~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~Stock Compensation - Scope of Modification Accounting

~~(UNAUDITED)~~This accounting standard provides clarity and reduces both diversity in practice and complexity when applying the stock compensation guidance to a change in the terms or conditions of a stock-based payment award. Specifically, the standard provides guidance as to which changes to the terms or conditions of a stock-based payment award require an entity to apply modification accounting.

~~Table of Contents~~The standard is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period, for reporting periods for which financial statements have not yet been issued. This standard should be applied prospectively to an award modified on or after the adoption date. PSEG plans to adopt this standard effective January 1, 2018.

Note 3. Early Plant Retirements

Fossil

In October 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. ~~Power has filed deactivation notices with PJM for these existing~~Both units ~~at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Power expects the units to continue to be~~were available to ~~generate electricity~~operate through May 31, 2017 and ~~receive previously cleared capacity payments through the date the units cease operations.~~were subsequently retired from operation on June 1, 2017.

In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.

~~In the first quarter~~As of June 1, 2017, Power recognized total D&A of ~~$574~~$964 million ~~and expects to recognize additional total D&A of $389 million in 2017~~ for the Hudson and Mercer ~~units.~~units to reflect the end of their economic useful lives in 2017. In the three and nine months ended September 30, 2017, Power ~~also~~ recognized pre-tax charges in Energy Costs of $7$1 million and $10 million, respectively, primarily for coal inventory lower of cost or market adjustments. For the three and nine months ended September 30, 2017, Power also recognized pre-tax charges in O&M of $8 million and $12 million, respectively, of shut down costs and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. 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 environmental remediation are neither currently probable nor estimable but may be material.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

As of December 31, 2016, Power had reduced the estimated useful life of Bridgeport Harbor Station unit 3 (BH3) from 2025 to the summer of 2021 as it was more likely than not it will retire the unit by this time. ~~The change in the estimated useful life is not expected to have a material impact on Power’s future financial results.~~

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 classification of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.

Nuclear

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced 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 low natural gas prices driven by 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 the market trends noted above continue or worsen, Power’s New Jersey 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.~~results and cash flows. PSEG and Power continue to advocate for sound policies that recognize nuclear power as a source of reliable ~~and~~ clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

The following table provides the balance sheet amounts by generating station as of ~~March 31,~~September 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 September 30, 2017
	Hope Creek			Salem			Support Facilities and Other (A)		Peach Bottom
	Millions
Assets
Materials and Supplies Inventory	$	85		$	81		$	—	$	41
Nuclear Production, net of Accumulated Depreciation	452			557			204		753
Nuclear Fuel In-Service, net of Accumulated Depreciation	120			94			—		109
Construction Work in Progress (including nuclear fuel)	216			130			9		92
Total Assets	$	873		$	862		$	213	$	995
Liability
Asset Retirement Obligation	$	148		$	162		$	—	$	164
Total Liabilities	$	148		$	162		$	—	$	164
Net Assets	$	725		$	700		$	213	$	831
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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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 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~~$114 million and ~~$98~~$116 million for the three months and $338 million and $315 million for the nine months ended ~~March 31,~~September 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)~~

~~Table of Contents~~

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~~.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:

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.

In October 2017, the 2018 Annual Formula Rate update was filed with FERC and requests approximately $212 million in increased annual transmission revenue effective January 1, 2018, subject to true-up.

Gas System Modernization Program (GSMP)—In July of each year, PSE&G files with the BPU for base rate recovery of GSMP investments which include a return of and on its investment.

In October 2017, PSE&G submitted the planned update to its annual GSMP cost recovery petition, originally filed in July 2017, to include GSMP investments in service as of September 30, 2017. This filing seeks BPU approval to recover in gas base rates an annual revenue increase of $25 million effective January 1, 2018. This increase represents the return of and on investment for GSMP investments in service through September 30, 2017. This proceeding is ongoing.

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 submitted the planned update to its March Energy Strong cost recovery petition, originally filed in March 2017, to include Energy Strong investments in service as of May 31, 2017. This filing requested estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. In August 2017, the BPU approved these rate increases effective September 1, 2017.

In September 2017, PSE&G filed its Energy Strong electric ~~and gas~~ cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs ~~associated with electric and gas plant investments under the program that is anticipated to be~~placed in service ~~by May 31,~~from June 1, 2017 through November 30, 2017. The petition requests rates to be effective ~~September~~March 1, ~~2017,~~2018, consistent with the BPU Order of approval of the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Energy Strong ~~Program.~~program. The annualized requested increase in electric revenue requirement is approximately ~~$22 million for electric and $3 million for gas.~~$9 million. This ~~matter~~proceeding is ~~pending.~~ongoing.

~~Green Program Recovery Charges~~Basic Gas Supply Services (BGSS)—In ~~March~~June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase in the BGSS rate from approximately 34 cents to 37 cents per therm effective October 1, 2017. In September 2017, the BPU ~~gave final approval to PSE&G’s petition to recover approximately $37 million~~approved a Stipulation in this matter on a provisional basis and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved programs. The rates are effective May 1, 2017. This Order also included the ~~return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge.~~ BGSS rate was increased.

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). In September 2017, the BPU approved this petition on a provisional basis with rates effective October 1, 2017, allowing recovery during the 2017-2018 Winter Period.

Green Program Recovery Charges (GPRC)—In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.

Each year PSE&G files with the BPU for annual recovery for the 11 combined components of its electric and gas Green Program investments which include a return on its investment and recovery of expenses.

In March 2017, the BPU gave final approval to PSE&G’s 2016 GPRC cost recovery 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 for the period October 1, 2016 through September 30, 2017. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge.

In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery of 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 for the period October 1, 2017 through September 30, 2018. This proceeding is ongoing.

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.

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.”

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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	September 30, 2017		December 31, 2016
	Millions
Commercial/Industrial	$	160	$	164
Residential	10		11
Total	$	170	$	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)~~

~~Table of Contents~~

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.

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 related to the lease ~~investments,~~receivables, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of ~~March 31,~~September 30, 2017.

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 and continues to discuss the situation with GenOn. 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 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 September 30, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The following table shows Energy Holdings’ gross and net lease investment as of ~~March 31,~~September 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
	September 30, 2017			December 31, 2016
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	546		$	629
Estimated Residual Value of Leased Assets	326			346
Total Investment in Rental Receivables	872			975
Unearned and Deferred Income	(309		)	(326		)
Gross Investment in Leases	563			649
Deferred Tax Liabilities	(631		)	(674		)
Net Investment in Leases	$	(68	)	$	(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 September 30, 2017
	As of September 30, 2017
	Millions
AA	$	15
BBB+ — BBB-	316
BB-	133
CCC-	82
Total	$	546

The “BB-” and the “CCC-” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of ~~March 31,~~September 30, 2017, the gross investment in the leases of such assets, net of non-recourse debt, was $~~371~~337 million ($~~(154)~~(184) million, net of deferred taxes). A more detailed description of such assets under lease, as of ~~March 31,~~September 30, 2017, is presented in the following table.




Asset	Location	Gross Investment		% Owned		Total MW	Fuel Type	Counterparties’ S&P Credit Ratings	Counterparty
		Millions
Powerton Station Units 5 and 6	IL	$	133	64	%	1,538	Coal	BB-	NRG Energy, Inc.
Joliet Station Units 7 and 8	IL	$	84	64	%	1,036	Gas	BB-	NRG Energy, Inc.
Keystone Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CCC-	REMA (A)
Conemaugh Station Units 1 and 2	PA	$	20	17	%	1,711	Coal	CCC-	REMA (A)
Shawville Station Units 1, 2, 3 and 4	PA	$	80	100	%	596	Gas	CCC-	REMA (A)


(A)	REMA’s parent company, GenOn, and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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

~~(A)~~

REMA’s parent company, GenOn Energy Inc. (GenOn), reported in August 2016 that GenOn 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 REMA) to “CCC-” from “CCC” reflecting the primary credit concern of the near-term maturity of GenOn’s senior unsecured notes in June 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.

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.~~investments and continues to discuss the situation with GenOn. 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.~~Service (IRS).

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)~~

~~Table of Contents~~

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 September 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	706	$	331	$	(5	)	$	1,032
Debt Securities
Government	561		10		(4		)	567
Corporate	352		7		(1		)	358
Total Debt Securities	913		17		(5		)	925
Other Securities	55		—		—			55
Total NDT Available-for-Sale Securities	$	1,674	$	348	$	(10	)	$	2,012

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents




	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.~~


(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)~~

~~Table of Contents~~




	As of		As of
	September 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	11	$	8
Accounts Payable	$	5	$	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 September 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)	$	67	$	(5	)	$	—	$	—		$	120	$	(10	)	$	8	$	(1	)
Debt Securities
Government (B)	237		(2		)	62		(2		)	276		(6		)	4		—
Corporate (C)	60		—			36		(1		)	139		(3		)	15		(1		)
Total Debt Securities	297		(2		)	98		(3		)	415		(9		)	19		(1		)
Other Securities	3		—			—		—			—		—			—		—
NDT Available-for-Sale Securities	$	367	$	(7	)	$	98	$	(3	)	$	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,~~September 30, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

(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,~~September 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,~~September 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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	Millions
Proceeds from NDT Fund Sales (A)	$	278		$	139		$	845		$	470
Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains	$	29		$	11		$	82		$	36
Gross Realized Losses	(5		)	(3		)	(14		)	(25		)
Net Realized Gains (Losses) on NDT Fund	$	24		$	8		$	68		$	11

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

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

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~~172 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of ~~March 31,~~September 30, 2017.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

The NDT available-for-sale debt securities held as of ~~March 31,~~September 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

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




Time Frame	Fair Value
	Millions
Less than one year	$	37
1 - 5 years	236
6 - 10 years	230
11 - 15 years	62
16 - 20 years	67
Over 20 years	293
Total NDT Available-for-Sale Debt Securities	$	925

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~~nine months ended ~~March 31,~~September 30, 2017, Other-Than-Temporary Impairments (OTTI) of$19 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)

Table of Contents

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)~~

~~Table of Contents~~




	As of September 30, 2017
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	22	$	1	$	—		$	23
Debt Securities
Government	82		2		—			84
Corporate	118		3		(1		)	120
Total Debt Securities	200		5		(1		)	204
Other Securities	2		—		—			2
Total Rabbi Trust Available-for-Sale Securities	$	224	$	6	$	(1	)	$	229




	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
	September 30, 2017		December 31, 2016
	Millions
Accounts Receivable	$	2	$	5
Accounts Payable	$	—	$	3

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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 September 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)	25		—			3		—		60		(2		)	1		—
Corporate (C)	14		(1		)	4		—		46		(2		)	3		—
Total Debt Securities	39		(1		)	7		—		106		(4		)	4		—
Rabbi Trust Available-for-Sale Securities	$	39	$	(1	)	$	7	$	—	$	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,~~September 30, 2017.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

(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,~~September 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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
	Millions
Proceeds from Rabbi Trust Sales (A)	$	24		$	20		$	168		$	81
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	—		$	2		$	17		$	5
Gross Realized Losses	(1		)	(2		)	(5		)	(4		)
Net Realized Gains (Losses) on Rabbi Trust	$	(1	)	$	—		$	12		$	1

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

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

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 ~~losses~~gains of ~~$(1)~~$3 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of ~~March 31,~~September 30, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The Rabbi Trust available-for-sale debt securities held as of ~~March 31,~~September 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

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




Time Frame	Fair Value
	Millions
Less than one year	$	—
1 - 5 years	40
6 - 10 years	27
11 - 15 years	6
16 - 20 years	19
Over 20 years	112
Total Rabbi Trust Available-for-Sale Debt Securities	$	204

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~~nine months ended ~~March 31,~~September 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)~~

~~Table of Contents~~

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
	September 30, 2017		December 31, 2016
	Millions
PSE&G	$	46	$	43
Power	57		53
Other	126		121
Total Rabbi Trust Available-for-Sale Securities	$	229	$	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 $36 million for the three months and nine months, ended September 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)

Table of Contents

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						Nine Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2017			2016			2017			2016			2017			2016			2017			2016
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	29		$	28		$	4		$	5		$	86		$	82		$	12		$	13
Interest Cost	51			50			15			15			153			151			47			44
Expected Return on Plan Assets	(98		)	(98		)	(8		)	(8		)	(295		)	(295		)	(25		)	(23		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(5		)	(3		)	(4		)	(14		)	(14		)	(8		)	(11		)
Actuarial Loss	24			39			13			10			73			118			38			30
Total Benefit Costs	$	1		$	14		$	21		$	18		$	3		$	42		$	64		$	53

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

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				Nine Months Ended					Nine Months Ended
	September 30,					September 30,				September 30,					September 30,
	2017			2016		2017		2016		2017			2016		2017		2016
	Millions
PSE&G	$	(1	)	$	8	$	13	$	11	$	(3	)	$	22	$	40	$	33
Power	—			3		7		6		1			11		20		17
Other	2			3		1		1		5			9		4		3
Total Benefit Costs	$	1		$	14	$	21	$	18	$	3		$	42	$	64	$	53

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$18 million and $6$16 million for the three months ended ~~March 31,~~September 30, 2017 and 2016, respectively, and $35 million and $28 million for the nine months ended September 30, 2017 and 2016, respectively. Servco’s pension-related costs of $35 million for the nine months ended September 30, 2017 represent its entire planned contribution for the year 2017. The OPEB-related revenues earned and costs incurred were $1 million and $3 million for the three months and nine months ended ~~March 31, 2017 were $1 million~~September 30, 2017. The OPEB-related revenues earned and costs incurred were immaterial for the three months and nine months ended ~~March 31,~~September 30, 2016.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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)~~

~~Table of Contents~~

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)

Table of Contents

The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of ~~March 31,~~September 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
	September 30, 2017			December 31, 2016
	Millions
Face Value of Outstanding Guarantees	$	1,846		$	1,806
Exposure under Current Guarantees	$	108		$	139

Letters of Credit Margin Posted	$	134		$	157
Letters of Credit Margin Received	$	59		$	99

Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(2	)	$	(1	)
Net Broker Balance Deposited (Received)	$	(6	)	$	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)~~

~~Table of Contents~~

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)~~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 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the

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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 5250 members as of ~~March 31,~~September 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~~$195 million, which the CPG continues to incur. Of the estimated ~~$190~~$195 million, as of ~~March 31,~~September 30, 2017, the CPG had spent approximately ~~$160~~$168 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.

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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, 2017, these~~These accruals ~~bring~~brought the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power. There have been no additional accruals recorded since the first quarter of 2016.

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

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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. The bankruptcy plan ordered by the Delaware Court in July, 2017 created a Liquidating Trust to pursue outstanding creditors’ claims, including alter ego claims against YPF. 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 20certain 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.~~settlements. 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 proposed settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs that received General Notice letters (excluding PRPs that settle pursuant to the early cash-out settlement that the EPA offered in March 2017, among others). The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform the remedial action under EPA oversight. Discussions on the matter are ongoing.

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

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

Newark Bay Study Area

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

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MGP Remediation Program

PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between ~~$386~~$390 million and ~~$443~~$440 million on an undiscounted basis 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~~$390 million as of ~~March 31,~~September 30, 2017. Of this amount, $74 million was recorded in Other Current Liabilities and ~~$312~~$316 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a ~~$386~~$390 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~~to what extent 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

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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 for the Second Circuit (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.~~remains pending.

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. This matter is still pending. 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

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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.

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~~Power is currently awaiting action by the CTDEEP ~~if the proposal is accepted,~~to issue a draft and then a final ~~permit could be issued in 2017. See Note 3. Early Plant Retirements.~~permit.

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 (CSC) issued an order to approve siting ~~BH5.~~Bridgeport Harbor Station unit 5. All major environmental permits have been ~~obtained. Operations~~received; however, secondary approvals are ~~expected~~still being obtained to allow operations to begin ~~in mid-2019.~~by June 2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed.

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 impacted cable was repaired in late-September 2017; however, the investigation and response actions related to the fluid discharge are ongoing. ~~The investigation of~~Also ongoing is the ~~discharge and its potential cause is in the preliminary~~

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~~stages, making it difficult~~process to determine ultimate responsibility for the ~~timing and potential~~ costs to ~~resolve this matter, as well as responsibility for such costs between~~address the leak among PSE&G, Con Edison and NADC, including an action filed by PSE&G in New Jersey federal court seeking damages from NADC. Based on theinformation currently available ~~information~~ and depending on the ~~potential scope~~outcome of the ~~necessary repair and remediation work,~~New Jersey federal action, PSE&G’s portion of the costs ~~will likely~~to address the leak may be ~~material.~~ In ~~addition, the timeline for completing the repairs has been extended due to the presence of debris within PSE&G’s easement. In November 2016,~~material; however, 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&Ganticipates 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 debris removal activities are ongoing.will recover these costs through regulatory proceedings.

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 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

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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,~~streams.In September 2017, the EPA issued a rule postponing for two years compliance dates solely related to bottom ash transport water and flue gas desulfurization ~~wastewater, flue gas mercury control wastewater,~~wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and ~~gasification wastewater.~~compliance dates for these two waste 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.

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




	Auction Year
	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, enrichment and fabrication requirements through ~~2018~~2020 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom.

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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,~~September 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	$	257
Enrichment	$	328
Fabrication	$	178
Natural Gas	$	963
Coal	$	308

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

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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 and continues to review its policies and practices 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~~In October 2017, FERC Staff closed the investigation with ~~FERC in this matter. PSEG cannot predict the outcome of this matter at this time.~~no impact to PSEG’s operations or future earnings results.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note 10. Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transactions occurred in the nine months ended September 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,~~September 30, 2017, the total available credit capacity was ~~$3.6~~$3.8 billion.

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

As of ~~March 31,~~September 30, 2017, ~~the~~ total credit capacity was in excess of ~~its~~the total anticipated maximum liquidity ~~requirements.~~requirements of PSEG, PSE&G and Power.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

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,~~September 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 September 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	215	$	1,285	Mar 2022	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	215	$	1,285
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	$	112	$	88	Mar 2020	Letters of Credit
5-year Credit Facilities	1,900		70		1,830		Mar 2022	Funding/Letters of Credit
Total Power	$	2,100	$	182	$	1,918
Total	$	4,200	$	412	$	3,788


(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 September 30, 2017, PSEG had $202 million outstanding at a weighted average interest rate of 1.37%. PSE&G had no amounts outstanding under its Commercial Paper Program as of September 30, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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)~~

~~Table of Contents~~

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,~~September 30, 2017 or December 31, 2016. The fair value hedges reduced interest expense by $2 million and $6 million for the three months and nine months ended ~~March 31,~~September 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,~~September 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, 2017 and~~ December 31, 2016, the fair value of these hedges was $2$1 million and ~~$1 million, respectively.~~was immaterial as of September 30, 2017. There was no ineffectiveness as of ~~March 31,~~September 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 $1 million and $2 million as of ~~March 31,~~September 30, 2017 and December 31, ~~2016.~~2016, respectively. The after-tax unrealized ~~gains on these hedges~~gain expected to be reclassified to earnings during the next 12 months is ~~$1 million.~~immaterial.

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)

Table of Contents

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)~~

~~Table of Contents~~




	As of September 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	$	352		$	(268	)	$	84		$	—	$	84
Noncurrent Assets	178			(116		)	62			—		62
Total Mark-to-Market Derivative Assets	$	530		$	(384	)	$	146		$	—	$	146
Derivative Contracts
Current Liabilities	$	(268	)	$	261		$	(7	)	$	—	$	(7	)
Noncurrent Liabilities	(110		)	109			(1		)	—		(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(378	)	$	370		$	(8	)	$	—	$	(8	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	152		$	(14	)	$	138		$	—	$	138




	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

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)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	2,263	$	2,450	$	(187	)	(8	)	$	6,988	$	6,971	$	17		—
Energy Costs	638		866		(228		)	(26	)	2,100		2,326		(226		)	(10	)
Operation and Maintenance	680		776		(96		)	(12	)	2,100		2,215		(115		)	(5	)
Depreciation and Amortization	252		231		21			9		1,721		679		1,042			N/A
Income from Equity Method Investments	3		3		—			—		11		9		2			22
Other Income (Deductions)	56		39		17			44		178		100		78			78
Other-Than-Temporary Impairments	5		5		—			—		9		25		(16		)	(64	)
Interest Expense	100		99		1			1		289		288		1			—
Income Tax Expense	252		188		64			34		340		562		(222		)	(40	)

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)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,509	$	1,684	$	(175	)	(10	)	$	4,689	$	4,746	$	(57	)	(1	)
Energy Costs	535		721		(186		)	(26	)	1,760		1,979		(219		)	(11	)
Operation and Maintenance	346		376		(30		)	(8	)	1,064		1,110		(46		)	(4	)
Depreciation and Amortization	169		137		32			23		506		412		94			23
Other Income (Deductions)	22		21		1			5		67		58		9			16
Interest Expense	79		72		7			10		223		214		9			4
Income Tax Expense	156		144		12			8		450		393		57			15

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

Operating Revenues ~~increased $100~~decreased $175 million due to changes in delivery, commodity, clause and other operating revenues.

Table of Contents

Delivery Revenues increased ~~$58~~$10 million due primarily to an increase in transmission revenues.

Transmission revenues were ~~$37~~$34 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

Gas distribution revenues increased ~~$24~~$5 million due to ~~an $11~~a $1 million increase ~~due to~~from the inclusion of Energy Strong in base rates, ~~a $5~~and $1 million ~~increase due to the Gas System Modernization Program, $4 million of higher delivery volumes, higher~~increases in both GSMP collections and Green Program Recovery Charges (GPRC) ~~of $2 million~~ and ~~$2 million in~~ higher ~~Weather Normalization Clause revenue.~~sales volumes.

Electric distribution revenues decreased $3$29 million due to ~~lower GPRC of $3 million and~~ a $2$38 million decrease due to lower sales volumes and lower GPRC of $6 million, partially offset by a $2$15 million increase ~~due to~~from the inclusion of Energy Strong in base rates.

~~Table of Contents~~

Commodity Revenue ~~increased $24~~decreased $186 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 ~~basic gas supply service (BGSS)~~BGS and ~~BGS~~BGSS to retail customers.

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

Electric commodity revenues decreased ~~$50~~$176 million due primarily to a $153 million decrease in BGS revenues due to $97 million in lower sales volumes and $56 million from lower prices and $23 million of lower revenues from collections of Non-Utility Generation Charges (NGC)~~, a $17 million decrease in BGS~~.

Gas commodity revenues ~~due to lower sales prices and volumes and a decrease of~~decreased $10 million due to lower BGSS sales prices of $22 million, partially offset by higher BGSS sales volumes of ~~Non-Utility Generation (NUG) energy sold.~~$12 million.

Clause Revenues increased ~~$19~~$1 million due primarily to the ~~2016~~ return of $20 million to customers ~~of $15 million~~in 2016 of overcollections of Securitization Transition Charges (STC), ~~and higher~~partially offset by lower Societal Benefit Charges (SBC) of $2$12 million and a $6 million decrease in ~~2017.~~2017 in Margin Adjustment Clause (MAC) revenues. The changes in the STC, SBC and ~~SBC~~MAC 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, SBC or ~~SBC~~MAC collections.

Operating Expenses

Energy Costs ~~increased $24~~decreased $186 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased ~~$15~~$30 million, primarily due to a $17 million reduction in clause-related costs, $6 million in lower appliance service costs, $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

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

~~a $3~~$4 million ~~net decrease~~ in certain operational expenses.

Depreciation and Amortization increased $32 million due primarily to an increase of ~~$17~~$19 million in amortization of Regulatory Assets and a $14 million increase in depreciation due to additional plant in service.

~~Other Income and (Deductions)~~Interest Expense increased $5$7 million due primarily to an increase of $5 million due to net debt issuances in 2016 and 2017 and a $2 million increase in other interest.

Income Tax Expense increased $12 million due primarily to uncertain tax positions and plant-related items.

Nine Months Ended September 30, 2017 as Compared to 2016

Operating Revenues decreased $57 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $119 million due primarily to an increase in transmission revenues.

Transmission revenues were $116 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

Gas distribution revenues increased $29 million due to a $14 million increase due to the inclusion of Energy Strong in base rates, $8 million in higher Weather Normalization Clause (WNC) revenue, a $7 million increase due to the GSMP and higher GPRC of $3 million, partially offset by $3 million of lower delivery volumes.

Electric distribution revenues decreased $26 million due to a $36 million decrease due to lower sales volumes and lower GPRC of $14 million, partially offset by a $24 million increase due to the inclusion of Energy Strong in ~~Allowance~~base rates.

Commodity Revenue decreased $219 million as a result of lower Electric revenues partially offset by higher Gas revenues. The changes in Commodity revenue for ~~Funds Used During Construction~~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 $266 million due primarily to a $188 million decrease in BGS revenues due to $116 million in lower sales volumes and $72 million of lower prices, $64 million of lower revenues from collections of NGC and a decrease of $14 million due to lower volumes of Non-Utility Generation energy sold.

Table of Contents

Gas commodity revenues increased $47 million due primarily to $69 million of higher BGSS sales prices, partially offset by $22 million of lower sales volumes.

Clause Revenues increased $41 million due primarily to the 2016 return to customers of $50 million of overcollections of STC, and higher MAC revenues of $2 million in 2017, partially offset by a $12 million decrease in collections of SBC. The changes in the STC, MAC and SBC amounts are entirely offset by changes 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, MAC or SBC collections.

Operating Expenses

Energy Costs decreased $219 million. This is entirely offset by the change in Commodity Revenue.

Operation and Maintenance decreased $46 million, of which the most significant components were decreases of $17 million in distribution corrective and preventative maintenance, $14 million in appliance service costs, $11 million in clause-related costs and $11 million in GPRC costs, partially offset by a $10 million net increase in certain operational expenses.

Depreciation and Amortization increased $94 million due primarily to an increase of $51 million in amortization of Regulatory Assets and a $43 million increase in depreciation due to additional plant in service.

Other Income and (Deductions) increased $9 million due primarily to an increase of $7 million in allowance for funds used during construction and a $3 million increase in realized gains on Rabbi Trust ~~investments.~~investments, partially offset by a net $1 million decrease in Solar Loan interest.

Interest Expense increased $7$9 million due primarily to an increase of $16 million due to net debt issuances in ~~2016.~~2016 and 2017, partially offset by a $7 million decrease predominantly driven by a reduction in clause interest.

Income Tax Expense increased ~~$20~~$57 million due primarily to higher pre-tax ~~income.~~income and changes in uncertain tax positions.

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				Increase/ (Decrease)					Nine Months Ended					Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,					Increase/ (Decrease)
	2017		2016		2017 vs. 2016					2017			2016		2017 vs. 2016
	Millions				Millions			%		Millions					Millions			%
Operating Revenues	$	873	$	1,075	$	(202	)	(19	)	$	3,086		$	3,102	$	(16	)	(1	)
Energy Costs	357		462		(105		)	(23	)	1,461			1,481		(20		)	(1	)
Operation and Maintenance	227		289		(62		)	(21	)	711			807		(96		)	(12	)
Depreciation and Amortization	76		86		(10		)	(12	)	1,191			245		946			N/A
Income from Equity Method Investments	3		3		—			—		11			9		2			22
Other Income (Deductions)	35		17		18			N/A		105			41		64			N/A
Other-Than-Temporary Impairments	5		5		—			—		9			25		(16		)	(64	)
Interest Expense	12		24		(12		)	(50	)	41			66		(25		)	(38	)
Income Tax Expense (Benefit)	98		90		8			9		(80		)	208		(288		)	N/A

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

Operating Revenuesdecreased~~$29~~ $202 million due to changes in generation and gas supply revenues.

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Generation Revenues decreased ~~$124~~$200 million due primarily to

a ~~net~~ decrease 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~~$110 million due to MTM losses in 2017 as compared to MTM gains in 2016. Of this amount, ~~$131~~$98 million was due to changes in forward ~~power prices. The decrease~~prices and $12 million was ~~offset by an increase of $107 million~~ due to ~~losses~~greater gains on positions reclassified to realized upon settlement this year as compared to ~~gains~~ last year,

a decrease of $83 million in electricity sold under our BGS contracts due to lower volumes and lower prices, and

a ~~charge~~decrease of ~~$10~~$25 million in energy sales in the PJM region due to ~~an increase in the FERC accrual related to the PJM bidding matter, see Note 9. Commitments~~lower generation volumes and ~~Contingent Liabilities,~~lower average realized prices,

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partially offset by a net increase of ~~$10~~$18 million due primarily to higher ~~volumes of~~capacity revenue and electricity sold under wholesale load contracts ~~in the NE region partially offset by lower~~at higher average ~~prices.~~

prices, coupled with new solar projects.

Gas Supply Revenues~~increased~~ ~~$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~~decreased $2 million due to ~~higher~~lower MTM gains in 2017 as compared to ~~2016, primarily due to losses on positions reclassified to realized upon settlement this year as compared to gains last year.~~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~~decreased $105 million due to

Generation costs decreased $1$108 million due primarily to

a net decrease of $59 million due to charges associated with the early retirement of the Mercer and Hudson units announced in October 2016, primarily related to a coal inventory write-down, partially offset by additional retirement costs incurred in 2017,

a net decrease of $26 million due primarily to lower natural gas costs reflecting lower volumes,

a net decrease of $11 million primarily due to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, and

a decrease of $8 million due to MTM gains in 2017 as compared to MTM losses in 2016.

Gas costs increased $3 million due mainly to a net increase of $2 million related to sales to third parties, of which $5 million was due to higher average gas costs, partially offset by $3 million due to lower volumes sold.

Operation and Maintenance decreased $62 million due primarily to

a $51 million decrease at our fossil plants, due to the retirement of the Hudson and Mercer units on June 1, 2017, and

a $10 million net decrease related to our nuclear plants due primarily to lower labor-related costs.

Depreciation and Amortization decreased$10 milliondue primarily to

$19 million of lower depreciation due to the retirement of the Hudson and Mercer units,

partially offset by $4 million of increased depreciation due to the accelerated retirement date at Bridgeport Harbor Station unit 3 (BH3),

$3 million of higher depreciation due to new solar projects, and

a $2 million increase due to additional nuclear plant placed into service.

Other Income (Deductions) increased $18 million due primarily to higher net realized gains in the NDT Fund.

Interest Expense decreased $12 million due primarily to

a $7 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and

a $5 million decrease due to debt maturities in September 2016.

Income Tax Expense (Benefit) reflected anincreased tax expense of $8 million due primarily to changes in the manufacturing deduction and higher pre-tax income in 2017.

Nine Months Ended September 30, 2017 as Compared to 2016

Operating Revenuesdecreased$16 million due to changes in generation and gas supply revenues.

Generation Revenues decreased $101 million due primarily to

a net decrease of $115 million in energy sales in the PJM and New England regions due primarily to lower average realized prices,

a decrease of $91 million in electricity sold under our BGS contracts due to lower volumes and lower prices,

a net decrease of $11 million in operating reserves in the PJM region, and

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

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partially offset by an increase of $86 million due to lower MTM losses in 2017 as compared to 2016. Of this amount, $110 million was due to lower gains on positions reclassified to realized upon settlement this year as compared to last year partially offset by a decrease of $24 million due to changes in forward power prices.

a net increase of $31 million due primarily to higher volumes of electricity sold under wholesale load contracts in the NE region, and

an increase of $10 million due to new solar projects.

Gas Supply Revenuesincreased $84 million due primarily to

an increase of $45 million in sales under the BGSS contract due primarily to higher average sales prices,

an increase of $25 million related to sales to third parties, of which $52 million was due to higher average sales prices, partially offset by $27 million of lower volumes sold, and

a net increase of $14 million due to MTM gains in 2017 as compared to MTM losses in 2016.

Operating Expenses

Generation costs decreased $76 million due primarily to

a net decrease of $57 million primarily due 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,

a net decrease of $49 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to a coal inventory write-down partially offset by additional retirement costs incurred in 2016,

partially offset by higher fuel costs of ~~$14~~$12 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,

ana net increase of $8$10 million primarily due to an increase in energy purchase volumes in the NE region to serve load obligations, and

~~a $7~~an increase of $9 million ~~charge associated primarily with a lower of cost or market coal inventory adjustment at Mercer.~~due to MTM losses in 2017 as compared to MTM gains in 2016.

Gas costs increased ~~$70~~$56 million due mainly to

an increase of ~~$39~~$32 million related to sales ~~to third parties~~under the BGSS contract due to higher average gas costs, and

an increase of ~~$31~~$24 million related to sales ~~under the BGSS contract~~to third parties, of which $48 million was due ~~primarily~~ to higher average gas costs, ~~and an increase~~partially offset by a $24 million decrease in volumes ~~sold due to periods of colder weather in March.~~sold.

Operation and Maintenance decreased ~~$23~~$96 million due primarily to

a ~~$15~~$71 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,

a $20 million net decrease related to our nuclear plants due primarily to lower labor-related costs and outage costs, and

~~a $7~~an $8 million legal ~~reserve~~accrual for environmental expenses recorded in 2016,

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

Depreciation and Amortization increased $~~571~~946 million due primarily to

$~~558~~914 million of ~~accelerated~~higher depreciation due to the early retirement of the Hudson and Mercer units,

$411 million of ~~greater~~increased depreciation due to the accelerated retirement date at ~~Bridgeport Harbor 3,~~

~~a $4 million increase due to a higher nuclear asset base, and~~BH3,

$39 million of higher depreciation due to new solar ~~projects.~~projects, and

a $9 million increase due to additional nuclear plant placed into service.

Other Income (Deductions) increased ~~$23~~$64 million due primarily to ~~$17~~$57 million of ~~lower~~higher net realized ~~losses from~~gains in the NDT Fund ~~in 2017~~ and $3 million of higher net realized gains in the Rabbi Trust Fund.

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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$25 million due primarily to

a $16 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and ~~Keys.~~Keys, and

a net $7 million decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.

Income Tax Expense (Benefit) decreased ~~$245~~$288 million in 2017 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~~nine months ended ~~March 31,~~September 30, 2017, our operating cash flow decreased $1827 million as compared to the same period in 2016. The net change was due primarily ~~due~~ to ~~the~~ net changes from PSE&G and Power as discussed below ~~largely offset by higher~~as well as net tax ~~refunds in 2017~~payments at ~~Energy Holdings.~~PSEG and its other subsidiaries.

PSE&G

PSE&G’s operating cash flow decreased $548 million from $~~568~~1,401 million to $~~514~~1,393 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2017, as compared to the same period in 2016, due primarily to lower tax refunds ~~partially offset by higher earnings,~~ and ~~an increase~~a decrease of ~~$45~~$49 million due to a change in regulatory ~~deferrals.~~deferrals, partially offset by higher earnings.

Power

Power’s operating cash flow decreased $8311 million from $~~663~~1,260 million to $~~580~~1,249 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2017, as compared to the same period in 2016, due primarily ~~due~~ to tax payments in 2017 as compared to tax refunds in 2016 and lower earnings, partially offset by a ~~$65~~$68 million decrease in margin deposit requirements and a $30 million increase from net collection of counterparty ~~receivables and a $12 million increase from fuels, materials and supplies.~~receivables.

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,~~September 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 September 30, 2017
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	215	$	1,285
PSE&G	600		15		585
Power	2,100		182		1,918
Total	$	4,200	$	412	$	3,788

As of ~~March 31,~~September 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

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would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of Power’s

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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~~$899 million and $783 million as of ~~March 31,~~September 30, 2017 and December 31, 2016, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units is not expected to have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 1. Note 3. Early Plant Retirements.

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

Long-Term Debt Financing

During the next twelve months, 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 and $350 million of 2.30% Medium-Term Notes maturing in September 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,~~July 18, 2017, our Board of Directors approved a $0.43 dividend per share of common stock for the ~~first quarter of 2017. On April 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. 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.

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CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. 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~~nine months ended ~~March 31,~~September 30, 2017, PSE&G made capital expenditures of ~~$752~~$2,118 million, primarily for ~~transmission and distribution~~T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$24~~$72 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~~nine months ended ~~March 31,~~September 30, 2017, Power made capital expenditures of ~~$274~~$779 million, excluding $33124 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~~July through ~~March~~September 2017, MTM VaR remained relatively stable between a low of $7$5 million and a high of ~~$25~~$9 million at the 95% confidence level. The range of VaR was narrower for the three months ended ~~March 31,~~September 30, 2017 as compared with the year ended December 31, 2016.

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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 September 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	$	7	$	16
High	$	9	$	32
Low	$	5	$	10
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	13	$	40
Average for the Period	$	11	$	25
High	$	15	$	51
Low	$	8	$	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~~third 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,~~discussed below, there have been no material changes to the risk factors set forth in the above-referenced ~~filing~~filings as of ~~March 31,~~September 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.

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Cybersecurity attacks or intrusions could adversely impact our businesses.

Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency. We rely on information technology systems that utilize sophisticated digital systems and network infrastructure to operate our generation, transmission and distribution systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and Independent System Operators (ISOs), among others. Our and third-party information technology systems may be vulnerable to cybersecurity attacks involving domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:

disruption of the operation of our assets and the power grid,

theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations,

general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and

breaches of vendors’ infrastructures where our confidential information is stored.

We have experienced and expect to continue to experience actual or attempted cyber-attacks on our information technology systems; however, none of these incidents has had a material impact on our operations or financial condition. If a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, reputational damage and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Part 1, Item 1. Regulatory Issues in our Annual Report on Form 10-K for the year ended December 31, 2016 and Item 5. Other Information in this Quarterly Report on Form 10-Q.

The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events may evolve as the industry matures. While we maintain insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damage we experience.


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

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the ~~first~~third quarter of 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 September 30, 2017	Total Number of Shares Purchased	Average Price Paid per Share
July 1 - July 31	—	$	—
August 1 - August 31	135,277	$	45.25
September 1- September 30	—	$	—

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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 quarters ended March 31, 2017 and June 30, 2017. References are to the related pages on the Forms 10-K and 10-Q as printed and distributed.

Employee Relations

December 31, 2016 Form 10-K page 15. In 2016, six of our eight labor unions ratified extensions of their collective bargaining agreements with us, with expiration dates from 2019 to 2021. In 2017, each of the remaining two unions ratified extensions of their collective bargaining agreements with us with expiration dates in 2021 and 2022.

Federal Regulation

FERC

Energy Clearing Prices/Price Formation Initiatives

December 31, 2016 Form 10-K page 16 and March 31, 2017 Form 10-Q on page 76. Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load) which can vary by location. In addition, recent rule changes in the energy markets administered by PJM and ISO-NE (see Capacity Market Issues below) impose rigorous performance obligations and nonperformance penalties on resources during times of system stress. These FERC rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance hour.

FERC has also recently ordered certain favorable changes to energy market price formation rules improving shortage pricing and enhancing bidding flexibility for units. We continue to advocate in this context for additional changes in market rules that would provide more transparency about energy market prices. We cannot predict what action FERC might ultimately take, but such an examination could lead to future rule changes.

In June 2017, PJM issued an energy price formation proposal to address a flaw in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot predict the outcome of this matter.

Notice of Proposed Rulemaking on Baseload Generation

In September 2017, the Secretary of the U.S. Department of Energy issued a Notice of Proposed Rulemaking (NOPR) to allow a full recovery of costs for certain eligible units physically located within the FERC-approved organized markets. The NOPR directs FERC to take final action within 60 days. The NOPR contemplates a cost-of-service payment and a fair rate of return for units that are able to provide certain essential energy and ancillary reliability services, have a 90-day fuel supply on site and are not subject to cost-of-service rate regulation by any State or local authority. We are participating in this proceeding, but we are unable to predict the outcome.

Capacity Market Issues

December 31, 2016 Form 10-K page ~~16.~~16, March 31, 2017 Form 10-Q on page 76 and June 30, 2017 Form 10-Q on page 83. 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, March 31, 2017 Form 10-Q on page 76 and June 30, 2017 Form 10-Q page 83. ~~During 2015,~~ PJM ~~implemented~~issued a ~~new “Capacity Performance” (CP) mechanism~~series of white papers in response to public policies that ~~created a more robust capacity product~~seek to recognize value associated with ~~enhanced incentives for performance during emergency conditions~~generation plants beyond their cost effectiveness and ~~significant penalties for non-performance. However, aspects of FERC’s order~~reliability attributes. The three proposals are currently pending appeal in the Court of Appeals for the D.C. Circuit (D.C. Circuit). The CP product will be implemented fully 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”). 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 the upcoming base residual auction in May 2017.

~~Capacity Market Issues—ISO-NE~~

~~December 31, 2016 Form 10-K page 17.~~ ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and DR. The market design consists of a forward-looking auction for installed capacity that is intended to ~~recognize the locational value of resources on the system~~spur stakeholder discussion 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~~include both potential capacity 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 currentenergy 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~~reforms. The first energy market ~~afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources.~~

reform (see Energy Clearing Prices/Price Formation ~~Initiatives~~

~~December 31, 2016 Form 10-K page 18.~~ ~~Power has been actively involved both through stakeholder processes~~Initiatives) would allow inflexible generating units to set prices resulting in reduced uplift payments 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, veryimproved

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~~close~~price signals while the second energy market reform contemplates a voluntary carbon pricing program where states that elect 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 formationparticipate in the ~~energy and ancillary services markets.~~program would agree to put a price on carbon emissions. The capacity market proposal contemplates a two-stage capacity auction which, in its current form, would improve prices for unsubsidized resources, but would still continue to provide capacity payments for subsidized resources.

Transmission Regulation—~~Transmission Policy Developments~~

December 31, 2016 Form 10-K page 18. In ~~August~~October 2017, PSE&G filed its 2018 Annual Formula Rate Update with FERC which requests approximately $212 million in increased annual transmission revenues effective January 1, 2018, subject to true-up. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. For additional information about our transmission formula rate, see Part I Item 1. Note 5. Rate Filings.

Transmission Regulation—Transmission Policy Developments

December 31, 2016 ~~PJM announced that it had suspended the Artificial Island transmission project~~Form 10-K page 18, March 31, 2017 Form 10-Q on page 77 and ~~would be performing~~June 30, 2017 Form 10-Q on page 83.

In a ~~comprehensive analysis to support~~February 2016 order, FERC reversed a ~~future course of action. In March 2017, PJM staff made its final recommendation to~~previous order and accepted a filing by the PJM transmission owners seeking authority to assign costs for Regional Transmission Expansion Plan projects (subject to PJM Board ~~with respect~~approval requirements) solely addressing localized needs to customers within the ~~project. Under~~local transmission owner’s zone. FERC’s action in this order provides an exemption from the ~~recommended project,~~Order 1000 open window procedures for projects constructed by transmission owners to meet local transmission planning criteria. FERC’s orders have been challenged at the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) and PSE&G ~~will construct necessary upgrade work~~has intervened in ~~Hope Creek, at a cost~~support of ~~approximately $130 million.~~ FERC.

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 ~~staff recommended project. The~~award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. In October 2017, FERC accepted PJM’s filing on the grounds that PJM ~~Board also stated that it would be analyzing project beneficiaries from an alternate perspective to potentially devise an alternative~~correctly applied its Tariff. However, FERC deferred a ruling on whether the cost allocation methodology ~~for stability projects.~~applied to the Artificial Island project is appropriate. FERC will decide this issue in a separate proceeding that is currently pending. We are unable to predict the outcome.

~~Transmission Regulation~~—~~Con Edison Wheeling Agreement~~Nuclear Regulatory Commission (NRC)

December 31, 2016 Form 10-K page ~~19.~~20. The NRC continues to evaluate potential revisions to its requirements in connection with its operational and safety reviews of nuclear facilities in the United States as a result of the Fukushima Daiichi incident. We are also subject to cybersecurity regulations promulgated by the NRC.

We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to our Salem, Hope Creek and Peach Bottom facilities, but such cost could be material.

State Regulation

Cybersecurity Requirements for Regulated Entities

December 31, 2016 Form 10-K page 21. In ~~April~~March 2016, ~~Con Edison informed PJM~~the BPU issued an order for the regulated electric, natural gas and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The order requires these regulated utilities, including PSE&G, to, among other conditions, implement a cybersecurity program that ~~it would allow its Wheeling Agreement~~defines and implements organization accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to ~~expire effective as of May 1, 2017. The Wheeling Agreement enables Con Edison~~critical systems. New Jersey utilities, including PSE&G, were required to move 1,000 MW of power from southeastern New York across the PSE&G system for delivery into New York City. NYISO and PJM submitted proposed tariff provisions in January 2017. The proposal concerns future operational procedures and transmission planning assumptions associatedbe compliant with ~~the affected transmission lines. FERC accepted the proposal, subject to refund, effective May~~these requirements by October 1, 2017. We have submitted the required certification of compliance to the BPU.

In an effort to reduce the likelihood and severity of cyber incidents, we have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our company and our customers’ information and our systems. In addition, we are subject to maintaining key cybersecurity controls to meet mandatory cybersecurity regulatory requirements. Our cybersecurity program is built on technical, procedural, and people-focused measures to detect, protect against, respond to, and recover from cyber threats to our systems and information including company, employee and customer data. Features of our program include: identifying critical information and systems; conducting cyber risk assessments of our and third party systems; maintaining awareness of cyber threats and vulnerabilities through partnerships with public and private entities, as well as industry groups; maintaining and testing our cybersecurity incident response plans and systems; training personnel on cybersecurity issues; and raising cybersecurity awareness throughout our company with electronic notices and seminars. We cannot ~~predict the impact~~assure that our cybersecurity program will be effective in preventing or mitigating cybersecurity incidents. For a discussion of the proposal on energy prices or transmission planning at this time. Both PSE&G and the BPU protested certain aspects of the proposal. 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, PSE&G will continue to recover the costsrisks associated with ~~the new arrangement through its formula rate. We cannot predict the outcome~~cybersecurity threats, see Item 1A. Risk Factors.

Table of ~~this proceeding.~~Contents

~~State Regulation~~

Energy Efficiency 2017 Program ~~(Energy Efficiency~~(EE 2017)

In ~~March~~August 2017, ~~we filed a petition with~~ the BPU approved PSE&G’s petition for ~~our~~an Energy Efficiency 2017 ~~program, requesting extension of~~Program (EE 2017) to extend three ~~Energy Efficiency Economic sub-programs~~existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and ~~the addition of~~establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs ~~(smart thermostat~~under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and ~~residential data analytics). The petition requested additional capital expenditures~~$16 million of ~~approximately $74 million,~~ additional administrative and ~~other costs of $22 million and~~ information technology ~~system enhancement costs~~costs. The EE 2017 was added as the 11th component of ~~$3 million. We proposed~~the GPRC rate effective September 1, 2017.

Consolidated Tax Adjustments (CTA)

December 31, 2016 Form 10-K page 21. New Jersey is one of only a few states that make CTA in setting rates for regulated utilities. These adjustments to ~~recover our investment~~rate base are madeduring the rate setting process andare intended to allocate to utility customers a portion of the tax benefits realized from the filing of a consolidated federal tax return by the utility’s parent corporation. The BPU has been considering the appropriateness of the adjustment and the methodology and mechanics of the calculation for some time. In October 2014, the BPU approved a proposal by its Staff that limits the tax benefit period to be considered in ~~these sub-programs under~~ the ~~same clause recovery~~calculation to five years, sets the distribution rate base adjustment at 25% of any such tax benefit and eliminates from the process ~~as currently approved. This matter~~any tax benefits tied to transmission earnings. In accordance with this October action, this CTA policy will be applied only with respect to future distribution rate base cases. In November 2014, the New Jersey Division of Rate Counsel appealed the BPU’s decision and in September 2017, the New Jersey Superior Court, Appellate Division granted that appeal on procedural grounds. While the issue has now been remanded to the BPU, it is ~~pending.~~

not expected that application of a CTA will have a material impact on PSE&G’s current earnings or in its upcoming rate case filing.

Environmental Matters

Air Pollution Control

Hazardous Air Pollutants Regulation

December 31, 2016 Form 10-K page 22. In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plants. In April 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to the U.S. Supreme Court’s ruling. Industry participants and various state authorities have filed petitions with the D.C. Circuit challenging the EPA’s Supplemental Finding. The D.C. Circuit is holding the case in abeyance pending further directions from the EPA. We do not expect this Supplemental Finding to impact operation of our facilities.

Climate Change

CO₂Regulation under theClean Air Act (CAA)

December 31, 2016 Form 10-K page 23.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 (CPP), 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. ~~Upon~~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, which was subsequently extended by the D.C. Circuit in August 2017. In October 2017, upon completion of the review, the EPA ~~is expected~~Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). Whether the EPA chooses to ~~suspend, revise or rescind the rules as appropriate.~~propose a replacement rule has not been decided. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

Regional Greenhouse Gas Initiative (RGGI)

December 31, 2016 Form 10-K page 23. In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO₂emission reductions in the electric power industry. New Jersey withdrew from RGGI in 2012. However, certain northeastern states (RGGI States), including New York and Connecticut where we have generation facilities, havestate-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO₂ emissions. These rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO₂ emissions. Generators are required to submit an allowance for each ton emitted over a three-year period. Allowances are available through the auction or through secondary markets.

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In September 2017, the RGGI States announced their new post-2020 program for a cap on regional CO₂ emissions, which would require a decline in CO₂ emissions in 2021 and each year thereafter, resulting in a 30% reduction in the CO₂ emissions cap by 2030.

Water Pollution Control

Steam Electric Effluent Guidelines

December 31, 2016 Form 10-K page ~~23.~~23, March 31, 2017 Form 10-Q on page 77 and June 30, 2017 Form 10-Q on page 85. 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-~~

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~~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.~~

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,~~streams. In September 2017, the EPA issued a rule postponing for two years compliance dates related solely to bottom ash transport water and flue gas desulfurization ~~wastewater, flue gas mercury control wastewater,~~wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and ~~gasification wastewater.~~compliance dates for these two waste 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.~~condition and results of operations.

~~Waters of the United States~~Cooling Water Intake Structure

December 31, 2016 Form 10-K page 24. In ~~April~~May 2014, the EPA ~~Administrator and the Assistant Secretary~~issued a final cooling water intake rule under Section 316(b) of the ~~Army (Civil Works) jointly published~~Clean Water Act (CWA) that establishes new requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a ~~proposed rule to clarify the definition~~design flow of ~~waters~~more than two million gallons of ~~the United States under the CWA programs in order to protect the streams~~water per day. In September 2014, several environmental non-governmental groups and ~~wetlands that form the foundation~~certain energy industry groups filed petitions for review 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 and various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the final rule as well as which court has jurisdiction over the rule. The U.S. Supreme Court is expected to rule on the question of jurisdiction by June 2017. Some states, including New Jersey, are subject to state requirements beyond thoseimposed under federal law. While we do not anticipate material impacts to projects in New Jersey, the new definition could impose requirements in other states and regions that could impact the development of renewables.

~~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.~~ ~~In June 2015, the Sierra Club and another environmental group submitted~~case has been assigned to the ~~NJDEP a sixty-day notice~~U.S. Second Circuit Court of ~~intent~~Appeals (Second Circuit). Environmental organizations, including but not limited to ~~sue alleging~~ the ~~agency has caused violations of~~environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species ~~Act by allowing our Mercer generation station to operate in~~Act. The cases were subsequently consolidated at the Second Circuit and a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a permit renewal action for Mercer which addresses the alleged Endangered Species Act violations. In March 2017, we submitted our Incidental Take Permit to the National Marine Fisheries Service outlining operation and monitoring requirements through retirement of the Mercer generation station ondecision remains pending.

~~June 1, 2017 and subsequent decommissioning.~~

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ITEM 6.	EXHIBITS

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



a. PSEG:
Exhibit 10		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 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		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 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		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 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

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SIGNATURE

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



PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)

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

Date: ~~April 28,~~October 31, 2017

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SIGNATURE



PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

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

Date: ~~April 28,~~October 31, 2017

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SIGNATURE



PSEG POWER LLC
(Registrant)

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

Date: ~~April 28,~~October 31, 2017

8292



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



Public Service Enterprise Group Incorporated	Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o

Public Service Electric and Gas Company	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company o

PSEG Power LLC	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company o



		Page
FORWARD-LOOKING STATEMENTS		ii
FILING FORMAT		iii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated	1
	Public Service Electric and Gas Company	6
	PSEG Power LLC	11
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization and Basis of Presentation	16
	Note 2. Recent Accounting Standards	16
	Note 3. Early Plant Retirements	19
	Note 4. Variable Interest Entity (VIE)	2021
	Note 5. Rate Filings	21
	Note 6. Financing Receivables	2122
	Note 7. Available-for-Sale Securities	2325
	Note 8. Pension and Other Postretirement Benefits (OPEB)	2930
	Note 9. Commitments and Contingent Liabilities	3032
	Note 10. Debt and Credit Facilities	3840
	Note 11. Financial Risk Management Activities	3941
	Note 12. Fair Value Measurements	4446
	Note 13. Other Income and Deductions	5154
	Note 14. Income Taxes	5255
	Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax	5356
	Note 16. Earnings Per Share (EPS) and Dividends	5660
	Note 17. Financial Information by Business Segments	5761
	Note 18. Related-Party Transactions	5762
	Note 19. Guarantees of Debt	5964
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6167
	Executive Overview of 2017 and Future Outlook	6167
	Results of Operations	6775
	Liquidity and Capital Resources	7180
	Capital Requirements	7382
	Accounting Matters	7382
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	7382
Item 4.	Controls and Procedures	7483

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	7483
Item 1A.	Risk Factors	7483
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	7684
Item 5.	Other Information	7685
Item 6.	Exhibits	7989
	Signatures	8090




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
OPERATING REVENUES	$	2,263		$	2,450		$	6,988		$	6,971
OPERATING EXPENSES
Energy Costs	638			866			2,100			2,326
Operation and Maintenance	680			776			2,100			2,215
Depreciation and Amortization	252			231			1,721			679
Total Operating Expenses	1,570			1,873			5,921			5,220
OPERATING INCOME	693			577			1,067			1,751
Income from Equity Method Investments	3			3			11			9
Other Income	66			47			208			139
Other Deductions	(10		)	(8		)	(30		)	(39		)
Other-Than-Temporary Impairments	(5		)	(5		)	(9		)	(25		)
Interest Expense	(100		)	(99		)	(289		)	(288		)
INCOME BEFORE INCOME TAXES	647			515			958			1,547
Income Tax Expense	(252		)	(188		)	(340		)	(562		)
NET INCOME	$	395		$	327		$	618		$	985
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505			505			505
DILUTED	507			508			507			508
NET INCOME PER SHARE:
BASIC	$	0.78		$	0.65		$	1.22		$	1.95
DILUTED	$	0.78		$	0.64		$	1.22		$	1.94
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.43		$	0.41		$	1.29		$	1.23




	March 31, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	193		$	423
Accounts Receivable, net of allowances of $67 in 2017 and $68 in 2016	1,212			1,161
Tax Receivable	9			78
Unbilled Revenues	209			260
Fuel	173			326
Materials and Supplies, net	566			561
Prepayments	56			76
Derivative Contracts	114			163
Regulatory Assets	176			199
Other	8			7
Total Current Assets	2,716			3,254
PROPERTY, PLANT AND EQUIPMENT	40,195			39,337
Less: Accumulated Depreciation and Amortization	(10,850		)	(10,051		)
Net Property, Plant and Equipment	29,345			29,286
NONCURRENT ASSETS
Regulatory Assets	3,287			3,319
Long-Term Investments	1,001			1,050
Nuclear Decommissioning Trust (NDT) Fund	1,913			1,859
Long-Term Tax Receivable	113			104
Long-Term Receivable of Variable Interest Entity (VIE)	595			589
Other Special Funds	221			217
Goodwill	16			16
Other Intangibles	106			98
Derivative Contracts	93			24
Other	258			254
Total Noncurrent Assets	7,603			7,530
TOTAL ASSETS	$	39,664		$	40,070




	Three Months Ended
	March 31,
	2017			2016
OPERATING REVENUES	$	2,592		$	2,616
OPERATING EXPENSES
Energy Costs	874			836
Operation and Maintenance	712			729
Depreciation and Amortization	828			224
Total Operating Expenses	2,414			1,789
OPERATING INCOME	178			827
Income from Equity Method Investments	3			2
Other Income	72			48
Other Deductions	(11		)	(21		)
Other-Than-Temporary Impairments	(1		)	(10		)
Interest Expense	(98		)	(92		)
INCOME BEFORE INCOME TAXES	143			754
Income Tax Expense	(29		)	(283		)
NET INCOME	$	114		$	471
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505
DILUTED	508			508
NET INCOME PER SHARE:
BASIC	$	0.23		$	0.93
DILUTED	$	0.22		$	0.93
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.43		$	0.41




	March 31, 2017			December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	500		$	500
Commercial Paper and Loans	315			388
Accounts Payable	1,245			1,459
Derivative Contracts	7			13
Accrued Interest	131			97
Accrued Taxes	172			31
Clean Energy Program	86			142
Obligation to Return Cash Collateral	135			132
Regulatory Liabilities	74			88
Other	446			426
Total Current Liabilities	3,111			3,276
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,567			8,658
Regulatory Liabilities	131			118
Asset Retirement Obligations	738			726
OPEB Costs	1,309			1,324
OPEB Costs of Servco	460			452
Accrued Pension Costs	547			568
Accrued Pension Costs of Servco	126			128
Environmental Costs	393			401
Derivative Contracts	1			3
Long-Term Accrued Taxes	180			180
Other	198			211
Total Noncurrent Liabilities	12,650			12,769
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	10,898			10,895
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016—534 shares	4,920			4,936
Treasury Stock, at cost, 2017 and 2016—29 shares	(743		)	(717		)
Retained Earnings	9,070			9,174
Accumulated Other Comprehensive Loss	(242		)	(263		)
Total Stockholders’ Equity	13,005			13,130
Total Capitalization	23,903			24,025
TOTAL LIABILITIES AND CAPITALIZATION	$	39,664		$	40,070




	March 31, 2017			December 31, 2016
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts Payable	$	513		$	539
Accounts Payable—Affiliated Companies	81			25
Derivative Contracts	7			8
Accrued Interest	42			20
Other	102			88
Total Current Liabilities	745			680
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	1,966			2,170
Asset Retirement Obligations	522			511
OPEB Costs	254			251
Derivative Contracts	1			3
Accrued Pension Costs	185			191
Long-Term Accrued Taxes	78			77
Other	117			129
Total Noncurrent Liabilities	3,123			3,332
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
LONG-TERM DEBT	2,383			2,382
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,437			4,782
Accumulated Other Comprehensive Loss	(187		)	(211		)
Total Member’s Equity	5,478			5,799
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,729		$	12,193




	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		%




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Three Months Ended					Three Months Ended
	March 31,					March 31,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	—		3		Interest Expense	—		—
Total PSEG	$	—	$	3		$	—	$	—




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)
	Three Months Ended					Three Months Ended
	September 30,					September 30,
	2017		2016			2017		2016
	Millions					Millions
PSEG
Interest Rate Swaps	$	1	$	1	Interest Expense	$	2	$	—
Total PSEG	$	1	$	1		$	2	$	—




Accumulated Other Comprehensive Income	Pre-Tax		After-Tax
	Millions
Balance as of December 31, 2015	$	—	$	—
Gain Recognized in AOCI	3		2
Less: Gain Reclassified into Income	—		—
Balance as of December 31, 2016	$	3	$	2
Gain Recognized in AOCI	—		—
Less: Gain Reclassified into Income	—		—
Balance as of March 31, 2017	$	3	$	2




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives		Pre-Tax Gain (Loss) Recognized in Income on Derivatives
			Three Months Ended
			March 31,
			2017			2016
		Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues		$	83		$	216
Energy-Related Contracts	Energy Costs		(5		)	2
Total PSEG and Power			$	78		$	218




Type	Notional	Total	PSEG	Power	PSE&G
		Millions
As of March 31, 2017
Natural Gas	Dekatherm (Dth)	357	—	355	2
Electricity	MWh	346	—	346	—
Financial Transmission Rights (FTRs)	MWh	5	—	5	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—
As of December 31, 2016
Natural Gas	Dth	357	—	348	9
Electricity	MWh	323	—	323	—
FTRs	MWh	9	—	9	—
Interest Rate Swaps	U.S. Dollars	500	500	—	—




Rating	Current Exposure		Securities Held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions		��
Investment Grade	$	433	$	94	$	339	1	$	202	(A)
Non-Investment Grade	9		1		8		—	—
Total	$	442	$	95	$	347	1	$	202




Rating	Current Exposure		Collateral Held		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	318	$	55	$	263	2	$	128	(A)
Non-Investment Grade	5		1		4		—	—
Total	$	323	$	56	$	267	2	$	128


(A)	~~Represents~~Includes net exposure of ~~$202~~$97 million with PSE&G.




	Recurring Fair Value Measurements as of March 31, 2017
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	125		$	—		$	125		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	205		$	(585	)	$	11		$	774		$	5
Interest Rate Swaps (C)	$	2		$	—		$	—		$	2		$	—
NDT Fund (D)
Equity Securities	$	1,007		$	—		$	1,005		$	2		$	—
Debt Securities—US Treasury	$	223		$	—		$	—		$	223		$	—
Debt Securities—Govt Other	$	294		$	—		$	—		$	294		$	—
Debt Securities—Corporate	$	343		$	—		$	—		$	343		$	—
Other Securities	$	46		$	—		$	46		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	36		$	—		$	—		$	36		$	—
Debt Securities—Govt Other	$	62		$	—		$	—		$	62		$	—
Debt Securities—Corporate	$	99		$	—		$	—		$	99		$	—
Other Securities	$	2		$	—		$	2		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(8	)	$	585		$	(6	)	$	(585	)	$	(2	)
Interest Rate Swaps (C)	$	—		$	—		$	—		$	—		$	—
PSE&G
Assets:
Cash Equivalents (A)	$	125		$	—		$	125		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	1		$	—		$	—		$	—		$	1
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	12		$	—		$	—		$	12		$	—
Debt Securities—Corporate	$	20		$	—		$	—		$	20		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	204		$	(585	)	$	11		$	774		$	4
NDT Fund (D)
Equity Securities	$	1,007		$	—		$	1,005		$	2		$	—
Debt Securities—US Treasury	$	223		$	—		$	—		$	223		$	—
Debt Securities—Govt Other	$	294		$	—		$	—		$	294		$	—
Debt Securities—Corporate	$	343		$	—		$	—		$	343		$	—
Other Securities	$	46		$	—		$	46		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	6		$	—		$	6		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	15		$	—		$	—		$	15		$	—
Debt Securities—Corporate	$	25		$	—		$	—		$	25		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(8	)	$	585		$	(6	)	$	(585	)	$	(2	)


(B)	Level 1— During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.


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




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	March 31, 2017					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	1	$	—		Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	1	$	—
Power
Electricity	Electric Load Contracts	$	4	$	(2	)	Discounted Cash flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	4	$	(2	)
Total PSEG		$	5	$	(2	)




	Three Months Ended March 31, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2017			Included in Income (A)		Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)			Balance as of March 31, 2017
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	1		$	19	$	6	$	—	$	(22	)	$	(1	)	$	3
PSE&G
Net Derivative Assets (Liabilities)	$	(5	)	$	—	$	6	$	—	$	—		$	—		$	1
Power
Net Derivative Assets (Liabilities)	$	6		$	19	$	—	$	—	$	(22	)	$	(1	)	$	2




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




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

	Nine Months Ended September 30, 2016
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2016			Included in Income (E)		Included in Regulatory Assets/ Liabilities (B)			Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2016

PSEG
Net Derivative Assets (Liabilities)	$	13		$	24	$	(6	)	$	4	$	(24	)	$	—	$	11
PSE&G
Net Derivative Assets (Liabilities)	$	2		$	—	$	(6	)	$	—	$	—		$	—	$	(4	)
Power
Net Derivative Assets (Liabilities)	$	11		$	24	$	—		$	4	$	(24	)	$	—	$	15


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


(C)	Represents ~~$(22)~~$(3) million and ~~$(15)~~$(28) million in settlements for the three months and nine months ended ~~March 31,~~September 30, 2017, respectively. Represents $(4) million and ~~2016, respectively.~~$(24) million in settlements for the three months and nine months


(D)	During the three months ended ~~March 31,~~September 30, 2017 there were no transfers in to or out of Level 3. During the nine months ended September 30, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in to or out of Level 3 during three months and nine months ended September 30, 2016.


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




	As of				As of
	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A) (B)	$	1,896	$	1,891	$	1,195	$	1,185
PSE&G (B)	8,243		8,857		7,818		8,240
Power - Recourse Debt (B)	2,385		2,657		2,382		2,578
Total Long-Term Debt	$	12,524	$	13,405	$	11,395	$	12,003


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




PSEG	Other Comprehensive Income (Loss)
	Three Months Ended March 31, 2017
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	2	$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—		—			30			30
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		6			(15		)	(9		)
Net Current Period Other Comprehensive Income (Loss)	—		6			15			21
Balance as of March 31, 2017	$	2	$	(392	)	$	148		$	(242	)

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




	Three Months Ended March 31,
	2017				2016
	Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	114	$	114	$	471	$	471
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505
Effect of Stock Based Compensation Awards	—		3		—		3
Total Shares	505		508		505		508

EPS
Net Income	$	0.23	$	0.22	$	0.93	$	0.93




	Three Months Ended September 30,								Nine Months Ended September 30,
	2017				2016				2017				2016
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	395	$	395	$	327	$	327	$	618	$	618	$	985	$	985
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	505		505		505		505		505		505		505		505
Effect of Stock Based Compensation Awards	—		2		—		3		—		2		—		3
Total Shares	505		507		505		508		505		507		505		508

EPS
Net Income	$	0.78	$	0.78	$	0.65	$	0.64	$	1.22	$	1.22	$	1.95	$	1.94




	Three Months Ended
	March 31,
Dividend Payments on Common Stock	2017		2016
Per Share	$	0.43	$	0.41
In Millions	$	218	$	207




	PSE&G		Power			Other (A)			Eliminations (B)			Consolidated
	Millions
Three Months Ended March 31, 2017
Operating Revenues	$	1,812	$	1,284		$	83		$	(587	)	$	2,592
Net Income (Loss)	299		(170		)	(15		)	—			114
Gross Additions to Long-Lived Assets	748		307			7			—			1,062
Three Months Ended March 31, 2016
Operating Revenues	$	1,712	$	1,313		$	122		$	(531	)	$	2,616
Net Income (Loss)	262		192			17			—			471
Gross Additions to Long-Lived Assets	724		333			8			—			1,065
As of March 31, 2017
Total Assets	$	26,487	$	11,729		$	2,249		$	(801	)	$	39,664
Investments in Equity Method Subsidiaries	$	—	$	103		$	—		$	—		$	103
As of December 31, 2016
Total Assets	$	26,288	$	12,193		$	2,373		$	(784	)	$	40,070
Investments in Equity Method Subsidiaries	$	—	$	102		$	—		$	—		$	102