's June ruling. We do not ~~submit an EPA-approved compliance plan. Comments are due by January 21, 2016.~~

~~Numerous states, including New Jersey, and several industry groups have filed petitions for review with the D.C. Court~~expect this Supplemental Finding to ~~challenge~~ ~~the CPP.~~ ~~In addition, the petitioners are seeking a stay~~impact operation of ~~the rule.~~ our facilities.

~~Water Pollution Control~~

~~Steam Electric Effluent Guidelines~~

~~December 31, 2014 Form 10-K page 24.~~ 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 has two electric generation facilities, its dual-

~~table~~Table of ~~contents~~Contents

fuel (gas/coal) Mercer station in New Jersey and coal-fired Bridgeport Harbor station in Connecticut, that have bottom ash transport water discharges that are regulated under this rule. We are unable to predict if these new standards will have a material impact on Power's future capital requirements, financial condition or results of operations.

~~Cooling Water Intake Structure Regulation~~

~~December 31, 2014 Form 10-K page 25 and June 30, 2015 Form 10-Q page 80.~~ On June 30, 2015, the NJDEP issued a draft permit for Salem. 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 with certain required system modifications. The draft permit is subject to a sixty-day public notice and comment period. We participated in the NJDEP’s August 5, 2015 public hearing and submitted comments on the draft permit on September 18, 2015.~~The NJDEP may make revisions before issuing the final permit expected in the first half of 2016. 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 and June 30, 2015 Form 10-Q page 80.~~ 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. 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. Some states, including New Jersey, are subject to state requirements beyond those imposed under federal law. While we do not anticipate material impacts to projects in New Jersey, the new definition could impose requirements in other states and regions that could impact the development of renewables.

Various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the final rule. On October 9, 2015, the Sixth Circuit Court of Appeals issued a stay of the rule pending further court action.

~~table of contents~~


ITEM 6.	EXHIBITS

A listing of exhibits being filed with this document is as follows:



a. PSEG:
~~Exhibit 10~~		~~Employment Agreement with Daniel J. Cregg. dated September 22, 2015~~
Exhibit 12:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

b. PSE&G:
Exhibit 10		~~Employment Agreement with Daniel J. Cregg, dated September 22, 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 Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

c. Power:
Exhibit 10		~~Employment Agreement with Daniel J. Cregg, dated September 22, 2015~~
~~Exhibit 12.3:~~12.2:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.4:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.4:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.5:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

~~table~~Table of ~~contents~~Contents

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.



PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: ~~October 30, 2015~~April 29, 2016

~~table~~Table of ~~contents~~Contents

SIGNATURE



PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: ~~October 30, 2015~~April 29, 2016

~~table~~Table of ~~contents~~Contents

SIGNATURE



PSEG POWER LLC
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: ~~October 30, 2015~~April 29, 2016

8776



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




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
OPERATING REVENUES	$	2,688		$	2,641		$	8,137		$	8,113
OPERATING EXPENSES
Energy Costs	815			863			2,577			3,008
Operation and Maintenance	746			714			2,170			2,370
Depreciation and Amortization	313			318			960			919
Total Operating Expenses	1,874			1,895			5,707			6,297
OPERATING INCOME	814			746			2,430			1,816
Income from Equity Method Investments	3			3			10			10
Other Income	47			75			171			185
Other Deductions	(14		)	(9		)	(36		)	(31		)
Other-Than-Temporary Impairments	(30		)	(10		)	(45		)	(14		)
Interest Expense	(96		)	(100		)	(291		)	(291		)
INCOME BEFORE INCOME TAXES	724			705			2,239			1,675
Income Tax Expense	(285		)	(261		)	(869		)	(633		)
NET INCOME	$	439		$	444		$	1,370		$	1,042
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			506			505			506
DILUTED	508			507			508			507
NET INCOME PER SHARE:
BASIC	$	0.87		$	0.88		$	2.71		$	2.06
DILUTED	$	0.87		$	0.87		$	2.70		$	2.05
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.39		$	0.37		$	1.17		$	1.11




	September 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	271		$	402
Accounts Receivable, net of allowances of $59 and $52 in 2015 and 2014, respectively	1,199			1,254
Tax Receivable	5			211
Unbilled Revenues	203			284
Fuel	451			538
Materials and Supplies, net	472			484
Prepayments	180			108
Derivative Contracts	162			240
Deferred Income Taxes	23			11
Regulatory Assets	189			323
Regulatory Assets of Variable Interest Entities (VIEs)	—			249
Restricted Cash of VIEs	26			—
Other	23			15
Total Current Assets	3,204			4,119
PROPERTY, PLANT AND EQUIPMENT	34,625			32,196
Less: Accumulated Depreciation and Amortization	(9,020		)	(8,607		)
Net Property, Plant and Equipment	25,605			23,589
NONCURRENT ASSETS
Regulatory Assets	3,161			3,192
Long-Term Investments	1,235			1,307
Nuclear Decommissioning Trust (NDT) Fund	1,715			1,780
Long-Term Tax Receivable	165			64
Long-Term Receivable of VIE	601			580
Other Special Funds	230			212
Goodwill	16			16
Other Intangibles	122			84
Derivative Contracts	91			77
Restricted Cash of VIEs	—			24
Other	279			289
Total Noncurrent Assets	7,615			7,625
TOTAL ASSETS	$	36,424		$	35,333




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating (Standard & Poor's (S&P))	As of
As of September 30, 2015	September 30, 2015
	Millions
AA	$	17
BBB+ — BBB-	316
BB-	134
B-	164
Total	$	631




	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	$	440
Enrichment	$	345
Fabrication	$	179
Natural Gas	$	1,001
Coal	$	331




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

	Nine Months Ended September 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2015		Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out		Balance as of September 30, 2015
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	37	$	12	$	(29	)	$	—	$	(18	)	$	—	$	2
PSE&G
Net Derivative Assets (Liabilities)	$	26	$	—	$	(29	)	$	—	$	—		$	—	$	(3	)
Power
Net Derivative Assets (Liabilities)	$	11	$	12	$	—		$	—	$	(18	)	$	—	$	5




	Three Months Ended September 30, 2014
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2014			Included in Income (E)			Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of September 30, 2014
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	13		$	(8	)	$	(9	)	$	—	$	(4	)	$	—		$	(8	)
PSE&G
Net Derivative Assets (Liabilities)	$	22		$	—		$	(9	)	$	—	$	—		$	—		$	13
Power
Net Derivative Assets (Liabilities)	$	(9	)	$	(8	)	$	—		$	—	$	(4	)	$	—		$	(21	)

	Nine Months Ended September 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 September 30, 2014
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	88		$	(66	)	$	(81	)	$	—	$	54		$	(3	)	$	(8	)
PSE&G
Net Derivative Assets (Liabilities)	$	94		$	—		$	(81	)	$	—	$	—		$	—		$	13
Power
Net Derivative Assets (Liabilities)	$	(6	)	$	(66	)	$	—		$	—	$	54		$	(3	)	$	(21	)




	Three Months Ended September 30,								Nine Months Ended September 30,
	2015				2014				2015				2014
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions)
Net Income	$	439	$	439	$	444	$	444	$	1,370	$	1,370	$	1,042	$	1,042
EPS Denominator (Millions)
Weighted Average Common Shares Outstanding	505		505		506		506		505		505		506		506
Effect of Stock Based Compensation Awards	—		3		—		1		—		3		—		1
Total Shares	505		508		506		507		505		508		506		507

EPS
Net Income	$	0.87	$	0.87	$	0.88	$	0.87	$	2.71	$	2.70	$	2.06	$	2.05




	MTM VaR
	Three Months Ended September 30, 2015		Year Ended December 31, 2014
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	10	$	36
Average for the Period	$	10	$	30
High	$	14	$	195
Low	$	8	$	14
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	16	$	56
Average for the Period	$	15	$	46
High	$	23	$	306
Low	$	12	$	22