NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and nine months ended ~~March 31,~~September 30, 2016 and ~~March 31,~~September 30, 2015, respectively, follows:

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

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

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of January 1, 2016
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of 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




	Three Months Ended September 30, 2016
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2016			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	5		$	8	$	(2	)	$	4	$	(4	)	$	—	$	11
PSE&G
Net Derivative Assets (Liabilities)	$	(2	)	$	—	$	(2	)	$	—	$	—		$	—	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	7		$	8	$	—		$	4	$	(4	)	$	—	$	15

	Nine Months Ended September 30, 2016
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2016
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	13		$	24	$	(6	)	$	4	$	(24	)	$	—	$	11
PSE&G
Net Derivative Assets (Liabilities)	$	2		$	—	$	(6	)	$	—	$	—		$	—	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	11		$	24	$	—		$	4	$	(24	)	$	—	$	15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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

for the Three Months and Nine Months Ended~~March 31,~~ 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 (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




	Three Months Ended September 30, 2015
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2015		Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		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 (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		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

(A)

PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include ~~$15~~$8 million and $3$24 million in Operating Income infor the three months and nine months ended September 30, 2016, ~~and 2015,~~ respectively. ~~The $15~~Of the $8 million in Operating Income, ~~in 2016~~$4 million is ~~realized. Of the $3~~unrealized. The $24 million in Operating Income ~~$(9) million~~ is ~~unrealized.~~realized.

~~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.


(C)	Represents ~~$(15)~~$(4) million and ~~$(12)~~$(24) million in settlements for the three months and nine months ended ~~March 31,~~September 30, 2016, respectively. Represents $(2) million and ~~2015.~~$(18) million in settlements for the three months and nine months ended September 30, 2015, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents


(D)	There were no transfers among levels during the three months and nine months ended ~~March 31,~~September 30, 2016 and 2015.


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

As of ~~March 31,~~September 30, 2016, PSEG carried ~~$2.8~~$2.6 billion of net assets that are measured at fair value on a recurring basis, of which ~~$21~~$11 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of ~~March 31,~~September 30, 2015, PSEG carried $~~3.1~~2.3 billion of net assets that are measured at fair value on a recurring basis, of which $92 million of net ~~liabilities~~assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

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

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




	As of				As of
	September 30, 2016				December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	500	$	500	$	503	$	506
PSE&G (B)	7,816		8,996		6,821		7,235
Power - Recourse Debt (B)	2,381		2,788		2,237		2,508
Energy Holdings:
Project Level, Non-Recourse Debt (C)	—		—		7		7
Total Long-Term Debt	$	10,697	$	12,284	$	9,568	$	10,256

(A)

Fair value 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 includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.

(B)

Given that most bonds do not trade, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.


(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

(UNAUDITED)

Table of Contents ~~(UNAUDITED)~~

Note ~~12.~~13. Other Income and Deductions

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




Other Income	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	21	$	—	$	21
Allowance for Funds Used During Construction	14		—		—		14
Solar Loan Interest	6		—		—		6
Other	2		2		2		6
Total Other Income	$	22	$	23	$	2	$	47
Nine Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	69	$	—	$	69
Allowance for Funds Used During Construction	35		—		—		35
Solar Loan Interest	17		—		—		17
Other	9		5		4		18
Total Other Income	$	61	$	74	$	4	$	139
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

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




Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended September 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	5	$	—	$	5
Other	1		1		1		3
Total Other Deductions	$	1	$	6	$	1	$	8
Nine Months Ended September 30, 2016
NDT Fund Realized Losses and Expenses	$	—	$	31	$	—	$	31
Other	3		2		3		8
Total Other Deductions	$	3	$	33	$	3	$	39
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


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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note ~~13.~~14. Income Taxes

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

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




	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2016	2015	2016	2015
PSEG	36.5%	39.4%	36.3%	38.8%
PSE&G	36.1%	38.2%	36.1%	38.7%
Power	39.3%	40.3%	39.4%	38.6%

For the three months and nine months ended ~~March 31,~~September 30, 2016, the overall decreases in ~~PSEG's and PSE&G's~~PSEG’s effective tax rates as compared to the same periods in the prior year as well as to the statutory tax rate of 40.85%, were due primarily to ~~depreciation flow through items and~~ changes in uncertain tax ~~positions.~~positions and plant related items.

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

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Table of 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note ~~14.~~15. Accumulated Other Comprehensive Income (Loss), Net of Tax

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 )




PSEG	Other Comprehensive Income (Loss)
	Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2016	$	1		$	(370	)	$	117		$	(252	)
Other Comprehensive Income before Reclassifications	1			—			26			27
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			9			(2		)	7
Net Current Period Other Comprehensive Income (Loss)	1			9			24			34
Balance as of September 30, 2016	$	2		$	(361	)	$	141		$	(218	)

PSEG	Other Comprehensive Income (Loss)
	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	)

PSEG	Other Comprehensive Income (Loss)
	Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(386	)	$	91		$	(295	)
Other Comprehensive Income before Reclassifications	2			—			44			46
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			25			6			31
Net Current Period Other Comprehensive Income (Loss)	2			25			50			77
Balance as of September 30, 2016	$	2		$	(361	)	$	141		$	(218	)

PSEG	Other Comprehensive Income (Loss)
	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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents ~~(UNAUDITED)~~

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 )




Power	Other Comprehensive Income (Loss)
	Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2016	$	—		$	(313	)	$	112		$	(201	)
Other Comprehensive Income before Reclassifications	—			—			24			24
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			7			(2		)	5
Net Current Period Other Comprehensive Income (Loss)	—			7			22			29
Balance as of September 30, 2016	$	—		$	(306	)	$	134		$	(172	)

Power	Other Comprehensive Income (Loss)
	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	)

Power	Other Comprehensive Income (Loss)
	Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2015	$	—		$	(327	)	$	87		$	(240	)
Other Comprehensive Income before Reclassifications	—			—			40			40
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			21			7			28
Net Current Period Other Comprehensive Income (Loss)	—			21			47			68
Balance as of September 30, 2016	$	—		$	(306	)	$	134		$	(172	)

Power	Other Comprehensive Income (Loss)
	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	)

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2016
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2

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

Realized Losses Other Deductions (17 ) 8
(9 )
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

(UNAUDITED)

Table of Contents ~~(UNAUDITED)~~

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
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




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2016									September 30, 2016
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	3		$	(2	)	$	1		$	9		$	(4	)	$	5
Amortization of Actuarial Loss	O&M Expense	(17		)	7			(10		)	(51		)	21			(30		)
Total Pension and OPEB Plans		(14		)	5			(9		)	(42		)	17			(25		)
Available-for-Sale Securities
Realized Gains	Other Income	13			(6		)	7			41			(20		)	21
Realized Losses	Other Deductions	(5		)	3			(2		)	(29		)	15			(14		)
Other-Than-Temporary Impairments (OTTI)	OTTI	(5		)	2			(3		)	(25		)	12			(13		)
Total Available-for-Sale Securities		3			(1		)	2			(13		)	7			(6		)
Total		$	(11	)	$	4		$	(7	)	$	(55	)	$	24		$	(31	)

Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations March 31, 2016
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2

Amortization of Actuarial Loss O&M Expense (15 ) 6
(9 )
Total Pension and OPEB Plans (12 ) 5
(7 )
Available-for-Sale Securities
Realized Gains Other Income 15
(8 ) 7

Realized Losses Other Deductions (16 ) 8
(8 )
OTTI OTTI (10 ) 5
(5 )
Total Available-for-Sale Securities (11 ) 5
(6 )
Total $ (23 ) $ 10
$ (13 )




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
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	3			(1		)	2			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		)
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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents ~~(UNAUDITED)~~

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
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




Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2016									September 30, 2016
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	$	3		$	(1	)	$	2		$	8		$	(3	)	$	5
Amortization of Actuarial Loss	O&M Expense	(15		)	6			(9		)	(44		)	18			(26		)
Total Pension and OPEB Plans		(12		)	5			(7		)	(36		)	15			(21		)
Available-for-Sale Securities
Realized Gains	Other Income	12			(5		)	7			37			(18		)	19
Realized Losses	Other Deductions	(4		)	2			(2		)	(26		)	13			(13		)
OTTI	OTTI	(5		)	2			(3		)	(25		)	12			(13		)
Total Available-for-Sale Securities		3			(1		)	2			(14		)	7			(7		)
Total		$	(9	)	$	4		$	(5	)	$	(50	)	$	22		$	(28	)




Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									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
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Energy-Related Contracts	Operating Revenues	$	—		$	—		$	—		$	17		$	(7	)	$	10
Total Cash Flow Hedges		—			—			—			17			(7		)	10
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense	3			(1		)	2			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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note ~~15.~~16. 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 ~~PSEG's~~PSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:

Three Months Ended March 31,
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




	Three Months Ended September 30,								Nine Months Ended September 30,
	2016				2015				2016				2015
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	327	$	327	$	439	$	439	$	985	$	985	$	1,370	$	1,370
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505		505		505		505		505
Effect of Stock Based Compensation Awards	—		3		—		3		—		3		—		3
Total Shares	505		508		505		508		505		508		505		508

EPS
Net Income	$	0.65	$	0.64	$	0.87	$	0.87	$	1.95	$	1.94	$	2.71	$	2.70

There were approximately ~~0.3 million and~~ 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months and nine months ended ~~March 31,~~September 30, 2016 and ~~2015, respectively.~~2015.




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Dividend Payments on Common Stock	2016		2015		2016		2015
Per Share	$	0.41	$	0.39	$	1.23	$	1.17
In Millions	$	207	$	198	$	622	$	592

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of 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.~~17. Financial Information by Business Segment

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




	PSE&G		Power		Other (A)			Eliminations (B)			Consolidated
	Millions
Three Months Ended September 30, 2016
Total Operating Revenues	$	1,684	$	1,075	$	7		$	(316	)	$	2,450
Net Income (Loss)	255		139		(67		)	—			327
Gross Additions to Long-Lived Assets	680		325		9			—			1,014
Nine Months Ended September 30, 2016
Operating Revenues	$	4,746	$	3,102	$	256		$	(1,133	)	$	6,971
Net Income (Loss)	696		320		(31		)	—			985
Gross Additions to Long-Lived Assets	2,035		923		27			—			2,985
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
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
As of September 30, 2016
Total Assets	$	25,486	$	12,810	$	2,385		$	(1,193	)	$	39,488
Investments in Equity Method Subsidiaries	$	—	$	106	$	—		$	—		$	106
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 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.~~18. Related-Party Transactions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents ~~(UNAUDITED)~~

Note ~~17.~~18. 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 as follows:




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Related-Party Transactions	2016		2015		2016		2015
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	320	$	294	$	1,162	$	1,287
Administrative Billings from Services (B)	73		66		224		197
Total Billings from Affiliates	$	393	$	360	$	1,386	$	1,484

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 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




	As of		As of
Related-Party Transactions	September 30, 2016		December 31, 2015
	Millions
Receivables from PSEG (C)	$	28	$	222
Payable to Power (A)	$	126	$	212
Payable to Services (B)	88		80
Accounts Payable—Affiliated Companies	$	214	$	292
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	92	$	109

Power

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

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




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Related-Party Transactions	2016		2015		2016		2015
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	320	$	294	$	1,162	$	1,287
Billings from Affiliates:
Administrative Billings from Services (B)	$	44	$	44	$	134	$	135

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents ~~(UNAUDITED)~~

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




	As of		As of
Related-Party Transactions	September 30, 2016		December 31, 2015
	Millions
Receivables from PSE&G (A)	$	126	$	212
Receivables from PSEG (C)	—		64
Accounts Receivable—Affiliated Companies	$	126	$	276
Payable to Services (B)	$	27	$	33
Payable to PSEG (C)	129		—
Accounts Payable—Affiliated Companies	$	156	$	33
Short-Term Loan Due (to) from Affiliate (E)	$	514	$	363
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	79	$	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

(UNAUDITED)

Table of Contents ~~(UNAUDITED)~~

Note ~~18.~~19. 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, as of ~~March 31,~~September 30, 2016 and December 31, 2015 and for the three months and nine months ended ~~March 31,~~September 30, 2016 and 2015.

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 ) $ —




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended September 30, 2016
Operating Revenues	$	—		$	1,059		$	43		$	(27	)	$	1,075
Operating Expenses	(2		)	826			40			(27		)	837
Operating Income (Loss)	2			233			3			—			238
Equity Earnings (Losses) of Subsidiaries	143			(1		)	3			(142		)	3
Other Income	18			26			—			(21		)	23
Other Deductions	(2		)	(4		)	—			—			(6		)
Other-Than-Temporary Impairments	—			(5		)	—			—			(5		)
Interest Expense	(30		)	(12		)	(3		)	21			(24		)
Income Tax Benefit (Expense)	8			(97		)	(1		)	—			(90		)
Net Income (Loss)	$	139		$	140		$	2		$	(142	)	$	139
Comprehensive Income (Loss)	$	168		$	161		$	2		$	(163	)	$	168
Nine Months Ended September 30, 2016
Operating Revenues	$	—		$	3,061		$	131		$	(90	)	$	3,102
Operating Expenses	10			2,494			119			(90		)	2,533
Operating Income (Loss)	(10		)	567			12			—			569
Equity Earnings (Losses) of Subsidiaries	347			(1		)	9			(346		)	9
Other Income	52			88			—			(66		)	74
Other Deductions	(2		)	(31		)	—			—			(33		)
Other-Than-Temporary Impairments	—			(25		)	—			—			(25		)
Interest Expense	(91		)	(29		)	(12		)	66			(66		)
Income Tax Benefit (Expense)	24			(234		)	2			—			(208		)
Net Income (Loss)	$	320		$	335		$	11		$	(346	)	$	320
Comprehensive Income (Loss)	$	388		$	381		$	11		$	(392	)	$	388
Nine Months Ended September 30, 2016
Net Cash Provided By (Used In) Operating Activities	$	175		$	1,261		$	234		$	(410	)	$	1,260
Net Cash Provided By (Used In) Investing Activities	$	(588	)	$	(1,166	)	$	(549	)	$	1,152		$	(1,151	)
Net Cash Provided By (Used In) Financing Activities	$	413		$	(95	)	$	315		$	(742	)	$	(109	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents ~~(UNAUDITED)~~

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 )




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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




	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of September 30, 2016
Current Assets	$	4,889	$	1,845	$	287	$	(5,262	)	$	1,759
Property, Plant and Equipment, net	57		6,570		2,080		—			8,707
Investment in Subsidiaries	4,709		483		—		(5,192		)	—
Noncurrent Assets	157		2,140		123		(76		)	2,344
Total Assets	$	9,812	$	11,038	$	2,490	$	(10,530	)	$	12,810
Current Liabilities	$	818	$	3,888	$	1,350	$	(5,262	)	$	794
Noncurrent Liabilities	473		2,704		394		(76		)	3,495
Long-Term Debt	2,381		—		—		—			2,381
Member’s Equity	6,140		4,446		746		(5,192		)	6,140
Total Liabilities and Member’s Equity	$	9,812	$	11,038	$	2,490	$	(10,530	)	$	12,810
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 of Contents


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and Power each make representations only as to itself and make no representations whatsoever as to any other company.

~~PSEG's~~PSEG’s business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:

PSE&G, our public utility company which is 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, and

Power, our multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy 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~~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~~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 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 2015 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 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 2015 Form 10-K.

EXECUTIVE OVERVIEW OF 2016 AND FUTURE OUTLOOK

Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives, including:

~~growing our~~

improving utility operations through ~~continued~~growth in investment in T&D and other infrastructure projects designed to enhance resiliency, and

maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.

Table of Contents

Financial Results

The results for PSEG, PSE&G and Power for the three months and ~~three~~nine months ended ~~March 31,~~September 30, 2016 and 2015 are presented as follows:

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




	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Earnings	2016			2015		2016			2015
	Millions
PSE&G	$	255		$	222	$	696		$	631
Power (A) (B)	139			206		320			707
Other (C)	(67		)	11		(31		)	32
PSEG Net Income	$	327		$	439	$	985		$	1,370

PSEG Net Income Per Share (Diluted)	$	0.64		$	0.87	$	1.94		$	2.70


(A)	Includes after-tax expenses of $67 million related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants in the three months and nine months ended September 30, 2016. See Item 1. Note 3. Early Plant Retirements for additional information.


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


~~(B)~~(C)	Other includes activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded an after-tax impairment of $86 million related to its investments in NRG REMA, LLC’s leveraged leases in the three months and nine months ended September 30, 2016. See Item 1. Note 6. Financing Receivables for further information.

Power’s results above include the realized gains, losses and earnings on the Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity and the impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with ~~forward~~future delivery dates.

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

Three Months Ended
March 31,
2016 2015
Millions, after tax
NDT Fund Income (Expense) (A) $ (5 ) $ 2

Non-Trading MTM Gains (Losses) $ 13
$ (20 )




	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2016		2015			2016			2015
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	2	$	(14	)	$	(4	)	$	(11	)
Non-Trading MTM Gains (Losses) (C)	$	34	$	50		$	(54	)	$	58

(A)

NDT Fund Income (Expense) includes the realized gains and losses, interest and dividend income and other costs related to the NDT Fund which are recorded in Other Income and Deductions, and impairments on certain NDT securities recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power’s nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization Expense.


(B)	Net of tax (expense) benefit of $(2) million, $10 million, $0 million and $3 million for the three and nine months ended September 30, 2016 and 2015, respectively.


(C)	Net of tax (expense) benefit of $(24) million, $(34) million, $37 million and $(40) million for the three and nine months ended September 30, 2016 and 2015, respectively.

Our ~~$115~~$112 million decrease in Net Income for the three months ended ~~March 31,~~September 30, 2016 was driven primarily by

~~reduced~~an impairment related to investments in certain leveraged leases at Energy Holdings (See Item 1. Note 6. Financing Receivables),

charges related to the early retirement of two coal/gas generation units at Power (See Item 1. Note 3. Early Plant Retirements), and

Table of Contents

lower volumes of ~~gas~~energy sold at lower average realized prices ~~under the BGSS contract,~~

and lower ~~sales volumes of energy~~capacity revenues, primarily in the PJM ~~and 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 Superstorm Sandy, and~~

~~lower operating reserve revenues and capacity revenues in PJM.~~Interconnection, L.L.C. (PJM) region.

These decreases were partially offset by

higher revenues due to increased investments in transmission projects,

higher electricity sales under non-BGS wholesale load contracts in PJM and New England (NE) and higher volumes of electricity sold at higher prices under our Basic Generation Service (BGS) contracts, and

lower other-than-temporary impairments of the NDT Fund.

Our $385 million decrease in Net Income for the nine months ended September 30, 2016 was driven primarily by

the aforementioned charges in the 2016 third quarter for the early retirement of the two coal/gas generation units at Power,

MTM losses in 2016 as compared to MTM gains in 2015,

lower volumes of energy sold at lower average realized sales prices,

lower capacity and operating reserve revenues in PJM,

higher 2016 congestion costs in PJM as a result of credits received in 2015 due to extremely colder weather,

lower volumes of gas sold at lower average prices under the Basic Gas Supply Service (BGSS) contract,

insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy, and

the aforementioned third quarter 2016 impairment on leveraged leases at Energy Holdings.

These decreases were partially offset by

lower generation costs driven by lower fuel costs, particularly for natural gas, ~~prices~~and reduced generation output at ~~Power.~~Power,

•higher costs incurred at Power for planned outages in 2015, and

higher revenues due to increased investments in transmission projects.

During the first ~~quarter~~nine months of 2016, we ~~sustained~~maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results 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 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~~continue 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.~~2014 and to seek recovery on such investments. We also commenced modernizing PSE~~&G's~~&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. In 2017, as a result of our Energy Strong Order from the BPU, we will be required to file a Distribution rate case proceeding. We cannot predict the impact such proceeding will have on our distribution business.

~~During~~Despite the ~~first quarter of~~unseasonable warm winter weather patterns in 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. Power manages these contracts for the benefit of PSE&G’s customers through the ~~basic gas supply service (BGSS)~~BGSS arrangement. The contracts are sized to ~~ensure~~provide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third party sales and supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s strategic hedging practices and ability to ~~use~~capitalize on market ~~conditions to its advantage~~opportunities help it to balance some of the volatility of the merchant power business.

Our recent investments in the latter half of 2015 and early 2016 in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These additions to

Table of Contents

our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.

Since 2013, eight nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, and four additional stations have been announced as being at risk for early retirement. This situation is generally due to low natural gas prices resulting from the growth of shale gas production since 2007, the continuing cost of regulatory compliance for nuclear facilities and both federal and state-level policies that provide credits to renewable energy such as wind and solar, but do not apply to nuclear generating stations. These trends have significantly reduced the revenues to nuclear generating stations while simultaneously raising the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating greater reliance on natural gas pipelines for delivery and less diversity of the generation fleet.

If trends noted above continue or worsen, our nuclear generating units could cease being economically competitive which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs and environmental remediation costs, could be material. We continue to advocate for sound policies that recognize nuclear power as a source of clean energy and an important part of a diverse and reliable energy portfolio.

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~~

In April 2013, PJM ~~Interconnection, L.L.C. (PJM)~~ initiated its first ~~"open window"~~“open window” solicitation process to allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues atin New Jersey. In February 2016, FERC issued an order granting PSE&G’s request that it be permitted to seek recovery of 100% of its portion of prudently incurred Artificial Island ~~in New Jersey.~~project costs if the project is cancelled for reasons beyond PSE&G’s control. In April 2016, PSE&G accepted construction responsibility for ~~the~~ three components of the Artificial Island project that PJM assigned to us. On August 5, 2016, PJM announced that it ~~based on having reached agreement with PJM regarding an estimate for~~has suspended the Artificial Island transmission project ~~base cost~~and is performing a comprehensive analysis to determine a future course of ~~$273 million, plus risk and contingency for a total~~action, which is expected to be completed by February 2017. We may also from time to time have opportunities to submit transmission project ~~cost of up to $340 million. PSE&G continues to work with PJM to optimize~~proposals in regions where we are not the ~~scope and cost of the project.~~incumbent. However, there can be no assurance that any such proposals would be successful.

In April 2016, PJM filed at FERC to incorporate a voltage threshold into PJM’s Regional Transmission Expansion Plan (RTEP) process to exempt, except under certain circumstances, reliability violations on facilities below 200 kV from PJM’s proposal window process. We generally support this reform as a measure to improve the efficiency of the open window procedure that will permit transmission developers to focus on the projects most likely to benefit from a competitive process.

There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE~~&G's~~&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~~&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~~Power’s business or results of operations.

~~Wholesale Power Market Design~~

~~In an important development~~Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ base ROEs. While we are not the subject of a challenge to the ROE employed in PSE&G’s transmission formula rate, the results of these other 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 actioncould set precedents for other transmission owners with formula rates 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.

place, including PSE&G.

Table of Contents

Wholesale Power Market Design

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. In June 2015, FERC conditionally accepted a proposal from PJM for a capacity performance ~~(CP)~~ product to include generators, Demand Response and energy efficiency providers, which will be required to perform during emergency conditions, as a supplement to the base capacity product. The proposal included enhanced performance-based incentives and penalties. We believe that the auction pricing adequately reflects the increased costs that could result from operating under more stringent rules for generation availability. Based on the auction results, the CPcapacity performance mechanism appears to have provided the opportunity for enhanced capacity market revenue streams for Power, but future impacts cannot be assured. Further, there may be requirements for additional investment and there are additional performance and financial risks. ~~Applications for rehearing~~Appeals of ~~FERC's CP order~~FERC’s capacity performance orders are pending.

~~An emerging issue~~In May 2016, PJM announced the results of the RPM capacity auction for the 2019-2020 delivery year. Power cleared 8,895 MW of its generating capacity at an average price of $116 per MW-day for the 2019-2020 delivery period. Of the cleared capacity, Power believes that nearly all is compliant with PJM’s capacity performance requirements. In the two prior capacity auctions covering the 2017-2018 and 2018-2019 delivery years, Power cleared approximately 8,700 MW at average prices of $177 per MW-day and $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the emergency transfer limits due to transmission expansion and the effects of both the new generation and uncleared generation from the prior year’s auction.

As a result of the efforts of certain entities in PJM ~~involves~~to obtain financial support arrangements from their state commission, a group of suppliers requested that FERC direct PJM to expand the ~~impact of~~currently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized ~~existing generation on RPM market outcomes. These subsidies~~generators would ~~likely enable the affected generators to~~ submit bids into the PJM capacity ~~markets~~market that ~~are~~did not ~~reflective of~~reflect 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~~prices. We are currently ~~effective “minimum offer price rule” (MOPR) which applies only to new gas-fired units, would not apply to these plants.~~awaiting FERC action on the suppliers’ request and cannot predict the outcome of the proceeding. See Part II, Item 5. Other Information—Federal Regulation—Capacity Market ~~Issues~~Issues—PJM for additional information.

Environmental Regulation

We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act (FWPCA) requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs. See Item 1. Note 8.9. Commitments and Contingent Liabilities for further information.

In October 2015, the EPA published the Clean Power Plan (CPP), a 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. 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 U.S. Supreme Court’s February 2016 decision to stay the implementation of the CPP will delay deadlines for submission of state requests for extensions and final plans. If the CPP is upheld, new deadlines will need to be established and the effective date of the compliance period may be impacted.

We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs of any such remediation efforts could be material.

For further information regarding the matters described above as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 8.9. Commitments and Contingent Liabilities.

FERC Compliance

~~The~~Since September 2014, FERC Staff has ~~initiated~~been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of ~~Power's~~Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. 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

Table of Contents

choose to pursue, it is likely that Power would record losses that would be material to ~~PSEG's~~PSEG’s and ~~Power's~~Power’s results of operations in the quarterly and annual periods in which they are recorded. For additional information, see Item 1. Note 8.9. Commitments and Contingent Liabilities.

~~Salem Inspection~~Early Retirement of Hudson and Mercer Units

In ~~April~~October 2016, Power determined it will cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. The exact timing of the early retirement of these units will be reviewed for reliability impacts by PJM, and may be impacted by operational and other conditions that could subsequently arise. The decision to retire the Hudson and Mercer units will have a material effect on PSEG’s and Power’s results of operations. In the third quarter of 2016, PSEG and Power recognized one-time pre-tax charges in Energy Costs, Operation and Maintenance and Depreciation and Amortization of $62 million, $48 million and $4 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs, construction work in progress impairments, and asset retirement obligation (ARO) adjustments, among other shut down items. In addition to these one-time charges, Power will recognize incremental Depreciation and Amortization during the remainder of 2016 of $568 million and $946 million into 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. Additional employee-related salary continuance and severance costs and various miscellaneous costs may also be incurred during the period prior to retirement. Finally, Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger investigation and possible remediation of identified environmental contamination. The amounts for any such environmental investigation or remediation are not currently probable or estimable but may be material. For additional information, including our estimated costs through 2017, see Item 1. Note 3. Early Plant Retirements.

The primary factors considered during our annual five-year strategic planning process that contributed to the decision to retire these units early include significant declines in revenues and margin caused by a ~~scheduled refueling outage~~sustained period of depressed wholesale power prices and reduced capacity factors caused by lower natural gas prices making coal generation less economically competitive than natural gas-fired generation. Despite experiencing recent warmer than normal weather in PJM this summer, Power did not experience the usual increase in electricity prices in PJM as it had in past hot summers. This trend has a further adverse economic impact to these units because they generally dispatch and earn energy margin on peak hot and cold days. In addition, the upcoming PJM capacity auction in May 2017 will be the first to require all generating units to meet the increased operating performance standards of PJM’s new capacity performance construct. Power determined that the costs to upgrade the existing units at ~~Salem Unit 1,~~the Hudson and Mercer stations to be able to comply with these higher reliability standards are too significant and not economic given current market conditions.

In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone, Conemaugh and Bridgeport Harbor generating stations, to ensure their economic viability through the end of their designated useful lives. The precise timing of a ~~visual inspection revealed degradation~~change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact our ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement of our other coal units before the end of their current estimated useful lives may have a ~~series~~material adverse impact on PSEG’s and Power’s future financial results.

Leveraged Lease Impairments

During the third quarter of ~~bolts inside~~2016, Energy Holdings completed its annual review of estimated residual values embedded in the ~~reactor vessel. We have initiated further testing,~~NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016, calculated by comparing the gross investment in the leases before and after the revised residual estimates. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.

Additional facilities in our leveraged lease portfolio include the Joliet facility, which ~~is ongoing and is~~has converted to natural gas. The coal-fired units at the Shawville generating facility are expected to ~~extend~~return to service in the ~~refueling outage. The impact~~fall of 2016 with the ability to use natural gas. However, these units may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. As a result, these facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by coal generation facilities, which could require Energy Holdings to write down the residual value 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.~~

leveraged leases associated with these facilities.

Table of Contents

REMA’s parent company, GenOn Energy, Inc. (GenOn), reported in August 2016 that it did not expect to have sufficient liquidity to repay their senior unsecured notes due in June 2017. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged leases.

Salem Operations

The previously announced bolt replacement at Salem Unit 1 was completed and the unit returned to service on July 30, 2016. We expect to continue to inspect and replace degraded bolts at both Salem units over the next several refueling outage cycles. We are participating with the Electric Power Research Institute, the Nuclear Energy Institute and other operators of similarly-designed pressurized water reactors in developing a strategy to maintain the long-term health of the reactor vessel internals.

Extension of the Salem Unit 1 outage into July and an unplanned outage at Salem Unit 2 due to transformer issues reduced output from the Salem units in the third quarter, which was partially offset by increased production at our Hope Creek and Peach Bottom units. As a result, our nuclear capacity factor for the nine months ended September 30, 2016 was 88%.

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~~in a rapidly evolving market as we remain diligent in managing costs. For the first ~~quarter~~nine months of 2016, our

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

~~nuclear output increased by 7.5% as compared to the same period in 2015, and~~

diverse fuel mix and dispatch flexibility allowed us to generate approximately 1340 terra-watt hours while addressing ~~unit outages and balancing~~ fuel availability and price ~~volatility.~~volatility and compensating for the extended outages at our Salem units, and

combined cycle fleet produced 13 terawatt hours at an average capacity factor of 63%.

Financial Strength

Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first ~~quarter~~nine months of 2016 as we

had cash on hand of ~~$592~~$450 million as of ~~March 31,~~September 30, 2016,

maintained solid investment grade credit ratings, and

increased our indicative annual dividend for 2016 to $1.64 per share.

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, without the issuance of new equity.

Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first ~~quarter~~nine months of 2016, we

made additional investments in transmission infrastructure projects,

began executing our GSMP and continued executing Energy Strong and other existing BPU-approved utility programs,

commenced construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and announced our plan to construct BH5 and commence operations in mid-2019, and

acquired three solar energy projects totaling 100 MW-direct ~~current~~current. Two of these projects are already in service in North Carolina and Colorado. The third project is in Colorado and expected to ~~go into~~be in service ~~during 2016.~~by year end.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a ~~slow-moving~~slow-growing economy and a cost-constrained environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to:

focus on controlling costs while maintaining safety and reliability and complying with applicable standards and requirements,

Table of Contents

successfully manage our energy obligations and re-contract our open supply positions in response to changes in demand,

execute our utility capital investment program, including our Energy Strong program, 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, 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~~LIPA’s fuel supply and generation dispatch obligations.

~~Table of Contents~~

For 2016 and beyond, the key issues and challenges we expect our business to confront include:

regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,

fair and timely rate relief from the BPU and FERC ~~Staff’s continuing investigation~~for recovery of ~~certain of Power’s New Jersey fossil generating unit bids in~~costs and return on investments, including with respect to our base rate case which must be filed with the ~~PJM energy market,~~BPU no later than November 1, 2017,

uncertainty in the slowly improving national and regional economic recovery, continuing customer conservation efforts, changes in energy usage patterns and evolving technologies, which impact customer behaviors and demand,

the potential for continued reductions in demand and sustained lower natural gas and electricity prices, both at market hubs and the locations where we operate,

the impact of lower natural gas prices and increasing environmental compliance costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,

delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory ~~approvals.~~approvals,

maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and

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

Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:

the acquisition, construction or disposition of transmission and distribution facilities and/or generation units,

the disposition or reorganization of our merchant generation business or other existing businesses or the acquisition or development of new businesses,

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.~~infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.

We continue to actively explore opportunities in the retail energy marketing business, which we believe would complement our existing wholesale marketing business. Our entry into the retail energy marketing business is subject to market conditions and regulatory approval, among other things.

Table of Contents

There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

~~Table of Contents~~

RESULTS OF OPERATIONS

PSEG

Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PSE&G and Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note ~~17.~~18. Related-Party Transactions.

Three Months Ended
Increase/
(Decrease)

March 31,
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 )




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2016		2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	2,450	$	2,688	$	(238	)	(9	)	$	6,971	$	8,137	$	(1,166	)	(14	)
Energy Costs	866		815		51			6		2,326		2,577		(251		)	(10	)
Operation and Maintenance	776		746		30			4		2,215		2,170		45			2
Depreciation and Amortization	231		313		(82		)	(26	)	679		960		(281		)	(29	)
Income from Equity Method Investments	3		3		—			—		9		10		(1		)	(10	)
Other Income (Deductions)	39		33		6			18		100		135		(35		)	(26	)
Other-Than-Temporary Impairments	5		30		(25		)	(83	)	25		45		(20		)	(44	)
Interest Expense	99		96		3			3		288		291		(3		)	(1	)
Income Tax Expense	188		285		(97		)	(34	)	562		869		(307		)	(35	)

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

PSE&G

Three Months Ended
Increase/
(Decrease)

March 31,
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				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2016		2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,684	$	1,766	$	(82	)	(5	)	$	4,746	$	5,234	$	(488	)	(9	)
Energy Costs	721		740		(19		)	(3	)	1,979		2,176		(197		)	(9	)
Operation and Maintenance	376		391		(15		)	(4	)	1,110		1,171		(61		)	(5	)
Depreciation and Amortization	137		231		(94		)	(41	)	412		712		(300		)	(42	)
Other Income (Deductions)	21		22		(1		)	(5	)	58		57		1			2
Interest Expense	72		67		5			7		214		203		11			5
Income Tax Expense	144		137		7			5		393		398		(5		)	(1	)

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

Operating Revenues decreased ~~$290~~$82 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased ~~$29~~$57 million due primarily to an increase in transmission revenues.

Transmission revenues were ~~$53~~$50 million higher due to increased capital investments.

Electric distribution revenues increased $8 million due primarily to $12 million in higher sales volumes and $12 million due to the inclusion of Energy Strong in base rates, partially offset by lower Green Program Recovery Charges (GPRC) of $16 million.

Table of Contents

Commodity Revenue decreased $19 million as a result of $14 million of lower Gas revenues and $5 million of lower Electric revenues. Commodity revenue for both gas and electric is entirely offset with the change in Energy Costs. PSE&G earns no margin on the provision of BGSS and BGS to retail customers.

Gas revenues decreased $14 million due to $25 million of lower BGSS sales volumes, partially offset by $11 million in higher prices.

Electric revenues decreased $5 million due primarily to $17 million of lower revenues from collections of Non-Utility Generation Charges (NGC) and a decrease of $14 million due to lower volumes of Non-Utility Generation (NUG) energy sold at lower prices. These decreases were partially offset by a $26 million increase in BGS revenues due to higher sales volumes.

Clause Revenues decreased $121 million due primarily to lower Securitization Transition Charges (STC) of $118 million. The STC reduction was a result of rate reductions due to the completion of securitization collections in 2015. The changes in the STC 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 collections.

Operating Expenses

Energy Costs decreased $19 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased $15 million, of which the most significant components were

a $23 million net reduction in costs related to various clause mechanisms, including SBC and STC, and GPRC, and

a $2 million decreasein pension and OPEB costs, net of capitalized amounts,

partially offset by a net increase of $10 million in operating expenses, including increases in appliance service costs, gas distribution costs and electric distribution corrective maintenance.

Depreciation and Amortization decreased $94 million due to a decrease of $114 million in amortization of Regulatory Assets primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by an $18 million increase in depreciation due to additional plant in service.

Interest Expense increased $5 million due primarily to an increase of $7 million due to net debt issuances in 2015 and 2016, partially offset by a $2 million decrease due to the redemption of securitization debt in 2015.

Income Tax Expense increased $7 million due primarily to higher pre-tax income, partially offset by plant-related items and uncertain tax positions.

Nine Months Ended September 30, 2016 as Compared to 2015

Operating Revenues decreased $488 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $116 million due primarily to an increase in transmission revenues.

Transmission revenues were $152 million higher due to increased capital investments.

Electric distribution revenues decreased ~~$23~~$30 million due primarily to lower ~~Green Program Recovery Charges (GPRC)~~GPRC of ~~$14~~$42 million and ~~$10~~a $4 million indecrease due to lower sales ~~volumes.~~volumes partially offset by $16 million increase due to the inclusion of Energy Strong in base rates.

Gas distribution revenues decreased $1$6 million due primarily to ~~$76~~$75 million of lower delivery ~~volume~~volumes and lower GPRC of $6$7 million due to lower sales volumes from warmer winter weather. These decreases were almost entirely offset by ~~$73~~$64 million in higher Weather Normalization Clause ~~(WNC)~~ revenue and $8a $12 million increase due to ~~roll in~~the inclusion of Energy Strong ~~into~~in base rates effective September 1, 2015.

~~Table of Contents~~

Commodity Revenue decreased ~~$163~~$197 million as a result of lower Gas and Electric revenues. Commodity revenue for both gas and electric is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of ~~Basic Gas Supply Service (BGSS)~~BGSS and ~~basic generation service (BGS)~~BGS to retail customers.

Gas revenues decreased ~~$109~~$108 million due primarily to lower BGSS ~~volume.~~sales volumes.

Electric revenues decreased ~~$54~~$89 million due primarily to ~~a $35 million or 8% decrease in BGS revenues due to lower sales volumes, $11~~$43 million of lower revenues from collections of ~~Non-Utility Generation Charges (NGC) and~~NGC, a decrease of $8$31 million due to ~~higher~~lower volumes of ~~Non-Utility Generation (NUG)~~NUG energy sold atand a $15 million or 1% decrease in BGS revenues due primarily to lower ~~prices.~~sales volumes.

Table of Contents

Clause Revenues decreased ~~$155~~$402 million due primarily to lower ~~Securitization Transition Charges (STC)~~STC of ~~$129~~$370 million, lower SBC of $38 million and $9 million of lower ~~Societal Benefit Charges (SBC) of $33 million,~~SPRC, partially offset by higher Margin Adjustment Clause ~~Revenue~~ (MAC) revenue of ~~$12~~$15 million. The STC reduction is a result of rate reductions due to the completion of securitization collections in 2015. The changes in the STC, SBC, SPRC and MAC 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, SBC, SPRC or MAC collections.

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

Operating Expenses

Energy Costs decreased ~~$163~~$197 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased ~~$30~~$61 million, of which the most significant components were

a ~~$44~~$95 million net reduction in costs related to various clause mechanisms, including SBC, SPRC, STC and MAC, and GPRC, and

a $10 million decrease in pension and OPEB costs, net of capitalized amounts,

partially offset by ~~$15~~$10 million of storm insurance recovery proceeds received in ~~2015.~~2015,

an $8 million increase in electric distribution corrective maintenance,

a $5 million increase in vegetation management,

a $5 million increase in transmission related maintenance and

a $16 million increase in operating expenses, including $3 million increases related to both appliance service costs and gas distribution costs.

Depreciation and Amortization decreased ~~$108~~$300 million due to a decrease of ~~$124~~$353 million in amortization of Regulatory Assets primarily as a result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by a ~~$16~~$49 million increase in depreciation due to of additional plant in service.

Interest Expense increased $11 million due primarily to an increase of $20 million due to net debt issuances in 2015 and 2016, partially offset by a $10 million decrease due to the redemption of securitization debt in 2015.

Income Tax Expense decreased $5 million due primarily to uncertain tax positions, plant-related and other flow through items, partially offset by higher pre-tax income.

Table of Contents

Power




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2016		2015		2016 vs. 2015					2016		2015		2016 vs. 2015
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,075	$	1,096	$	(21	)	(2	)	$	3,102	$	3,846	$	(744	)	(19	)
Energy Costs	462		367		95			26		1,481		1,669		(188		)	(11	)
Operation and Maintenance	289		263		26			10		807		748		59			8
Depreciation and Amortization	86		75		11			15		245		226		19			8
Income from Equity Method Investments	3		3		—			—		9		11		(2		)	(18	)
Other Income (Deductions)	17		11		6			55		41		77		(36		)	(47	)
Other-Than-Temporary Impairments	5		30		(25		)	(83	)	25		45		(20		)	(44	)
Interest Expense	24		30		(6		)	(20	)	66		94		(28		)	(30	)
Income Tax Expense	90		139		(49		)	(35	)	208		445		(237		)	(53	)

Three Months Ended September 30, 2016 as Compared to 2015

Operating Revenues decreased $21 million due to changes in generation, gas supply and other revenues.

Generation Revenues decreased $23 million due primarily to

a decrease of $73 million in energy sales volumes and lower average realized prices, primarily in the PJM region, and

a decrease of $24 million in capacity revenue, primarily in the PJM region,

partially offset by a net increase of $44 million in electricity sold under non-BGS wholesale load contracts in the PJM and NE regions due to higher volumes sold partially offset by lower average prices, and

an increase of $24 million in electricity sold under our BGS contracts due primarily to higher volumes as a result of warmer weather, coupled with higher average prices.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $95 million due primarily to

Generation costs increased $93 million due to

a $62 million charge associated with the announced early retirement of the coal/gas Mercer and Hudson generation units, primarily related to a coal inventory write-down of $57 million,

an increase of $32 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $25 million was due to lower gains on positions reclassified to realized upon settlement this year compared to last year, and

an increase of $13 million due to increases in purchases of renewable energy credits and energy to serve load contracts,

partially offset by a decrease of $20 million due primarily to lower natural gas costs reflecting lower average realized prices.

Operation and Maintenance increased $26 million due primarily to

$48 million of charges related to the early retirement of the Hudson and Mercer units,

partially offset by a net decrease of $18 million due to the timing of a planned outage at our 50%-owned Peach Bottom nuclear plant.

Table of Contents

Depreciation and Amortization increased $11 million due primarily to

a $7 million increase due primarily to a higher nuclear asset base, and

$4 million of accelerated depreciation on asset retirement costs from previously retired assets at the Hudson and Mercer plants.

Other Income (Deductions) increased $6 million due primarily to lower net realized losses from the NDT Fund in 2016.

Other-Than-Temporary Impairments decreased $25 million due to lower impairments of equity securities in the NDT Fund in 2016.

Interest Expense decreased $6 million due primarily to ~~depreciation flow through items and uncertain tax positions offset by~~ higher capitalized interest in 2016.

Income Tax Expense decreased $49 million in 2016 due primarily to lower pre-tax income.

~~Power~~

Three Months Ended
Increase/
(Decrease)

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

Operating Revenues decreased $~~412~~744 million due to changes in generation, ~~and~~ gas supply and other revenues.

Generation Revenues decreased ~~$174~~$497 million due primarily to

a decrease of ~~$75~~$213 million in energy sales volumes in the PJM, NE and New York (NY) regions due primarily to milder weather and lower average realized prices,

a decrease of $166 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $127 million was due to higher gains on positions reclassified to realized upon settlement this year compared to last year. Also contributing to the decrease were lower MTM gains of $39 million due to minor changes in forward power prices this year compared to last year,

a net decrease of $113 million primarily in the PJM region due to lower ~~operating reserve~~capacity revenue ~~coupled with lower capacity revenues~~ resulting from the retirement of older peaking units in June 2015,

~~Table of Contents~~

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

a net decrease of ~~$38~~$10 million in electricity sold under our BGS contracts 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.~~prices.

Gas Supply Revenues decreased ~~$238~~$248 million due primarily to

a ~~net~~ decrease of ~~$220~~$241 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 ~~$18~~$7 million onin sales to third party customers, of which ~~$47~~$45 million was due to lower average ~~sales~~ prices, partially offset by ~~$29~~$38 million of higher volumes sold.

Operating Expenses

Generation costs decreased ~~$123~~$67 million due primarily to

lower fuel costs of ~~$234~~$287 million reflecting lower average realized prices for natural gas ~~prices~~ and the utilization of lower volumes of ~~coal, oil and gas. These decreased costs were~~ fuel,

partially offset by higher congestion costs in ~~the~~ PJM ~~region~~ of ~~$145~~$137 million, mainly as a result of credits received in the prior year due to extremely cold ~~weather. Also,~~winter weather,

a $62 million charge associated with the announced early retirement of the Mercer and Hudson units, primarily related to a coal inventory write-down of $57 million, and

a net increase of $15 million due to lower MTM ~~losses~~gains in 2016 ~~resulted in a $20~~as compared to 2015. Of this amount, $10 million ~~decrease.~~was due to lower gains on positions reclassified to realized upon settlement this year compared to last year.

Table of Contents

Gas costs decreased ~~$132~~$121 million mainly related to

a decrease ~~in volumes sold~~of $142 million related to sales under the BGSS contract ~~coupled with~~due primarily to lower volumes sold due to warmer average temperatures during the 2016 winter heating season and lower average gas ~~costs. Gas~~ costs, on

partially offset by a net increase of $21 million related to sales to third parties ~~were flat.~~

due primarily to an increase in volumes sold.

Operation and Maintenance increased ~~$81~~$59 million due primarily to

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

$48 million of charges related to early retirement of the Hudson and Mercer units,

partially offset by a net decrease of ~~$48~~$75 million related to our fossil plants, largely due to higher costs incurred in 2015 for our planned major ~~outages.~~outages at the Bethlehem Energy Center and Bergen generating plants, and

a net decrease of $58 million related to our nuclear plants due primarily to a planned outage at our 100%-owned Hope Creek plant and our 50%-owned Peach Bottom plant in 2015, partly offset in 2016 by an extended refueling outage at our 57%-owned Salem Unit 1 plant.

Depreciation and Amortization increased$19 milliondue primarily to

a $12 million increase due primarily to a higher nuclear asset base,

$4 million of accelerated depreciation on asset retirement costs from previously retired assets at the Hudson and Mercer plants, and

$3 million of higher depreciation due to new solar projects.

Other Income ~~and~~ (Deductions) decreased ~~$10~~$36 million due primarily to ~~higher~~$28 million of insurance recoveries received in 2015 related to Superstorm Sandy and lower net realized ~~losses~~gains from the NDT ~~Fund.~~Fund in 2016.

Other-Than-Temporary Impairments ~~increased $5~~decreased $20 million due ~~primarily~~ to ~~an increase in~~lower impairments of equity securities in the NDT ~~Fund.~~Fund in 2016.

Interest Expense decreased $9$28 million due primarily to ~~the maturity of a $300 million 5.50% Senior Note in December 2015 and~~ higher capitalized interest in 2016 and the maturity of $300 million of 5.50% Senior Notes in December 2015, partially offset by the issuance of $700 million of 3.00% Senior Notes in June 2016.

Income Tax Expense decreased ~~$105~~$237 million in 2016 due primarily to 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

We expect operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder dividend payments.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2016, our operating cash flow decreased $~~465~~467 million as compared to the same period in 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 decreased $~~109~~117 million from $~~677~~1,518 million to $~~568~~1,401 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2016, as compared to the same period in 2015, due primarily to a decrease of ~~$83~~$113 million due to a change in regulatory deferrals, ~~primarily driven by lower volumes due to warmer weather impacting our Gas Weather Normalization, SBC, GPRC~~

~~Table of Contents~~

~~and BGSS clauses,~~ a ~~$42 million decrease in other current assets and liabilities and a $40~~$64 million decrease due to higher vendor ~~payments.~~payments and a decrease due to the completion of securitization collections in 2015. These amounts were partially offset by higher earnings and ~~a reduction~~higher tax refunds in ~~tax payments.~~2016.

Power

Power’s operating cash flow decreased $~~187~~298 million from $~~850~~1,558 million to $~~663~~1,260 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2016, as compared to the same period in 2015, primarily due to lower earnings, ~~and~~ a ~~$141~~$140 million decrease ~~for fuel,~~from fuels, materials and supplies, and a $146 million increase in margin deposit requirements, partially offset by a reduction in tax payments.

Table of Contents

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~~We continually monitor our ~~$4.3 billion credit facilities are provided by a diverse bank group. As of~~ ~~March 31, 2016~~,liquidity and seek to add capacity as needed to meet our ~~total available credit capacity was $4.0 billion.~~

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

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

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




Company/Facility	As of September 30, 2016
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,000	$	265	$	735
PSE&G	600		14		586
Power	2,553		205		2,348
Total	$	4,153	$	484	$	3,669


~~(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)~~As of September 30, 2016, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power ~~facility will~~losing its investment grade credit rating, which would represent a three level downgrade from its current S&P and Moody’s ratings. In the event of a deterioration of Power’s credit rating certain of Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be ~~reduced by $48~~required to post under these agreements if Power were to lose its investment grade credit rating was approximately $807 million ~~in April~~and $864 million as of September 30, 2016 and ~~$24~~December 31, 2015, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units is not expected to have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 1. Note 3. Early Plant Retirements.

As of September 30, 2016, PSEG’s credit facilities are primarily available to back-stop its Commercial Paper Program under which PSEG had $255 million outstanding. PSE&G’s credit facility primary use is to support its Commercial Paper Program under which as of September 30, 2016, no amounts were outstanding. Most of our credit facilities expire in ~~March 2018.~~2019 and 2020.


~~(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.

~~Table of Contents~~

For additional information, see Item 1.Note 10. Debt and Credit Facilities.

Long-Term Debt Financing

~~Power has $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 2016, see Item 1. Note ~~9. Changes in Capitalization.~~10. Debt and Credit Facilities.

Common Stock Dividends

On ~~February 16, 2016, our Board of Directors approved a $0.41 per share common stock dividend for the first quarter of 2016. On April~~July 19, 2016, our Board of Directors ~~declared~~approved a quarterly dividend of $0.41 per share of common stock for the ~~second~~third quarter of 2016. This reflects an indicative annual dividend rate of $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.~~16. 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'~~agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

In January 2016, S&P published updated research reports on PSEG and PSE&G and the existing ratings and outlooks were unchanged. In ~~March~~June 2016, ~~Moody's~~Moody’s published credit opinions on Power and PSE&G and the existing ratings and outlooks were

Table of Contents

unchanged. In June 2016, S&P published an updated research report on Power and the existing rating and outlook were unchanged. In September 2016, Moody’s published an updated research report on PSEG and the existing rating and outlook were unchanged.




	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~~PSEG’s or PSE~~&G's~~&G’s Commercial Paper Rating or PSE~~&G's~~&G’s Mortgage Bond rating.

~~Table of Contents~~

CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures at ~~PSE&G,~~ Power and Services as compared to amounts disclosed in our 2015 Form 10-K.

PSEG

In July 2016, PSEG partnered with Vectren Corporation on a FERC 1000 proposal to construct, own and operate a twenty mile, 345 kilovolt transmission line in the midwest region served by the Midcontinent Independent System Operator (MISO). MISO estimated the project would cost approximately $60 million and would go in service in 2021. MISO is expected to select a proposal in December 2016. This project is not included in PSEG’s projected capital expenditures.

PSE&G

PSE&G increased its estimate of its capital expenditure program as reported in our 2015 Form 10-K by approximately $300 million from $8.3 billion to $8.6 billion primarily to address new business requests and replace aging equipment and infrastructure.

In August 2016, PSE&G filed a petition with the BPU requesting approval of the $268 million investment and an associated cost recovery mechanism to develop a project where PSE&G would rebuild New Jersey Transit’s Mason substation and related facilities in Kearny, NJ. This is not included in PSE&G’s projected capital expenditures.

On October 20, 2016, PSE&G submitted a settlement agreement to the BPU providing for an extension of the existing landfill/brownfield solar program to construct up to 33 MW of grid connected facilities with projected capital expenditures of approximately $80 million through May 2020. This extension is pending approval by the BPU. This is not included in PSE&G’s projected capital expenditures.

During the ~~three~~nine months ended ~~March 31,~~September 30, 2016, PSE&G made capital expenditures of ~~$724~~$2,035 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$35~~$109 million, which are included in operating cash flows.

Power

During the ~~three~~nine months ended ~~March 31,~~September 30, 2016, Power made capital expenditures of ~~$283~~$767 million, excluding $50156 million for nuclear fuel, primarily related to our Keys, Sewaren 7, BH5 and other generation projects.

ACCOUNTING MATTERS

For information related to recent accounting matters, see Item 1. Note 2. Recent Accounting Standards.


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.

Commodity Contracts

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

Value-at-Risk (VaR) Models

VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

MTM VaR consists of MTM derivatives that are economic hedges, 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 ~~January~~July through ~~March~~September 2016, MTM VaR remained relatively stable between low of $11 million to high of ~~$25~~$16 million at 95% confidence level. The range of VaR was narrower for the three months ended ~~March 31,~~September 30, 2016 as compared with the year ended December 31, 2015.




	MTM VaR
	Three Months Ended September 30, 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	$	13	$	17
High	$	16	$	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	$	21	$	26
High	$	25	$	63
Low	$	17	$	12

See Item 1. Note 11. Financial Risk Management Activities for a discussion of credit risk.

Table of Contents

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.~~


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 ~~first~~third quarter of 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 2015 Annual Report on Form 10-K, see Part I, Item 1. Note 8.9. Commitments and Contingent Liabilities and Item 5. Other Information.

~~Environmental Matters~~Ewing Explosion

~~The following updates information previously reported~~In February 2014, pursuant to an existing contract, PSE&G assigned Henkels and McCoy (Henkels) to replace the electrical service at a home in ~~Item 3~~the South Fork Townhouse Community in Ewing Township, Mercer County, New Jersey. In March 2014, after Henkels began work to install new electric service, a gas explosion occurred in the townhouse community resulting in damage to numerous properties, personal injuries and one fatality.

Twenty-two lawsuits have been filed to date relating to the gas explosion, of ~~Part I~~which PSE&G was named as a defendant in nineteen cases. To date, six of these cases have resolved through private negotiations and/or mediation. In one 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

~~Table of Contents~~

remaining pending matters, plaintiffs representing 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~~estate of the ~~remedy was completed in 2010; however, an additional estimated cost~~decedent are seeking damages under the New Jersey Wrongful Death Act and the New Jersey Survivors Act as well as punitive damages. PSE&G has denied all allegations of ~~$200,000 will be incurred by PSE&G in 2016~~liability. We intend to ~~repair part~~continue to vigorously defend these lawsuits. At this stage of the ~~remedy. Although~~litigation, we are unable to determine or predict the ~~PRP Group has not received a formal Certification~~ultimate outcome of ~~Completion~~any 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.remaining lawsuits.


ITEM 1A.	RISK FACTORS

There are no additional Risk Factors to be added to those disclosed in Part I, Item 1A of our 2015 Annual Report on Form 10-K.

Table of Contents


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 ~~first~~third quarter of 2016.

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




Three Months Ended September 30, 2016	Total Number of Shares Purchased	Average Price Paid per Share
July 1 - July 31	—	$	—
August 1 - August 31	167,430	$	45.21
September 1- September 30	43,000	$	42.85

ITEM 5. OTHER INFORMATION

Certain information reported in the 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 2015 Annual Report on Form ~~10-K.~~10-K and the Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016. References are to the related pages on the ~~Form~~Forms 10-K and 10-Q as printed and distributed.

~~Employee Relations~~Federal Regulation

FERC

Capacity Market Issues-PJM

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 of17, March 31, 2016 ~~our collective bargaining agreements will expire in November~~Form 10-Q page 70 and June 30, 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~~

~~Capacity Market Issues—PJM~~

~~December 31, 2015~~ Form ~~10-K~~10-Q page ~~17.~~80. ~~An emerging issue~~Over the past several years, certain entities in PJM, ~~involves the impact of subsidized generation on RPM market outcomes. In particular,~~namely, FirstEnergy Corp. (FE) and American Electric Power (AEP) have been looking to the Ohio Public Utility Commission (PUCO) to provide financial support arrangements for their coal plants and a nuclear plant (FE). FE and AEP originally 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~~PUCO Staff proposed a payment to support modernization of the ~~PPAs on terms similar to~~distribution system (distribution modernization rider) in the ~~terms sought~~FE case which was ultimately accepted by ~~those companies.~~the PUCO. The Dayton Power and Light Company ~~has~~also recently ~~also~~ filed for ~~comparable arrangements covering~~a distribution modernization rider for the generating plants that it owns.

The ~~subsidies under these contracts~~PUCO proceedings created a concern that subsidized units within the PJM footprint would ~~likely enable the affected generators to~~ submit bids ~~into PJM~~in the capacity ~~markets~~market that are not reflective of their actual operating costs ~~of operation~~ and ~~may prevent uneconomic generating facilities from retiring. Either of these conditions could~~would, in turn, artificially suppress capacity ~~market prices, especially given~~prices. As a result, certain parties requested that ~~PJM’s currently effective~~FERC should direct PJM to expand the “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.~~units.

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.

~~Table of Contents~~

~~Capacity Market Issues—ISO-New England~~Transmission Regulation

December 31, 2015 Form 10-K page ~~18.~~19 and June 30, 2016 Form 10-Q page 80. In ~~March 2015,~~October 2016,PSE&G filed its 2017 Annual Formula Rate Update with FERC which requests approximately $121 million in conjunction with other companies, we filed a petition for review with the D.C. Court of FERC's ruling accepting the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources. On Decemberincreased annual transmission revenues effective January 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 that would allow resource owners to submit bids into the capacity auction reflecting their desire to retire a resource. In April 2016, FERC accepted the proposal2017, subject to ~~a compliance filing by ISO-NE. We remain concerned that the new rules may be disruptive to efficient price formation in the 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~~true-up. For additional information about ~~$39 million per year. Following settlement discussions with FERC Trial Staff, Power agreed to accept an overall~~our transmission formula rate, ~~of $34 million per year, which FERC approved in February 2016. FERC had earlier referred the filing to the FERC Office of Enforcement for its evaluation, which remains pending.~~see Part 1, Item 1. Financial Information—Note 5. Recent Rate Filings.

~~Long-Term Capacity Agreement Pilot Program Act (LCAPP)~~

~~December 31, 2015 Form 10-K page 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 (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 (Fourth Circuit). Both appeals were denied. These denials were challenged on appeal to the U.S. Supreme Court. On April 19, 2016, the U.S. Supreme Court 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 Third Circuit decision.

Transmission Regulation—Transmission Policy Developments

December 31, 2015 Form 10-K page ~~19.~~19, March 31, 2016 Form 10-Q page 71 and June 30, 2016 Form 10-Q page 80. FERC concluded in Order 1000 that the incumbent transmission owner should not always have a Right of First Refusal (ROFR) to construct and own transmission projects in its service territory. We and other companies appealed various aspects of the FERC order approving PJM’s implementation of Order 1000, including the elimination of the ROFR from the PJM Tariff. In ~~April 2013, PJM initiated its first "open window" solicitation process~~July 2016, the D.C. Court dismissed the case, thus upholding FERC’s determination. We have decided not to ~~allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues at Artificial Island in New Jersey.~~ pursue further action on this decision.

In April 2016, PSE&G accepted construction responsibility for the three components of the transmission project that PJM assigned to it, based on having reached agreement with PJM regarding an estimate for the project base cost of $273 million, plus risk and contingency for a total project cost of up to $340 million. PSE&G continues to work with PJM to optimize the scope and cost of the project.

involving upgrades at Artificial Island in New Jersey. On ~~April 1,~~August 5, 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 efficiency of the open window procedureannounced that ~~will permit transmission developers to focus on the 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. 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 includehas suspended the Artificial Island transmission project ~~the Bergen-Linden project in New Jersey~~ and is performing 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~~comprehensive analysis to ~~the Artificial Island and Bergen-Linden projects. Due~~determine a future course of action, which is expected 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.~~completed by February 2017.

Table of Contents

~~Compliance~~—~~Reliability Standards~~

~~December 31, 2015 Form 10-K page 21.~~ In August 2016, FERC issued an order to PJM and the PJM Transmission Owners with respect to their compliance with a previous FERC order (Order 890) that requires transparency in the transmission planning process. The order directs PJM and PJM Transmission Owners to propose revisions to the PJM governing documents to ensure compliance with Order 890 or show cause why they should not do so. The PJM Transmission Owners jointly filed for rehearing of the order to show cause and jointly responded to FERC’s directives. FERC is considering whether to direct the North American Electric Reliability Council (NERC) to develop a new reliability standard to provide security controls for supply chain management associated with the procurement of industrial control system hardware, software, and servicesalso evaluating issues related to ~~bulk electric system operations. If adopted, compliance with~~competitive transmission development processes, including the use of cost containment provisions. PSE&G has argued against the use of cost caps in the assessment of Order 1000 open window project bids. We are unable to predict at this time the results of these ~~new standards would be expected to impose additional obligations~~proceedings and ~~costs~~the impact they will have on ~~transmission providers.~~our business.

State Regulation

~~BPU Cybersecurity Requirements for Regulated Entities~~Solar 4 All Program Extension II

~~In March~~On October 20, 2016, PSE&G submitted a settlement agreement to the BPU ~~issued~~providing for an Order for the regulated electric, natural gas, and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The Order requires these regulated utilities, including PSE&G, to implement a cybersecurity program that defines and implements organization accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems.

~~New Jersey utilities, including PSE&G, are required to be compliant with these requirements by October 31, 2017. We are currently evaluating the requirements. For a discussion~~extension of the ~~risks associated~~existing landfill/brownfield solar program to construct up to 33 MW of grid connected facilities with ~~cyber threats, see Part I, Item 1A. Risk Factors—"Cyber security attacks or intrusions could adversely impact our businesses." in our 2015 Annual Report on~~

~~Form 10-K.~~projected capital expenditures of approximately $80 million through May 2020. This matter is pending approval by the BPU.

Environmental Matters

Air Pollution Control

~~Hazardous~~Cross-State Air ~~Pollutants Regulation~~Pollution Rule (CSAPR)

December 31, 2015 Form 10-K page 24.In ~~February 2012~~, ~~theEnvironmental Protection Agency~~(EPA) published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources under the National Emission Standard for Hazardous Air Pollutants (NESHAP) provisions of the CAA. The MATS established allowable levels for mercury as well as other hazardous air pollutants and went into effect in April 2015. In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plants and remanded the matter back to the D.C. Court. On December 15, 2015, the D.C. Court remanded the MATS to the EPA without vacating the rule. On April 15,September 2016, the EPA ~~released~~published the final ~~Supplemental Finding that considers~~CSAPR Updating Rule to address the ~~materiality of costs~~2008 National Ambient Air Quality Standards for ground-level ozone. The rule establishes more stringent annual ozone season (May 1 through September 30) caps beginning in ~~determining whether to regulate hazardous air pollutants from power plants in response to the U.S. Supreme Court's June ruling.~~May 2017. We do not ~~expect this Supplemental Finding~~anticipate any material impact on our business or financial condition due to ~~impact operation of our facilities.~~the CSAPR.

Table of Contents


ITEM 6.	EXHIBITS

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



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

b. PSE&G:
Exhibit 12.1:		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.2:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

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

Table of Contents

SIGNATURE

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



PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

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

Date: ~~April 29,~~October 31, 2016

Table of 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: ~~April 29,~~October 31, 2016

Table of Contents

SIGNATURE



PSEG POWER LLC
(Registrant)

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

Date: ~~April 29,~~October 31, 2016

7689



Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 http://www.pseg.com	22-2625848
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 http://www.pseg.com	22-1212800
001-34232	PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 http://www.pseg.com	22-3663480



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



		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~~ Early Plant Retirements	18
	Note ~~5. Financing Receivables~~ 4. Variable Interest Entities (VIEs)	1819
	Note ~~6. Available-for-Sale Securities~~ 5. Rate Filings	20
	Note 6. Financing Receivables	21
	Note 7. Available-for-Sale Securities	23
	Note 8. Pension and Other Postretirement Benefits (OPEB)	2628
	Note 8.9. Commitments and Contingent Liabilities	2730
	Note ~~9. Changes in Capitalization~~ 10. Debt and Credit Facilities	3537
	Note ~~10.~~11. Financial Risk Management Activities	3539
	Note ~~11.~~12. Fair Value Measurements	4045
	Note ~~12.~~13. Other Income and Deductions	4753
	Note ~~13.~~14. Income Taxes	4754
	Note ~~14.~~15. Accumulated Other Comprehensive Income (Loss), Net of Tax	4855
	Note ~~15.~~16. Earnings Per Share (EPS) and Dividends	5159
	Note ~~16.~~17. Financial Information by Business Segments	5260
	Note ~~17.~~18. Related-Party Transactions	5361
	Note ~~18.~~19. Guarantees of Debt	5563
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	5766
	Executive Overview of 2016 and Future Outlook	5766
	Results of Operations	6374
	Liquidity and Capital Resources	6579
	Capital Requirements	6881
	Accounting Matters	6882
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	6882
Item 4.	Controls and Procedures	6983

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	6983
Item 1A.	Risk Factors	7083
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	7084
Item 5.	Other Information	7084
Item 6.	Exhibits	7386
	Signatures	7487




	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




	September 30, 2016			December 31, 2015
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	450		$	394
Accounts Receivable, net of allowances of $67 in 2016 and 2015	1,031			1,068
Tax Receivable	23			305
Unbilled Revenues	180			197
Fuel	366			463
Materials and Supplies, net	591			513
Prepayments	145			135
Derivative Contracts	149			242
Regulatory Assets	253			164
Other	21			13
Total Current Assets	3,209			3,494
PROPERTY, PLANT AND EQUIPMENT	38,225			35,494
Less: Accumulated Depreciation and Amortization	(9,421		)	(8,955		)
Net Property, Plant and Equipment	28,804			26,539
NONCURRENT ASSETS
Regulatory Assets	3,124			3,196
Long-Term Investments	1,066			1,233
Nuclear Decommissioning Trust (NDT) Fund	1,857			1,754
Long-Term Tax Receivable	177			171
Long-Term Receivable of Variable Interest Entity (VIE)	509			495
Other Special Funds	243			227
Goodwill	16			16
Other Intangibles	154			102
Derivative Contracts	86			77
Other	243			231
Total Noncurrent Assets	7,475			7,502
TOTAL ASSETS	$	39,488		$	37,535




	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




	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




	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




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




	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




Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	134	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	83	64	%	1,044	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	55	17	%	1,711	Coal	CCC (B)	REMA
Conemaugh Station Units 1 and 2	PA	$	55	17	%	1,711	Coal	CCC (B)	REMA
Shawville Station Units 1, 2, 3 and 4	PA	$	109	100	%	603	Coal (A)	CCC (B)	REMA


(A)	REMA notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the late fall of 2016 with the ability to use natural gas.




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


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




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


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




		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




	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 in the 2016 BGS auction year ~~will become~~became effective on June 1, 2016 when the 2013 BGS auction agreements ~~expire.~~expired.




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


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


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


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


(D)	The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective CP Programs. As of September 30, 2016, PSEG had $255 million outstanding under its CP Program at a weighted average interest rate of 0.79%. As of September 30, 2016, PSE&G had no amounts outstanding under its CP Program.




	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




	As of September 30, 2016 (A)
	Power									PSE&G			PSEG		Consolidated
	Not Designated									Not Designated			Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Energy- Related Contracts			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	432		$	(283	)	$	149		$	—		$	—	$	149
Noncurrent Assets	305			(219		)	86			—			—		86
Total Mark-to-Market Derivative Assets	$	737		$	(502	)	$	235		$	—		$	—	$	235
Derivative Contracts
Current Liabilities	$	(314	)	$	278		$	(36	)	$	(4	)	$	—	$	(40	)
Noncurrent Liabilities	(219		)	206			(13		)	—			—		(13		)
Total Mark-to-Market Derivative (Liabilities)	$	(533	)	$	484		$	(49	)	$	(4	)	$	—	$	(53	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	204		$	(18	)	$	186		$	(4	)	$	—	$	182




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




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




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	)




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	—	—




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 $114 million with PSE&G. The remaining net exposure of $33 million is with a non-affiliated power purchaser which is an investment grade counterparty.