regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation ~~fleet and greater reliance on natural gas pipelines for fuel delivery.~~fleet.

If trends noted above continue or worsen, Power’s nuclear generating units could cease being economically competitive which may cause Power to retire such units prior to the end of their useful lives. The costs associated with any such potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs, and additional funding of the NDT Fund ~~will~~would likely have a material adverse impact on PSEG’s and Power’s future financial results. PSEG and Power continue to advocate for sound policies that recognize nuclear power as a source of reliable and ~~clean~~air emissions free energy and an important part of a diverse and reliable energy portfolio.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

The following table provides the balance sheet amounts by generating station as of ~~March 31,~~June 30, 2017 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.

As of March 31, 2017
Hope Creek Salem Support Facilities and Other (A) Peach Bottom
Millions
Assets
Materials and Supplies Inventory $ 82
$ 86
$ —
$ 39

Nuclear Production, net of Accumulated Depreciation 456
545
208
774

Nuclear Fuel In-Service, net of Accumulated Depreciation 152
77
—
142

Construction Work in Progress (including nuclear fuel) 156
137
12
26

        Total Assets $ 846
$ 845
$ 220
$ 981

Liability
Asset Retirement Obligation $ 144
$ 157
$ —
$ 159

        Total Liabilities $ 144
$ 157
$ —
$ 159

         Net Assets $ 702
$ 688
$ 220
$ 822

NRC License Renewal Term 2046 2036/2040
—
2033/2034

% Owned 100 % 57 % —
50 %




	As of June 30, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	83		$	80		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	453			561			208		758
Nuclear Fuel In-Service, net of Accumulated Depreciation	136			113			—		125
Construction Work in Progress (including nuclear fuel)	168			109			9		31
Total Assets	$	840		$	863		$	217	$	955
Liability
Asset Retirement Obligation	$	146		$	159		$	—	$	162
Total Liabilities	$	146		$	159		$	—	$	162
Net Assets	$	694		$	704		$	217	$	793
NRC License Renewal Term	2046			2036/2040			—		2033/2034
% Owned	100		%	57		%	—		50		%


(A)	Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.

The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments and decommissioning trust fund requirements and other commitments, as well as future energy prices. Power maintains a NDT Fund that funds its decommissioning obligations. See Note 7. Available-for-Sale Securities.

Note 4. Variable Interest Entity (VIE)

VIE for which PSEG LI is the Primary Beneficiary

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

Pursuant to the OSA, Servco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.

For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. Servco recorded $112 million and ~~$98~~$101 million for the three months and $224 million and $199 million for the six months ended ~~March 31,~~June 30, 2017 and 2016, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Condensed Consolidated Statement of Operations.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Note 5. Rate Filings

This Note should be read in conjunction with Note 6. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2016.

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

Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June 2017, PSE&G ~~filed~~updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2017 which represents estimated annual increases in electric and gas ~~cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs associated with electric~~revenues of $16 million and ~~gas plant investments under the program that is anticipated to be in service by May 31, 2017.~~$2 million, respectively. The petition requests rates to be effective September 1, 2017, consistent with the BPU Order of approval of the Energy Strong ~~Program. The annualized requested~~program. This matter is pending.

Basic Gas Supply Services (BGSS)—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase of $61 million in ~~revenue requirement is~~annual BGSS revenues. If approved, the BGSS rate would be increased from approximately ~~$22 million~~34 cents to 37 cents per therm for ~~electric and $3 million for gas.~~residential gas customers effective October 1, 2017. This matter is pending.

Green Program Recovery Charges (GPRC)—Each year PSE&G files with the BPU for annual recovery of its Green Program investments which include a return on its investment and recovery of expenses. In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery for the ten combined components of the electric and gas GPRC. The filing proposes rates for the period October 1, 2017 through September 30, 2018 designed to recover approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU-approved programs. This matter is pending.

In March 2017, the BPU gave final approval to PSE&G’s petition to recover approximately $37 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved GPRC programs. The rates ~~are~~were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge.

Weather Normalization Clause—In April 2017, the BPU gave final approval to PSE&G’s petition to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period.

In June 2017, PSE&G filed a petition requesting approval to collect $55 million in total net deficiency revenues comprised of $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and the remaining carryover balance of $24 million in net deficiency gas revenue from the 2015-2016 Winter Period. The deficiency gas revenue would be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May 31). This matter is pending.

Transmission Formula Rate Filings—In June 2017, PSE&G filed its 2016 true-up adjustment pertaining to its transmission formula rates in effect for 2016. This resulted in an adjustment of $12 million more than the 2016 originally filed revenues.

Remediation Adjustment Charge (RAC)—In June 2017, the BPU approved PSE&G's filing with respect to its RAC 24 petition allowing recovery of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016.

Gas System Modernization Program (GSMP)—In July 2017, PSE&G filed its annual GSMP cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $28 million effective January 1, 2018. This increase represents the return of and on investment for GSMP investments expected to be in service through September 30, 2017. This request will be updated in October 2017 for actual costs.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 6. Financing Receivables

PSE&G

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

Outstanding Loans by Class of Customer
As of As of
Consumer Loans March 31,
2017 December 31,
2016
Millions
Commercial/Industrial $ 168
$ 164

Residential 11
11

Total $ 179
$ 175




Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	June 30, 2017		December 31, 2016
	Millions
Commercial/Industrial	$	167	$	164
Residential	11		11
Total	$	178	$	175

Energy Holdings

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

During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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. During the fourth quarter of 2016, Energy Holdings recorded a $10 million pre-tax charge for its best estimate of loss related to the leveraged ~~leases~~lease receivables as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of December 31, 2016.

In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. GenOn is a subsidiary of NRG Energy, Inc. and is the parent of REMA. REMA was not included in the GenOn filing. Energy Holdings continues to monitor the restructuring of GenOn and its possible impacts on REMA. During the second quarter of 2017, Energy Holdings completed its review of estimated residual values embedded in its leveraged lease portfolio of generating assets and the outcome indicated that one of the residual value estimates was lower than the recorded residual value due to a further deterioration of market conditions and changes to operating cost estimates. This decline was determined to be other than temporary. As a result, a pre-tax write-down of $7 million was recorded in the quarter ended June 30, 2017. In addition, based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15 million pre-tax charge for its current best estimate of loss related to

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

lease receivables. The second quarter 2017 pre-tax write-down and additional charge were reflected in Operating Revenues and are included in Gross Investment in Leases for June 30, 2017.

The following table shows Energy Holdings’ gross and net lease investment as of ~~March 31,~~June 30, 2017 and December 31, 2016, respectively.

As of As of
March 31,
2017 December 31,
2016
Millions
Lease Receivables (net of Non-Recourse Debt) $ 574
$ 629

Estimated Residual Value of Leased Assets 346
346

Total Investment in Rental Receivables 920
975

Unearned and Deferred Income (324 ) (326 )
Gross Investment in Leases 596
649

Deferred Tax Liabilities (640 ) (674 )
Net Investment in Leases $ (44 ) $ (25 )




	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	559		$	629
Estimated Residual Value of Leased Assets	333			346
Total Investment in Rental Receivables	892			975
Unearned and Deferred Income	(315		)	(326		)
Gross Investment in Leases	577			649
Deferred Tax Liabilities	(619		)	(674		)
Net Investment in Leases	$	(42	)	$	(25	)

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

Lease Receivables, Net of
Non-Recourse Debt

Counterparties’ Credit Rating Standard & Poor’s (S&P) as of March 31, 2017
As of March 31, 2017
Millions
AA $ 16

BBB+ — BBB- 316

BB- 133

CCC- 109

Total $ 574




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor’s (S&P) as of June 30, 2017
	As of June 30, 2017
	Millions
AA	$	15
BBB+ — BBB-	317
BB-	133
CC	94
Total	$	559

The “BB-” and the ~~“CCC-”~~“CC” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of ~~March 31,~~June 30, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $~~371~~348 million ($~~(154)~~(159) million, net of deferred taxes). A more detailed description of such assets under lease, as of ~~March 31,~~June 30, 2017, is presented in the following table.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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 % 1,036
Gas BB- NRG Energy, Inc.
Keystone Station Units 1 and 2 PA $ 26
17 % 1,711
Coal CCC- (A) REMA
Conemaugh Station Units 1 and 2 PA $ 29
17 % 1,711
Coal CCC- (A) REMA
Shawville Station Units 1, 2, 3 and 4 PA $ 99
100 % 596
Gas CCC- (A) REMA




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	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CC (A)	REMA
Shawville Station Units 1, 2, 3 and 4	PA	$	91	100	%	596	Gas	CC (A)	REMA

(A)

REMA’s parent company, GenOn, ~~Energy Inc. (GenOn), reported in August 2016 that GenOn~~and certain of its subsidiaries (which did not ~~expect to have sufficient liquidity to repay its senior unsecured notes due in June 2017. In January 2017, S&P further lowered its corporate credit rating on GenOn and its affiliates (including~~include REMA) ~~to “CCC-” from “CCC” reflecting the primary credit concern~~filed voluntary petitions for relief under Chapter 11 of the ~~near-term maturity of GenOn’s senior unsecured notes~~U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. On June 16, 2017, ~~and expressed a negative outlook reflecting the continuing pressure on financial measures. In October 2016,~~ Moody’s downgraded the GenOn Corporate Family Rating to ~~“Caa3” to reflect its high debt burden relative to cash flow.~~D-PD and provided a rating of Caa1 for REMA.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s ~~efforts to restructure its portfolio and improve its liquidity and~~restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material ~~cash~~deferred tax liabilities to the Internal Revenue Service.

Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.

Note 7. Available-for-Sale Securities

NDT Fund

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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

As of March 31, 2017
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 717
$ 297
$ (7 ) $ 1,007

Debt Securities
Government 515
8
(6 ) 517

Corporate 342
5
(4 ) 343

Total Debt Securities 857
13
(10 ) 860

Other Securities 46
—
—
46

Total NDT Available-for-Sale Securities $ 1,620
$ 310
$ (17 ) $ 1,913




	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	699	$	305	$	(5	)	$	999
Debt Securities
Government	551		10		(4		)	557
Corporate	356		6		(1		)	361
Total Debt Securities	907		16		(5		)	918
Other Securities	51		—		—			51
Total NDT Available-for-Sale Securities	$	1,657	$	321	$	(10	)	$	1,968

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	705	$	263	$	(11	)	$	957
Debt Securities
Government	518		8		(6		)	520
Corporate	337		4		(4		)	337
Total Debt Securities	855		12		(10		)	857
Other Securities	44		—		—			44
Total NDT Available-for-Sale Securities (A)	$	1,604	$	275	$	(21	)	$	1,858

(A) The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund.

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

As of As of
March 31,
2017 December 31,
2016
Millions
Accounts Receivable $ 15
$ 8

Accounts Payable $ 4
$ 5

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~




	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	25	$	8
Accounts Payable	$	22	$	5

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

As of March 31, 2017 As of December 31, 2016

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) $ 80
$ (6 ) $ 4
$ (1 ) $ 120
$ (10 ) $ 8
$ (1 )
Debt Securities
Government (B) 276
(6 ) 4
—
276
(6 ) 4
—

Corporate (C) 125
(3 ) 9
(1 ) 139
(3 ) 15
(1 )
Total Debt Securities 401
(9 ) 13
(1 ) 415
(9 ) 19
(1 )
NDT Available-for-Sale Securities $ 481
$ (15 ) $ 17
$ (2 ) $ 535
$ (19 ) $ 27
$ (2 )




	As of June 30, 2017									As of December 31, 2016
	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)	$	63	$	(5	)	$	—	$	—	$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	279		(4		)	7		—		276		(6		)	4		—
Corporate (C)	94		(1		)	7		—		139		(3		)	15		(1		)
Total Debt Securities	373		(5		)	14		—		415		(9		)	19		(1		)
Other Securities	51		—			—		—		—		—			—		—
NDT Available-for-Sale Securities	$	487	$	(10	)	$	14	$	—	$	535	$	(19	)	$	27	$	(2	)


(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,~~June 30, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(B)

Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of ~~March 31,~~June 30, 2017.

(C)

Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of ~~March 31,~~June 30, 2017.

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

Three Months Ended
March 31,
2017 2016
Millions
Proceeds from NDT Fund Sales (A) $ 247
$ 177

Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains $ 21
$ 15

Gross Realized Losses (4 ) (16 )
Net Realized Gains (Losses) on NDT Fund $ 17
$ (1 )




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from NDT Fund Sales (A)	$	320		$	154		$	567		$	331
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	32		$	10		$	53		$	25
Gross Realized Losses	(5		)	(6		)	(9		)	(22		)
Net Realized Gains (Losses) on NDT Fund	$	27		$	4		$	44		$	3

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements of Operations. Net unrealized gains of $~~149~~158 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of ~~March 31,~~June 30, 2017.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

The NDT available-for-sale debt securities held as of ~~March 31,~~June 30, 2017 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ 16

1 - 5 years 257

6 - 10 years 199

11 - 15 years 59

16 - 20 years 63

Over 20 years 266

Total NDT Available-for-Sale Debt Securities $ 860




Time Frame	Fair Value
	Millions
Less than one year	$	29
1 - 5 years	239
6 - 10 years	223
11 - 15 years	65
16 - 20 years	66
Over 20 years	296
Total NDT Available-for-Sale Debt Securities	$	918

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

Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the ~~three~~six months ended ~~March 31,~~June 30, 2017, Other-Than-Temporary Impairments (OTTI) of $14 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

Rabbi Trust

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

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

As of March 31, 2017
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 22
$ —
$ —
$ 22

Debt Securities
Government 99
—
(1 ) 98

Corporate 99
1
(1 ) 99

Total Debt Securities 198
1
(2 ) 197

Other Securities 2
—
—
2

Total Rabbi Trust Available-for-Sale Securities $ 222
$ 1
$ (2 ) $ 221

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~




	As of June 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	—	$	—		$	22
Debt Securities
Government	85		1		(1		)	85
Corporate	113		2		—			115
Total Debt Securities	198		3		(1		)	200
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	222	$	3	$	(1	)	$	224




	As of December 31, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	11	$	11	$	—		$	22
Debt Securities
Government	105		—		(2		)	103
Corporate	92		1		(2		)	91
Total Debt Securities	197		1		(4		)	194
Other Securities	1		—		—			1
Total Rabbi Trust Available-for-Sale Securities	$	209	$	12	$	(4	)	$	217

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

As of As of
March 31,
2017 December 31,
2016
Millions
Accounts Receivable $ 1
$ 5

Accounts Payable $ 1
$ 3




	As of		As of
	June 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	—	$	3

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

As of March 31, 2017 As of December 31, 2016

Less Than 12
Months

Greater Than 12
Months

Less Than 12
Months

Greater Than 12
Months

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

Fair
Value

Gross
Unrealized
Losses

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

Debt Securities
Government (B) 53
(1 ) 1
—
60
(2 ) 1
—

Corporate (C) 36
(1 ) 3
—
46
(2 ) 3
—

Total Debt Securities 89
(2 ) 4
—
106
(4 ) 4
—

Rabbi Trust Available-for-Sale Securities $ 89
$ (2 ) $ 4
$ —
$ 106
$ (4 ) $ 4
$ —




	As of June 30, 2017									As of December 31, 2016
	Less Than 12 Months					Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	—	$	—		$	—	$	—	$	—	$	—		$	—	$	—
Debt Securities
Government (B)	29		(1		)	1		—		60		(2		)	1		—
Corporate (C)	19		—			3		—		46		(2		)	3		—
Total Debt Securities	48		(1		)	4		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	48	$	(1	)	$	4	$	—	$	106	$	(4	)	$	4	$	—


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

(B)

Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of ~~March 31,~~June 30, 2017.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

(C)

Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of ~~March 31,~~June 30, 2017.

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

Three Months Ended
March 31,
2017 2016
Millions
Proceeds from Rabbi Trust Sales (A) $ 51
$ 25

Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains $ 15
$ 1

Gross Realized Losses (3 ) (1 )
Net Realized Gains (Losses) on Rabbi Trust $ 12
$ —




	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)	$	93		$	36		$	144		$	61
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	2		$	2		$	17		$	3
Gross Realized Losses	(1		)	(1		)	(4		)	(2		)
Net Realized Gains (Losses) on Rabbi Trust	$	1		$	1		$	13		$	1

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

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains/losses ~~of $(1) million (after-tax) were recognized~~ in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets were immaterial as of ~~March 31,~~June 30, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The Rabbi Trust available-for-sale debt securities held as of ~~March 31,~~June 30, 2017 had the following maturities:

Time Frame Fair Value
Millions
Less than one year $ 6

1 - 5 years 50

6 - 10 years 42

11 - 15 years 9

16 - 20 years 8

Over 20 years 82

Total Rabbi Trust Available-for-Sale Debt Securities $ 197




Time Frame	Fair Value
	Millions
Less than one year	$	1
1 - 5 years	35
6 - 10 years	29
11 - 15 years	6
16 - 20 years	18
Over 20 years	111
Total Rabbi Trust Available-for-Sale Debt Securities	$	200

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

PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in ~~a commingled~~an indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). For the ~~three~~six months ended ~~March 31,~~June 30, 2017, no OTTIs were recognized on securities in the Rabbi Trust. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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

As of As of
March 31,
2017 December 31,
2016
Millions
PSE&G $ 44
$ 43

Power 55
53

Other 122
121

Total Rabbi Trust Available-for-Sale Securities $ 221
$ 217




	As of		As of
	June 30, 2017		December 31, 2016
	Millions
PSE&G	$	45	$	43
Power	55		53
Other	124		121
Total Rabbi Trust Available-for-Sale Securities	$	224	$	217

Note 8. Pension and Other Postretirement Benefits (OPEB)

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

As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, ~~as of March 31, 2017,~~ the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $12 million ~~net of amounts capitalized,~~and $24 million for the three months and six months, ended June 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, ~~except for~~excluding Servco.

Pension Benefits OPEB
Three Months Ended Three Months Ended
March 31, March 31,
2017 2016 2017 2016
Millions
Components of Net Periodic Benefit Costs
Service Cost $ 29
$ 27
$ 4
$ 4

Interest Cost 51
50
16
15

Expected Return on Plan Assets (98 ) (98 ) (8 ) (8 )
Amortization of Net
Prior Service Cost (Credit) (5 ) (4 ) (3 ) (3 )
Actuarial Loss 24
39
13
10

Total Benefit Costs $ 1
$ 14
$ 22
$ 18




	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Six Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2017			2016			2017			2016			2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	28		$	27		$	4		$	4		$	57		$	54		$	8		$	8
Interest Cost	51			51			16			14			102			101			32			29
Expected Return on Plan Assets	(99		)	(99		)	(9		)	(7		)	(197		)	(197		)	(17		)	(15		)
Amortization of Net
Prior Service Cost (Credit)	(4		)	(5		)	(2		)	(4		)	(9		)	(9		)	(5		)	(7		)
Actuarial Loss	25			40			12			10			49			79			25			20
Total Benefit Costs	$	1		$	14		$	21		$	17		$	2		$	28		$	43		$	35

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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

Pension Benefits OPEB
Three Months Ended Three Months Ended
March 31, March 31,
2017 2016 2017 2016
Millions
PSE&G $ (1 ) $ 7
$ 14
$ 11

Power —
4
7
6

Other 2
3
1
1

Total Benefit Costs $ 1
$ 14
$ 22
$ 18




	Pension Benefits					OPEB				Pension Benefits					OPEB
	Three Months Ended					Three Months Ended				Six Months Ended					Six Months Ended
	June 30,					June 30,				June 30,					June 30,
	2017			2016		2017		2016		2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	7	$	13	$	11	$	(2	)	$	14	$	27	$	22
Power	1			4		6		5		1			8		13		11
Other	1			3		2		1		3			6		3		2
Total Benefit Costs	$	1		$	14	$	21	$	17	$	2		$	28	$	43	$	35

During the three months ended March 31, 2017, PSEG contributed its entire planned contribution for the year 2017 of $14 million into its OPEB plan.

Servco Pension and OPEB

At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB benefit cost disclosures. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. Servco plans to contribute $35 million into its pension plan trusts during 2017. Servco’s pension-related revenues and costs were $9$8 million and $6 million for the three months ended ~~March 31,~~June 30, 2017 and 2016, respectively, and $17 million and $12 million for the six months ended June 30, 2017 and 2016, respectively. The OPEB-related revenues earned and costs incurred were $1 million and $2 million for the three months and six months ended ~~March 31, 2017 were $1 million~~June 30, 2017. The OPEB-related revenues earned and costs incurred were immaterial for the three months and six months ended ~~March 31,~~June 30, 2016.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 9. Commitments and Contingent Liabilities

Guaranteed Obligations

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

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

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

obtain credit.

Power is subject to

counterparty collateral calls related to commodity contracts, and

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

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

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

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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

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

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

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of ~~March 31,~~June 30, 2017 and December 31, 2016.

As of As of
March 31,
2017 December 31,
2016
Millions
Face Value of Outstanding Guarantees $ 1,886
$ 1,806

Exposure under Current Guarantees $ 151
$ 139

Letters of Credit Margin Posted $ 183
$ 157

Letters of Credit Margin Received $ 104
$ 99

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

Counterparty Cash Margin Received $ (1 ) $ (1 )
Net Broker Balance Deposited (Received) $ 61
$ 57

Additional Amounts Posted:
Other Letters of Credit $ 69
$ 51




	As of			As of
	June 30, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,898		$	1,806
Exposure under Current Guarantees	$	137		$	139

Letters of Credit Margin Posted	$	142		$	157
Letters of Credit Margin Received	$	98		$	99

Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(1	)	$	(1	)
Net Broker Balance Deposited (Received)	$	(2	)	$	57

Additional Amounts Posted:
Other Letters of Credit	$	61		$	51

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 11. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Condensed Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.

Environmental Matters

Passaic River

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

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

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

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

In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

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

On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River.

The CPG, which consisted of 5251 members as of ~~March 31,~~June 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million, which the CPG continues to incur. Of the estimated $190 million, as of ~~March 31,~~June 30, 2017, the CPG had spent approximately ~~$160~~$163 million, of which PSEG’s total share was approximately ~~$11~~$12 million.

The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranged from approximately $518 million to $772 million. Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G’s and Power’s estimated share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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

Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of ~~March 31,~~June 30, 2017, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”

In June 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Maxus and Tierra are subsidiaries of YPF Holdings, Inc. (YPF Holdings). YPF Holdings is a wholly owned subsidiary of YPF S.A. (YPF), a company controlled by the Argentinian government. Neither YPF Holdings nor YPF is a party to the bankruptcy proceedings. However, Tierra and Maxus have filed a plan of liquidation that may allow the parties to assert one or more causes of action to hold YPF responsible for certain amounts owed by Tierra and Maxus. PSEG cannot currently determine the impact, if any, that the bankruptcy of Tierra and Maxus or any related proceeding might have on its allocable share or total liability for the Passaic River matter, and therefore, PSEG, through the CPG and independently, will continue to monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs.

In March 2017, the EPA sent a letter to 20 PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements in return for payments by each PRP of $280,600. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. It is unclear how the EPA made that determination or how many PRPs will accept the proposal. The settlement is subject to a 30 day public comment period that has not yet commenced. The impact of this settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.

Natural Resource Damage Claims

In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter.

Newark Bay Study Area

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

MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

that the estimated cost to remediate all MGP sites to completion could range between ~~$386~~$373 million and ~~$443~~$430 million through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of ~~$386~~$373 million as of ~~March 31,~~June 30, 2017. Of this amount, $74 million was recorded in Other Current Liabilities and ~~$312~~$299 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a ~~$386~~$373 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.

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

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

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

Clean Water Act (CWA) Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

In May 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing

power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing

adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for

review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental

organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the

Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by

mid-2017.

In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the ~~Clean Water Act,~~CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the ~~Clean Water Act. Such service~~CWA. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intake structures and cooling systems.

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

Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at BH3. To address compliance with the EPA’s ~~Clean Water Act~~CWA Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements.

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

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting BH5. All major environmental permits have been obtained. Operations are expected to begin in mid-2019.

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

In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter.

Jersey City, New Jersey Subsurface Feeder Cable Matter

In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working ~~order;~~order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ~~ongoing. The investigation of the discharge and its potential cause is in the preliminary~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~stages,~~ongoing, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the actions necessary ~~repair~~to address the leak and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs ~~has been~~was extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s initial debris removal activities were completed in May 2017. Since then, efforts have been ongoing to inspect portions of the pipe-type cables. As of mid-July 2017, the immediate vicinity of the leak appears to have been located and efforts are ~~ongoing.~~ongoing to identify the precise leak location and attempt repairs. If the leak cannot be located or if repairs cannot be effectuated at a reasonable cost and within a reasonable time frame, retirement of the affected facilities may be an option to address the leakage.

Steam Electric Effluent Guidelines

In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and ~~is acting promptly to issue~~issued an administrative stay of the compliance dates in the rule that ~~have not yet passed~~were the subject of pending ~~judicial review. The~~litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines ~~that are expected to be stayed include~~for the BAT limitations and pretreatment standards for ~~each of~~ the ~~following~~aforementioned waste ~~streams: fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater.~~streams. Power is unable to determine how this will ultimately impact its compliance requirements or ~~the~~its financial ~~impact it may have on the company.~~

~~Coal Combustion Residuals (CCRs)~~

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

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

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

The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2016 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $335.33 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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




	Auction Year
	2014	2015	2016	2017
36-Month Terms Ending	May 2017	May 2018	May 2019	May 2020	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$97.39	$99.54	$96.38	$90.78


(A)	Prices set in the 2017 BGS auction year ~~will become~~became effective on June 1, 2017 when the 2014 BGS auction agreements ~~expire.~~expired.

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

PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 18. Related-Party Transactions.

Minimum Fuel Purchase Requirements

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

enrichment and fabrication requirements through 2018 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

Power has various multi-year contracts for natural gas and firm pipeline transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess pipeline capacity available beyond the needs of PSE&G’s customers, Power can use the gas to make third-party sales and if excess volume remains after the third-party sales, supply its fossil generating stations in New Jersey.

Power also has various long-term fuel purchase commitments for coal through ~~2019~~2021 to support its Keystone and Conemaugh fossil generation stations.

As of ~~March 31,~~June 30, 2017, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type Power's Share of Commitments through 2021
Millions
Nuclear Fuel
Uranium $ 301

Enrichment $ 359

Fabrication $ 192

Natural Gas $ 1,101

Coal $ 181




Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	301
Enrichment	$	340
Fabrication	$	184
Natural Gas	$	1,040
Coal	$	331

Regulatory Proceedings

FERC Compliance

PJM Bidding Matter

In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power has implemented procedures to mitigate the risk of similar issues occurring in the future. During the three months ended March 31, 2014, based upon its best estimate available at the time, Power recorded a pre-tax charge to income in the amount of $25 million related to this matter.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into these matters. While considerable uncertainty remains as to the final resolution of these matters, based upon ~~recent~~ developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. Power is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power.

Power continues to believe that it has legal defenses that it may assert in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majority of the hours was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial. Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement. As a result, PSEG and Power cannot predict the final outcome of these matters.

Financial Transmission Rights (FTR) Auction Matter

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in ~~the~~PJM’s annual FTR auction ~~in PJM~~ for the 2016-2017 planning year and the monthly PJM FTR auctions ~~in PJM~~ for February, March and April 2016. PSEG is cooperating with FERC in this matter. PSEG cannot predict the outcome of this matter at this time.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

table of ~~PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs,~~

Note 10. Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transaction occurred in the six months ended June 30, 2017:

PSEG

entered into an agreement for a new term loan maturing June 2019. The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.80% and can be terminated at any time without penalty.

PSE&G

issued $425 million of 3.00% Secured Medium-Term Notes, Series L due May 2027.

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.

In March 2017, PSEG, Power and PSE&G amended their credit agreements, extending the expiration dates to March 2022. Concurrently, PSEG increased its existing $1 billion in credit facilities to $1.5 billion and Power decreased its existing $2.6 billion in credit facilities to $2.1 billion, which includes two new 3-year $100 million letter of credit facilities that expire in March 2020.

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of ~~March 31,~~June 30, 2017, the total available credit capacity was ~~$3.6~~$4.0 billion.

As of ~~March 31,~~June 30, 2017, no single institution represented more than 8% of the total commitments in the credit facilities.

As of ~~March 31,~~June 30, 2017, ~~the~~ total credit capacity was in excess of ~~its~~the total anticipated maximum liquidity ~~requirements.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table~~requirements of ~~Contents~~

PSEG, PSE&G and Power.

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of ~~March 31,~~June 30, 2017 were as follows:

As of March 31, 2017
Company/Facility
Total
Facility
Usage
Available
Liquidity

Expiration
Date
Primary Purpose
Millions
PSEG
  5-year Credit Facilities (A) $ 1,500
$ 332
$ 1,168
Mar 2022 Commercial Paper Support/Funding/Letters of Credit
Total PSEG $ 1,500
$ 332
$ 1,168

PSE&G
5-year Credit Facility (A) $ 600
$ 14
$ 586
Mar 2022 Commercial Paper Support/Funding/Letters of Credit
Total PSE&G $ 600
$ 14
$ 586

Power
  3-year LC Facilities $ 200
$ 137
$ 63
Mar 2020 Letters of Credit
  5-year Credit Facilities 1,900
98
1,802
Mar 2022 Funding/Letters of Credit
Total Power $ 2,100
$ 235
$ 1,865

Total $ 4,200
$ 581
$ 3,619




	As of June 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	13	$	1,487	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	13	$	1,487
PSE&G
5-year Credit Facility (A)	$	600	$	15	$	585	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	15	$	585
Power
3-year LC Facilities	$	200	$	140	$	60	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		50		1,850		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	190	$	1,910
Total	$	4,200	$	218	$	3,982


(A)	The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of June 30, 2017, neither PSEG nor PSE&G had amounts outstanding.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~(A)The primary use~~(UNAUDITED)

under which as of March 31, 2017, PSEG had $315 million outstanding at a weighted average interest rate of 1.25%. As of March 31, 2017, PSE&G had no amounts outstanding under its Commercial Paper Program.contents

Note 11. Financial Risk Management Activities

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchases and normal sales (NPNS), cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. Power and PSE&G enter into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value.

Commodity Prices

Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk relating primarily ~~relating~~ to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings.

Interest Rates

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of ~~March 31,~~June 30, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $4 million for the three months and six months ended ~~March 31,~~June 30, 2016.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, related primarily ~~related~~ to variable-rate debt instruments. As of ~~March 31,~~June 30, 2017 and December 31, 2016, PSEG had interest rate hedges outstanding totaling $500 million. These hedges convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. As of ~~March 31,~~June 30, 2017 and December 31, 2016, the fair value of these hedges was ~~$2 million and~~ $1 ~~million, respectively.~~million. There was no ineffectiveness as of ~~March 31,~~June 30, 2017 and December 31, 2016.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of ~~March 31,~~June 30, 2017 and December 31, 2016. The after-tax unrealized ~~gains on these hedges~~gain expected to be reclassified to earnings during the next 12 months is $1 million.

Fair Values of Derivative Instruments

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

As of March 31, 2017
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 $ 525
$ (414 ) $ 111
$ 1
$ 2
$ 114

Noncurrent Assets 264
(171 ) 93
—
—
93

Total Mark-to-Market Derivative Assets $ 789
$ (585 ) $ 204
$ 1
$ 2
$ 207

Derivative Contracts
Current Liabilities $ (425 ) $ 418
$ (7 ) $ —
$ —
$ (7 )
Noncurrent Liabilities (168 ) 167
(1 ) —
—
(1 )
Total Mark-to-Market Derivative (Liabilities) $ (593 ) $ 585
$ (8 ) $ —
$ —
$ (8 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 196
$ —
$ 196
$ 1
$ 2
$ 199

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~




	As of June 30, 2017
	Power (A)									PSEG (A)		Consolidated
	Not Designated									Designated as Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Interest Rate Swaps		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	479		$	(367	)	$	112		$	1	$	113
Noncurrent Assets	268			(178		)	90			—		90
Total Mark-to-Market Derivative Assets	$	747		$	(545	)	$	202		$	1	$	203
Derivative Contracts
Current Liabilities	$	(373	)	$	365		$	(8	)	$	—	$	(8	)
Noncurrent Liabilities	(170		)	169			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(543	)	$	534		$	(9	)	$	—	$	(9	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	204		$	(11	)	$	193		$	1	$	194




	As of December 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	$	435		$	(273	)	$	162		$	—		$	1	$	163
Noncurrent Assets	122			(98		)	24			—			—		24
Total Mark-to-Market Derivative Assets	$	557		$	(371	)	$	186		$	—		$	1	$	187
Derivative Contracts
Current Liabilities	$	(285	)	$	277		$	(8	)	$	(5	)	$	—	$	(13	)
Noncurrent Liabilities	(98		)	95			(3		)	—			—		(3		)
Total Mark-to-Market Derivative (Liabilities)	$	(383	)	$	372		$	(11	)	$	(5	)	$	—	$	(16	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	174		$	1		$	175		$	(5	)	$	1	$	171

~~higher transmission revenues, and~~

MTMgains in 2017 as compared to MTM losses in 2016,

~~increased gas distribution revenues.~~

higher transmission revenues, and

higher realized gains in the NDT Fund.

During the first ~~three~~six months of 2017, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our ~~multi-year,~~ long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, 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, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging ~~infrastructure.~~infrastructure, including our $275 million Newark Switch project that was approved by PJM in July 2017. We also continue to make investments 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 and to seek recovery on such investments. We also continue to modernize PSE&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.

As a result of our Energy Strong Order from the BPU, we will be required to file a distribution base rate case proceeding by no later than November 1, 2017. The case will provide PSE&G with the opportunity to reset assumptions on sales and O&M growth as well as provide the opportunity to recover investments not recognized in various clause mechanisms since our last base rate proceeding in 2010, and to recover prior approved storm costs. PSE&G, as part of the filing, will also request approval for a de-coupling of electric revenue from sales. We cannot predict when the distribution base rate will be approved by the BPU and the impact ~~such~~this proceeding will have on our distribution business.

In July, we filed for a petition with the BPU for GSMP II, a five-year extension of GSMP, which would accelerate the pace of replacement of our aging cast iron and unprotected steel mains and associated service. We proposed to invest up to $540 million per year over this five-year program beginning in 2019. In July, we also reached an agreement in principle with the BPU Staff and Rate Counsel for an extension of our Energy Efficiency program. For additional information, see Part II, Item 5. Other Information.

Although the weather in the first ~~quarter~~three months of 2017 was warmer than normal, Power’s results saw a continuing benefit from access to natural gas supplies through existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the BGSS arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter demand days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third-party sales and if excess volume remains after the third-party sales, 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 hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. ~~More than half of~~ Power’s ~~expected gross margin~~hedging program in ~~2017 relates to our hedging strategy, our~~combination with expected revenues from the capacity market mechanisms and certain ancillary service payments, such as reactive ~~power.~~power, has secured approximately 60% of its estimated gross margin for the 2017-2019 period.

Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to ~~contribute to the overall efficiency of operations.~~improve our financial performance.

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced as being at risk for early retirement. This situation is generally due to low natural gas prices, and the related decline in market prices of energy, resulting from the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation ~~fleet and greater reliance on natural gas pipelines for fuel delivery.~~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 potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs,

environmental remediation costs, and additional funding of nuclear decommissioning trust funds ~~will~~would likely have a material adverse impact on future financial results. We continue to advocate for sound policies that recognize nuclear power as a source of reliable and ~~clean~~air emissions free energy and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.

A number of states have either taken action or are investigating the situation faced by nuclear generating units. Recently, courts in Illinois and New York upheld challenges to the programs which established zero emissions credits (ZECs), recognizing the importance of nuclear units for providing air emissions free energy.

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

In April 2017, the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission project and approved the award to PSE&G of the construction of necessary upgrade work ~~in Hope Creek~~ at a cost of approximately $130 million. Also, in April 2017, PJM submitted a proposal to FERC concerning the cost responsibility assigned to certain entities, including PSE&G, for the Artificial Island project.

There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New Jersey. 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,~~recovery, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.

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~~The results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

Wholesale Power Market Design

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The CP product ~~is expected to be~~was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources ~~(“seasonal resources”)~~(seasonal resources). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions. ~~We do not expect action on~~

In May 2017, PJM announced the ~~complaints before~~results of the ~~upcoming 2020/2021 base residual~~RPM capacity auction for the 2020-2021 delivery year. Power cleared approximately 7,800 MW of its generating capacity at an average price of $174 per MW-day for the 2020-2021 delivery period. In the two prior capacity auctions covering the 2019-2020 and 2018-2019 delivery years, Power cleared approximately 8,900 MW at an average price of $116 and approximately 8,700 MW at an average price of $215 per MW-day, respectively. Prices in ~~May 2017.~~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 to obtain financial support arrangements from their state commissions, a group of suppliers requested that FERC direct PJM to expand the 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 generators would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ request and cannot predict the outcome of the proceeding.

Distribution

In June 2017, the BPU issued proposed Infrastructure Investment Program (IIP) regulations that would allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under the proposed regulations, utilities could seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the

IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. The proposed regulations will be subject to comment from interested parties.

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.

In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards, which establish emissions standards for CO₂ for certain new fossil power plants, and the Clean Power Plan, a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. Upon completion of the review, the EPA is expected to suspend, revise or rescind the rules as appropriate.

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 9. Commitments and Contingent Liabilities.

FERC Compliance

Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of 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. While considerable uncertainty remains as to the final resolution of these matters, based upon ~~recent~~ developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 1. Note 9. Commitments and Contingent Liabilities.

Early Retirement of Hudson and Mercer Units

~~In October 2016,~~On June 1, 2017, Power ~~determined it will cease~~completed its previously announced retirement of the 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 may be impacted by operational and other conditions that could subsequently arise.~~stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operations in 2016 and continues to adversely impact their results of operations in 2017. During the first ~~three~~six months of 2017, Power recognized incremental D&A of ~~$558~~$938 million ($~~574~~964 million in total) ~~and expects to recognize an additional incremental $379 million ($389 million in total) in 2017~~ due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first ~~quarter~~half of 2017, Energy Costs of $7$9 million ~~for coal inventory adjustments was~~and O&M of $4 million were also incurred and other costs may be incurred during the remaining period in ~~2017 prior to retirement.~~2017. See Item 1. Note 3. Early Plant Retirements for additional information.

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 obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.

In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or

capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.

Leveraged Lease Portfolio

GenOn Energy, Inc. (GenOn), the parent company of NRG REMA LLC, (REMA), ~~reported~~and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. REMA was not included in ~~August 2016 that it did not expect~~the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to ~~have sufficient liquidity to repay their senior unsecured notes due in June 2017.~~complete. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its ~~portfolio~~balance sheet and improve its ~~liquidity~~liquidity. We continue to monitor the restructuring of GenOn and the possible related impact on REMA.

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as ~~certain recent~~ discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its ~~investments in the~~ REMA ~~leases,~~leveraged lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. 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.~~lease receivables. For additional information, see Item 1. Note 6. Financing Receivables. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.

Additional facilities in our leveraged lease portfolio include the Joliet and Powerton generating facilities. Similar to Shawville, ~~generating facilities, which were~~Joliet was recently converted to use natural gas. Converted natural gas units such as Shawville and ~~Powerton, a coal facility. However, these units~~Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. AsPowerton is a ~~result,~~coal-fired generating facility in Illinois. Each of these three facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged ~~leases~~lease receivables associated with these facilities.

Salem

Concurrently with the planned refueling outage at the Salem 2 unit that ~~is scheduled for~~was conducted in the second quarter of 2017, we ~~intend to inspect~~inspected and ~~replace degraded~~replaced baffle bolts as part of our ~~multi-year project~~strategy to replace baffle bolts at the Salem station. ~~As a result, we expect the duration of this outage~~The unit was returned to ~~be modestly longer than our typical refueling outage, which will reduce production and lower the nuclear capacity factor for the second quarter of 2017 as compared to the first quarter of~~service in June 2017.

Operational Excellence

We emphasize operational performance, exercising diligence in managing costs, while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving ~~market as we remain diligent in managing costs.~~market. For the first ~~three~~six months of 2017, our

our utility continued top decile performance in electric reliability,

total nuclear fleet achieved an average capacity factor of ~~100%~~95%,

diverse fuel mix and dispatch flexibility allowed us to generate approximately 1326 terawatt hours, ~~while addressing fuel availability and price volatility,~~ and

combined cycle fleet produced ~~three~~seven terawatt hours at an equivalent availability factor of ~~94%~~92%.

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 ~~three~~six months of 2017 as we

maintained sufficient liquidity,

maintained solid investment grade credit ratings, and

increased our indicative annual dividend for 2017 to $1.72 per share.

We expect to be able to fund our planned capital requirements 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 ~~three~~six months of 2017, we

made additional investments in transmission infrastructure projects,

continued to execute our GSMP, Energy Strong and other existing BPU-approved utility programs, and

continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and began construction of BH5 for targeted commercial operations in mid-2019.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance in a ~~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,

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

successfully launch and grow our retail energy business, which complements our existing wholesale energy business,

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 and start-up of our Keys, ~~Energy Center (Keys) ,~~ Sewaren 7, ~~(BH5)~~BH5 and other generation projects,

advocate for measures to ensure the implementation by PJM and FERC of market design and transmission planning rules that continue to promote fair and efficient electricity markets,

engage multiple stakeholders, including regulators, government officials, customers and investors, and

successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations.

For 2017 and beyond, the key issues, challenges and ~~challenges~~opportunities we expect our business to confront include:

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

fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our distribution base rate case proceeding to be filed in 2017,

the potential for comprehensive tax reform, particularly in light of public statements by the current U.S. administration and key members of Congress,

uncertainty in the national and regional economic performance, 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~~ensuring timely completion of construction of our T&D, generation and other development projects, including ~~in connection with permitting~~obtaining required permits and regulatory 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, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.

In 2016, Power announced its intention to develop a retail platform to sell physical electricity and natural gas, which we believe would begin to complement our existing wholesale marketing business. Power was granted licenses in 2016 to sell both electricity and gas in the states of New Jersey and Pennsylvania.

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.

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 18. Related-Party Transactions.

Three Months Ended
Increase/
(Decrease)

March 31,
2017 2016 2017 vs. 2016
Millions Millions %
Operating Revenues $ 2,592
$ 2,616
$ (24 ) (1 )
Energy Costs 874
836
38
5

Operation and Maintenance 712
729
(17 ) (2 )
Depreciation and Amortization 828
224
604
270

Income from Equity Method Investments 3
2
1
50

Other Income (Deductions) 61
27
34
126

Other-Than-Temporary Impairments 1
10
(9 ) (90 )
Interest Expense 98
92
6
7

Income Tax Expense 29
283
(254 ) (90 )




	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,				Increase/ (Decrease)					June 30,				Increase/ (Decrease)
	2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	2,133	$	1,905	$	228		12		$	4,725	$	4,521	$	204		5
Energy Costs	588		624		(36		)	(6	)	1,462		1,460		2			—
Operation and Maintenance	708		710		(2		)	—		1,420		1,439		(19		)	(1	)
Depreciation and Amortization	641		224		417			N/A		1,469		448		1,021			N/A
Income from Equity Method Investments	5		4		1			25		8		6		2			33
Other Income (Deductions)	61		34		27			79		122		61		61			100
Other-Than-Temporary Impairments	3		10		(7		)	(70	)	4		20		(16		)	(80	)
Interest Expense	91		97		(6		)	(6	)	189		189		—			—
Income Tax Expense	59		91		(32		)	(35	)	88		374		(286		)	(76	)

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,
2017 2016 2017 vs. 2016
Millions Millions %
Operating Revenues $ 1,812
$ 1,712
$ 100
6

Energy Costs 753
729
24
3

Operation and Maintenance 367
382
(15 ) (4 )
Depreciation and Amortization 171
139
32
23

Other Income (Deductions) 24
19
5
26

Interest Expense 75
68
7
10

Income Tax Expense 171
151
20
13




	Three Months Ended				Increase/ (Decrease)					Six Months Ended				Increase/ (Decrease)
	June 30,				Increase/ (Decrease)					June 30,				Increase/ (Decrease)
	2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,368	$	1,350	$	18		1		$	3,180	$	3,062	$	118		4
Energy Costs	472		529		(57		)	(11	)	1,225		1,258		(33		)	(3	)
Operation and Maintenance	351		352		(1		)	—		718		734		(16		)	(2	)
Depreciation and Amortization	166		136		30			22		337		275		62			23
Other Income (Deductions)	21		18		3			17		45		37		8			22
Interest Expense	69		74		(5		)	(7	)	144		142		2			1
Income Tax Expense	123		98		25			26		294		249		45			18

Three Months Ended ~~March 31,~~June 30, 2017 as Compared to 2016

Operating Revenues increased ~~$100~~$18 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased ~~$58~~$54 million due primarily to an increase in transmission revenues.

Transmission revenues were ~~$37~~$45 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

~~Gas~~Electric distribution revenues increased ~~$24~~$8 million due to ~~an $11~~a $6 million increase ~~due to~~from the inclusion of Energy Strong in base rates and a $5$7 million increase due to ~~the Gas System Modernization Program, $4 million of~~ higher ~~delivery~~sales volumes, ~~higher~~partially offset by lower Green Program Recovery Charges (GPRC) of $2$5 million.

Gas distribution revenues increased $1 million ~~and $2~~due to $6 million in higher Weather Normalization Clause ~~revenue.~~

~~Electric distribution revenues decreased $3 million due to lower GPRC of $3 million and a $2 million decrease due to lower sales volumes, partially offset by~~(WNC) revenue, a $2 million increase ~~due to~~from the inclusion of Energy Strong in base ~~rates.~~

rates, and $1 million increases in both GSMP collections and GPRC. These increases were almost entirely offset by lower sales volumes.

Commodity Revenue ~~increased $24~~decreased $57 million as a result of ~~higher Gas revenues partially offset by~~ lower Electric and Gas revenues. The changes in Commodity revenue for both ~~gas~~electric and ~~electric~~gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and basic gas supply service (BGSS) ~~and BGS~~ to retail customers.

~~Gas commodity revenues increased $74 million due primarily to higher BGSS sales prices.~~

Electric commodity revenues decreased ~~$50~~$40 million due primarily to ~~$23~~an $18 million decrease in BGS revenues due to lower sales volumes and prices, $18 million of lower revenues from collections of Non-Utility Generation Charges (NGC)~~, a $17 million decrease in BGS revenues due to lower sales prices and volumes~~ and a decrease of ~~$10~~$4 million due to lower volumes of Non-Utility Generation (NUG) energy sold.

Gas commodity revenues decreased $17 million due to lower BGSS sales volumes of $24 million partially offset by higher BGSS sales prices of $7 million.

Clause Revenues increased $19 million due primarily to the return in 2016 ~~return~~ to customers of $15 million of overcollections of Securitization Transition Charges (STC), and ~~higher~~a $7 million increase in 2017 in Margin Adjustment Clause (MAC) revenues, partially offset by lower Societal Benefit Charges (SBC) of ~~$2 million in 2017.~~$3 million. The changes in the STC, MAC and SBC amounts are entirely offset by ~~decreases~~changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, ~~Depreciation and Amortization~~D&A and Interest Expense. PSE&G does not earn margin on STC, MAC or SBC collections.

Operating Expenses

Energy Costs ~~increased $24~~decreased $57 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased ~~$15~~$1 million, primarily due to $6 million of ~~which the most significant components were~~

~~a $6 million decrease in appliance service costs,~~

~~a $4 million decrease in~~lower distribution corrective and preventative maintenance,

partially offset by a $2$5 million ~~decrease~~increase in ~~pension and OPEB costs, net of capitalized amounts and~~

~~a $3 million net decrease in operational expenses.~~transmission maintenance.

Depreciation and Amortization increased ~~$32~~$30 million due primarily to an increase of ~~$17~~$15 million in amortization of Regulatory Assets and a $14 million increase in depreciation due to additional plant in service.

Other Income and (Deductions) increased $5$3 million due primarily to an increase ~~of $3 million~~ in Allowance for Funds Used During Construction ~~and a $3 million increase in realized gains on Rabbi Trust investments.~~(AFUDC).

Interest Expense ~~increased $7~~decreased $5 million due primarily to a $9 million decrease predominantly driven by a reduction in clause interest. This decrease was partially offset by an increase of $4 million due to net debt issuances in ~~2016.~~

~~Income Tax Expense~~ ~~increased $20 million due primarily to higher pre-tax income.~~

~~Power~~

Three Months Ended
Increase/
(Decrease)

March 31,
2017 2016 2017 vs. 2016
Millions Millions %
Operating Revenues $ 1,284
$ 1,313
$ (29 ) (2 )
Energy Costs 707
638
69
11

Operation and Maintenance 230
253
(23 ) (9 )
Depreciation and Amortization 650
79
571
N/A

Income from Equity Method Investments 3
2
1
50

Other Income (Deductions) 31
8
23
N/A

Other-Than-Temporary Impairments 1
10
(9 ) (90 )
Interest Expense 16
22
(6 ) (27 )
Income Tax Expense (Benefit) (116 ) 129
(245 ) N/A

~~Three Months Ended March 31, 2017 as Compared to~~ 2016

~~Operating Revenuesdecreased$29 million~~ ~~due to changes in generation~~ and ~~gas supply revenues.~~2017.

Income Tax Expense increased $25 million due primarily to higher pre-tax income.

Six Months Ended June 30, 2017 as Compared to 2016

Operating Revenues increased $118 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $112 million due primarily to an increase in transmission revenues.

Transmission revenues were $82 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

Gas distribution revenues increased $25 million due to a $13 million increase due to the inclusion of Energy Strong in base rates, $8 million in higher WNC revenue, a $6 million increase due to the GSMP and higher GPRC of $2 million partially offset by $4 million of lower delivery volumes.

Electric distribution revenues increased $5 million due to an $8 million increase due to the inclusion of Energy Strong in base rates and a $5 million increase due to higher sales volumes, partially offset by lower GPRC of $8 million.

Commodity Revenue decreased $33 million as a result of lower Electric revenues partially offset by higher Gas revenues. The changes in Commodity revenue for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

Electric commodity revenues decreased $90 million due primarily to $41 million of lower revenues from collections of NGC, a $35 million decrease in BGS revenues due to lower sales prices and volumes and a decrease of $14 million due to lower volumes of NUG energy sold.

Gas commodity revenues increased $57 million due primarily to higher BGSS sales prices.

Clause Revenues increased $38 million due primarily to the 2016 return to customers of $30 million of overcollections of STC, and higher MAC revenues of $8 million in 2017. The changes in the STC and MAC amounts are entirely offset by increase in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC or MAC collections.

Operating Expenses

Energy Costs decreased $33 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased $16 million, of which the most significant components were decreases of

$10 million in distribution corrective and preventative maintenance,

$8 million in appliance service costs,

$6 million in gas bad debt and

$4 million in pension and other postretirement benefit costs, net of capitalized amounts, partially offset by

a $6 million increase in transmission maintenance costs and

a $6 million net increase in operational expenses.

Depreciation and Amortization increased $62 million due primarily to an increase of $32 million in amortization of Regulatory Assets and a $29 million increase in depreciation due to additional plant in service.

Other Income and (Deductions) increased $8 million due primarily to an increase of $7 million in AFUDC and a $3 million increase in realized gains on Rabbi Trust investments, partially offset by a net $2 million decrease in Solar Loan interest.

Interest Expense increased $2 million due primarily to an increase of $11 million due to net debt issuances in 2016 and 2017, partially offset by $8 million decrease predominantly driven by a reduction in clause interest.

Income Tax Expense increased $45 million due primarily to higher pre-tax income.

Power




	Three Months Ended						Increase/ (Decrease)					Six Months Ended					Increase/ (Decrease)
	June 30,						Increase/ (Decrease)					June 30,					Increase/ (Decrease)
	2017			2016			2017 vs. 2016					2017			2016		2017 vs. 2016
	Millions						Millions			%		Millions					Millions			%
Operating Revenues	$	929		$	714		$	215		30		$	2,213		$	2,027	$	186		9
Energy Costs	397			381			16			4		1,104			1,019		85			8
Operation and Maintenance	254			265			(11		)	(4	)	484			518		(34		)	(7	)
Depreciation and Amortization	465			80			385			N/A		1,115			159		956			N/A
Income from Equity Method Investments	5			4			1			25		8			6		2			33
Other Income (Deductions)	39			16			23			N/A		70			24		46			N/A
Other-Than-Temporary Impairments	3			10			(7		)	(70	)	4			20		(16		)	(80	)
Interest Expense	13			20			(7		)	(35	)	29			42		(13		)	(31	)
Income Tax Expense (Benefit)	(62		)	(11		)	51			N/A		(178		)	118		N/A			N/A

Three Months Ended June 30, 2017 as Compared to 2016

Operating Revenues increased $215 million due to changes in generation and gas supply revenues.

Generation Revenues ~~decreased $124~~increased $223 million due primarily to

~~a net decrease~~an increase of ~~$95 million in energy sales in the PJM and New England (NE) regions due primarily to lower average realized prices, and~~

~~a net decrease of $24~~$219 million due to MTM ~~losses~~gains in 2017 as compared to MTM ~~gains~~losses in 2016. Of this amount, ~~$131~~$182 million was due to changes in forward power ~~prices. The decrease~~prices and $37 million was ~~offset by an increase of $107 million~~ due to ~~losses~~lower gains on positions reclassified to realized upon settlement this year as compared to gains last year, and

a ~~charge~~net increase of ~~$10~~$15 million in electricity sold under wholesale load contracts in the New England (NE) region due to higher volumes sold,

partially offset by a decrease of $11 million in electricity sold under our BGS contracts due primarily to lower volumes.

Gas Supply Revenues decreased $9 million due primarily to ~~an increase in the FERC accrual~~

a net decrease of $17 million related to ~~the PJM bidding matter, see Note 9. Commitments and Contingent Liabilities,~~sales to third parties, of which $22 million was due to lower volumes sold, partially offset by $5 million of higher average sales prices,

partially offset by a net increase of ~~$10~~$9 million due ~~primarily~~ to ~~higher volumes of electricity sold under wholesale load contracts in the NE region partially offset by lower average prices.~~

~~Gas Supply Revenuesincreased~~ ~~$95 million due primarily to~~

~~an increase of $46 million in sales under the BGSS contract due primarily to higher average sales prices coupled with an increase in sales volumes due to periods of colder weather in March,~~

~~an increase of $41 million related to sales to third parties due to higher average sales prices, and~~

~~a net increase of $8 million due to higher~~ MTM gains in 2017 as compared to ~~2016, primarily due to~~MTM losses ~~on positions reclassified to realized upon settlement this year as compared to gains last year.~~in 2016.

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 ~~$69~~$16 million due to

Generation costs ~~decreased $1~~increased $33 million due primarily to

an increase of $20 million due to MTM losses in 2017 as compared to MTM gains in 2016,

an increase of $21 million due primarily to higher natural gas costs reflecting higher average realized prices,

an increase of $8 million in energy purchase volumes in the NE region to serve load obligations, and

a $2 million charge associated with a lower of cost or market coal inventory adjustment at Hudson and Mercer,

partially offset by a net decrease of ~~$26~~$19 million primarily due to lower congestion rates coupled with less congestion volumes.

Gas costs ~~in PJM~~ decreased $17 million due mainly to a net decrease of $16 million related to sales to third parties, of which $21 million was due to lower ~~congestion rates~~volumes sold, partially offset by $5 million of higher average costs.

Operation and Maintenance decreased $11 million due primarily to a $14 million decrease at our fossil plants, due largely to higher planned outage costs in the second quarter of 2016 and retirement of the Hudson and Mercer coal units on June 1, 2017.

Depreciation and Amortization increased$385 milliondue primarily to

$380 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,

$4 million of greater depreciation due to the accelerated retirement date at Bridgeport Harbor 3 (BH3), and

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

Other Income (Deductions) increased $23 million due primarily to higher net realized gains in the NDT Fund.

Other-Than-Temporary Impairments decreased $7 million due to lower impairments of equity securities in the NDT Fund in 2017.

Interest Expense decreased $7 million due primarily to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys.

Income Tax Expense (Benefit) reflected anincreased tax benefit of $51 million due primarily to a higher pre-tax loss in 2017.

Six Months Ended June 30, 2017 as Compared to 2016

Operating Revenuesincreased$186 million due to changes in generation and gas supply revenues.

Generation Revenues increased $99 million due primarily to

an increase of $196 million due to MTM gains in 2017 as compared to MTM losses in 2016. Of this amount, $106 million was due to lower gains on positions reclassified to realized upon settlement this year as compared to last year and $90 million due to changes in forward power prices, and

a net increase of $24 million due primarily to higher volumes of electricity sold under wholesale load contracts in the NE region partially offset by lower average prices,

partially offset by a net decrease of $90 million in energy sales in the PJM and NE regions due primarily to lower average realized prices,

a net decrease of $8 million in electricity sold under our BGS contracts of which $21 million was due to lower volumes, partially offset by $13 million of higher average prices, and

a charge of $10 million due to an increase in the FERC accrual related to the PJM bidding matter see Item 1. Note 9. Commitments and Contingent Liabilities.

Gas Supply Revenuesincreased $86 million due primarily to

an increase of $45 million in sales under the BGSS contract, of which $37 million was due to higher average sales prices coupled with an $8 million increase in sales volumes due to periods of colder weather in March,

an increase of $24 million related to sales to third parties, of which $48 million was due to higher average sales prices, partially offset by $24 million of lower volumes sold, and

a net increase of $17 million due to MTM gains in 2017 as compared to MTM losses in 2016.

Operating Expenses

Generation costs increased $32 million due primarily to

higher fuel costs of ~~$14~~$35 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas and oil,

an increase of $8$18 million due to MTM losses in 2017 as compared to MTM gains in 2016,

an increase of $15 million in energy purchase volumes in the NE region to serve load obligations, and

a $7$9 million charge associated ~~primarily~~ with a lower of cost or market coal inventory adjustment at ~~Mercer.~~Hudson and Mercer,

partially offset by a net decrease of $45 million due primarily to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, partially offset by higher transmission charges due to higher rates.

Gas costs increased ~~$70~~$53 million due mainly to

~~an increase of $39 million related to sales to third parties due to higher average gas costs, and~~

an increase of $31 million related to sales under the BGSS contract due primarily to higher average gas costs and an increase in volumes sold due to periods of colder weather in ~~March.~~March, and

an increase of $22 million related to sales to third parties, of which $44 million was due to higher average gas costs, partially offset by a $22 million decrease in volumes sold.

Operation and Maintenance decreased ~~$23~~$34 million due primarily to

a ~~$15~~$16 million decrease at our fossil plants, due primarily to the retirement of the Hudson and Mercer units and higher planned outage costs in 2016 as compared to 2017,

an $11 million net decrease related to our nuclear plants due primarily to lower labor-related costs and outage costs, and

a $7$9 million legal ~~reserve~~accrual for environmental expenses recorded in 2016,

partially offset by $3 million of costs related to seven new solar plants placed into service since June 2016.

Depreciation and Amortization increased $~~571~~956 million due primarily to

$~~558~~938 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,

$48 million of greater depreciation due to the accelerated retirement date at ~~Bridgeport Harbor 3,~~BH3,

a $4$6 million increase due to a higher nuclear asset base, and

$36 million of higher depreciation due to new solar projects.

Other Income (Deductions) increased ~~$23~~$46 million due primarily to ~~$17~~$41 million of ~~lower~~higher net realized ~~losses from~~gains in the NDT Fund ~~in 2017~~ and $3 million of higher realized gains in the Rabbi Trust Fund.

Table of ~~$45 million due to a change in regulatory deferrals.~~Contents

Other-Than-Temporary Impairments decreased $9$16 million due to lower impairments of equity securities in the NDT Fund in 2017.

Interest Expense decreased $6$13 million due primarily to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys.

Income Tax Expense (Benefit) ~~decreased $245~~reflected a tax benefit of $(178) million in 2017 and a $118 million tax expense in 2016 due primarily to a pre-tax loss in 2017 as compared to pre-tax income in 2016.

LIQUIDITY AND CAPITAL RESOURCES

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

Operating Cash Flows

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

For the ~~three~~six months ended ~~March 31,~~June 30, 2017, our operating cash flow ~~decreased~~increased $1834 million as compared to the same period in 2016. The net change was due primarily ~~due~~ to tax refunds in 2017 at Energy Holdings and the net changes from PSE&G and Power as discussed ~~below largely offset by higher tax refunds in 2017 at Energy Holdings.~~below.

PSE&G

PSE&G’s operating cash flow decreased $5438 million from $~~568~~808 million to $~~514~~770 million for the ~~three~~six months ended ~~March 31,~~June 30, 2017, as compared to the same period in 2016, due primarily to lower tax refunds, partially offset by higher ~~earnings, and an increase~~earnings.

Power

Power’s operating cash flow ~~decreased~~increased $8315 million from $~~663~~917 million to $~~580~~932 million for the ~~three~~six months ended ~~March 31,~~June 30, 2017, as compared to the same period in 2016, due primarily ~~due~~ to a $105 million decrease in margin deposit requirements and a $48 million increase from net collection of counterparty receivables, partially offset by tax payments in 2017 as compared to tax refunds in 2016, ~~and lower earnings, partially offset by~~ a ~~$65~~$28 million ~~increase from net collection of counterparty receivables and a $12 million increase~~decrease from fuels, materials and ~~supplies.~~supplies and lower earnings.

Short-Term Liquidity

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

In March 2017, PSEG, Power and PSE&G amended their credit agreements, extending the expiration dates to March 2022. Concurrently, PSEG increased its existing $1 billion in credit facilities to $1.5 billion, Power decreased its existing $2.6 billion in credit facilities to $2.1 billion, which includes two new 3-year $100 million letter of credit facilities that expire in March 2020.

Our total credit facilities and available liquidity as of ~~March 31,~~June 30, 2017 were as follows:

Company/Facility As of March 31, 2017

Total
Facility
Usage
Available
Liquidity

Millions
PSEG $ 1,500
$ 332
$ 1,168

PSE&G 600
14
586

Power 2,100
235
1,865

Total $ 4,200
$ 581
$ 3,619




Company/Facility	As of June 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	13	$	1,487
PSE&G	600		15		585
Power	2,100		190		1,910
Total	$	4,200	$	218	$	3,982

As of ~~March 31,~~June 30, 2017, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power losing its investment grade credit rating from S&P or Moody’s, which

would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s credit rating certain of Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if Power were to lose its investment grade credit rating was approximately ~~$801~~$808 million and $783 million as of ~~March 31,~~June 30, 2017 and December 31, 2016, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units isdid 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.

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

Long-Term Debt Financing

PSEG Parent has a floating rate $500 million term loan maturing in November 2017. PSE&G has $400 million of 5.30% Medium-Term Notes maturing in May 2018.

For a discussion of our long-term debt issuances and maturities during 2017, see Item 1. Note 10. Debt and Credit Facilities.

Common Stock Dividends

On ~~February 21,~~April 18, 2017, our Board of Directors approved a $0.43 dividend per share of common stock for the ~~first~~second quarter of 2017. On ~~April~~July 18, 2017, our Board of Directors declared a $0.43 dividend per share of common stock for the ~~second~~third quarter of 2017. This reflects an indicative annual dividend rate of $1.72 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. Note16. Earnings Per Share (EPS) and Dividends.

Credit Ratings

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

In April 2017, S&P published updated research and affirmed the ratings and outlooks of PSEG and PSE&G. ~~PSEG Power’s~~In June 2017, S&P published updated research on Power and the rating and outlook ~~also remain~~remained unchanged. Also in June 2017, Moody’s published updated research on PSE&G and Power and the ratings and outlooks remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.




	Moody’s (A)	S&P (B)
PSEG
Outlook	~~Positive~~Stable	Stable
Senior Notes	~~Baa2~~Baa1	BBB
Commercial Paper	P2	A2
PSE&G
Outlook	Stable	Stable
Mortgage Bonds	Aa3	A
Commercial Paper	P1	A2
Power
Outlook	Stable	Stable
Senior Notes	Baa1	BBB+


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


(B)	S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

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 2016 Form 10-K.

PSE&G

During the ~~three~~six months ended ~~March 31,~~June 30, 2017, PSE&G made capital expenditures of ~~$752~~$1,389 million, primarily for ~~transmission and distribution~~T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$24~~$47 million, which are included in operating cash flows.

In July 2017, PSE&G filed a petition with the BPU for a GSMP II program, requesting extension of our gas system modernization program through which PSE&G has proposed investing up to $540 million per year beginning in 2019 to continue to modernize our gas system. Under this proposed program, PSE&G plans to replace up to 1,250 miles of gas mains and associated service lines. This is not included in PSE&G’s projected capital expenditures.

Power

During the ~~three~~six months ended ~~March 31,~~June 30, 2017, Power made capital expenditures of ~~$274~~$518 million, excluding $3358 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. 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~~April through ~~March~~June 2017, MTM VaR remained relatively stable between a low of $7$6 million and a high of ~~$25~~$10 million at the 95% confidence level. The range of VaR was narrower for the three months ended ~~March 31,~~June 30, 2017 as compared with the year ended December 31, 2016.

MTM VaR
Three Months Ended March 31, 2017 Year Ended December 31, 2016
Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End $ 7
$ 26

Average for the Period $ 12
$ 16

High $ 25
$ 32

Low $ 7
$ 10

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 11
$ 40

Average for the Period $ 19
$ 25

High $ 39
$ 51

Low $ 10
$ 16




	MTM VaR
	Three Months Ended June 30, 2017		Year Ended December 31, 2016
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	8	$	26
Average for the Period	$	8	$	16
High	$	10	$	32
Low	$	6	$	10
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	13	$	40
Average for the Period	$	12	$	25
High	$	16	$	51
Low	$	9	$	16

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


ITEM 4.	CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG, PSE&G and Power

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG, PSE&G and Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG, PSE&G and Power have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

PSEG, PSE&G and Power

There have been no changes in internal control over financial reporting that occurred during the ~~first~~second quarter of 2017 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 2016 Annual Report on Form 10-K, see Part I, Item 1. Note 9. Commitments and Contingent Liabilities and Item 5. Other Information.


ITEM 1A.	RISK FACTORS

The discussion of our business and operations in this Quarterly Report on Form 10-Q should be read together with the risk factors contained in Part I, Item 1A of our 2016 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, which describe various risks and uncertainties that could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report. ~~Except as follows, there~~There have been no material changes to the risk factors set forth in the above-referenced ~~filing~~filings as of ~~March 31,~~June 30, 2017.

~~We may be unable to obtain an adequate fuel supply in the future.~~

We obtain substantially all of our physical natural gas, coal and nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and other contracts to ensure that the natural gas, coal and nuclear fuel are delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.

Additionally, the PJM power market has recently experienced an increase in natural gas-fired generation assets that supply electricity to the region. As a result, there has been a corresponding increase in the need for natural gas transportation assets to serve power generation assets. When extreme cold temperatures significantly increase the demand for natural gas used for residential heating, it can also create constraints on natural gas pipelines that serve power generation assets. When these conditions exist, it could interrupt the fuel supply to our natural gas-fired power plants in the PJM power market.

We are exposed to increases in the price of natural gas, coal and nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of natural gas, coal and nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of natural gas, coal and nuclear fuel by, our power plants including the following:

~~transportation may be unavailable if pipeline infrastructure is damaged or disabled;~~

~~pipeline tariff changes may adversely affect our ability to, or cost to, deliver such fuels;~~

~~creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;~~

~~market liquidity for physical supplies of such fuels or availability of related services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;~~

~~variation in the quality of such fuels may adversely affect our power plant operations;~~

~~legislative or regulatory actions or requirements, including those related to pipeline integrity inspections, may increase the cost of such fuels;~~

~~fuel supplies diverted to residential heating may limit the availability of such fuels for our power plants; and~~

the loss of critical infrastructure, terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.

Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, such fuel may not be available at any price, or we may not be able to transport it to our facilities on a timely basis. In this case, we may not be able to run those facilities even if it would be profitable. If we had sold forward the power from such a facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

In March 2017, Westinghouse Electric Company (WEC) announced that it had filed for Chapter 11 bankruptcy in New York. WEC provides nuclear fuel fabrication services for Salem Units 1 and 2. In the event that WEC is unable to continue to provide fabrication services, we can provide no assurance that we would be able to find alternative providers of such services in a timely manner or on acceptable terms. As a result, a failure by WEC to perform its obligations during the pendency of, or following its emergence from, bankruptcy could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our liquidity, financial condition and results of operations. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used could impact our results of operations.


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~~second quarter of 2017.

Three Months Ended March 31, 2017
Total Number
of Shares
Purchased

Average
Price Paid
per Share

January 1 - January 31 —
$ —

February 1 - February 28 —
$ —

March 1- March 31 927,971
$ 44.94




Three Months Ended June 30, 2017	Total Number of Shares Purchased	Average Price Paid per Share
April 1 - April 30	—	$	—
May 1 - May 31	130,749	$	43.77
June 1- June 30	30,000	$	44.72

ITEM 5. OTHER INFORMATION

Certain information reported in the 2016 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 2016 Annual Report on Form ~~10-K.~~10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.

Federal Regulation

FERC

Capacity Market Issues

December 31, 2016 Form 10-K page ~~16.~~16 and March 31, 2017 Form 10-Q on page 76. PJM, ~~NYISO~~the New York Independent System Operator (NYISO) and ~~ISO-NE~~the Independent System Operator New England, Inc. each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. ~~Issues presented in various~~Various forums ~~include consideration of whether~~are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources or resource attributes, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. FERC held a technical conference to seek input from the industry on potential options to integrate public policy goals in wholesale markets. We cannot predict what action, if any, FERC might take with regard to capacity market designs.

Capacity Market Issues—PJM

December 31, 2016 Form 10-K page ~~16.~~16 and March 31, 2017 Form 10-Q on page 76. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. ~~However, aspects of FERC’s order are currently pending appeal in the~~The Court of Appeals for the D.C. Circuit (D.C. Circuit). denied petitions challenging certain aspects of FERC’s Order. The CP product ~~will be~~was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. FERC has approved changes to the CP construct that will enhance the participation of intermittent and DR resources ~~(“seasonal resources”)~~(seasonal resources). Specifically, FERC approved PJM’s modifications to the aggregation rules to improve the ability of seasonal resources to participate. However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions. We do not expect action on the complaints ~~before~~until additional commissioners have been nominated and confirmed so that FERC has a quorum necessary to take action.

PJM issued a series of white papers in response to public policies that seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes. The three proposals are intended to spur stakeholder discussion and include both potential capacity and energy market reforms. One energy market reform would allow inflexible generating units to set prices resulting in reduced uplift payments and improved price signals while the ~~upcoming base residual~~second energy market reform contemplates a voluntary carbon pricing program where states that elect to participate in the program would agree to put a price on carbon emissions. The capacity market proposal contemplates a two-stage capacity auction which, in ~~May 2017.~~

~~Capacity Market Issues—ISO-NE~~

~~December 31, 2016 Form 10-K page 17.~~ ~~ISO-NE’s market~~its current form, would improve prices for ~~installed capacity in New England provides fixed~~unsubsidized resources, but would still continue to provide capacity payments for generators, imports and DR. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of resources on the system and contains incentive mechanisms to encourage availability during stressed system conditions. ISO-NE also employs a mechanism, similar to PJM’s CP mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance. One aspect of the current market design that we do not support and are currently challenging in the D.C. Circuit is the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewablesubsidized resources.

~~Price Formation Initiatives~~

~~December 31, 2016 Form 10-K page 18.~~ 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. FERC recently issued a notice of proposed rulemaking (NOPR) proposing that RTOs/ISOs modify their rules governing fast-start resources. Fast-start resources typically are committed in real-time, very

close to the interval when needed and can respond quickly to unforeseen system needs. However, without fast-start pricing, some fast-start resources are ineligible to set prices due to inflexible operating limits. As a result, prices may not reflect the marginal cost of serving load. In a separate proceeding, PJM has submitted a proposal at FERC’s request to modify its rules to allow market sellers to submit day-ahead offers that vary by hour and to allow market sellers to update their offers in real time on an hourly basis under certain circumstances. FERC has accepted PJM’s proposal which will become effective on November 1, 2017. We believe that both changes will improve price formation in the energy and ancillary services markets.

Transmission Regulation—Transmission Policy Developments

December 31, 2016 Form 10-K page ~~18.~~18 and March 31, 2017 Form 10-Q on page 77. 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. Although not named as a respondent in the complaint, according to the complaint, PSE&G is identified as one of the companies claimed to have been involved. FERC set the complaint for hearing and settlement procedures and the parties are currently engaged in discovery. We are unable to predict the outcome of these proceedings.

In August 2016, PJM announced that it had suspended the Artificial Island transmission project and would be performing a comprehensive analysis to support a future course of action. In March 2017, PJM staff made its final recommendation to the PJM Board with respect to the project. Under the recommended project, PSE&G will construct necessary upgrade work ~~in Hope Creek,~~ at a cost of approximately $130 million. In April 2017, the PJM Board announced that it would be lifting the suspension and approved the staff recommended project. ~~The~~Also, in April 2017, PJM ~~Board also stated that it would be analyzing project beneficiaries from an alternate perspective~~submitted a proposal to ~~potentially devise an alternative~~FERC concerning the cost ~~allocation methodology~~responsibility assigned to certain entities, including PSE&G, for ~~stability projects.~~the Artificial Island project. PSE&G plans to participate in this proceeding. However, we are unable to predict the outcome.

Transmission Regulation—Transmission Rate Proceedings

Numerous complaints have been filed at FERC in recent years seeking to reduce the base ROE of transmission owners across the country. Many of those complaints were resolved through agreement and settlement resulted in ROE reductions while others remain pending in the FERC adjudication process or are being litigated in the courts. Recent court decisions, as well as anticipated changes in the makeup at FERC, create some uncertainty as to the timing and outcome of these complaints. The

results of these settlement and proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

Transmission Regulation—Con Edison Wheeling Agreement

December 31, 2016 Form 10-K page ~~19.~~19 and March 31, 2017 Form 10-Q on page 77. ~~In April 2016, Con Edison informed PJM that it would allow its Wheeling Agreement to expire effective as of~~ EffectiveMay 1, ~~2017. The Wheeling Agreement enables~~2017, a wheeling arrangement which enabled Con Edison to move 1,000 MW of power from southeastern New York across the PSE&G system for delivery into New York ~~City.~~City expired. NYISO and PJM ~~submitted proposed tariff provisions in January 2017. The proposal concerns future~~revised their Joint Operating Agreement to modify the operational ~~procedures and transmission planning assumptions associated with~~protocols for the affected ~~transmission lines.~~interconnection between NYISO and PJM in a submittal to FERC ~~accepted the proposal,~~that became effective, subject to refund, ~~effective~~on May 1, 2017. ~~We cannot predict the impact of the proposal on energy prices or transmission planning at this time. Both~~ PSE&G and the BPU ~~protested certain aspects~~jointly filed for rehearing of ~~the proposal.~~FERC’s order. In a related filing, PJM submitted a proposal to FERC revising the cost responsibility assigned to certain entities, including PSE&G, due to the termination of the Wheeling Agreement. ~~Also,~~This filing was accepted, subject to refund, effective May 1, 2017. PSE&G will continue to recover the costs associated with the new arrangement through its formula rate. We cannot predict the outcome of this proceeding.

State Regulation

~~Energy Efficiency~~Gas System Modernization Program ~~(Energy Efficiency 2017)~~II (GSMP II)

In ~~March~~July 2017, we filed a petition with the BPU for ~~our Energy Efficiency 2017~~a GSMP II program, requesting extension of ~~three~~ our gas system modernization program through which PSE&G has proposed investing $2.7 billion over five years beginning in 2019 to continue to modernize our gas system. Under this proposed program, we plan to replace up to 1,250 miles of gas mains and associated service lines, with cost recovery at a 9.75% rate of return on equity through an accelerated recovery mechanism. This matter is pending. We believe the petition is consistent with the draft regulations that the BPU issued in June 2017 regarding infrastructure investment programs as described below.

Connecticut Rate Filing

December 31, 2016 Form 10-K page 21. In June 2017, Power’s subsidiary, PSEG New Haven LLC, filed a mandatory annual rate case with the Connecticut Public Utilities Regulatory Authority for recovery of its costs and investment in its Connecticut-based peaking unit. Power requested 2018 revenues of $20 million. This matter is pending.

Energy Efficiency ~~Economic sub-programs (multi-family, direct install~~Program (Energy Efficiency 2017)

March 31, 2017 Form 10-Q on page 77. In July 2017, we reached an agreement in principle with BPU Staff and ~~hospital efficiency) and~~Rate Counsel related to our proposed Energy Efficiency program extension. Under the ~~addition of two new sub-programs (smart thermostat and residential data analytics). The petition requested additional capital expenditures of approximately $74~~agreement, PSE&G would invest $69 million ~~additional administrative~~in energy efficiency equipment for hospitals, multi-family housing and other ~~costs of $22 million~~sectors and ~~information technology system enhancement costs of $3 million.~~a residential energy efficiency offering for smart thermostats and data analytics. We ~~proposed to~~would recover our investment with an initial ROE of 9.75% to be reset in ~~these sub-programs under~~our upcoming rate case and receive recovery of administrative costs. This agreement is subject to review by the ~~same clause~~BPU.

Infrastructure Investment Programs (IIP)

In June 2017, the BPU issued proposed IIP regulations that would allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under the proposed regulations, utilities could seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery ~~process~~mechanisms. The BPU characterized the IIP regulations as ~~currently approved. This matter is pending.~~

a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. The proposed regulations will be subject to comment from interested parties.

Environmental Matters

Climate Change

CO₂ Regulation under the Clean Air Act (CAA)

December 31, 2016 Form 10-K page ~~23.~~23 and March 31, 2017 Form 10-Q on page 77. In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO₂ for certain new fossil power plants and the Clean Power Plan, a greenhouse gas emissions regulation under the CAA for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In April 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance for at least 60 days while the agency reviews the rule.

Upon completion of the review, the EPA is expected to suspend, revise or rescind the rules as appropriate. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

Water Pollution Control

Steam Electric Effluent Guidelines

December 31, 2016 Form 10-K page ~~23.~~23 and March 31, 2017 Form 10-Q on page 77. In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the ~~jointly-~~

~~owned~~jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

Waters of the United States

December 31, 2016 Form 10-K page ~~24.~~24 and March 31, 2017 Form 10-Q on page 78. In April 2014, the EPA ~~Administrator~~ and the ~~Assistant Secretary~~U.S. Army Corps of ~~the Army (Civil Works)~~Engineers jointly published a proposed rule to clarify the definition of waters of the United States under the ~~CWA~~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 in June 2015 (June 2015 rule) and various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the ~~final~~June 2015 rule.

In February 2017, the President of the United States issued an Executive Order that instructed the EPA to review the June 2015 rule ~~as well as which court has jurisdiction over~~and issue a proposal to redefine “Waters of the ~~rule. The~~United States.” In June 2017, the EPA and the U.S. ~~Supreme Court~~Army Corps of Engineers announced the agencies will be (1) issuing a proposed rule to rescind the 2015 Rule and reinstate the previously existing definition of “Waters of the United States” and (2) developing a new rule, including a revised definition of “Waters of the United States.” Publication of the proposed rule to rescind the June 2015 rule is expected toin the third quarter of 2017 and the process regarding a new rule ~~on the question of jurisdiction by June 2017.~~ will likely take several years.

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~~rule could impose requirements in other states and regions that could impact the development of renewables.

~~In February 2017, the President of the United States issued an Executive Order that instructed the EPA to review the rule and issue a proposal to redefine “Waters of the United States.”~~

Endangered Species Act

December 31, 2016 Form 10-K page ~~25.~~25 and March 31, 2017 Form 10-Q on page 78. In June 2015, the Sierra Club and another environmental group submitted to the ~~NJDEP~~New Jersey Department of Environmental Protection (NJDEP) a sixty-day notice of intent to sue alleging the agency has caused violations of the Endangered Species Act by allowing our Mercer generation station to operate in a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a New Jersey Pollutant Discharge Elimination System (NJPDES) permit renewal action for Mercer which addresses the alleged Endangered Species Act violations. In May 2017, the NJDEP issued a final NJPDES renewal permit for Mercer effective June 1, 2017. The new permit will cover the waste water discharges that will be present during the period of decommissioning. In March 2017, we submitted ~~our~~an Incidental Take Permit application to the National Marine Fisheries Service outlining proposed operation and monitoring requirements through retirement of the Mercer generation station on

June 1, 2017 and subsequent decommissioning.


ITEM 6.	EXHIBITS

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



a. PSEG:
Exhibit 10.1:		Supplemental Executive Retirement Income Plan dated July 10, 2017
Exhibit 10.2:		Retirement Income Reinstatement Plan dated July 10, 2017
Exhibit 12:		Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 101.INS:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

b. PSE&G:
Exhibit 10.1:		Supplemental Executive Retirement Income Plan dated July 10, 2017
Exhibit 10.2:		Retirement Income Reinstatement Plan dated July 10, 2017
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 10.1:		Supplemental Executive Retirement Income Plan dated July 10, 2017
Exhibit 10.2:		Retirement Income Reinstatement Plan dated July 10, 2017
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

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~~July 28, 2017

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~~July 28, 2017