table of ~~$500 million of MTN in the latter half of 2014 and a $4 million decrease due to the partial redemption of securitization debt.~~contents

Electric distribution revenues increased$3 $45 million due primarily to higher sales volumes of $37 million, an

increase in Capital Stimulus Infrastructure Program (CIP) ~~related~~ revenues of $2$5 million due to the inclusion of CIP II in base rates beginning in July 2014 and $3 million of higher revenues from GPRC.

Gas distribution revenues increased $9 million due primarily to $16 million from higher sales volumes and an increase in CIP revenues of ~~$1 million.~~

$2 million, partially offset by lower Weather Normalization Charges (WNC) revenue of $9 million due to colder weather in 2015 compared to 2014.

Commodity Revenuedecreased~~$153~~ $102 million due to lower Gas revenues offset partially by higher Electric revenues. Commodity revenue for both electric and ~~Gas revenues. This~~gas is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of ~~basic generation service (BGS)~~BGS and BGSS to retail customers.

~~Electric~~Gas revenues decreased$4 $209 million due primarily to ~~$20 million~~ in lower ~~revenues~~ from collection of Non-Utility Generation Charges (NGC) and lower sales volumes of Non-Utility Generation (NUG) energy, partially offset by $16 million of higher BGS revenues. BGS revenues increased $27 million or 6%~~, due to higher sales volumes, partially offset by $11 million of lower BGS prices.~~

~~Gas revenues~~ ~~decreased$149 million~~ ~~due primarily to~~ ~~lower~~ BGSS prices of ~~$220~~$290 million,, of which ~~$162~~$215 million was due to lower residential rates resulting from $133 million in residential bill credits and $82 million of lower commodity prices, partially offset by higher BGSS volumes of ~~$71~~$81 million due to colder weather in 2015.

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

Clause Revenuesdecreased~~$30~~ $75 million due primarily to lower ~~Margin Adjustment Clause (MAC)~~MAC revenue of ~~$18~~$24 million, lower STC of $24 million, lower SBC of $23 million and lower ~~Societal Benefit Charges (SBC)~~SPRC of ~~$14 million, partially offset by higher Securitization Transition Charges (STC) of $2~~$4 million. The changes in the MAC, STC, SBC and ~~STC~~SPRC amounts were entirely offset by the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on MAC, STC, SBC or ~~STC~~SPRC collections.

Other Operating Revenues experienced no material change.

Operating Expenses

Energy Costsdecreased~~$153~~ $102 million. due to lower Gas costs partially offset by higher Electric costs. This is entirely offset by decreased Commodity Revenue.

~~Electric costs declined~~ ~~$4 million~~ ~~or 1% due to~~ ~~$47 million~~ of ~~decreased~~ ~~deferred cost recovery largely offset by $28 million of~~ ~~higher~~ ~~BGS and NUG prices and $15 million in~~ ~~higher~~ ~~BGS volumes, partially offset by lower NUG volumes. BGS volumes increased~~ 5% ~~due primarily to reverse customer migration.~~

Gas costs decreased~~$149~~ $209 million or 27% due to a ~~$220~~$290 million or ~~40%~~37% decline in prices, partially offset by ~~$71~~$81 million or ~~13%~~10% in higher sales volumes due to colder than normal weather.

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

Operation and Maintenance decreased ~~$50~~$19 million, of which the most significant components were

a ~~$40~~$63 million decrease in costs related primarily to a net decrease in SBC, MAC, GPRC, CIP, SPRC and ~~Green Program Recovery Charges (GPRC).~~STC. Due to the nature of the SBC, MAC, ~~CIP~~SPRC and ~~GPRC~~STC clause mechanisms, these are entirely offset in revenues,

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

~~a $4~~

decreased injuries and damages of $6 million net decrease in operational expenses due to reductions in damage claims of $6 million and storm-related costs of $3 million, partially offset by increases in transmission related costs of $2 million and general operating expenses of $3 million,,

•partially offset by a $9$28 million increase in pension and OPEB expenses,

•increased transmission operating expenses of $10 million,

•$8 million of higher appliance service costs,

increased bad debt expense of $6 million, and

an $8 million increase in other general operating expenses.

Depreciation and Amortization increased $2030 million due primarily to a $1542 million increase in depreciation of additional plant in service related to increased investments in various transmission and distribution projects, ~~and an increase~~offset by a decrease of $5$13 million in amortization of Regulatory ~~Assets.~~Assets which is fully offset in Clause Revenues.

Other Income and (Deductions) increased $3$16 million due primarily to an increase in ~~Allowance for Funds used During Construction.~~AFUDC.

Interest Expense ~~increased $1~~decreased $3 million due primarily to ~~a $9 million increase related to issuance~~partial redemption of ~~$1,250 million~~securitization debt partially offset by net issuances of Medium Term Notes ~~(MTN)~~ in 2015 and the latter half of ~~2014, partially offset by a $4 million decrease related to maturities~~2014.

Income Tax Expense increased $1443 million due primarily to higher pre-tax income.

Power

Three Months Ended
Increase/
(Decrease)

March 31,
2015 2014 2015 vs. 2014
Millions Millions %
Operating Revenues $ 1,725
$ 1,700
$ 25
1

Energy Costs 893
1,044
(151 ) (14 )
Operation and Maintenance 172
302
(130 ) (43 )
Depreciation and Amortization 76
72
4
6

Income from Equity Method Investments 3
4
(1 ) (25 )
Other Income (Deductions) 18
23
(5 ) (22 )
Other-Than-Temporary Impairments 5
2
3
150

Interest Expense 31
32
(1 ) (3 )
Income Tax Expense 234
111
123
111




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2015		2014		2015 vs. 2014					2015		2014		2015 vs. 2014
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,096	$	1,138	$	(42	)	(4	)	$	3,846	$	3,824	$	22		1
Energy Costs	367		472		(105		)	(22	)	1,669		2,036		(367		)	(18	)
Operation and Maintenance	263		242		21			9		748		871		(123		)	(14	)
Depreciation and Amortization	75		71		4			6		226		215		11			5
Income from Equity Method Investments	3		4		(1		)	(25	)	11		11		—			—
Other Income (Deductions)	11		50		(39		)	(78	)	77		110		(33		)	(30	)
Other-Than-Temporary Impairments	30		10		20			N/A		45		14		31			N/A
Interest Expense	30		31		(1		)	(3	)	94		92		2			2
Income Tax Expense	139		144		(5		)	(3	)	445		277		168			61

Three Months Ended September 30, 2015 as Compared to 2014

Operating Revenues decreased $42 million due to changes in generation, gas supply and other operating revenues.

Gas Supply Revenues decreased $44 million due primarily to

a decrease of $14 million in sales under the BGSS contract substantially comprised of lower average sales prices, and

a decrease of $30 million due to lower average sales prices and volumes to third party customers.

Generation Revenues increased $3 million due primarily to

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

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

Other Operating Revenues decreased ~~March 31,~~$1 milliondue tolower fees received from fuel management and power supply management contracts with LIPA.

Operating Expenses

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

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

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

Operation and Maintenance increased $21 million due primarily to

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

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

Depreciation and Amortization increased $4 million due primarily to a higher depreciable fossil and nuclear asset base.

Income from Equity Method Investments experienced no material change.

Other Income and (Deductions) decreased $39 million due primarily to lower net realized gains from the NDT Fund.

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

Interest Expense experienced no material change.

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

Nine Months EndedSeptember 30, 2015 as Compared to 2014

Operating Revenues increased $2522 million due to changes in generation, gas supply and other operating revenues.

Generation Revenuesincreased~~$108~~ $203 million due primarily to

higher net revenues of ~~$127~~$232 million due primarily to ~~lower~~MTM gains in 2015 compared to MTM losses ~~in 2015 resulting from higher price increases on forward positions~~ in 2014, partially offset by lower energy volumes sold in ~~PJM~~the NE region and ~~NE regions at~~ lower average realized prices in the NE and New York (NY) regions,

an increase of ~~$81~~$78 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM and NE regions, and

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

partially offset by a ~~net~~ decrease of ~~$98~~$155 million due primarily to lower capacity revenues resulting from lower average auction prices coupled with lower ancillary and operating reserve revenues in the PJM region.

Gas Supply Revenues decreased~~$83~~ $182 million due primarily to

a net decrease of ~~$48~~$86 million in sales under the BGSS contract, substantially comprised of lower average sales prices, partially offset by higher ~~sales~~ volumes due to colder average temperatures in the 2015 winter heating season, and

a decrease of ~~$35~~$96 million due to lower average sales prices and volumes to third party customers.

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

Operating Expenses

Generation costs decreased~~$35~~ $149 million due primarily to lower fuel costs, reflecting lower average realized natural gas and oil prices and the utilization of lower volumes of ~~oil.~~coal, coupled with MTM gains in 2015 as compared to MTM losses in 2014. These decreased costs were partially offset by the utilization of higher volumes of natural gas, coupled with higher congestion costs in the PJM region.

Gas costs decreased~~$116~~ $218 million, related to lower average gas inventory costs on both obligations under the BGSS contract and sales to third parties, coupled with lower volumes sold to third parties. This was partially offset by higher volumes sold under the BGSS contract due to colder average temperatures during the 2015 winter heating season.

Operation and Maintenance decreased $~~130~~123 million due primarily to

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

a net decrease of ~~$18~~$48 million related to our fossil plants, largely due to higher costs incurred in 2014 for planned outage costs, including maintenance and installation of upgraded technology at our Linden combined cycle gas generating plant, ~~partly~~partially offset by planned outage costs in 2015 at our ~~combined cycle Bergen and~~ Bethlehem Energy Center generating ~~plants,~~plant and installation of upgraded technology at our combined cycle Bergen plant,

6474

partially offset by an increase of ~~$14~~$48 million at our nuclear facilities, primarily due to ~~the preparation work for a~~higher planned outage costs at our 100%-owned Hope Creek and 50%-owned Peach Bottom 3 nuclear ~~plant.~~plants in 2015 as compared to our 57%-owned Salem nuclear unit 2 in 2014, and

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

Depreciation and Amortization increased $411 million due primarily to a higher depreciable fossil and nuclear asset base.

Income from Equity Method Investments experienced no material change.

Other Income and (Deductions) decreased $5 $33 million due primarily to lower net realized gains from the NDT Fund ~~realized losses.~~partially offset by a $28 million insurance recovery related to Superstorm Sandy.

Other-Than-Temporary Impairments increased $3$31 million due to an increase in impairments of the NDT Fund.

Interest Expense experienced no material change.

Income Tax Expense increased $~~123~~168 million in 2015 due primarily to higher pre-tax income.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.

Operating Cash Flows

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

For the ~~three~~nine months ended ~~March 31,~~September 30, 2015, our operating cash flow increased $~~563~~692 million as compared to the same period in 2014. The net change was due primarily to ~~higher tax payments in 2014 at the parent company and Energy Holdings and~~ the net changes from PSE&G and Power as discussed below.

PSE&G

PSE&G’s operating cash flow increased $98175 million from $~~579~~1,343 million to $~~677~~1,518 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2015, as compared to the same period in 2014, due primarily to higher earnings, a ~~$143~~$203 million ~~higher net~~reduction in tax ~~refund~~payments, $37 million reduction in vendor payments and ~~increased customer collections of $122 million.~~a $25 million decrease in prepayments. These amounts were partially offset by a decrease of ~~$198~~$232 million due to a change in regulatory deferrals primarily driven by the return of prior year overcollections to customers for BGSS gas costs, Gas Weather Normalization charges and ~~Non Utility~~Non-Utility Generation charges.

Power

Power’s operating cash flow increased $~~176~~448 million from $~~674~~1,110 million to $~~850~~1,558 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2015, as compared to the same period in 2014, primarily due to higher earnings and a reduction in margin deposit requirements, ~~and higher earnings,~~ partially offset by an increase of ~~$98~~$197 million in tax payments.

Short-Term Liquidity

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

The commitments under our ~~$4.3~~$4.2 billion credit facilities are provided by a diverse bank group. As of ~~March 31,~~September 30, 2015, our total available credit capacity was ~~$4.1~~$3.9 billion.

As of ~~March 31,~~September 30, 2015, no single institution represented more than 8%7% of the total commitments in our credit facilities.

As of ~~March 31,~~September 30, 2015, our total credit capacity was in excess of our anticipated maximum liquidity requirements.

Each of our credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries' liquidity needs. Our total credit facilities and available liquidity as of ~~March 31,~~September 30, 2015 were as follows:

6575

As of March 31, 2015
Company/Facility
Total
Facility
Usage
Available
Liquidity

Expiration
Date
Primary Purpose
Millions
PSEG
  5-year Credit Facility $ 500
$ 8
$ 492
Apr 2019 Commercial Paper (CP) Support/Funding/Letters of Credit
  5-year Credit Facility (A) (B) 500
—
500
Mar 2018 CP Support/Funding/Letters of Credit
Total PSEG $ 1,000
$ 8
$ 992

PSE&G
5-year Credit Facility (A) (C) $ 600
$ 14
$ 586
Mar 2018 CP Support/Funding/Letters of Credit
Total PSE&G $ 600
$ 14
$ 586

Power
  5-year Credit Facility $ 1,600
$ 178
$ 1,422
Apr 2019 Funding/Letters of Credit
  5-year Credit Facility (A) (D) 1,000
—
1,000
Mar 2018 Funding/Letters of Credit
  Bilateral Credit Facility 100
—
100
Sept 2015 Letters of Credit
Total Power $ 2,700
$ 178
$ 2,522

Total $ 4,300
$ 200
$ 4,100




	As of September 30, 2015
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facility	$	500	$	10	$	490	Apr 2019	Commercial Paper (CP) Support/Funding/Letters of Credit
5-year Credit Facility (A)	500		—		500		Apr 2020	CP Support/Funding/Letters of Credit
Total PSEG	$	1,000	$	10	$	990
PSE&G
5-year Credit Facility (B)	$	600	$	34	$	566	Apr 2020	CP Support/Funding/Letters of Credit
Total PSE&G	$	600	$	34	$	566
Power
5-year Credit Facility	$	1,600	$	201	$	1,399	Apr 2019	Funding/Letters of Credit
5-year Credit Facility (C)	1,000		14		986		Apr 2020	Funding/Letters of Credit
Total Power	$	2,600	$	215	$	2,385
Total	$	4,200	$	259	$	3,941


~~(A)~~	~~In April 2015, expiration dates of these facilities were extended to April 2020.~~


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


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


~~(D)~~	~~Power facility will be reduced by $48 million in April 2016 and $24 million in March 2018.~~

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

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

(C)Power facility will be reduced by $48 million in April 2016 and $24 million in March 2018.

Long-Term Debt Financing

PSE&G has ~~$300 million of 2.70%, Series G, Medium Term Notes maturing in May 2015 and~~ $171 million of 6.75%, Mortgage Bonds maturing in January 2016. Power has $300 million of 5.50% Senior Notes maturing in December ~~2015.~~2015 and $303 million of 5.32% Senior Notes and $250 million of 2.75% Senior Notes maturing in September 2016.

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

Common Stock Dividends

On ~~February 17,~~July 21, 2015, our Board of Directors approved a $0.39 per share common stock dividend for the ~~first quarter of 2015. On April 21, 2015, our Board of Directors declared a quarterly dividend of $0.39 per share of common stock for the second~~third quarter of 2015. This reflects an indicated annual dividend rate of $1.56 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. Note 15. Earnings Per Share (EPS) and Dividends.

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks ~~assigned to ratings~~ are ~~as follows: stable, negative (Neg)~~shown for Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or ~~positive (Pos).~~Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies' ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

In May 2015, Moody’s published research reports on PSEG, PSE&G and Power and the existing ratings and outlooks were unchanged. In May 2015, S&P published updated research reports and revised the outlook to stable from positive for PSEG’s Corporate Credit Rating and Power’s Senior Notes. S&P also affirmed the senior unsecured rating of BBB+ at Power and the mortgage bond rating of A at PSE&G. In September 2015, Moody's published an updated research report on PSEG and revised the outlook to positive from stable. In September and October 2015, Fitch published full rating reports on PSEG and Power leaving ratings and outlooks unchanged. As of October 2015, PSEG has ended a contractual agreement with Fitch to provide credit rating services for PSEG, PSE&G and Power.

6676




	Moody’s (A)			S&P (B)	~~Fitch (C)~~
PSEG
Outlook	Positive		Stable
Commercial Paper	P2		A2
PSE&G
Outlook	Stable		Stable	~~Positive~~
Mortgage Bonds	Aa3	~~Stable~~	A
Commercial Paper	P2	P1		A2	F2
~~PSE&G~~			Power
Outlook	Stable			~~Positive~~	~~Stable~~
~~Mortgage Bonds~~	~~Aa3~~			A	A+
~~Commercial Paper~~	P1			A2	F2
~~Power~~
~~Outlook~~	~~Stable~~			~~Positive~~	Stable
Senior Notes	Baa1			~~BBB+~~	BBB+


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


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


~~(C)~~	~~Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1+ (highest) to D (lowest) for short-term securities.~~

CAPITAL REQUIREMENTS

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

In September 2015, we reached a settlement in principle with the BPU Staff and the New Jersey Division of Rate Counsel regarding our GSMP, through which, if approved, we will invest $905 million over the next three years to modernize PSE&G’s gas systems.

In June 2015, we acquired a development project to construct a 755 MW gas-fired combined cycle generating station in Maryland (Keys Energy Center). We plan to start constructing this year with expected completion in 2018 at an estimated investment of $825 million - $875 million.

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

The aforementioned estimated project expenditures related to the GSMP at PSE&G and the Maryland and Woodbridge, New Jersey projects at Power are not included in the $8.7 billion three-year capital forecast table in our 2014 Form 10-K. There were no material changes to our projected capital expenditures at ~~PSE&G, Power and~~ Services as compared to amounts disclosed in our 2014 Form 10-K.

In February 2015, we filed a petition with the BPU seeking authority to invest $1.6 billion over the next 5 years, or about $320 million per year, to modernize PSE&G’s gas systems. The estimated project expenditures related to this petition are not included in our $8.7 billion three-year capital forecast table in our 2014 Form 10-K. For additional information, see Part II, Item 5. Other Information—Gas System Modernization Program.

PSE&G

During the ~~three~~nine months ended ~~March 31,~~September 30, 2015, PSE&G made capital expenditures of ~~$601~~$1,946 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$26~~$82 million, which are included in operating cash flows.

Power

During the ~~three~~nine months ended ~~March 31,~~September 30, 2015, Power made capital expenditures of ~~$94~~$597 million, excluding $45200 million for nuclear fuel, primarily related to various projects at its fossil and nuclear generation ~~stations.~~stations, including the new Maryland generating station noted above.

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 2015, MTM VaR remained relatively ~~stable.~~stable between low of $8 million to high of $14 million at 95% confidence level. The range of VaR was narrower for the three months ended ~~March 31,~~September 30, 2015 as compared with the year ended December 31, 2014.

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

Average for the Period $ 20
$ 30

High $ 26
$ 195

Low $ 15
$ 14

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 31
$ 56

Average for the Period $ 31
$ 46

High $ 40
$ 306

Low $ 24
$ 22




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

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 2015 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 3.3 of Part I of the 2014 Annual Report on Form 10-K, see see Part I, Item 1. Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.


ITEM 1A.	RISK FACTORS

There are no additional Risk Factors to be added to those disclosed in Part I Item 1A of our 2014 Annual Report on Form 10-K.


ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the ~~first~~third quarter of 2015.

Three Months Ended March 31, 2015
Total Number
of Shares
Purchased

Average
Price Paid
per Share

January 1 - January 31 —
$ —

February 1- February 28 731,784
$ 42.80

March 1 - March 31 70,078
$ 42.37




Three Months Ended September 30, 2015	Total Number of Shares Purchased	Average Price Paid per Share
July 1 - July 31	—	$	—
August 1- August 31	189,018	$	42.23
September 1- September 30	20,000	$	38.97

ITEM 5. OTHER INFORMATION

Certain information reported in the 2014 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2014 Annual Report on Form ~~10-K.~~10-K and the Quarterly Report on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015. References are to the related pages on the ~~Form~~Forms 10-K and 10-Q as printed and distributed.

Federal Regulation

FERC

Regulation of Wholesale Sales—Generation/Market Issues

Capacity Market ~~Issues~~—Issues—PJM

December 31, 2014 Form 10-K page 16, March 31, 2015 Form 10-Q page 69 and June 30, 2015 Form 10-Q page 78. The RPM is the locational installed capacity market design for the PJM region, including a forward auction for installed capacity. There is currently significant activity concerning two topics: (i) the future role of DR in the RPM market in light of a decision by the D.C. Circuit Court of Appeals (D.C. Court) holding that DR is not a FERC-jurisdictional product, and (ii) PJM’s development of a new capacity product called a Capacity Performance (CP) product.

In May 2014, the D.C. Court held that DR is not a FERC-jurisdictional product, thereby calling into question DR resources’ ability to participate in either the energy or capacity markets in the future. The U.S. Supreme Court is currently considering whether to hear this case. A decision not to hear the case or a ruling on merits of upholding the lower court decision would be expected to have a significant impact on the amount and manner of participation by DR in PJM's markets. However, unless the U.S. Supreme Court declines to hear the case, it appears that DR will be allowed to participate in RPM for the upcoming base residual auction as supply resources under the currently effective rules.

On December 12, 2014, PJM filed a proposal at ~~the~~ FERC to implement a CPCapacity Performance (CP) mechanism. Under this mechanism, PJM created a more robust capacity product definition with enhanced incentives for performance during emergency conditions and

significant penalties for non-performance. On ~~March 31,~~June 9, 2015, ~~the~~ FERC issued a “deficiency letter” requiring PJM to submit additional information about its filing. Since that time, PJM has (i) sought to delay the residual capacity auction, currently scheduled to begin on May 11, 2015, for between 30 and 75 days, but no later than mid-August, to provide additional time for approval and implementation ofconditionally accepted the CP proposal; and (ii) responded to the March 31, 2015 deficiency letter in a manner that, if accepted by the FERC, would largely preserve the core elements of the proposal. We have filed in support of PJM's proposals. On April 24, 2015, the FERC approved PJM’s request to delay the upcoming base residual auction. However, we are unable to predict whether the FERC will approve the CP proposal. This new product, if accepted by the FERC,mechanism which will be phased in over the next few years, with ~~full implementation~~the participation of both the CP product and a base product that has less rigorous performance obligations. The CP mechanism was implemented for the 2015 base residual auction (covering the 2018-2019 Delivery Year) which concluded on August 21, 2015. The CP product will be implemented fully for the 2020-2021 Delivery Year. ~~PJM’s approach may provide~~Based upon the August 2015 base residual auction results, the CP mechanism appears to have provided the opportunity for enhanced capacity market revenue streams for ~~Power. However,~~Power but future impacts cannot be assured. Further, there may be requirements for additional investment and there are additional performance ~~risks, as well as risks associated~~risks.

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

Price Formation Initiatives

Power has been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for setting prices for energy in the day-ahead and real-time markets administered by PJM and other system operators. A recent development which we consider positive involves a September 17, 2015 FERC notice of proposed rulemaking on two issues: aligning settlements with ~~our ability~~dispatch intervals (more granular “5-minute pricing” in real-time markets) and improving real-time scarcity pricing. Comments made by FERC commissioners stressed these two items are intended to ~~bid in a manner that would ensure recovery of any capital investment.~~

~~Capacity Market Issues~~—~~ISO-New England (ISO-NE)~~

~~December 31, 2014 Form 10-K page 17.~~ ~~ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and DR. The market design consists~~be the first of a ~~forward-looking auction for installed capacity, employing an administratively determined demand curve, that is intended to recognize the locational value~~series of ~~resources~~steps FERC will take on the system and contains incentive mechanisms to encourage availability during stressed system conditions. One aspect of the current market design that we do disagree with is the exemption from the Minimum Offer Price Rule in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources. We believe that the exemption is unduly discriminatory and will artificially suppress capacity prices. On March 31, 2015, in conjunction with other companies, we filed a petition for review with the D.C. Court of FERC's ruling accepting the exemption.

We anticipate that ISO-NE will complete an ongoing stakeholder process addressing zonal demand curves for its capacity market in the near future and will seek approval of those curves at the FERC. These curves will have a significant impact upon the revenues our generation can expect to receive in the capacity market in New England. Also under consideration in the ISO-NE stakeholder process are proposals that would place restrictions or impose penalties on generators wishing to retire. We believe that, if adopted, these proposals could have a disruptive effect on efficientenergy price formation in the ~~capacity market.~~future.

~~Capacity Market Issues~~—~~NYISO~~Reactive Power Rates

~~December 31, 2014 Form 10-K page 17.~~ ~~NYISO operates~~In June 2015, Power submitted a ~~short-term capacity market~~tariff filing with FERC to increase Power’s rates for reactive supply and voltage control service from approximately $27 million per year to about $39 million per year. The rates were last adjusted in 2008 and since that ~~provides a forward price signal only for six months into~~time various generating units have been de-activated, activated or improved with the ~~future. Prior~~net impact supportive of an upward rate adjustment. FERC accepted Power’s rate filing increase to ~~2013,~~become effective in January 2016, subject to refund, hearing and settlement procedures. FERC also referred the ~~NYISO capacity model had recognized only two separate zones that potentially may separate in price: New York City and Long Island. In August 2013,~~filing to the FERC issued an order approving a third capacity zone that would encompass the super zone that includes the lower Hudson Valley and New York City which took effect on May 1, 2014. On April 2, 2015, the Second Circuit CourtOffice of ~~Appeals upheld the FERC’s decision.~~

~~Matters have been pending before~~Enforcement for its evaluation. Power has participated in two settlement conferences to date with the FERC concerning potential changes to the NYISO capacity markets, including rules to govern payments and bidding requirements for generators proposing to exit the market but required to remain in service for reliability reasons. On March 19, 2015, the FERC issued an order which held that units receiving special reliability payments could properly take those payments into account in formulating capacity market bids. We believe that this ruling could have impacts on efficient price formation in the capacity market and could artificially suppress capacity market outcomes. On April 20, 2015, a trade association of which we are a member filed for rehearing by the FERC of this ruling.trial staff.

~~Transmission Regulation~~—~~Transmission Policy Developments~~Long-Term Capacity Agreement Pilot Program Act (LCAPP)

December 31, 2014 Form 10-K page 18. In 2011, the State of New Jersey enacted the LCAPP to subsidize approximately 2,000 MW of new natural gas-fired generation. The ~~FERC concluded~~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 ~~Order 1000~~New Jersey found that the ~~incumbent transmission owner should not always~~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. 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. Both appeals were denied, with the U.S. Fourth Circuit Court of Appeals (Fourth Circuit) denying the appeal regarding the State of Maryland’s action in June 2014 and the U.S. Third Circuit Court of Appeals denying the LCAPP appeal in September 2014. These denials have ~~a ROFR~~been challenged on appeal to ~~construct and own transmission projects in its service territory. We and other companies appealed Order 1000 but this~~the U.S. Supreme Court. In October 2015, the U.S. Supreme Court announced that it would consider the appeal was denied last year. The current PJM rules retain carve-outs for projects that will continue to default to incumbents for construction responsibility, including projects being built on existing right-of-way and whose construction would interfere with incumbents’ use of their right-of-way. While these carve-outs ameliorate the impacts of the Order 1000 ruling, we and several other companies appealed various aspects of the FERC order approving PJM’s implementation of Order 1000 on the grounds that the FERC had not met the requisite legal burden in eliminating the ROFR from the PJM Tariff. This appeal remains pending in federal court. Moreover, on April 14, 2015, the D.C.Fourth Circuit's decision involving Maryland. The U.S. Supreme Court ~~reviewing another FERC decision addressing the issue of pre-Order 1000 participation by a non-incumbent transmission developer in the PJM transmission planning process (a~~is expected to consider this case in ~~which we are an appellant) found that such review was no longer needed due to~~2016. We cannot predict the ~~intervening events~~outcome of ~~Order 1000. At the same time, however, that court acknowledged that our pending appeal remained a “live” controversy.~~this appeal.

Transmission Regulation—Transmission Policy Developments

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

~~PJM's first action toward complying with Order 1000 began in~~In April 2013, ~~when it~~PJM initiated its first "open window" solicitation process to allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues at Artificial ~~Island. On~~Island off the shore of New Jersey. In April ~~28,~~ 2015, the PJM staff advised stakeholders that it ~~intends~~intended to recommend a transmission project to the PJM Board of Managers consisting of various components to be constructed by LS Power, PSE&G and Potomac Holding Company. ~~Based~~On July 29, 2015, the PJM Board approved the PJM staff's recommendation. In August 2015, PJM sent PSE&G a Construction Responsibility Letter (to which PSE&G will be responding on ~~PJM’s presentation,~~November 9) awarding PSE&G ~~expects the total construction cost~~three components of

the project, ~~components that would be assigned~~estimated by PJM to ~~it, if~~cost approximately $126 million. PSE&G is currently in discussions with PJM regarding the ~~recommendation is approved, to range between $100 million and $130 million. The recommendation will be open to public comment until May 29, 2015. The PJM Board is expected to act on~~accuracy of this estimate given the ~~recommendation in either June or July. We are currently reviewing the PJM staff recommendation. Our~~complexities associated with construction work at Artificial Island. In a related matter, FERC denied a complaint ~~against PJM at the FERC, asserting~~filed by PSE&G contending that PJM had failed to follow its ~~tariff~~ rules ~~governing~~during the Artificial Island ~~“open window”~~solicitation process. PSE&G, however, continues to work with both PJM and its stakeholders to improve the rules governing open window processes in PJM.

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

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

In June 2015, a transmission developer filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process ~~still remains~~for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. According to the complaint, PJM and certain transmission owners wrongfully inflated the scope and associated costs of mitigation work needed to accommodate the developer’s proposal in order to prevent it from pursuing its projects. Although not named as a respondent in the complaint, PSE&G is identified as one of the companies claimed to have been involved. In July 2015, PJM filed a response, which included a supporting affidavit from PSE&G, contesting the allegations. The matter is pending. ~~For additional information, see Part I, Item 2. MD&A—Transmission Planning.~~

State Regulation

Gas System Modernization Program (GSMP)

~~Compliance~~March 31, 2015 Form 10-Q page 71. —In September 2015, PSE&G reached a settlement in principle with the BPU Staff and the New Jersey Division of Rate Counsel regarding PSE&G’s GSMP through which, if approved, PSE&G will invest $905 million over the next three years to modernize its gas system. The settlement in principle will enable the utility to replace up to 510 miles of gas mains and 38,000 service lines over a three-year period, with cost recovery at a 9.75% rate of return on equity on the first $650 million of the investment through an accelerated recovery mechanism. Under the settlement in principle, PSE&G will seek recovery of the remaining $255 million of investment in its next base rate case, which is to be filed no later than November 1, 2017.

Connecticut Rate Filing

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

Environmental Matters

Air Pollution Control

Demand Response (DR) Reciprocating Internal Combustion Engines (RICE) Litigation

December 31, 2014 Form 10-K page ~~19.~~23 and June 30, 2015 Form 10-Q page 79. ~~In the first quarter of 2014,~~In March 2013, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, we retained outside counsel to assist in the conduct of an investigation into the matter. As the investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. We informed the FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for its peaking units. Power continues to implement procedures to help mitigate the risk of similar issues occurring in the future. On September 2, 2014, the FERC Staff initiated a preliminary, non-public staff investigation into the matter. This investigation, which is ongoing, could result in the FERC seeking disgorgement of any over-collected amounts, civil penalties and non-financial remedies.

During the three months ended March 31, 2014, based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. It is not possible, at this time, to reasonably estimate the potential range of loss or full impact or predict any resulting penalties or other costs associated with this matter, or the applicability of mitigating factors. As new information becomes available or future developments occur in this investigation, it is possible that Power will record additional estimated losses and such additional losses may be material.

~~State Regulation~~

~~Energy Strong Program~~

~~December 31, 2014 Form 10-K page 21~~. ~~Our Energy Strong Program encompasses infrastructure investments of $1.22 billion that we will make to our BPU jurisdictional electric and gas system to improve resiliency for the future.~~

~~In February 2015, the BPU approved our initial Energy Strong cost recovery petition which provides for an estimated annual revenue increase of $1.1 million effective March 1, 2015.~~

In March 2015, PSE&G filed its second Energy Strong cost recovery petition seeking BPU approval to recover in base rates capitalized Energy Strong investment costs expected to be in service by May 31, 2015. The filing requests estimated annual increases in electric revenues of $6 million and gas revenues of $17 million effective September 1, 2015, consistent with the BPU Order of approval of the Energy Strong program.

~~Gas System Modernization Program (GSMP)~~

~~In February 2015, we~~ filed a petition ~~with~~at the ~~BPU seeking authority~~EPA challenging the National Emission Standards for Hazardous Air Pollutants (NESHAP) for RICE issued in January 2013. Among other things, the final EPA rule includes two exemptions that allow owners and operators of stationery emergency RICE to ~~invest approximately $1.6 billion over~~operate their engines without the ~~next five years, or about $320 million~~installation and operation of emission controls (1) as part of an emergency DR program for 100 hours per year (100 hour exemption) or (2) as part of a financial arrangement with another entity per specified restrictions in non-emergency situations for 50 hours per year (50 hour exemption). This waiver of NESHAP standards results in disparate treatment of different generation technology types. In its appeal, Power sought more stringent emission control standards for RICE to ~~modernize PSE&G’s gas systems. PSE&G’s GSMP would include~~support more competitive markets, particularly the ~~replacement of an average of approximately 160 miles of cast iron~~PJM capacity market. In August 2014, the EPA denied the March 2013 petition and ~~unprotected steel gas mains and about 11,000 unprotected steel service lines~~in October 2014, Power appealed the EPA's denial to ~~homes and businesses per each of five years. The mains and service lines would be replaced with stronger, more durable plastic piping, reducing~~ the potential for leaks and release of methane gas. The new elevated pressure systems also enable the installation of excess flow valves that automatically shut off gas flow if a service line is damaged, and better support the use of high-efficiency appliances. The matter is pending.

~~Energy Efficiency Economic Stimulus Extension II (EEE Ext II)~~

~~December 31, 2014 Form 10-K page 22~~. D.C. Court. On ~~April 15,~~May 1, 2015, the BPU approved our petition to extend three EEE subprograms (multi-family, direct install and hospital efficiency). The Order allows for $95 million of additional capital expenditures and $12 million of additional administrative expenses effectiveD.C. Court vacated the 100 hour exemption but thereafter granted a stay until May 1, ~~2015.~~2016. On September 23, 2015, the D.C. Court granted the EPA's motion for voluntary remand of the 50 hour exemption provision to the EPA. While both provisions remain in place, the EPA will undergo proceedings to address the D.C. Court's orders. We believe that the impact of the D.C. Court's rulings would likely benefit Power's and its competitors' operations of their power generation peaking units.

~~Environmental Matters~~

~~Air Pollution Control~~

Ozone Standard

OnMarch 31, 2015 Form 10-Q page 71. In December ~~17,~~ 2014, the EPA proposed a rule to lower the ambient air quality standard for the level of ozone in the atmosphere from 75 parts per billion (ppb) to a level in the range of 65-70 ppb. ~~The Edison Electric Institute, of which we are a member, submitted comments on its members' behalf. The EPA is expected to finalize the rule by~~On October 1, ~~2015. Depending on~~2015, the ~~level set, some~~EPA finalized a standard of 70 ppb. To meet the new standard, the EPA and the states have to implement additional emission reduction strategies for NO_X and volatile organic compounds. Some portions of the Mid-Atlantic and New England states are not expected to be able to meet the new

~~Table~~ standard. Although the majority of ~~Contents~~

~~standard. To meet the proposed new standard, additional emission reduction strategies for~~our fossil generating units employ state-of-the-art NO_X ~~and volatile organic compounds may have to be implemented. We~~emission controls, we cannot predict the outcome of this ~~matter.~~matter since new requirements of the EPA and the states are unknown at this time. A coal mining company has filed a petition for review with the D.C. Court to challenge the rule.

Climate Change

CO₂CO2 Regulation Under the Clean Air Act (CAA)

December 31, 2014 Form 10-K page ~~23.~~23, March 31, 2015 Form 10-Q page 72 and June 30, 2015 Form 10-Q page 80. ~~In June 2014,~~On October 23, 2015, the EPA ~~issued~~published the Clean Power Plan (CPP), a ~~proposed~~ greenhouse gas (GHG) emissions regulation under the CAA for existing power plants. The regulation establishes state-specific emission rate targets based on implementation of the best system of emission reduction (BSER). The BSER consists of ~~four~~three components: (i) heat rate improvements at existing coal-fired power plants, (ii) increased use of existing natural gas combined cycle capacity, and (iii) operation of incremental zero-emitting generation (renewables and nuclear)~~, and (iv) increased use of demand-side energy efficiency.~~. States may choose these or other methodologies to achieve the necessary reductions of CO₂ emissions.

~~Since~~Each state must submit a compliance plan to the EPA ~~has requested comments on many aspects of the proposal,~~by September 6, 2016 or seek a two-year extension to September 6, 2018. States can comply using an emission rate-based plan (pounds CO₂/MWh) or a mass-based plan (tons). Compliance with the final rule ~~may look considerably different than~~is effective January 1, 2022.

The EPA, FERC and the ~~proposal. We~~U.S. Department of Energy announced that they plan to meet at least quarterly to evaluate states' plans and identify reliability concerns so adjustments can be made before the final plans are submitted. The agencies are engaging various stakeholders, including the Regional Transmission Operators/Independent System Operators. The agencies will continue to ~~work with state and federal regulators, as well as industry partners,~~meet after the states' plans are in effect to ~~determine the potential impact. A final rule is expected in mid-summer 2015.~~assess if revisions are required.

~~The FERC held a series of technical conferences ending in early April~~On October 23, 2015, to discuss the implications of compliance approaches to the EPA’s proposed GHG regulation for existing power plants. The conferences focused on issues related to electric reliability, wholesale electric markets and operations and energy infrastructure. The FERC also solicited and received written comments. It is expected that the FERC will provide guidance to the EPA ~~in finalizing~~also published proposed federal implementation requirements for states that do not submit an EPA-approved compliance plan. Comments are due by January 21, 2016.

Numerous states, including New Jersey, and several industry groups have filed petitions for review with the ~~rule for existing power plants.~~D.C. Court to challenge the CPP. In addition, the petitioners are seeking a stay of the rule.

Water Pollution Control

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

In April 2015, we determined that monitoring and reporting practices related to certain permitted wastewater discharges at our Bridgeport Harbor station may have violated conditions of the station's NPDES permit and applicable regulations and could subject us to fines and penalties. We have notified the Connecticut Department of Energy and Environmental Protection of the issues and have taken actions to investigate and resolve the potential non-compliance. At this early stage we cannot predict the impact of this matter.

~~Fuel and Waste Disposal~~

~~Coal Combustion Residuals (CCRs)~~Steam Electric Effluent Guidelines

December 31, 2014 Form 10-K page 26.24. On ~~December 19, 2014,~~September 30, 2015, the EPA issued a ~~final~~new Effluent Guidelines Limitation Rule for steam electric generating units. The rule ~~which regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also~~ establishes new ~~provisions~~best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the ~~construction of new surface impoundments and landfills. Our Hudson and Mercer generating stations, along with our co-owned Keystone and Conemaugh stations, are subject~~intervening time period, existing discharge standards continue to ~~the provisions of this rule. The scope of the work entailed to comply~~apply. Power has ~~not yet been finalized but we expect that the impacts of this rule will not be material to our results of operations, financial condition or cash flows.~~two electric generation facilities, its dual-

7282

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

Cooling Water Intake Structure Regulation

December 31, 2014 Form 10-K page 25 and June 30, 2015 Form 10-Q page 80. On June 30, 2015, the NJDEP issued a draft permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system with certain required system modifications. The draft permit is subject to a sixty-day public notice and comment period. We participated in the NJDEP’s August 5, 2015 public hearing and submitted comments on the draft permit on September 18, 2015.The NJDEP may make revisions before issuing the final permit expected in the first half of 2016. For additional information, see Part I, Item 1. Note 8. Commitments and Contingent Liabilities.

Waters of the United States

December 31, 2014 Form 10-K page 25 and June 30, 2015 Form 10-Q page 80. In April 2014, the EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published a proposed rule to clarify the definition of waters of the U.S. under the Clean Water Act (CWA) programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. The final rule was published on June 29, 2015 and we are reviewing it to determine the materiality of the impacts that might result from the final rule. Some states, including New Jersey, are subject to state requirements beyond those imposed under federal law. While we do not anticipate material impacts to projects in New Jersey, the new definition could impose requirements in other states and regions that could impact the development of renewables.

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


ITEM 6.	EXHIBITS

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



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

b. PSE&G:
Exhibit 10		Employment Agreement with Daniel J. Cregg, dated September 22, 2015
Exhibit 12.1:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.2:		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.2:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

c. ~~PSE&G:~~Power:
Exhibit ~~12.1:~~10		~~Computation of Ratios of Earnings to Fixed Charges~~
~~Exhibit 12.2:~~		~~Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements~~
~~Exhibit 31.2:~~		~~Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act~~
~~Exhibit 31.3:~~		~~Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act~~
~~Exhibit 32.2:~~		~~Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code~~
~~Exhibit 32.3:~~		~~Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code~~
~~Exhibit 101.INS:~~		~~XBRL Instance Document~~
~~Exhibit 101.SCH:~~		~~XBRL Taxonomy Extension Schema~~
~~Exhibit 101.CAL:~~		~~XBRL Taxonomy Extension Calculation Linkbase~~
~~Exhibit 101.LAB:~~		~~XBRL Taxonomy Extension Labels Linkbase~~
~~Exhibit 101.PRE:~~		~~XBRL Taxonomy Extension Presentation Linkbase~~
~~Exhibit 101.DEF:~~		~~XBRL Taxonomy Extension Definition Document~~

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

7384

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: ~~May 1,~~October 30, 2015

7485

SIGNATURE



PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

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

Date: ~~May 1,~~October 30, 2015

7586