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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.~~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

~~all~~

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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.

~~Power is subject to~~

~~counterparty collateral calls related to commodity contracts, and~~

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

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

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

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The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015.~~2016.

As of As of
September 30,
2016 December 31,
2015
Millions
Face Value of Outstanding Guarantees $ 1,797
$ 1,734

Exposure under Current Guarantees $ 143
$ 172

Letters of Credit Margin Posted $ 164
$ 122

Letters of Credit Margin Received $ 136
$ 192

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

Counterparty Cash Margin Received $ (4 ) $ (15 )
Net Broker Balance Deposited (Received) $ (12 ) $ (5 )

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




	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 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 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.

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Environmental Matters

Passaic River

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

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

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

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

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

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

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

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

On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which ~~contemplated~~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 ~~set~~sets forth various alternatives for remediating this portion of the Passaic River.

The CPG, which consisted of 52 members as of ~~September 30, 2016,~~March 31, 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 ~~for the preparation~~ of the RI/FS is approximately ~~$167~~$190 million, which the CPG continues to incur. Of the estimated ~~$167~~$190 million, as of ~~September 30, 2016,~~March 31, 2017, the CPG had spent approximately ~~$156~~$160 million, of which ~~PSE&G’s and Power’s combined~~PSEG’s total share was approximately ~~$10~~$11 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 ~~September 30, 2016,~~March 31, 2017, these accruals bring the total liability to approximately $57 million, $46 million applicable to PSE&G and $11 million applicable to Power.

Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond

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Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA 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 ~~PRP.~~PRPs.”

OnIn June ~~16,~~ 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. ~~Although PSEG does not currently anticipate~~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 ~~filing~~parties to assert one or more causes of action to hold YPF responsible for ~~bankruptcy~~certain amounts owed by Tierra and Maxus. PSEG cannot currently determine the impact, if any, that the bankruptcy of Tierra and Maxus ~~will affect~~or any related proceeding might have on its allocable share or total liability for the Passaic River matter, and therefore, PSEG, through the CPG and independently, will continue to monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs.

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

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

Natural Resource Damage Claims

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

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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.

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 ~~$424~~$386 million and ~~$481~~$443 million through 2021, including its $46 million share for the Passaic River ~~accrued as of September 30, 2016,~~ as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of ~~$424~~$386 million as of ~~September 30, 2016.~~March 31, 2017. Of this amount, ~~$70~~$74 million was recorded in Other Current Liabilities and ~~$354~~$312 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a ~~$424~~$386 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.

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

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

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

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The 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.

OnIn May ~~19,~~ 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. ~~On August 15, 2014,~~

The EPA has structured the ~~EPA established October 14, 2014 as the effective date for~~rule so that each state Permitting Director will continue to ~~implement the provisions of the rule going forward when considering the~~consider renewal of permits for existing

power facilities on a case by case basis. OnIn 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 5, 2014, several environmental non-governmental groups and certain energy industry groups filed ~~motions to litigate the provisions~~petitions for

review of the ~~rule. This~~rule and the case ~~is pending at~~has been assigned to the U.S. Second Circuit Court of ~~Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges~~Appeals (Second Circuit). Environmental

organizations, including but not limited to the ~~endangered species act provisions of~~environmental petitioners in the ~~316 (b) rule. Power~~Second Circuit, have also filed suit under the

Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is ~~unable to determine the ultimate impact of these actions on the implementation of the rule.~~expected by

Onmid-2017.

In June ~~10,~~ 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, it requires additional studies and the selection of technology to address impingement for the service water system. OnIn July 8, 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the Clean Water Act. Such service 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 ~~Bridgeport Harbor Station Unit 3 (BH3).~~BH3. To address compliance with the EPA’s Clean Water Act Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the ~~current~~previously estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in ~~late 2016.~~2017. See Note 3. Early Plant Retirements.

Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, ~~Connecticut.~~Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt

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of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power ~~will~~may seek to operate BH3 through the ~~current~~previously estimated useful life.

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

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

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

Jersey City, New Jersey Subsurface Feeder Cable Matter

In early October 2016, a discharge of ~~mineral oil~~ dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the ~~New Jersey Department of Environmental Protection (NJDEP).~~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; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, ~~has~~the NJDEP and the Army Corps of Engineers, have issued ~~Notices of Federal Interest for an Oil Pollution Incident,~~multiple notices, orders and directives to the ~~property owners, PSE&G and Con Edison, and the NJDEP has issued a Field Directive~~various parties related to ~~both PSE&G and Con Edison.~~this matter. The investigation and response actions related to the fluid discharge are ongoing. The investigation of the discharge and its potential cause is in the preliminary

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stages, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and ~~NADC; however, based~~NADC. Based on currently available information and the potential scope of the necessary repair and remediation work, the costs ~~could~~will likely 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, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s debris removal activities are ongoing.

Steam Electric Effluent Guidelines

OnIn September ~~30,~~ 2015, the EPA issued a new Effluent Limitation Guidelines ~~Limitation~~ 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. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations.

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

Coal Combustion Residuals (CCRs)

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

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

PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, 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

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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 ~~$335.33~~$276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of ~~$272.78~~$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
2013 2014 2015 2016
36-Month Terms Ending May 2016
May 2017
May 2018
May 2019
(A)
Load (MW) 2,800
2,800
2,900
2,800

$ per MWh $92.18 $97.39 $99.54 $96.38




	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 ~~2016~~2017 BGS auction year ~~became~~will become effective on June 1, ~~2016~~2017 when the ~~2013~~2014 BGS auction agreements ~~expired.~~expire.

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

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 ~~2017~~2018 and a significant portion through ~~2020~~2021 at Salem, Hope Creek and Peach Bottom.

Power has various multi-year contracts for natural gas and firm pipeline transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess ~~delivery~~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.~~stations in New Jersey.

Power also has various long-term fuel purchase commitments for coal through ~~2018~~2019 to support its fossil generation stations.

As of ~~September 30, 2016,~~March 31, 2017, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type Power's Share of Commitments through 2020
Millions
Nuclear Fuel
Uranium $ 338

Enrichment $ 307

Fabrication $ 179

Natural Gas $ 904

Coal $ 235

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~




Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	301
Enrichment	$	359
Fabrication	$	192
Natural Gas	$	1,101
Coal	$	181

Regulatory Proceedings

FERC Compliance

PJM Bidding Matter

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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 ~~continues to implement~~has implemented procedures to ~~help~~ mitigate the risk of similar issues occurring in the future.

During the three ~~month period~~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. ~~No additional charges to income have been recorded for this matter since that time.~~

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, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and ~~issued data requests covering a period from 2002 through~~$135 million, depending on the ~~date~~legal interpretation of the ~~self-report. This investigation~~principles under the PJM Tariff, plus penalties. Since no point within this range is ~~ongoing. Since that time,~~more likely than any other, Power has ~~responded~~accrued the low end of this range of $35 million by recording an additional pre-tax charge to ~~data requests from FERC Staff, including recent data requests in which~~income of $10 million during the three months ended March 31, 2017. Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC’s response to PSEG’s legal arguments and the amount of disgorgement or other remedies FERC may ultimately seek.

~~PSEG~~ is unable to reasonably estimate the range of possible loss, if any, for ~~this matter; however,~~ the ~~amounts~~quantity of ~~potential disgorgement and other potential~~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 ~~incur span~~assert in a ~~wide range depending on~~judicial challenge, including the ~~success of PSEG’s~~ legal ~~arguments. These arguments include~~defense that ~~Power’s energy market bids~~its cost-based bidding in a substantial majority of the hours ~~were~~was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were ~~immaterial and that~~immaterial. Furthermore, it is unclear whether the quantity of ~~the bids~~energy offered violated any legal requirement. ~~If PSEG’s legal arguments do not prevail~~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 ~~whole or~~the annual FTR auction in ~~part~~PJM for the 2016-2017 planning year and the monthly FTR auctions in PJM for February, March and April 2016. PSEG is cooperating with FERC or in a~~judicial challenge that~~this matter. PSEG ~~may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to PSEG’s and Power’s Consolidated Statements~~cannot predict the outcome of ~~Operations in the quarterly and annual periods in which they are recorded.~~

~~Nuclear Insurance Coverages~~

The following should be read in conjunction with Note 12. Commitments and Contingent Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2015.

Based upon a review of its nuclear insurance, Power made changes to its Nuclear Electric Insurance Limited (NEIL) insurance coverage of the excess layer for property damage which became effective on April 1, 2016. The excess layer provides coverage above the primary layer of NEIL insurance coverage for property damage of $1.5 billion. For the excess layerthis matter at the Salem/Hope Creek site, Power purchased coverage for property damage of $300 million due to a nuclear event and $300 million due to a non-nuclear event. For the excess layer at the Peach Bottom site, Power purchased coverage for its ownership interest for property damage of $300 million due to a nuclear event. For the excess layer at the Peach Bottom site, Exelon purchased coverage for property damage of $600 million due to a non-nuclear event which covers the ownership interest of Power. this time.

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, 2016~~:

~~PSE&G~~

~~issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021,~~

~~issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046,~~

~~issued~~ ~~$425 million~~ of ~~2.25%~~ ~~Secured Medium-Term Notes, Series L due~~ ~~September 2026~~,

~~retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds, Series VV at maturity, and~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

~~repurchased at par~~ ~~$100 million~~ of Pollution Control Financing Authority of Salem County Bonds (Salem Bonds) and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds.

~~Power~~

~~issued $700 million of 3.00% Senior Notes due June 2021,~~

~~retired~~ ~~$303 million~~ of ~~5.32%~~ ~~Senior Notes due~~ ~~September 2016~~ ~~and~~

~~retired~~ ~~$250 million~~ of ~~2.75%~~ ~~Senior Notes due~~ ~~September 2016~~.

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, 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 ~~PSEG’s~~the $4.2 billion credit facilities are provided by a diverse bank ~~group with~~group. As of March 31, 2017, the total available credit capacity was $3.6 billion.

As of March 31, 2017, no single institution ~~representing~~represented more than 7%8% of the total commitments in ~~PSEG’s~~the credit facilities.

As of ~~September 30, 2016, PSEG’s~~March 31, 2017, the total ~~available~~ credit capacity ~~of $3.7 billion~~ was in excess of its anticipated maximum liquidity requirements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Each of ~~PSEG’s~~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. ~~PSEG’s~~The total credit facilities and available liquidity as of ~~September 30, 2016~~March 31, 2017 were as follows:

As of September 30, 2016
Company/Facility
Total
Facility
Usage (D)
Available
Liquidity

Expiration
Date
Primary Purpose
Millions
PSEG
  5-year Credit Facility $ 500
$ 10
$ 490
Apr 2019 Commercial Paper (CP) Support/Funding/Letters of Credit
  5-year Credit Facility (A) 500
255
245
Apr 2020 CP Support/Funding/Letters of Credit
Total PSEG $ 1,000
$ 265
$ 735

PSE&G
5-year Credit Facility (B) $ 600
$ 14
$ 586
Apr 2020 CP Support/Funding/Letters of Credit
Total PSE&G $ 600
$ 14
$ 586

Power
  5-year Credit Facility $ 1,600
$ 194
$ 1,406
Apr 2019 Funding/Letters of Credit
  5-year Credit Facility (C) 953
11
942
Apr 2020 Funding/Letters of Credit
Total Power $ 2,553
$ 205
$ 2,348

Total $ 4,153
$ 484
$ 3,669


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


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


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


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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~




	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

~~(UNAUDITED)~~(A)The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs,

~~Table~~under which as of ~~Contents~~

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.

Note 11. Financial Risk Management Activities

The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal ~~purchase~~purchases and normal ~~sale~~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. ~~Transactions receiving NPNS treatment~~PSEG uses interest rate swaps and other derivatives, which are ~~accounted for upon settlement. For a derivative instrument that qualifies~~designated and ~~is designated~~effective as a cash flow ~~hedge, the changes in the~~or fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period.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 primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. PSEG had no commodity derivative transactions designatedsuch as ~~cash flow or fair value hedges as of September 30, 2016 and December 31, 2015.~~

~~Economic Hedges~~

~~Power enters into derivative contracts that are not designated as either cash flow or fair value hedges. Power enters into~~ financial options, futures, swaps, fuel purchases and forward purchases and sales of ~~electricity. These transactions are economic hedges, intended~~electricity, to ~~mitigate~~manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of ~~these~~the derivative contracts are recorded in earnings. ~~PSE&G is a party to a long-term natural gas sales derivative contract tooptimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities.~~

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 ~~the~~ changes in the fair value of the underlying forecasted interest payments of the debt. ~~Interest rate swaps totaling $550 million that converted the retired Power’s Senior Notes due September 2016 into variable-rate debt matured in the third quarter.~~ There were no outstanding interest rate swaps as of ~~September 30, 2016. As of~~March 31, 2017 or December 31, ~~2015, the~~2016. The fair value ~~of all the underlying hedges was $6 million. The effect of these~~ hedges reduced interest expense by $2 million ~~and $5 million~~ for the three months ended ~~September 30, 2016 and 2015, respectively, and $6 million and $15 million for the nine months ended September 30, 2016 and 2015, respectively.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

March 31, 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, primarily related to variable-rate debt instruments. As of ~~September 30,~~March 31, 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. ~~The~~As of March 31, 2017 and December 31, 2016, the fair value of these hedges was $2 million and ~~the related~~$1 million, respectively. There was no ineffectiveness ~~were immaterial~~ as of ~~September 30, 2016. PSEG interest rate hedges totaling $400 million were terminated during the second quarter~~March 31, 2017 and a gain of $2 million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power’s $700 million of 3% Senior Notes due June 2021. For additional information see Note 10. Debt and Credit Facilities. There were no outstanding interest rate cash flow hedges as of December 31, ~~2015.~~ 2016.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of ~~September 30, 2016~~March 31, 2017 and ~~was immaterial as of~~ December 31, ~~2015.~~2016. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months ~~are immaterial. The expiration date of the longest-dated interest rate hedge~~ is ~~in May 2021.~~$1 million.

Fair Values of Derivative Instruments

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

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

As of September 30, 2016 (A)
Power PSE&G PSEG Consolidated
Not Designated Not Designated Designated as Hedges
Balance Sheet Location
Energy-
Related
Contracts

Netting
(B)

Total
Power

Energy-
Related
Contracts

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 432
$ (283 ) $ 149
$ —
$ —
$ 149

Noncurrent Assets 305
(219 ) 86
—
—
86

Total Mark-to-Market Derivative Assets $ 737
$ (502 ) $ 235
$ —
$ —
$ 235

Derivative Contracts
Current Liabilities $ (314 ) $ 278
$ (36 ) $ (4 ) $ —
$ (40 )
Noncurrent Liabilities (219 ) 206
(13 ) —
—
(13 )
Total Mark-to-Market Derivative (Liabilities) $ (533 ) $ 484
$ (49 ) $ (4 ) $ —
$ (53 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 204
$ (18 ) $ 186
$ (4 ) $ —
$ 182




	As of 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 December 31, 2015 (A)
Power PSE&G PSEG Consolidated
Not Designated Not Designated Designated as Hedges
Balance Sheet Location
Energy-
Related
Contracts

Netting
(B)

Total
Power

Energy-
Related
Contracts

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 700
$ (477 ) $ 223
$ 13
$ 6
$ 242

Noncurrent Assets 208
(131 ) 77
—
—
77

Total Mark-to-Market Derivative Assets $ 908
$ (608 ) $ 300
$ 13
$ 6
$ 319

Derivative Contracts
Current Liabilities $ (513 ) $ 437
$ (76 ) $ —
$ —
$ (76 )
Noncurrent Liabilities (132 ) 116
(16 ) (11 ) —
(27 )
Total Mark-to-Market Derivative (Liabilities) $ (645 ) $ 553
$ (92 ) $ (11 ) $ —
$ (103 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 263
$ (55 ) $ 208
$ 2
$ 6
$ 216




	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

(A)

Substantially all of Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015.~~2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.

(B)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Condensed Consolidated Balance Sheets. As of ~~September 30, 2016~~March 31, 2017 net cash collateral (received) paid was netted against the corresponding net derivative contract positions with $(4) million of cash collateral netted against noncurrent assets, and $4 million netted against current liabilities. As of December 31, ~~2015,~~2016, net cash collateral (received) paid of ~~$(18)~~$1 million ~~and $(55) million, respectively, were~~was netted against the corresponding net derivative contract positions. Of the ~~$(18)~~$1 million as of ~~September 30,~~December 31, 2016, ~~$(13)~~$(3) million ~~and $(14) million of cash collateral were~~was netted against ~~current~~noncurrent assets and ~~noncurrent assets, respectively, and $9~~$4 million was netted against current liabilities. ~~Of the $(55) million as of December 31, 2015, $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and~~ ~~$2 million were netted against current liabilities and noncurrent liabilities, respectively.~~

Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P ~~and~~or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully ~~collateralized, and contracts designated as NPNS)~~collateralized) was ~~$42~~$13 million and ~~$78~~$19 million as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015,~~2016, respectively. As of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015,~~2016, Power had the contractual right of offset of ~~$11~~$7 million and ~~$12~~$9 million, respectively, related to derivative instruments that are assets with the same counterparty under agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of ~~$31~~$6 million and ~~$66~~$10 million as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015,~~2016, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended September 30, 2016 and 2015.

Derivatives in
Cash Flow Hedging
Relationships

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

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

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

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

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

Three Months Ended Three Months Ended Three Months Ended
September 30, September 30, September 30,
2016 2015 2016 2015 2016 2015
Millions
PSEG
Energy-Related Contracts $ —
$ 1
Operating Revenues $ —
$ —
Operating Revenues $ —
$ —

Interest Rate Swaps 1
—
Interest Expense —
—
Interest Expense —
—

Total PSEG $ 1
$ 1
$ —
$ —
$ —
$ —

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

Total Power $ —
$ 1
$ —
$ —
$ —
$ —

Derivatives in
Cash Flow Hedging
Relationships

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

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

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

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

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

Nine Months Ended Nine Months Ended Nine Months Ended
September 30, September 30, September 30,
2016 2015 2016 2015 2016 2015
Millions
PSEG
Energy-Related Contracts $ —
$ 2
Operating Revenues $ —
$ 17
Operating Revenues $ —
$ —

Interest Rate Swaps 3
—
Interest Expense —
—
Interest Expense —
—

Total PSEG $ 3
$ 2
$ —
$ 17
$ —
$ —

Power
Energy-Related Contracts $ —
$ 2
Operating Revenues $ —
$ 17
Operating Revenues $ —
$ —

Total Power $ —
$ 2
$ —
$ 17
$ —
$ —




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		$	—	$	—

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table~~There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of ~~Contents~~

March 31, 2017 and 2016.

The following reconciles the ~~Accumulated Other Comprehensive Income~~AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis.

Accumulated Other Comprehensive Income Pre-Tax After-Tax
Millions
Balance as of December 31, 2015 $ —
$ —

Gain Recognized in AOCI 2
—
1

Less: Gain Reclassified into Income —
—

Balance as of June 30, 2016 $ 2
$ 1

Gain Recognized in AOCI 1
1

Less: Gain Reclassified into Income —
—

Balance as of September 30, 2016 $ 3
$ 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

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS ~~such as its BGS contracts and certain other energy supply contracts,~~ for the three months ended March 31, 2017 and ~~nine months ended September 30, 2016 and 2015.~~2016. Power’s derivative contracts reflected in ~~these tables~~this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts for which Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.

Derivatives Not Designated as Hedges
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives
Pre-Tax Gain (Loss) Recognized in Income on Derivatives
Three Months Ended Nine Months Ended
September 30, September 30,
2016 2015 2016 2015
Millions
PSEG and Power
Energy-Related Contracts Operating Revenues $ 125
$ 154
$ 255
$ 202

Energy-Related Contracts Energy Costs (11 ) (4 ) (3 ) (4 )
Total PSEG and Power $ 114
$ 150
$ 252
$ 198




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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The following reflects the gross volume, on an absolute value basis, of derivatives as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015.~~2016.

Type Notional Total PSEG Power PSE&G
Millions
As of September 30, 2016
Natural Gas Dekatherm (Dth) 315
—
300
15

Electricity MWh 349
—
349
—

Financial Transmission Rights (FTRs) MWh 14
—
14
—

Interest Rate Swaps U.S. Dollars 500
500
—
—

As of December 31, 2015
Natural Gas Dth 201
—
168
33

Electricity MWh 299
—
299
—

FTRs MWh 23
—
23
—

Interest Rate Swaps U.S. Dollars 550
550
—
—

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~




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	—	—

Credit Risk

Credit risk relates to the risk of loss that wePower would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. ~~We have~~PSEG has established credit policies that ~~we believe~~it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.

As of ~~September 30, 2016, 92%~~March 31, 2017, 98% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and ~~non-derivatives and normal purchases/normal sales)~~non-derivatives).

The following table provides information on Power’s credit risk from others, net of collateral, as of ~~September 30, 2016.~~March 31, 2017. It further delineates that exposure by the credit rating of the counterparties, ~~and~~which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.

Rating
Current
Exposure

Securities
Held as
Collateral

Net
Exposure

Number of
Counterparties
>10%

Net Exposure of
Counterparties
>10%

Millions Millions
Investment Grade—External Rating $ 384
$ 135
$ 249
2
$ 147
(A)
Non-Investment Grade—External Rating 24
—
24
—
—

Investment Grade—No External Rating 9
—
9
—
—

Non-Investment Grade—No External Rating 1
1
—
—
—

Total $ 418
$ 136
$ 282
2
$ 147




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


(A)	Represents net exposure of ~~$114~~$202 million with PSE&G. ~~The remaining net exposure of $33 million is with a non-affiliated power purchaser which is an investment grade counterparty.~~

As of ~~September 30, 2016,~~March 31, 2017, collateral held from counterparties where Power had credit exposure included $3$1 million in cash collateral and ~~$133~~$94 million in letters of credit.

As of ~~September 30, 2016~~March 31, 2017, Power had ~~135~~159 active counterparties.

PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of ~~September 30, 2016,~~March 31, 2017, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of ~~September 30, 2016,~~March 31, 2017, PSE&G had no net credit exposure with suppliers, including Power.

PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Note 12. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and Power have the ability to access. These consist primarily of listed equity securities and money market mutual ~~funds.~~funds, as well as natural gas futures contracts executed on NYMEX.

Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of ~~September 30, 2016,~~March 31, 2017, these consisted primarily of ~~long-term gas supply contracts and~~ certain electric load contracts and gas contracts.

Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.

The following tables present information about PSEG’s, PSE&G’s and Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015,~~2016, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Recurring Fair Value Measurements as of September 30, 2016
Description Total

Netting (E)

Quoted Market Prices for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs
(Level 3)

Millions
PSEG
Assets:
Cash Equivalents (A) $ 357
$ —
$ 357
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 235
$ (502 ) $ —
$ 722
$ 15

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

NDT Fund (D)
Equity Securities $ 922
$ —
$ 922
$ —
$ —

Debt Securities—Govt Obligations $ 530
$ —
$ —
$ 530
$ —

Debt Securities—Other $ 360
$ —
$ —
$ 360
$ —

Other Securities $ 45
$ —
$ 45
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 22
$ —
$ 22
$ —
$ —

Debt Securities—Govt Obligations $ 107
$ —
$ —
$ 107
$ —

Debt Securities—Other $ 94
$ —
$ —
$ 94
$ —

Other Securities $ 1
$ —
$ 1
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (53 ) $ 484
$ —
$ (533 ) $ (4 )
Interest Rate Swaps (C) $ —
$ —
$ —
$ —
$ —

PSE&G
Assets:
Cash Equivalents (A) $ 357
$ —
$ 357
$ —
$ —

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

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

Debt Securities—Govt Obligations $ 22
$ —
$ —
$ 22
$ —

Debt Securities—Other $ 18
$ —
$ —
$ 18
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

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

Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 235
$ (502 ) $ —
$ 722
$ 15

NDT Fund (D)
Equity Securities $ 922
$ —
$ 922
$ —
$ —

Debt Securities—Govt Obligations $ 530
$ —
$ —
$ 530
$ —

Debt Securities—Other $ 360
$ —
$ —
$ 360
$ —

Other Securities $ 45
$ —
$ 45
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 6
$ —
$ 6
$ —
$ —

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

Debt Securities—Other $ 23
$ —
$ —
$ 23
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (49 ) $ 484
$ —
$ (533 ) $ —




	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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Recurring Fair Value Measurements as of December 31, 2015
Description Total Netting (E)
Quoted Market Prices for Identical Assets
(Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs
(Level 3)

Millions
PSEG
Assets:
Cash Equivalents (A) $ 326
$ —
$ 326
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 313
$ (608 ) $ —
$ 896
$ 25

Interest Rate Swaps (C) $ 6
$ —
$ —
$ 6
$ —

NDT Fund (D)
Equity Securities $ 865
$ —
$ 865
$ —
$ —

Debt Securities—Govt Obligations $ 488
$ —
$ —
$ 488
$ —

Debt Securities—Other $ 359
$ —
$ —
$ 359
$ —

Other Securities $ 42
$ —
$ 42
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 22
$ —
$ 22
$ —
$ —

Debt Securities—Govt Obligations $ 108
$ —
$ —
$ 108
$ —

Debt Securities—Other $ 81
$ —
$ —
$ 81
$ —

Other Securities $ 2
$ —
$ 2
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (103 ) $ 553
$ —
$ (644 ) $ (12 )
PSE&G
Assets:
Cash Equivalents (A) $ 160
$ —
$ 160
$ —
$ —

Derivative Contracts:
Energy Related Contracts (B) $ 13
$ —
$ —
$ —
$ 13

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

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

Debt Securities—Other $ 16
$ —
$ —
$ 16
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (11 ) $ —
$ —
$ —
$ (11 )
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 300
$ (608 ) $ —
$ 896
$ 12

NDT Fund (D)
Equity Securities $ 865
$ —
$ 865
$ —
$ —

Debt Securities—Govt Obligations $ 488
$ —
$ —
$ 488
$ —

Debt Securities—Other $ 359
$ —
$ —
$ 359
$ —

Other Securities $ 42
$ —
$ 42
$ —
$ —

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

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

Debt Securities—Other $ 20
$ —
$ —
$ 20
$ —

Other Securities $ 1
$ —
$ 1
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (92 ) $ 553
$ —
$ (644 ) $ (1 )




	Recurring Fair Value Measurements as of December 31, 2016
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
Interest Rate Swaps (C)	$	1		$	—		$	—		$	1		$	—
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	22		$	—		$	22		$	—		$	—
Debt Securities—US Treasury	$	37		$	—		$	—		$	37		$	—
Debt Securities—Govt Other	$	66		$	—		$	—		$	66		$	—
Debt Securities—Corporate	$	91		$	—		$	—		$	91		$	—
Other Securities	$	1		$	—		$	1		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(16	)	$	372		$	(18	)	$	(364	)	$	(6	)
PSE&G
Assets:
Cash Equivalents (A)	$	365		$	—		$	365		$	—		$	—
Derivative Contracts:
Energy Related Contracts (B)	$	—		$	—		$	—		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	7		$	—		$	—		$	7		$	—
Debt Securities—Govt Other	$	13		$	—		$	—		$	13		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(5	)	$	—		$	—		$	—		$	(5	)
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	186		$	(371	)	$	17		$	533		$	7
NDT Fund (D)
Equity Securities	$	957		$	—		$	954		$	3		$	—
Debt Securities—US Treasury	$	227		$	—		$	—		$	227		$	—
Debt Securities—Govt Other	$	293		$	—		$	—		$	293		$	—
Debt Securities—Corporate	$	337		$	—		$	—		$	337		$	—
Other Securities	$	44		$	—		$	44		$	—		$	—
Rabbi Trust (D)
Equity Securities—Mutual Funds	$	5		$	—		$	5		$	—		$	—
Debt Securities—US Treasury	$	9		$	—		$	—		$	9		$	—
Debt Securities—Govt Other	$	16		$	—		$	—		$	16		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Other Securities	$	—		$	—		$	—		$	—		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(11	)	$	372		$	(18	)	$	(364	)	$	(1	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents


(A)	Represents money market mutual funds.

(B)

Level ~~2—Fair values for~~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 ~~obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are~~being valued ~~using~~solely on settled pricing inputs which come directly from the ~~average of the bid/ask~~exchange.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

~~midpoints~~Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from ~~multiple broker or dealer quotes~~an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.


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

(D)

The fair value measurement tables exclude an immaterial amount of cash as of March 31, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in ~~an S&P 500~~a Russell 3000 index fund and various fixed income securities classified as “available for ~~sale.”~~sale” as of March 31, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.

Level 2—NDT and Rabbi Trust fixed income securities ~~are limited to~~include investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(E)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of ~~September 30,~~March 31, 2017, $(4) million of cash collateral was netted against assets, and $4 million was netted against liabilities. As of December 31, 2016, net cash collateral (received) paid of ~~$(18)~~$1 million was netted against the corresponding net derivative contract positions. Of the $(18) million as of September 30, 2016, $(27) million of cash collateral was netted against assets, and $9 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55)$1 million of cash collateral as of December 31, ~~2015, $(69)~~2016, $(3) million was netted against assets, and ~~$14~~$4 million was netted against liabilities.

Additional Information Regarding Level 3 Measurements

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Corporate Governance and Audit ~~Committee~~Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

For PSE&G, the natural gas supply ~~contracts are~~contract is measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015.~~2016.

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position September 30, 2016 Technique(s) Input Range
Assets (Liabilities)
Millions
PSE&G
Gas Natural Gas Supply Contracts $ —
$ (4 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth
Total PSE&G $ —
$ (4 )
Power
Electricity Electric Load Contracts $ 12
$ —
Discounted Cash flow Historic Load Variability 0% to +10%
Gas (A) Other 3
—

Total Power $ 15
$ —

Total PSEG $ 15
$ (4 )




	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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position December 31, 2015 Technique(s) Input Range
Assets (Liabilities)
Millions
PSE&G
Gas Natural Gas Supply Contracts $ 13
$ (11 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth
Total PSE&G $ 13
$ (11 )
Power
Electricity Electric Load Contracts $ 11
$ (1 ) Discounted Cash Flow Historic Load Variability 0% to +10%
Electricity Other 1
—

Total Power $ 12
$ (1 )
Total PSEG $ 25
$ (12 )




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2016					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSE&G
Gas	Natural Gas Supply Contract	$	—	$	(5	)	Discounted Cash Flow	Transportation Costs	$0.60 to $0.80/Dth
Total PSE&G		$	—	$	(5	)
Power
Electricity	Electric Load Contracts	$	7	$	(1	)	Discounted Cash Flow	Historic Load Variability	0% to +10%
Gas (A)	Other	—		—
Total Power		$	7	$	(1	)
Total PSEG		$	7	$	(6	)

(A) Includes gas ~~supply~~ positions ~~that are immaterial.~~which were immaterial as of March 31, 2017 and December 31, 2016.

Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months ~~and nine months~~ ended ~~September 30, 2016~~March 31, 2017 and ~~September 30, 2015,~~March 31, 2016, respectively, follows:

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

for the Three Months ~~andNine Months~~ Ended ~~September 30, 2016~~ March 31, 2017

Three Months Ended September 30, 2016

Total Gains or (Losses)
Realized/Unrealized

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

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of September 30, 2016
Millions
PSEG
Net Derivative Assets (Liabilities) $ 5
$ 8
$ (2 ) $ 4
$ (4 ) $ —
$ 11

PSE&G
Net Derivative Assets (Liabilities) $ (2 ) $ —
$ (2 ) $ —
$ —
$ —
$ (4 )
Power
Net Derivative Assets (Liabilities) $ 7
$ 8
$ —
$ 4
$ (4 ) $ —
$ 15

Nine Months Ended September 30, 2016

Total Gains or (Losses)
Realized/Unrealized

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

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of September 30, 2016
Millions
PSEG
Net Derivative Assets (Liabilities) $ 13
$ 24
$ (6 ) $ 4
$ (24 ) $ —
$ 11

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




	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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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

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

Three Months Ended September 30, 2015

Total Gains or (Losses)
Realized/Unrealized

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

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

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

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

Nine Months Ended September 30, 2015

Total Gains or (Losses)
Realized/Unrealized

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

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

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

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




	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


(A)	PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $8$19 million and ~~$24~~$15 million in Operating Income for the three months ~~and nine months~~ ended ~~September 30,~~March 31, 2017 and 2016, respectively. Of the $8$19 million in Operating Income, $4$3 million is unrealized. The ~~$24~~$15 million in Operating Income is realized.


(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 ~~$(4)~~$(22) million and ~~$(24)~~$(15) million in settlements for the three months ~~and nine months~~ ended ~~September 30,~~March 31, 2017 and 2016, respectively. ~~Represents $(2) million and $(18) million in settlements for the three months and nine months ended September 30, 2015, respectively.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~


(D)	During the three months ended March 31, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers ~~among levels~~in to or out of Level 3 during ~~the three months and nine months ended September 30, 2016 and 2015.~~2016.


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

As of ~~September 30, 2016,~~March 31, 2017, PSEG carried ~~$2.6~~$2.5 billion of net assets that are measured at fair value on a recurring basis, of which ~~$11~~$3 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015~~2016.

As of As of
September 30, 2016 December 31, 2015

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Millions
Long-Term Debt:
PSEG (Parent) (A) $ 500
$ 500
$ 503
$ 506

PSE&G (B) 7,816
8,996
6,821
7,235

Power - Recourse Debt (B) 2,381
2,788
2,237
2,508

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

Total Long-Term Debt $ 10,697
$ 12,284
$ 9,568
$ 10,256




	As of				As of
	March 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (Parent) (A)	$	1,196	$	1,184	$	1,195	$	1,185
PSE&G (B)	7,819		8,349		7,818		8,240
Power - Recourse Debt (B)	2,383		2,611		2,382		2,578
Total Long-Term Debt	$	11,398	$	12,144	$	11,395	$	12,003

(A)

Fair value includes a $500 million floating rate term loan and net ~~offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power.~~offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. ~~Carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.~~

(B)

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


~~(C)~~	~~Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Note 13. Other Income and Deductions

Other Income PSE&G Power Other (A) Consolidated
Millions
Three Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 21
$ —
$ 21

Allowance for Funds Used During Construction 14
—
—
14

Solar Loan Interest 6
—
—
6

Other 2
2
2
6

Total Other Income $ 22
$ 23
$ 2
$ 47

Nine Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 69
$ —
$ 69

Allowance for Funds Used During Construction 35
—
—
35

Solar Loan Interest 17
—
—
17

Other 9
5
4
18

Total Other Income $ 61
$ 74
$ 4
$ 139

Three Months Ended September 30, 2015
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 24
$ —
$ 24

Allowance for Funds Used During Construction 14
—
—
14

Solar Loan Interest 6
—
—
6

Other 2
1
—
3

Total Other Income $ 22
$ 25
$ —
$ 47

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

Allowance for Funds Used During Construction 36
—
—
36

Solar Loan Interest 18
—
—
18

Gain on Insurance Recovery —
28
—
28

Other 5
3
3
11

Total Other Income $ 59
$ 109
$ 3
$ 171




Other Income	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended March 31, 2017
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	31	$	—	$	31
Allowance for Funds Used During Construction	14		—		—		14
Rabbi Trust Realized Gains, Interest and Dividends	3		4		9		16
Solar Loan Interest	5		—		—		5
Other	3		3		—		6
Total Other Income	$	25	$	38	$	9	$	72
Three Months Ended March 31, 2016
NDT Fund Gains, Interest, Dividend and Other Income	$	—	$	25	$	—	$	25
Allowance for Funds Used During Construction	11		—		—		11
Solar Loan Interest	6		—		—		6
Other	3		1		2		6
Total Other Income	$	20	$	26	$	2	$	48

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Other Deductions PSE&G Power Other (A) Consolidated
Millions
Three Months Ended September 30, 2016
  NDT Fund Realized Losses and Expenses $ —
$ 5
$ —
$ 5

  Other 1
1
1
3

    Total Other Deductions $ 1
$ 6
$ 1
$ 8

Nine Months Ended September 30, 2016
  NDT Fund Realized Losses and Expenses $ —
$ 31
$ —
$ 31

  Other 3
2
3
8

    Total Other Deductions $ 3
$ 33
$ 3
$ 39

Three Months Ended September 30, 2015
  NDT Fund Realized Losses and Expenses $ —
$ 13
$ —
$ 13

  Other —
1
—
1

  Total Other Deductions $ —
$ 14
$ —
$ 14

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

  Other 2
2
2
6

  Total Other Deductions $ 2
$ 32
$ 2
$ 36




Other Deductions	PSE&G		Power		Other (A)		Consolidated
	Millions
Three Months Ended March 31, 2017
NDT Fund Realized Losses and Expenses	$	—	$	7	$	—	$	7
Other	1		—		3		4
Total Other Deductions	$	1	$	7	$	3	$	11
Three Months Ended March 31, 2016
NDT Fund Realized Losses and Expenses	$	—	$	18	$	—	$	18
Other	1		—		2		3
Total Other Deductions	$	1	$	18	$	2	$	21


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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Note 14. Income Taxes

PSEG’s, PSE&G’s and Power’s effective tax rates for the three months ~~and nine months~~ ended ~~September 30, 2016~~March 31, 2017 and ~~2015~~2016 were as follows:

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




	Three Months Ended
	March 31,
	2017	2016
PSEG	20.3%	37.5%
PSE&G	36.4%	36.6%
Power	40.6%	40.2%

For the three months ~~and nine months~~ ended ~~September 30, 2016,~~March 31, 2017, the overall ~~decreases~~decrease in PSEG’s effective tax rates as compared to the same ~~periods~~period in the prior year as well as to the statutory tax rate of 40.85%, ~~were~~was primarily due ~~primarily~~ to changes in uncertain tax positions and ~~plant related items.~~

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

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

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

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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

PSEG Other Comprehensive Income (Loss)
Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2016 $ 1
$ (370 ) $ 117
$ (252 )
Other Comprehensive Income before Reclassifications 1
—
26
27

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
9
(2 ) 7

Net Current Period Other Comprehensive Income (Loss) 1
9
24
34

Balance as of September 30, 2016 $ 2
$ (361 ) $ 141
$ (218 )

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

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

PSEG Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2015 $ —
$ (386 ) $ 91
$ (295 )
Other Comprehensive Income before Reclassifications 2
—
44
46

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
25
6
31

Net Current Period Other Comprehensive Income (Loss) 2
25
50
77

Balance as of September 30, 2016 $ 2
$ (361 ) $ 141
$ (218 )

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

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




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	)




Power	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	$	—	$	(340	)	$	129		$	(211	)
Other Comprehensive Income before Reclassifications	—		—			28			28
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		5			(9		)	(4		)
Net Current Period Other Comprehensive Income (Loss)	—		5			19			24
Balance as of March 31, 2017	$	—	$	(335	)	$	148		$	(187	)

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Power Other Comprehensive Income (Loss)
Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2016 $ —
$ (313 ) $ 112
$ (201 )
Other Comprehensive Income before Reclassifications —
—
24
24

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
7
(2 ) 5

Net Current Period Other Comprehensive Income (Loss) —
7
22
29

Balance as of September 30, 2016 $ —
$ (306 ) $ 134
$ (172 )

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

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

Power Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2015 $ —
$ (327 ) $ 87
$ (240 )
Other Comprehensive Income before Reclassifications —
—
40
40

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
21
7
28

Net Current Period Other Comprehensive Income (Loss) —
21
47
68

Balance as of September 30, 2016 $ —
$ (306 ) $ 134
$ (172 )

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

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




PSEG			Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		March 31, 2017
	Location of Pre-Tax Amount In Statement of Operations		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense		$	2		$	(1	)	$	1
Amortization of Actuarial Loss	O&M Expense		(12		)	5			(7		)
Total Pension and OPEB Plans			(10		)	4			(6		)
Available-for-Sale Securities
Realized Gains	Other Income		36			(17		)	19
Realized Losses	Other Deductions		(7		)	3			(4		)
OTTI	OTTI		(1		)	1			—
Total Available-for-Sale Securities			28			(13		)	15
Total			$	18		$	(9	)	$	9




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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2016 September 30, 2016
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense $ 3
$ (2 ) $ 1
$ 9
$ (4 ) $ 5

Amortization of Actuarial Loss O&M Expense (17 ) 7
(10 ) (51 ) 21
(30 )
Total Pension and OPEB Plans (14 ) 5
(9 ) (42 ) 17
(25 )
Available-for-Sale Securities
Realized Gains Other Income 13
(6 ) 7
41
(20 ) 21

Realized Losses Other Deductions (5 ) 3
(2 ) (29 ) 15
(14 )
Other-Than-Temporary Impairments (OTTI) OTTI (5 ) 2
(3 ) (25 ) 12
(13 )
Total Available-for-Sale Securities 3
(1 ) 2
(13 ) 7
(6 )
Total $ (11 ) $ 4
$ (7 ) $ (55 ) $ 24
$ (31 )




Power			Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
			Three Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations		March 31, 2017
	Location of Pre-Tax Amount In Statement of Operations		Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	O&M Expense		$	2		$	(1	)	$	1
Amortization of Actuarial Loss	O&M Expense		(11		)	5			(6		)
Total Pension and OPEB Plans			(9		)	4			(5		)
Available-for-Sale Securities
Realized Gains	Other Income		25			(13		)	12
Realized Losses	Other Deductions		(5		)	2			(3		)
OTTI	OTTI		(1		)	1			—
Total Available-for-Sale Securities			19			(10		)	9
Total			$	10		$	(6	)	$	4

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

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

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

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

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2016 September 30, 2016
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense $ 3
$ (1 ) $ 2
$ 8
$ (3 ) $ 5

Amortization of Actuarial Loss O&M Expense (15 ) 6
(9 ) (44 ) 18
(26 )
Total Pension and OPEB Plans (12 ) 5
(7 ) (36 ) 15
(21 )
Available-for-Sale Securities
Realized Gains Other Income 12
(5 ) 7
37
(18 ) 19

Realized Losses Other Deductions (4 ) 2
(2 ) (26 ) 13
(13 )
OTTI OTTI (5 ) 2
(3 ) (25 ) 12
(13 )
Total Available-for-Sale Securities 3
(1 ) 2
(14 ) 7
(7 )
Total $ (9 ) $ 4
$ (5 ) $ (50 ) $ 22
$ (28 )

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

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

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

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

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




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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note 16. Earnings Per Share (EPS) and Dividends

EPS

Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
Basic Diluted Basic Diluted Basic Diluted Basic Diluted

EPS Numerator (Millions):

Net Income $ 327
$ 327
$ 439
$ 439
$ 985
$ 985
$ 1,370
$ 1,370

EPS Denominator (Millions):

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

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

Total Shares 505
508
505
508
505
508
505
508

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




	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

There were approximately ~~0.4~~0.3 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the three months ended March 31, 2017 and ~~nine months ended September 30, 2016 and 2015.~~2016.

Dividends

Three Months Ended Nine Months Ended
September 30, September 30,
Dividend Payments on Common Stock 2016 2015 2016 2015
Per Share $ 0.41
$ 0.39
$ 1.23
$ 1.17

In Millions $ 207
$ 198
$ 622
$ 592




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

On April 18, 2017, PSEG’s Board of Directors approved a $0.43 per share common stock dividend for the second quarter of 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note 17. Financial Information by Business Segment

PSE&G Power Other (A) Eliminations (B) Consolidated
Millions
Three Months Ended September 30, 2016
Total Operating Revenues $ 1,684
$ 1,075
$ 7
$ (316 ) $ 2,450

Net Income (Loss) 255
139
(67 ) —
327

Gross Additions to Long-Lived Assets 680
325
9
—
1,014

Nine Months Ended September 30, 2016
Operating Revenues $ 4,746
$ 3,102
$ 256
$ (1,133 ) $ 6,971

Net Income (Loss) 696
320
(31 ) —
985

Gross Additions to Long-Lived Assets 2,035
923
27
—
2,985

Three Months Ended September 30, 2015
Total Operating Revenues $ 1,766
$ 1,096
$ 120
$ (294 ) $ 2,688

Net Income (Loss) 222
206
11
—
439

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

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

Net Income (Loss) 631
707
32
—
1,370

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

As of September 30, 2016
Total Assets $ 25,486
$ 12,810
$ 2,385
$ (1,193 ) $ 39,488

Investments in Equity Method Subsidiaries $ —
$ 106
$ —
$ —
$ 106

As of December 31, 2015
Total Assets $ 23,677
$ 12,250
$ 2,810
$ (1,202 ) $ 37,535

Investments in Equity Method Subsidiaries $ —
$ 119
$ —
$ —
$ 119




	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


(A)	Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.

(B)

Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 18. Related-Party Transactions.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Note 18. Related-Party Transactions

The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

PSE&G

The financial statements for PSE&G include transactions with related parties as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
Related-Party Transactions 2016 2015 2016 2015
Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A) $ 320
$ 294
$ 1,162
$ 1,287

Administrative Billings from Services (B) 73
66
224
197

Total Billings from Affiliates $ 393
$ 360
$ 1,386
$ 1,484




	Three Months Ended
	March 31,
Related-Party Transactions	2017		2016
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	599	$	545
Administrative Billings from Services (B)	65		69
Total Billings from Affiliates	$	664	$	614

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

As of As of
Related-Party Transactions September 30, 2016 December 31, 2015
Millions
Receivables from PSEG (C) $ 28
$ 222

Payable to Power (A) $ 126
$ 212

Payable to Services (B) 88
80

Accounts Payable—Affiliated Companies $ 214
$ 292

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

Long-Term Accrued Taxes Payable
$ 92
$ 109




	As of		As of
Related-Party Transactions	March 31, 2017		December 31, 2016
	Millions
Receivables from PSEG (C)	$	34	$	76
Payable to Power (A)	$	175	$	193
Payable to Services (B)	43		67
Accounts Payable—Affiliated Companies	$	218	$	260
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	116	$	130

Power

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

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

Billings from Affiliates:
Administrative Billings from Services (B) $ 44
$ 44
$ 134
$ 135

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~




	Three Months Ended
	March 31,
Related-Party Transactions	2017		2016
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	599	$	545
Billings from Affiliates:
Administrative Billings from Services (B)	$	36	$	45

As of As of
Related-Party Transactions September 30, 2016 December 31, 2015
Millions
Receivables from PSE&G (A) $ 126
$ 212

Receivables from PSEG (C) —
64

Accounts Receivable—Affiliated Companies $ 126
$ 276

Payable to Services (B) $ 27
$ 33

Payable to PSEG (C) 129
—

Accounts Payable—Affiliated Companies $ 156
$ 33

Short-Term Loan Due (to) from Affiliate (E) $ 514
$ 363

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

Long-Term Accrued Taxes Payable
$ 79
$ 35




	As of		As of
Related-Party Transactions	March 31, 2017		December 31, 2016
	Millions
Receivables from PSE&G (A)	$	175	$	193
Receivables from PSEG (C)	—		12
Accounts Receivable—Affiliated Companies	$	175	$	205
Payable to Services (B)	$	10	$	25
Payable to PSEG (C)	71		—
Accounts Payable—Affiliated Companies	$	81	$	25
Short-Term Loan Due (to) from Affiliate (E)	$	157	$	87
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	78	$	77

(A)

PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.


(B)	Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.

(C)

PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.


(D)	PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Condensed Consolidated Balance Sheets.


(E)	Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note 19. Guarantees of Debt

~~Each series of~~ Power’s Senior Notes ~~Pollution Control Notes and its syndicated revolving credit facilities~~ are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015~~2016 and for the three months ended March 31, 2017 and ~~nine months ended September 30, 2016 and 2015.~~2016.




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended March 31, 2017
Operating Revenues	$	—		$	1,270		$	52		$	(38	)	$	1,284
Operating Expenses	4			1,569			52			(38		)	1,587
Operating Income (Loss)	(4		)	(299		)	—			—			(303		)
Equity Earnings (Losses) of Subsidiaries	(161		)	(1		)	3			162			3
Other Income	25			41			—			(28		)	38
Other Deductions	(1		)	(6		)	—			—			(7		)
Other-Than-Temporary Impairments	—			(1		)	—			—			(1		)
Interest Expense	(30		)	(9		)	(5		)	28			(16		)
Income Tax Benefit (Expense)	1			111			4			—			116
Net Income (Loss)	$	(170	)	$	(164	)	$	2		$	162		$	(170	)
Comprehensive Income (Loss)	$	(146	)	$	(143	)	$	2		$	141		$	(146	)
Three Months Ended March 31, 2017
Net Cash Provided By (Used In) Operating Activities	$	77		$	377		$	91		$	35		$	580
Net Cash Provided By (Used In) Investing Activities	$	251		$	20		$	(154	)	$	(511	)	$	(394	)
Net Cash Provided By (Used In) Financing Activities	$	(328	)	$	(395	)	$	68		$	476		$	(179	)

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Total
Millions
Three Months Ended September 30, 2016
Operating Revenues $ —
$ 1,059
$ 43
$ (27 ) $ 1,075

Operating Expenses (2 ) 826
40
(27 ) 837

Operating Income (Loss) 2
233
3
—
238

Equity Earnings (Losses) of Subsidiaries 143
(1 ) 3
(142 ) 3

Other Income 18
26
—
(21 ) 23

Other Deductions (2 ) (4 ) —
—
(6 )
Other-Than-Temporary Impairments —
(5 ) —
—
(5 )
Interest Expense (30 ) (12 ) (3 ) 21
(24 )
Income Tax Benefit (Expense) 8
(97 ) (1 ) —
(90 )
Net Income (Loss) $ 139
$ 140
$ 2
$ (142 ) $ 139

Comprehensive Income (Loss) $ 168
$ 161
$ 2
$ (163 ) $ 168

Nine Months Ended September 30, 2016
Operating Revenues $ —
$ 3,061
$ 131
$ (90 ) $ 3,102

Operating Expenses 10
2,494
119
(90 ) 2,533

Operating Income (Loss) (10 ) 567
12
—
569

Equity Earnings (Losses) of Subsidiaries 347
(1 ) 9
(346 ) 9

Other Income 52
88
—
(66 ) 74

Other Deductions (2 ) (31 ) —
—
(33 )
Other-Than-Temporary Impairments —
(25 ) —
—
(25 )
Interest Expense (91 ) (29 ) (12 ) 66
(66 )
Income Tax Benefit (Expense) 24
(234 ) 2
—
(208 )
Net Income (Loss) $ 320
$ 335
$ 11
$ (346 ) $ 320

Comprehensive Income (Loss) $ 388
$ 381
$ 11
$ (392 ) $ 388

Nine Months Ended September 30, 2016

Net Cash Provided By (Used In)
   Operating Activities
$ 175
$ 1,261
$ 234
$ (410 ) $ 1,260

Net Cash Provided By (Used In)
   Investing Activities
$ (588 ) $ (1,166 ) $ (549 ) $ 1,152
$ (1,151 )

Net Cash Provided By (Used In)
   Financing Activities
$ 413
$ (95 ) $ 315
$ (742 ) $ (109 )




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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Power
Guarantor
Subsidiaries

Other
Subsidiaries

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

Operating Expenses 3
692
35
(25 ) 705

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

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

Other Income 10
26
—
(11 ) 25

Other Deductions —
(14 ) —
—
(14 )

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

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

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

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

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

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

Other Income 33
111
—
(35 ) 109

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

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

Nine Months Ended September 30, 2015

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

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

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Total
Millions
As of September 30, 2016
Current Assets $ 4,889
$ 1,845
$ 287
$ (5,262 ) $ 1,759

Property, Plant and Equipment, net 57
6,570
2,080
—
8,707

Investment in Subsidiaries 4,709
483
—
(5,192 ) —

Noncurrent Assets 157
2,140
123
(76 ) 2,344

Total Assets $ 9,812
$ 11,038
$ 2,490
$ (10,530 ) $ 12,810

Current Liabilities $ 818
$ 3,888
$ 1,350
$ (5,262 ) $ 794

Noncurrent Liabilities 473
2,704
394
(76 ) 3,495

Long-Term Debt 2,381
—
—
—
2,381

Member’s Equity 6,140
4,446
746
(5,192 ) 6,140

Total Liabilities and Member’s Equity $ 9,812
$ 11,038
$ 2,490
$ (10,530 ) $ 12,810

As of December 31, 2015
Current Assets $ 4,501
$ 1,912
$ 364
$ (4,828 ) $ 1,949

Property, Plant and Equipment, net 83
6,502
1,542
—
8,127

Investment in Subsidiaries 4,501
346
—
(4,847 ) —

Noncurrent Assets 155
1,959
136
(76 ) 2,174

Total Assets $ 9,240
$ 10,719
$ 2,042
$ (9,751 ) $ 12,250

Current Liabilities $ 1,112
$ 3,866
$ 1,076
$ (4,828 ) $ 1,226

Noncurrent Liabilities 442
2,597
375
(76 ) 3,338

Long-Term Debt 1,684
—
—
—
1,684

Member’s Equity 6,002
4,256
591
(4,847 ) 6,002

Total Liabilities and Member’s Equity $ 9,240
$ 10,719
$ 2,042
$ (9,751 ) $ 12,250




	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of March 31, 2017
Current Assets	$	4,244	$	1,332	$	174	$	(4,458	)	$	1,292
Property, Plant and Equipment, net	56		5,582		2,447		—			8,085
Investment in Subsidiaries	4,104		343		—		(4,447		)	—
Noncurrent Assets	175		2,154		129		(106		)	2,352
Total Assets	$	8,579	$	9,411	$	2,750	$	(9,011	)	$	11,729
Current Liabilities	$	187	$	3,436	$	1,580	$	(4,458	)	$	745
Noncurrent Liabilities	531		2,171		527		(106		)	3,123
Long-Term Debt	2,383		—		—		—			2,383
Member’s Equity	5,478		3,804		643		(4,447		)	5,478
Total Liabilities and Member’s Equity	$	8,579	$	9,411	$	2,750	$	(9,011	)	$	11,729
As of December 31, 2016
Current Assets	$	4,412	$	1,593	$	152	$	(4,697	)	$	1,460
Property, Plant and Equipment, net	55		6,145		2,320		—			8,520
Investment in Subsidiaries	4,249		344		—		(4,593		)	—
Noncurrent Assets	168		2,016		129		(100		)	2,213
Total Assets	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193
Current Liabilities	$	171	$	3,752	$	1,454	$	(4,697	)	$	680
Noncurrent Liabilities	532		2,398		502		(100		)	3,332
Long-Term Debt	2,382		—		—		—			2,382
Member’s Equity	5,799		3,948		645		(4,593		)	5,799
Total Liabilities and Member’s Equity	$	8,884	$	10,098	$	2,601	$	(9,390	)	$	12,193

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

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

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

PSE&G~~our~~—which is a public utility ~~company which is~~ engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU, and

Power ~~our~~—which is a multi-regional ~~wholesale~~ energy supply company that integrates the operations of its merchant nuclear and fossil generating ~~asset operations and gas supply commitments~~assets with its ~~wholesale~~power marketing businesses through competitive energy sales in well-developed energy markets and fuel supply ~~and energy transacting~~ functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA), and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries ~~are:~~include PSEG Energy Holdings L.L.C. (Energy Holdings), which ~~earns its revenues~~ primarily ~~from its portfolio of lease investments;~~has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under aan Operations and Services Agreement contractual agreement; and PSEG Services Corporation (Services), which provides ~~us and these operating subsidiaries with~~ certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in Part I, Item 1. Business of our ~~2015~~2016 Annual Report on 10-K (Form 10-K) provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part I, Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of ~~2015~~2016 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during ~~2016~~2017 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the ~~2015~~2016 Form 10-K.

EXECUTIVE OVERVIEW OF ~~2016~~2017 AND FUTURE OUTLOOK

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

improving utility operations through ~~growth in~~ investment in T&D and other infrastructure projects designed to enhance system reliability and resiliency and to meet customer expectations and public policy objectives,

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

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Financial Results

The results for PSEG, PSE&G and Power for the ~~three months and~~ ~~nine~~three months ended ~~September 30,~~March 31, 2017 and 2016 ~~and 2015~~ are presented as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
Earnings 2016 2015 2016 2015
Millions
PSE&G $ 255
$ 222
$ 696
$ 631

Power (A) (B) 139
206
320
707

Other (C) (67 ) 11
(31 ) 32

PSEG Net Income $ 327
$ 439
$ 985
$ 1,370

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




		Three Months Ended
		March 31,
Earnings (Losses)		2017			2016
	Millions
PSE&G		$	299		$	262
Power (A)		(170		)	192
Other (B)		(15		)	17
PSEG Net Income		$	114		$	471

PSEG Net Income Per Share (Diluted)		$	0.22		$	0.93


(A)	Includes after-tax expenses of ~~$67~~$334 million primarily for accelerated depreciation related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants in the three months ~~and nine months~~ ended ~~September 30, 2016.~~March 31, 2017. See Item 1. Note 3. Early Plant Retirements for additional information.


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

~~(C)~~

Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded an after-tax ~~impairment~~charge of ~~$86~~$32 million related to its investments in NRG REMA, LLC’s leveraged leases in the three months ~~and nine months~~ ended ~~September 30, 2016.~~March 31, 2017. See Item 1. Note 6. Financing Receivables for ~~further~~additional information.

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

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

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




		Three Months Ended
		March 31,
		2017		2016
	Millions, after tax
NDT Fund Income (Expense) (A) (B)		$	8	$	(5	)
Non-Trading MTM Gains (Losses) (C)		$	6	$	13

(A)

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


(B)	Net of tax (expense) benefit of ~~$(2) million, $10 million, $0~~$(9) million and $3 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2017 and 2016, ~~and 2015,~~ respectively.


(C)	Net of tax (expense) benefit of ~~$(24) million, $(34) million, $37~~$(4) million and ~~$(40)~~$(10) million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2017 and 2016, ~~and 2015,~~ respectively.

Our ~~$112~~$357 million decrease in Net Income for the three months ended ~~September 30, 2016~~March 31, 2017 was driven primarily by

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

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

a decrease in energy sales due primarily to lower average realized sales prices, and

a charge for estimated losses related to leveraged lease investments (see Item 1. Note 6. Financing Receivables).

These decreases were partially offset by:

higher transmission revenues, and

increased gas distribution revenues.

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~~lower volumes of energy sold at lower average realized prices and lower capacity revenues, primarily in the PJM Interconnection, L.L.C. (PJM) region.~~

~~These decreases were partially offset by~~

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

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

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

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

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

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

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

~~lower capacity and operating reserve revenues in PJM,~~

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

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

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

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

~~These decreases were partially offset by~~

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

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

~~higher revenues due to increased investments in transmission projects.~~

During the first ~~nine~~three months of ~~2016,~~2017, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our multi-year, long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, ~~our merchant generator,~~ we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.

At PSE&G, we continue to invest in ~~2016 we~~transmission projects that focus on reliability improvements and replacement of aging infrastructure. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We also ~~commenced modernizing~~continue to modernize PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. ~~In 2017, as~~As a result of our Energy Strong Order from the BPU, we will be required to file a ~~Distribution~~distribution base rate case ~~proceeding.~~proceeding by no later than November 1, 2017. We cannot predict the impact such proceeding will have on our distribution business.

~~Despite~~Although the ~~unseasonable warm winter~~ weather ~~patterns~~ in ~~2016,~~the first quarter of 2017 was warmer than normal, Power’s results ~~benefited~~saw a continuing benefit from access to natural gas supplies through existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the BGSS arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make ~~third party~~third-party sales and if excess volume remains after the third-party sales, supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s ~~strategic~~ hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in 2017 relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.

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

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

Since 2013, ~~eight~~several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, ~~and four additional stations~~or have ~~been~~ announced as being at risk for early retirement. This situation is generally due to low natural gas prices, and the related decline in market prices of energy, resulting from the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide ~~credits~~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 toof nuclear generating stations while ~~simultaneously raising~~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 ~~delivery and less diversity of the generation fleet.~~fuel delivery.

If trends noted above continue or worsen, our nuclear generating units could cease being economically competitive which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such retirement, which may include, among other things, accelerated ~~depreciation and amortization~~D&A or impairment charges, accelerated asset retirement costs, severance costs, ~~and~~ environmental remediation costs, ~~could be material.~~and additional funding of nuclear decommissioning trust funds will likely have a material adverse impact on future financial results. We continue to advocate for sound policies that recognize nuclear power as a source of reliable and clean energy and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.

Regulatory, Legislative and Other Developments

In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets.

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Transmission

In April ~~2013,~~2017, the PJM initiated its first “open window” solicitation process to allow both incumbents and non-incumbents the opportunity to submit transmission project proposals to address identified high voltage issues in New Jersey. In February 2016, FERC issued an order granting PSE&G’s request that it be permitted to seek recovery of 100% of its portion of prudently incurred Artificial Island project costs if the project is cancelled for reasons beyond PSE&G’s control. In April 2016, PSE&G accepted construction responsibility for three components of the Artificial Island project that PJM assigned to us. On August 5, 2016, PJMBoard announced that it ~~has suspended~~would be lifting the previously disclosed suspension of the Artificial Island transmission project and ~~is performing a comprehensive analysis~~approved the award to determine a future course of action, which is expected to be completed by February 2017. We may also from time to time have opportunities to submit transmission project proposals in regions where we are not the incumbent. However, there can be no assurance that any such proposals would be successful.

In April 2016, PJM filed at FERC to incorporate a voltage threshold into PJM’s Regional Transmission Expansion Plan (RTEP) process to exempt, except under certain circumstances, reliability violations on facilities below 200 kV from PJM’s proposal window process. We generally support this reform as a measure to improve the efficiencyPSE&G of the ~~open window procedure that will permit transmission developers to focus on the projects most likely to benefit from~~construction of necessary upgrade work in Hope Creek at a ~~competitive process.~~cost of approximately $130 million.

There are several matters pending before FERC that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayers in New ~~Jersey and may cause increased scrutiny regarding PSE&G’s future capital investments.~~Jersey. In addition, as a basic generation service (BGS) supplier, Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to an adjustment, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.

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

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Wholesale Power Market Design

Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. ~~In June~~During 2015, ~~FERC conditionally accepted~~PJM implemented a ~~proposal from PJM~~new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for ~~a capacity~~ performance ~~product to include generators, Demand Response and energy efficiency providers, which will be required to perform~~ during emergency conditions ~~as a supplement~~and significant penalties for non-performance. The CP product is expected to be implemented fully for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources (“seasonal resources”). 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 ~~capacity product. The proposal included enhanced performance-based incentives and penalties.~~resources for future auctions. We ~~believe that the auction pricing adequately reflects the increased costs that could result from operating under more stringent rules for generation availability. Based~~do not expect action on the complaints before the upcoming 2020/2021 base residual auction results, the capacity performance mechanism appears to have provided the opportunity for enhanced capacity market revenue streams for Power, but future impacts cannot be assured. Further, there may be requirements for additional investment and there are additional performance and financial risks. Appeals of FERC’s capacity performance orders are pending.

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

As a result of the efforts of certain entities in PJM to obtain financial support arrangements from their state ~~commission,~~commissions, a group of suppliers requested that FERC direct PJM to expand the currently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized generators would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ request and cannot predict the outcome of the proceeding. ~~See Part II, Item 5. Other Information—Federal Regulation—Capacity Market Issues—PJM for additional information.~~

Environmental Regulation

We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act (FWPCA) requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs. ~~See Item 1. Note 9. Commitments and Contingent Liabilities for further information.~~

In ~~October 2015,~~March 2017, the President of the United States issued an Executive Order that instructed the EPA ~~published~~to review the New Source Performance Standards, which establish emissions standards for CO₂ for certain new fossil power plants, and the Clean Power Plan, ~~(CPP),~~ a greenhouse gas emissions regulation under the Clean Air Act ~~(CAA)~~ for existing power ~~plants. The regulation~~plants that establishes state-specific emission rate targets based on implementation of the best ~~systems~~system of emission reduction. ~~We continue to work with FERC and other federal and state regulators, as well as industry partners, to determine the potential impact of these regulations.~~

~~The U.S. Supreme Court’s February 2016 decision to stay the implementation~~Upon completion of the ~~CPP will delay deadlines for submission of state requests for extensions and final plans. If~~review, the ~~CPP~~EPA is ~~upheld, new deadlines will need~~expected to ~~be established and~~suspend, revise or rescind the ~~effective date of the compliance period may be impacted.~~rules as appropriate.

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

For further information regarding the matters described above as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 9. Commitments and Contingent ~~Liabilities.~~Liabilities.

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FERC Compliance

Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. ~~This~~While considerable uncertainty remains as to the final resolution of these matters, based upon recent developments in the investigation, ~~is ongoing. The amounts of potential~~Power believes the disgorgement and ~~other potential penalties that we~~interest costs related to the cost-based bidding matter may ~~incur span a wide~~ range between approximately $35 million and $135 million, depending on the ~~success~~legal interpretation of ~~our legal arguments. If our legal arguments do not prevail, in whole~~the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or ~~in part with~~the penalties that FERC would impose relating to either the cost-based bidding or ~~in a judicial challenge that we may~~

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~~choose to pursue, it is likely that Power would record losses that would~~energy matter. However, any of these amounts could be individually material to ~~PSEG’s~~PSEG and ~~Power’s results~~Power. We cannot predict the final outcome of ~~operations in the quarterly and annual periods in which they are recorded.~~these matters. For additional information, see ~~Item 1.~~ Note 9. Commitments and Contingent Liabilities.

Early Retirement of Hudson and Mercer Units

In October 2016, Power determined it will cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. The exact timing of the early retirement of these units ~~will be reviewed for reliability impacts by PJM, and~~ may be impacted by operational and other conditions that could subsequently arise. The decision to retire the Hudson and Mercer units ~~will have~~had a material effect on PSEG’s and Power’s results of ~~operations. In~~operations in 2016 and continues to adversely impact their results of operations in 2017. During the ~~third quarter~~first three months of ~~2016, PSEG and~~2017, Power recognized ~~one-time pre-tax charges~~incremental D&A of $558 million ($574 million in ~~Energy Costs, Operation~~total) and ~~Maintenance and Depreciation and Amortization of $62~~expects to recognize an additional incremental $379 million ~~$48~~($389 million and $4 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs, construction work in progress impairments, and asset retirement obligation (ARO) adjustments, among other shut down items. In addition to these one-time charges, Power will recognize incremental Depreciation and Amortization during the remainder of 2016 of $568 million and $946 million intototal) in 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. ~~Additional employee-related salary continuance~~During the first quarter of 2017, Energy Costs of $7 million for coal inventory adjustments was also incurred and ~~severance~~other costs ~~and various miscellaneous costs~~ may ~~also~~ be incurred during the remaining period in 2017 prior to retirement. ~~Finally,~~ See Item 1. Note 3. Early Plant Retirements for additional information.

Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger ~~investigation and~~obligations under certain environmental regulations, including possible ~~remediation of identified environmental contamination.~~remediation. The amounts for any such ~~environmental investigation or~~ remediation are ~~not~~neither currently probable ornor estimable but may be material. ~~For additional information, including our estimated costs through 2017, see Item 1. Note 3. Early Plant Retirements.~~

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

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

Leveraged Lease ~~Impairments~~Portfolio

~~During~~GenOn Energy, Inc. (GenOn), the ~~third quarter~~parent company of ~~2016, Energy Holdings completed its annual review of estimated residual values embedded in the~~ NRG REMA LLC, (REMA) ~~leveraged leases. The~~, reported in August 2016 that it did not expect to have sufficient liquidity to repay their senior unsecured notes due in June 2017. Although all lease payments are current, PSEG cannot predict the outcome ~~indicated that the revised residual value estimates were lower than the recorded residual values~~of GenOn’s efforts to restructure its portfolio and improve its liquidity and the ~~decline was deemed to be other than temporary~~possible related impact on REMA.

During the first quarter of 2017, due to ~~the adverse~~continuing liquidity issues facing REMA, economic ~~conditions experienced by~~challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as ~~discussed~~well as certain recent discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its investments in ~~Note 3. Early Plant Retirements, negatively impacting~~ the ~~economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million~~REMA leases, which was reflected in Operating ~~Revenues in~~Revenues. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the ~~quarter ended September 30, 2016, calculated by comparing the gross investment in the leases before and after the revised residual estimates.~~values of Energy Holdings’ leveraged leases. For additional information, see Item 1. Note 6. Financing Receivables. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.

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

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~~REMA’s parent company, GenOn Energy, Inc. (GenOn), reported in August 2016~~

Salem

Concurrently with the planned refueling outage at the Salem 2 unit that ~~it did not expect to have sufficient liquidity to repay their senior unsecured notes due in June 2017. Although all lease payments are current, PSEG cannot predict~~is scheduled for the ~~outcome~~second quarter of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged leases.

~~Salem Operations~~

~~The previously announced bolt replacement at Salem Unit 1 was completed and the unit returned to service on July 30, 2016. We expect to continue~~2017, we intend to inspect and replace degraded baffle bolts as part of our multi-year project to replace baffle bolts at both Salem units over the next several refueling outage cycles. We are participating with the Electric Power Research Institute, the Nuclear Energy Institute and other operators of similarly-designed pressurized water reactors in developing a strategy to maintain the long-term health of the reactor vessel internals.

~~Extension of~~ the Salem Unit 1 outage into July and an unplanned outage at Salem Unit 2 due to transformer issues reduced output from the Salem units in the third quarter, which was partially offset by increased production at our Hope Creek and Peach Bottom units. station.As a result, we expect the duration of this outage to be modestly longer than our typical refueling outage, which will reduce production and lower the nuclear capacity factor for the ~~nine months ended September 30, 2016 was 88%.~~second quarter of 2017 as compared to the first quarter of 2017.

Operational Excellence

We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs. For the first ~~nine~~three months of ~~2016,~~2017, our

our utility continued top decile performance in electric reliability,

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

diverse fuel mix and dispatch flexibility allowed us to generate approximately ~~40 terra-watt~~13 terawatt hours while addressing fuel availability and price volatility, and ~~compensating for the extended outages at our Salem units, and~~

combined cycle fleet produced 13three terawatt hours at an ~~average capacity~~equivalent availability factor of ~~63%~~94%.

Financial Strength

Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first ~~nine~~three months of ~~2016~~2017 as we

~~had cash on hand of $450 million as of September 30, 2016,~~maintained sufficient liquidity,

maintained solid investment grade credit ratings, and

increased our indicative annual dividend for ~~2016~~2017 to ~~$1.64~~$1.72 per share.

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

Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first ~~nine~~three months of ~~2016,~~2017, we

made additional investments in transmission infrastructure projects,

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

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

acquired three solar energy projects totaling 100 MW-direct current. Two of these projects are already in service in North Carolina and Colorado. The third project is in Colorado and expected to be in service by year end.mid-2019.

Future Outlook

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

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

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

execute our utility capital investment program, including our Energy Strong program, GSMP and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,

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

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

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

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

For ~~2016~~2017 and beyond, the key issues and challenges we expect our business to confront include:

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

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

the ~~BPU no later than November 1, 2017,~~potential for comprehensive tax reform, particularly in light of public statements by the current U.S. administration and key members of Congress,

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

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

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

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

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

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

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

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

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

the expansion of our geographic footprint,

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

investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.

~~We continue~~In 2016, Power announced its intention to ~~actively explore opportunities in the~~develop a retail ~~energy marketing business,~~platform to sell physical electricity and natural gas, which we believe would begin to complement our existing wholesale marketing business. ~~Our entry into~~Power was granted licenses in 2016 to sell both electricity and gas in the ~~retail energy marketing business is subject to market conditions~~states of New Jersey and ~~regulatory approval, among other things.~~

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Pennsylvania.

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

RESULTS OF OPERATIONS

PSEG

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

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

September 30, September 30,
2016 2015 2016 vs. 2015 2016 2015 2016 vs. 2015
Millions Millions % Millions Millions %
Operating Revenues $ 2,450
$ 2,688
$ (238 ) (9 ) $ 6,971
$ 8,137
$ (1,166 ) (14 )
Energy Costs 866
815
51
6
2,326
2,577
(251 ) (10 )
Operation and Maintenance 776
746
30
4
2,215
2,170
45
2

Depreciation and Amortization 231
313
(82 ) (26 ) 679
960
(281 ) (29 )
Income from Equity Method Investments 3
3
—
—
9
10
(1 ) (10 )
Other Income (Deductions) 39
33
6
18
100
135
(35 ) (26 )
Other-Than-Temporary Impairments 5
30
(25 ) (83 ) 25
45
(20 ) (44 )
Interest Expense 99
96
3
3
288
291
(3 ) (1 )
Income Tax Expense 188
285
(97 ) (34 ) 562
869
(307 ) (35 )




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	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	)

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

PSE&G

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

September 30, September 30,
2016 2015 2016 vs. 2015 2016 2015 2016 vs. 2015
Millions Millions % Millions Millions %
Operating Revenues $ 1,684
$ 1,766
$ (82 ) (5 ) $ 4,746
$ 5,234
$ (488 ) (9 )
Energy Costs 721
740
(19 ) (3 ) 1,979
2,176
(197 ) (9 )
Operation and Maintenance 376
391
(15 ) (4 ) 1,110
1,171
(61 ) (5 )
Depreciation and Amortization 137
231
(94 ) (41 ) 412
712
(300 ) (42 )
Other Income (Deductions) 21
22
(1 ) (5 ) 58
57
1
2

Interest Expense 72
67
5
7
214
203
11
5

Income Tax Expense 144
137
7
5
393
398
(5 ) (1 )




	Three Months Ended				Increase/ (Decrease)
	March 31,				Increase/ (Decrease)
	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 ~~September 30, 2016~~March 31, 2017 as Compared to ~~2015~~2016

Operating Revenues ~~decreased $82~~increased $100 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased ~~$57~~$58 million due primarily to an increase in transmission revenues.

Transmission revenues were ~~$50~~$37 million higher due to ~~increased capital~~higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

~~Electric~~Gas distribution revenues increased $8$24 million due ~~primarily~~ to ~~$12~~an $11 million ~~in higher sales volumes and $12 million~~increase due to the inclusion of Energy Strong in base rates, ~~partially offset by lower~~a $5 million increase due to the Gas System Modernization Program, $4 million of higher delivery volumes, higher Green Program Recovery Charges (GPRC) of ~~$16 million.~~$2 million and $2 million in higher Weather Normalization Clause revenue.

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

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Commodity Revenue ~~decreased $19~~increased $24 million as a result of ~~$14 million of lower~~higher Gas revenues ~~and $5 million of~~partially offset by lower Electric revenues. The changes in Commodity revenue for both gas and electric isare entirely offset ~~with~~by the ~~change~~changes in Energy Costs. PSE&G earns no margin on the provision of ~~BGSS~~basic gas supply service (BGSS) and BGS to retail customers.

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

~~Electric revenues decreased $5~~increased $74 million due primarily to ~~$17~~higher BGSS sales prices.

Electric commodity revenues decreased $50 million due primarily to $23 million of lower revenues from collections of Non-Utility Generation Charges (NGC), a $17 million decrease in BGS revenues due to lower sales prices and volumes and a decrease of ~~$14~~$10 million due to lower volumes of Non-Utility Generation (NUG) energy ~~sold at lower prices. These decreases were partially offset by a $26 million increase in BGS revenues due to higher sales volumes.~~sold.

Clause Revenues ~~decreased $121~~increased $19 million due primarily to ~~lower~~the 2016 return to customers of $15 million of overcollections of Securitization Transition Charges (STC), and higher Societal Benefit Charges (SBC) of ~~$118 million. The STC reduction was a result of rate reductions due to the completion of securitization collections~~$2 million in ~~2015.~~2017. The changes in the STC and SBC amounts are entirely offset by decreases in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC or SBC collections.

Operating Expenses

Energy Costs ~~decreased $19~~increased $24 million. This is entirely offset by the change in Commodity Revenue.

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

a ~~$23~~$6 million ~~net reduction~~decrease in appliance service costs, ~~related to various clause mechanisms, including SBC~~

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

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

and

~~partially offset by~~ a $3 million net ~~increase of $10 million~~decrease in ~~operating expenses, including increases in appliance service costs, gas distribution costs and electric distribution corrective maintenance.~~operational expenses.

Depreciation and Amortization ~~decreased $94~~increased $32 million due primarily to ~~a decrease~~an increase of ~~$114~~$17 million in amortization of Regulatory Assets ~~primarily as~~and a ~~result of the completion of the amortization of the securitization charges in 2015 (which is completely offset in STC Revenues), partially offset by an $18~~$14 million increase in depreciation due to additional plant in service.

~~Interest Expense~~Other Income and (Deductions) increased $5 million due primarily to an increase of $7$3 million ~~due to net debt issuances~~ in ~~2015~~Allowance for Funds Used During Construction and ~~2016, partially offset by~~ a $2$3 million ~~decrease due to the redemption of securitization debt~~increase in ~~2015.~~realized gains on Rabbi Trust investments.

~~Income Tax~~Interest Expense increased $7 million due primarily to net debt issuances in 2016.

Income Tax Expense increased $20 million due primarily to higher pre-tax ~~income, partially offset by plant-related items and uncertain tax positions.~~income.

Power




	Three Months Ended					Increase/ (Decrease)
	March 31,					Increase/ (Decrease)
	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

~~Nine~~Three Months Ended ~~September 30, 2016~~March 31, 2017 as Compared to ~~2015~~2016

Operating Revenuesdecreased ~~$488~~$29 million due to changes in ~~delivery, commodity, clause~~generation and ~~other operating~~gas supply revenues.

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

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

Electric distribution revenues decreased $30 million due primarily to lower GPRC of $42 million and a $4 million decrease due to lower sales volumes partially offset by $16 million increase due to the inclusion of Energy Strong in base rates.

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

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

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

Electric revenues decreased $89 million due primarily to $43 million of lower revenues from collections of NGC, a decrease of $31 million due to lower volumes of NUG energy sold and a $15 million or 1% decrease in BGS revenues due primarily to lower sales volumes.

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~~Clause Revenues~~ decreased $402 million due primarily to lower STC of $370 million, lower SBC of $38 million and $9 million of lower SPRC, partially offset by higher Margin Adjustment Clause (MAC) revenue of $15 million. The STC reduction is a result of rate reductions due to the completion of securitization collections in 2015. The changes in the STC, SBC, SPRC and MAC amounts are entirely offset by decreases in the amortization of Regulatory Assets and related costs in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on STC, SBC, SPRC or MAC collections.

~~Operating Expenses~~

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

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

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

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

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

~~an $8 million increase in electric distribution corrective maintenance,~~

~~a $5 million increase in vegetation management,~~

~~a $5 million increase in transmission related maintenance and~~

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

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

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

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

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~~Power~~

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

September 30, September 30,
2016 2015
2016 vs. 2015 2016 2015 2016 vs. 2015
Millions Millions % Millions Millions %
Operating Revenues $ 1,075
$ 1,096
$ (21 ) (2 ) $ 3,102
$ 3,846
$ (744 ) (19 )
Energy Costs 462
367
95
26
1,481
1,669
(188 ) (11 )
Operation and Maintenance 289
263
26
10
807
748
59
8

Depreciation and Amortization 86
75
11
15
245
226
19
8

Income from Equity Method Investments 3
3
—
—
9
11
(2 ) (18 )
Other Income (Deductions) 17
11
6
55
41
77
(36 ) (47 )
Other-Than-Temporary Impairments 5
30
(25 ) (83 ) 25
45
(20 ) (44 )
Interest Expense 24
30
(6 ) (20 ) 66
94
(28 ) (30 )
Income Tax Expense 90
139
(49 ) (35 ) 208
445
(237 ) (53 )

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

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

Generation Revenues decreased ~~$23~~$124 million due primarily to

a net decrease of ~~$73~~$95 million in energy sales ~~volumes~~in the PJM and New England (NE) regions due primarily to lower average realized prices, ~~primarily in the PJM region,~~ and

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

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

partially offset by a net increase of ~~$44~~$10 million indue primarily to higher volumes of electricity sold under ~~non-BGS~~ wholesale load contracts in the ~~PJM and~~ NE ~~regions due to higher volumes sold~~region partially offset by lower average ~~prices, and~~prices.

Gas Supply Revenuesincreased $95 million due primarily to

an increase of ~~$24~~$46 million in ~~electricity sold~~sales under ~~our BGS contracts~~the BGSS contract due primarily to higher ~~volumes as a result of warmer weather,~~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 ~~prices.~~sales prices, and

a net increase of $8 million due to higher 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.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased ~~$95~~$69 million due to

Generation costs decreased $1 million due primarily to

~~Generation costs~~ ~~increased $93~~a net decrease of $26 million primarily due to lower congestion costs in PJM due to lower congestion rates and volumes,

~~a $62~~partially offset by higher fuel costs of $14 million ~~charge associated~~reflecting higher average realized prices for natural gas coupled with the ~~announced early retirement~~utilization of higher volumes of coal, partially offset by the ~~coal/~~utilization of lower volumes of gas ~~Mercer~~ and ~~Hudson generation units, primarily related to a coal inventory write-down of $57 million,~~oil,

an increase of ~~$32~~$8 million in energy purchase volumes in the NE region to serve load obligations, and

a $7 million charge associated primarily with a lower of cost or market coal inventory adjustment at Mercer.

Gas costsincreased $70 million due mainly to

an increase of $39 million related to ~~MTM losses in 2016 as compared~~sales to ~~MTM gains in 2015. Of this amount, $25 million was~~third parties due to ~~lower gains on positions reclassified to realized upon settlement this year compared to last year,~~higher average gas costs, and

an increase of ~~$13~~$31 million ~~due~~related to ~~increases in purchases of renewable energy credits and energy to serve load contracts,~~

~~partially offset by a decrease of $20 million~~sales under the BGSS contract due primarily to ~~lower natural~~higher average gas costs ~~reflecting lower average realized prices.~~and an increase in volumes sold due to periods of colder weather in March.

Operation and Maintenance ~~increased $26~~decreased $23 million due primarily to

a $15 million decrease related to our nuclear plants due primarily to lower labor-related costs, and

a $7 million legal reserve for environmental expenses recorded in 2016.

Depreciation and Amortization increased$48571 milliondue primarily to

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

~~partially offset by a net decrease~~$4 million of ~~$18 million~~greater depreciation due to the ~~timing of a planned outage~~accelerated retirement date at ~~our 50%-owned Peach Bottom nuclear plant.~~

~~Table of Contents~~

~~Depreciation and Amortization~~ ~~increased $11 million due primarily to~~Bridgeport Harbor 3,

a $7$4 million increase due ~~primarily~~ to a higher nuclear asset base, ~~and~~

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

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

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

~~Interest Expense~~ ~~decreased $6 million due primarily to higher capitalized interest in 2016.~~

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

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

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

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

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

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

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

~~a net decrease of $10 million in electricity sold under our BGS contracts due primarily to lower volumes as a result of milder weather, partially offset by higher average prices.~~

~~Gas Supply Revenuesdecreased~~ ~~$248 million due primarily to~~

a decrease of $241 million in sales under the BGSS contract, substantially comprised of lower sales volumes due to warmer average temperatures in the 2016 winter heating season, coupled with lower average sales prices, and

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

~~Operating Expenses~~

~~Energy Costs~~ represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs ~~decreased$188 million~~ ~~due to~~

~~Generation costsdecreased~~ ~~$67 million due primarily to~~

~~lower fuel costs of $287 million reflecting lower average realized prices for natural gas and the utilization of lower volumes of fuel,~~

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

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

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

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~~Gas costsdecreased~~ ~~$121 million mainly related to~~

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

~~partially offset by a net increase of $21 million related to sales to third parties due primarily to an increase in volumes sold.~~

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

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

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

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

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

~~Depreciation and Amortization~~ ~~increased$19 milliondue primarily to~~

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

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

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

Other Income (Deductions) ~~decreased $36~~increased $23 million due primarily to ~~$28~~$17 million of ~~insurance recoveries received in 2015 related to Superstorm Sandy and~~ lower net realized ~~gains~~losses from the NDT Fund in ~~2016.~~2017 and $3 million of higher realized gains in the Rabbi Trust Fund.

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Other-Than-Temporary Impairments decreased ~~$20~~$9 million due to lower impairments of equity securities in the NDT Fund in ~~2016.~~2017.

Interest Expense decreased ~~$28~~$6 million due primarily to higher interest capitalized ~~interest in 2016~~for the construction of three new fossil stations: BH5, Sewaren 7 and ~~the maturity of $300 million of 5.50% Senior Notes in December 2015, partially offset by the issuance of $700 million of 3.00% Senior Notes in June 2016.~~Keys.

Income Tax Expense decreased ~~$237~~$245 million in ~~2016~~2017 due primarily to ~~lower~~a pre-tax ~~income.~~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 ~~planned~~ capital expenditures and shareholder dividend payments.

For the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017, our operating cash flow decreased $~~467~~18 million as compared to the same period in ~~2015.~~2016. The net change was primarily due ~~primarily~~ to the net changes from PSE&G and Power as discussed ~~below.~~below largely offset by higher tax refunds in 2017 at Energy Holdings.

PSE&G

PSE&G’s operating cash flow decreased $~~117~~54 million from $~~1,518~~568 million to $~~1,401~~514 million for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017, as compared to the same period in ~~2015~~2016, due primarily to ~~a decrease~~lower tax refunds, partially offset by higher earnings, and an increase of ~~$113~~$45 million due to a change in regulatory deferrals, a $64 million decrease due to higher vendor payments and a decrease due to the completion of securitization collections in 2015. These amounts were partially offset by higher earnings and higher tax refunds in 2016.deferrals.

Power

Power’s operating cash flow decreased $~~298~~83 million from $~~1,558~~663 million to $~~1,260~~580 million for the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2017, as compared to the same period in ~~2015,~~2016, primarily due to tax payments in 2017 as compared to tax refunds in 2016 and lower earnings, partially offset by a ~~$140~~$65 million ~~decrease~~increase from net collection of counterparty receivables and a $12 million increase from fuels, materials and ~~supplies, and a $146 million increase in margin deposit requirements, partially offset by a reduction in tax payments.~~supplies.

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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.

Our total credit facilities and available liquidity as of ~~September 30, 2016~~March 31, 2017 were as follows:

Company/Facility As of September 30, 2016

Total
Facility
Usage
Available
Liquidity

Millions
PSEG $ 1,000
$ 265
$ 735

PSE&G 600
14
586

Power 2,553
205
2,348

Total $ 4,153
$ 484
$ 3,669




Company/Facility	As of March 31, 2017
Company/Facility	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

As of ~~September 30, 2016,~~March 31, 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 ~~and~~or Moody’s ratings. In the event of a deterioration of Power’s credit rating certain of Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if Power were to lose its investment grade credit rating was approximately ~~$807~~$801 million and ~~$864~~$783 million as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015,~~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.

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

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

Long-Term Debt Financing

~~For~~PSEG Parent has a ~~discussion of our long-term debt transactions during 2016, see Item 1. Note 10. Debt and Credit Facilities.~~floating rate $500 million term loan maturing in November 2017.

Common Stock Dividends

On ~~July 19, 2016,~~February 21, 2017, our Board of Directors approved a ~~quarterly~~$0.43 dividend ~~of $0.41~~ per share of common stock for the ~~third~~first quarter of ~~2016.~~2017. On April 18, 2017, our Board of Directors declared a $0.43 dividend per share of common stock for the second quarter of 2017. This reflects an indicative annual dividend rate of ~~$1.64~~$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. ~~Note 16.~~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 ~~January 2016,~~April 2017, S&P published updated research ~~reports on~~and affirmed the ratings and outlooks of PSEG and PSE~~&G and the existing ratings and outlooks were unchanged. In June 2016, Moody’s published credit opinions on Power and PSE&G and the existing ratings and outlooks were~~

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




	Moody’s (A)	S&P (B)
PSEG
Outlook	Positive	Stable
Senior Notes	Baa2	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. ~~The Corporate Credit Rating outlook does not apply to PSEG’s or PSE&G’s Commercial Paper Rating or PSE&G’s Mortgage Bond rating.~~

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CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures at PSE&G, Power and Services as compared to amounts disclosed in our ~~2015~~2016 Form 10-K.

~~PSEG~~

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

PSE&G

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

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

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

During the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2017, PSE&G made capital expenditures of ~~$2,035~~$752 million, primarily for transmission and distribution system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$109~~$24 million, which are included in operating cash flows.

Power

During the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2017, Power made capital expenditures of ~~$767~~$274 million, excluding $~~156~~33 million for nuclear fuel, primarily related to our Keys, Sewaren 7, BH5 and other generation projects.

ACCOUNTING MATTERS

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


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Contracts

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

Value-at-Risk (VaR) Models

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

MTM VaR consists of MTM derivatives that are economic ~~hedges, some of which qualify for hedge accounting.~~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 ~~July~~January through ~~September 2016,~~March 2017, MTM VaR remained relatively stable between a low of ~~$11~~$7 million toand a high of ~~$16~~$25 million at the 95% confidence level. The range of VaR was narrower for the three months ended ~~September 30, 2016~~March 31, 2017 as compared with the year ended December 31, ~~2015.~~2016.

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MTM VaR
Three Months Ended September 30, 2016 Year Ended December 31, 2015
Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End $ 11
$ 24

Average for the Period $ 13
$ 17

High $ 16
$ 40

Low $ 11
$ 8

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 17
$ 38

Average for the Period $ 21
$ 26

High $ 25
$ 63

Low $ 17
$ 12




	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

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

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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 ~~Public Service Enterprise Group Incorporated, Public Service Electric~~PSEG, PSE&G and ~~Gas Company and PSEG Power LLC.~~Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of ~~Public Service Enterprise Group Incorporated, Public Service Electric~~PSEG, PSE&G and ~~Gas Company and PSEG~~ Power ~~LLC~~ have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

PSEG, PSE&G and Power

There have been no changes in internal control over financial reporting that occurred during the ~~third~~first quarter of ~~2016~~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 ~~2015~~2016 Annual Report on Form 10-K, see Part I, Item 1. Note 9. Commitments and Contingent Liabilities and Item 5. Other Information.

~~Ewing Explosion~~

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

Twenty-two lawsuits have been filed to date relating to the gas explosion, of which PSE&G was named as a defendant in nineteen cases. To date, six of these cases have resolved through private negotiations and/or mediation. In one of the remaining pending matters, plaintiffs representing the estate of the decedent are seeking damages under the New Jersey Wrongful Death Act and the New Jersey Survivors Act as well as punitive damages. PSE&G has denied all allegations of liability. We intend to continue to vigorously defend these lawsuits. At this stage of the litigation, we are unable to determine or predict the ultimate outcome of any of the remaining lawsuits.


ITEM 1A.	RISK FACTORS

~~There are no additional Risk Factors to~~The discussion of our business and operations in this Quarterly Report on Form 10-Q should be ~~added to those disclosed~~read together with the risk factors contained in Part I, Item 1A of our ~~2015~~2016 Annual Report on Form ~~10-K.~~10-K, which describe various risks and uncertainties that could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report. Except as follows, there have been no material changes to the risk factors set forth in the above-referenced filing as of March 31, 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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ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the ~~third~~first quarter of ~~2016~~2017.

Three Months Ended September 30, 2016
Total Number
of Shares
Purchased

Average
Price Paid
per Share

July 1 - July 31 —
$ —

August 1 - August 31 167,430
$ 45.21

September 1- September 30 43,000
$ 42.85




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

ITEM 5. OTHER INFORMATION

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

Federal Regulation

FERC

Capacity Market ~~Issues-PJM~~Issues

December 31, ~~2015~~2016 Form 10-K page ~~17, March 31, 2016 Form 10-Q page 70~~16. PJM, NYISO and ~~June 30, 2016 Form 10-Q page 80.~~ ~~Over the past several years, certain entities in PJM, namely, FirstEnergy Corp. (FE) and American Electric Power (AEP)~~ISO-NE each have capacity markets that have been ~~looking~~approved by FERC. FERC regulates these markets and continues to examine whether the ~~Ohio Public Utility Commission (PUCO) to provide financial~~market design for each of these three capacity markets is working optimally. Issues presented in various forums include consideration of whether the competitive market framework can be reconciled with state public policies that support arrangements for their coal plants and a nuclear plant (FE). FE and AEP originally proposed to enter into power purchase agreements (PPAs) with their non-utility generation affiliates providing for above-market purchases from certain coal plants and a nuclear plant (in FE's case). The PUCO Staff proposed a payment to support modernization of the distribution system (distribution modernization rider) in the FE case which was ultimately accepted by the PUCO. The Dayton Power and Light Company also recently filed for a distribution modernization rider for the generating plants that it owns.

~~The PUCO proceedings created a concern that subsidized units within the PJM footprint would submit bids~~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. 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. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. However, aspects of FERC’s order are currently pending appeal in the 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 ~~reflective~~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 and contains incentive mechanisms to encourage availability during stressed system conditions. ISO-NE also employs a mechanism, similar to PJM’s CP mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance. One aspect of the current market design that we do not support and are currently challenging in the D.C. Circuit is the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources.

Price Formation Initiatives

December 31, 2016 Form 10-K page 18. Power has been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for setting prices for energy in the day-ahead and real-time markets administered by PJM and other system operators. FERC recently issued a notice of proposed rulemaking (NOPR) proposing that RTOs/ISOs modify their ~~actual~~rules governing fast-start resources. Fast-start resources typically are committed in real-time, very

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close to the interval when needed and can respond quickly to unforeseen system needs. However, without fast-start pricing, some fast-start resources are ineligible to set prices due to inflexible operating ~~costs and would, in turn, artificially suppress capacity prices.~~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 ~~parties requested~~circumstances. FERC has accepted PJM’s proposal which will become effective on November 1, 2017. We believe that ~~FERC should direct PJM to expand~~both changes will improve price formation in the ~~“minimum offer price rule” to apply to existing units.~~

~~We are unable to predict the results of these pending proceedings or any future related proceedings or to calculate the potential impacts on our business.~~

~~Transmission Regulation~~

~~December 31, 2015 Form 10-K page 19~~energy and ~~June 30, 2016 Form 10-Q page 80.~~ ~~In October 2016,~~PSE&G filed its 2017 Annual Formula Rate Update with FERC which requests approximately $121 million in increased annual transmission revenues effective January 1, 2017, subject to true-up. For additional information about our transmission formula rate, see Part 1, Item 1. Financial Information—Note 5. Recent Rate Filings.ancillary services markets.

Transmission Regulation—Transmission Policy Developments

December 31, ~~2015~~2016 Form 10-K page ~~19, March 31, 2016 Form 10-Q page 71 and June 30, 2016 Form 10-Q page 80.~~18. FERC concluded in Order 1000 that the incumbent transmission owner should not always have a Right of First Refusal (ROFR) to construct and own transmission projects in its service territory. We and other companies appealed various aspects of the FERC order approving PJM’s implementation of Order 1000, including the elimination of the ROFR from the PJM Tariff. In ~~July 2016, the D.C. Court dismissed the case, thus upholding FERC’s determination. We have decided not to pursue further action on this decision.~~

~~In April 2016, PSE&G accepted construction responsibility for the three components of the transmission project involving upgrades at Artificial Island in New Jersey. On~~ August 5, 2016, PJM announced that it ~~has~~had suspended the Artificial Island transmission project and iswould be performing a comprehensive analysis to ~~determine~~support a future course of ~~action, which~~action. In March 2017, PJM staff made its final recommendation to the PJM Board with respect to the project. Under the recommended project, PSE&G will construct necessary upgrade work in Hope Creek, at a cost of approximately $130 million. In April 2017, the PJM Board announced that it would be lifting the suspension and approved the staff recommended project. The PJM Board also stated that it would be analyzing project beneficiaries from an alternate perspective to potentially devise an alternative cost allocation methodology for stability projects.

Transmission Regulation—Con Edison Wheeling Agreement

December 31, 2016 Form 10-K page 19. In April 2016, Con Edison informed PJM that it would allow its Wheeling Agreement to expire effective as of May 1, 2017. The Wheeling Agreement enables Con Edison 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 associated with the affected transmission lines. FERC accepted the proposal, subject to refund, effective May 1, 2017. We cannot predict the impact of the proposal on energy prices or transmission planning at this time. Both PSE&G and the BPU protested certain aspects 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 costs associated with the new arrangement through its formula rate. We cannot predict the outcome of this proceeding.

State Regulation

Energy Efficiency Program (Energy Efficiency 2017)

In March 2017, we filed a petition with the BPU for our Energy Efficiency 2017 program, requesting extension of three Energy Efficiency Economic sub-programs (multi-family, direct install and hospital efficiency) and the addition of two new sub-programs (smart thermostat and residential data analytics). The petition requested additional capital expenditures of approximately $74 million, additional administrative and other costs of $22 million and information technology system enhancement costs of $3 million. We proposed to recover our investment in these sub-programs under the same clause recovery process as currently approved. This matter is pending.

Environmental Matters

Climate Change

CO₂ Regulation 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, 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 completion of the review, the EPA is expected to ~~be completed by February 2017.~~ suspend, revise or rescind the rules as appropriate. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

Water Pollution Control

Steam Electric Effluent Guidelines

December 31, 2016 Form 10-K page 23. 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. 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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~~In August 2016, FERC issued an order to PJM~~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 PJM Transmission Owners with respect to their compliance with a previous FERC order (Order 890) that requires transparency in the transmission planning process. The order directs PJM and PJM Transmission Owners to propose revisions to the PJM governing documents to ensure compliance with Order 890 or show cause why they should not do so. The PJM Transmission Owners jointly filed for rehearing of the order to show cause and jointly responded to FERC’s directives. FERCrule. Power is also evaluating issues related to competitive transmission development processes, including the use of cost containment provisions. PSE&G has argued against the use of cost caps in the assessment of Order 1000 open window project bids. We are unable to predict atif this ~~time the~~rule will have a material impact on its future capital requirements, financial condition and results of ~~these proceedings~~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 an administrative stay of the compliance dates in the rule that have not yet passed pending judicial review. The deadlines that are expected to be stayed include the BAT limitations and pretreatment standards for each of the following waste streams: fly ash transport water, bottom ash transport water, flue gas desulfurization wastewater, flue gas mercury control wastewater, and gasification wastewater. Power is unable to determine how this will ultimately impact ~~they will~~compliance requirements or the financial impact it may have on ~~our business.~~the company.

~~State Regulation~~

~~Solar 4 All Program Extension II~~

~~On October 20, 2016, PSE&G submitted a settlement agreement to the BPU providing for an extension~~Waters of the existing landfill/brownfield solar program to construct up to 33 MW of grid connected facilities with projected capital expenditures of approximately $80 million through May 2020. This matter is pending approval by the BPU.

~~Environmental Matters~~

~~Air Pollution Control~~

~~Cross-State Air Pollution Rule (CSAPR)~~ United States

December 31, ~~2015~~2016 Form 10-K page 24.In ~~September 2016,~~April 2014, the EPA Administrator and the Assistant Secretary of the Army (Civil Works) jointly published a proposed rule to clarify the definition of waters of the United States under the CWA programs in order to protect the streams and wetlands that form the foundation of the nation’s water resources. This definition will have broad application to all areas of compliance under the CWA, including permitted discharges and construction activities. The final rule was published in June 2015 and various states, industry coalitions and environmental organizations have initiated legal action related to the provisions of the final ~~CSAPR Updating Rule~~rule as well as which court has jurisdiction over the rule. The U.S. Supreme Court is expected to ~~address~~rule on the ~~2008 National Ambient Air Quality Standards for ground-level ozone. The rule establishes more stringent annual ozone season (May 1 through September 30) caps beginning in May~~question of jurisdiction by June 2017. WeSome states, including New Jersey, are subject to state requirements beyond thoseimposed under federal law. While we do not anticipate ~~any~~ material impacts to projects in New Jersey, the new definition could impose requirements in other states and regions that could impact ~~on our business or financial condition due~~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 to the ~~CSAPR.~~NJDEP a sixty-day notice of intent to sue alleging the agency has caused violations of the Endangered Species Act by allowing our Mercer generation station to operate in a manner which has caused the mortality of certain species of sturgeon. Among other things, the notice requested the NJDEP to prioritize completion of a 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 on

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

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

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

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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: ~~October 31, 2016~~April 28, 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: ~~October 31, 2016~~April 28, 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: ~~October 31, 2016~~April 28, 2017

8982



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	1819
	Note 4. Variable Interest ~~Entities (VIEs)~~Entity (VIE)	1920
	Note 5. Rate Filings	2021
	Note 6. Financing Receivables	21
	Note 7. Available-for-Sale Securities	23
	Note 8. Pension and Other Postretirement Benefits (OPEB)	2829
	Note 9. Commitments and Contingent Liabilities	30
	Note 10. Debt and Credit Facilities	3738
	Note 11. Financial Risk Management Activities	39
	Note 12. Fair Value Measurements	4544
	Note 13. Other Income and Deductions	5351
	Note 14. Income Taxes	5452
	Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax	5553
	Note 16. Earnings Per Share (EPS) and Dividends	5956
	Note 17. Financial Information by Business Segments	6057
	Note 18. Related-Party Transactions	6157
	Note 19. Guarantees of Debt	6359
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6661
	Executive Overview of ~~2016~~2017 and Future Outlook	6661
	Results of Operations	7467
	Liquidity and Capital Resources	7971
	Capital Requirements	8173
	Accounting Matters	8273
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	8273
Item 4.	Controls and Procedures	8374

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	8374
Item 1A.	Risk Factors	8374
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	8476
Item 5.	Other Information	8476
Item 6.	Exhibits	8679
	Signatures	8780




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




	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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
OPERATING REVENUES	$	2,450		$	2,688		$	6,971		$	8,137
OPERATING EXPENSES
Energy Costs	866			815			2,326			2,577
Operation and Maintenance	776			746			2,215			2,170
Depreciation and Amortization	231			313			679			960
Total Operating Expenses	1,873			1,874			5,220			5,707
OPERATING INCOME	577			814			1,751			2,430
Income from Equity Method Investments	3			3			9			10
Other Income	47			47			139			171
Other Deductions	(8		)	(14		)	(39		)	(36		)
Other-Than-Temporary Impairments	(5		)	(30		)	(25		)	(45		)
Interest Expense	(99		)	(96		)	(288		)	(291		)
INCOME BEFORE INCOME TAXES	515			724			1,547			2,239
Income Tax Expense	(188		)	(285		)	(562		)	(869		)
NET INCOME	$	327		$	439		$	985		$	1,370
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	505			505			505			505
DILUTED	508			508			508			508
NET INCOME PER SHARE:
BASIC	$	0.65		$	0.87		$	1.95		$	2.71
DILUTED	$	0.64		$	0.87		$	1.94		$	2.70
DIVIDENDS PAID PER SHARE OF COMMON STOCK	$	0.41		$	0.39		$	1.23		$	1.17




	September 30, 2016			December 31, 2015
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	—		$	734
Commercial Paper and Loans	255			364
Accounts Payable	1,363			1,369
Derivative Contracts	40			76
Accrued Interest	127			96
Accrued Taxes	214			42
Clean Energy Program	185			142
Obligation to Return Cash Collateral	132			128
Regulatory Liabilities	96			123
Regulatory Liabilities of VIEs	9			42
Other	383			459
Total Current Liabilities	2,804			3,575
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,661			8,166
Regulatory Liabilities	151			175
Asset Retirement Obligations	708			679
OPEB Costs	1,207			1,228
OPEB Costs of Servco	395			375
Accrued Pension Costs	400			487
Accrued Pension Costs of Servco	108			114
Environmental Costs	430			415
Derivative Contracts	13			27
Long-Term Accrued Taxes	197			212
Other	241			181
Total Noncurrent Liabilities	12,511			12,059
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	10,697			8,834
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2016 and 2015—534 shares	4,928			4,915
Treasury Stock, at cost, 2016—29 shares; 2015—28 shares	(714		)	(671		)
Retained Earnings	9,480			9,117
Accumulated Other Comprehensive Loss	(218		)	(295		)
Total Common Stockholders’ Equity	13,476			13,066
Noncontrolling Interest	—			1
Total Stockholders’ Equity	13,476			13,067
Total Capitalization	24,173			21,901
TOTAL LIABILITIES AND CAPITALIZATION	$	39,488		$	37,535




	September 30, 2016			December 31, 2015
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	—		$	553
Accounts Payable	477			432
Accounts Payable—Affiliated Companies	156			33
Derivative Contracts	36			76
Accrued Interest	43			25
Other	82			107
Total Current Liabilities	794			1,226
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	2,375			2,347
Asset Retirement Obligations	485			457
OPEB Costs	238			230
Derivative Contracts	13			16
Accrued Pension Costs	143			166
Long-Term Accrued Taxes	79			35
Other	162			87
Total Noncurrent Liabilities	3,495			3,338
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
LONG-TERM DEBT	2,381			1,684
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	5,084			5,014
Accumulated Other Comprehensive Loss	(172		)	(240		)
Total Member’s Equity	6,140			6,002
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	12,810		$	12,250




	Three Months Ended September 30,
	2016
	Millions
Statement of Operations Expense (pre-tax)
Energy Costs
Coal Inventory Lower of Cost or Market Adjustments and Capacity Penalties	$	62
Operation and Maintenance
Materials and Supplies Obsolescence	31
Write-down of Construction Work in Progress	14
Other (A)	3
Depreciation and Amortization
Accelerated Depreciation including Asset Retirement Costs	4
Total Pre-Tax Expense	$	114




	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		%


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




Outstanding Loans by Class of Customer
	As of		As of
Consumer Loans	September 30, 2016		December 31, 2015
	Millions
Commercial/Industrial	$	165	$	177
Residential	11		12
Total	$	176	$	189




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor’s (S&P) as of September 30, 2016
	As of September 30, 2016
	Millions
AA	$	16
BBB+ — BBB-	316
BB-	134
CCC	164
Total	$	630




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


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




	As of September 30, 2016
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	691	$	238	$	(7	)	$	922
Debt Securities
Government Obligations	509		21		—			530
Other	349		13		(2		)	360
Total Debt Securities	858		34		(2		)	890
Other Securities	45		—		—			45
Total NDT Available-for-Sale Securities	$	1,594	$	272	$	(9	)	$	1,857




	As of December 31, 2015
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities	$	693	$	185	$	(13	)	$	865
Debt Securities
Government Obligations	483		8		(3		)	488
Other	366		3		(10		)	359
Total Debt Securities	849		11		(13		)	847
Other Securities	42		—		—			42
Total NDT Available-for-Sale Securities	$	1,584	$	196	$	(26	)	$	1,754




	As of September 30, 2016										As of December 31, 2015
	Less Than 12 Months					Greater Than 12 Months					Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)	$	101	$	(6	)	$	4	$	(1	)	$	151	$	(13	)	$	1	$	—
Debt Securities
Government Obligations (B)	41		—			4		—			245		(2		)	19		(1		)
Other (C)	34		—			25		(2		)	222		(7		)	36		(3		)
Total Debt Securities	75		—			29		(2		)	467		(9		)	55		(4		)
NDT Available-for-Sale Securities	$	176	$	(6	)	$	33	$	(3	)	$	618	$	(22	)	$	56	$	(4	)


(A)	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of ~~September 30, 2016.~~March 31, 2017.


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




Time Frame	Fair Value
	Millions
Less than one year	$	22
1 - 5 years	233
6 - 10 years	214
11 - 15 years	56
16 - 20 years	62
Over 20 years	303
Total NDT Available-for-Sale Debt Securities	$	890




	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,
	2016			2015			2016			2015			2016			2015			2016			2015
	Millions
Components of Net Periodic Benefit Costs
Service Cost	$	28		$	30		$	5		$	5		$	82		$	92		$	13		$	16
Interest Cost	50			59			15			16			151			176			44			50
Expected Return on Plan Assets	(98		)	(103		)	(8		)	(7		)	(295		)	(310		)	(23		)	(22		)
Amortization of Net
Prior Service Cost (Credit)	(5		)	(5		)	(4		)	(4		)	(14		)	(14		)	(11		)	(11		)
Actuarial Loss	39			38			10			11			118			112			30			32
Total Benefit Costs	$	14		$	19		$	18		$	21		$	42		$	56		$	53		$	65




	Auction Year
	2013	2014	2015	2016
36-Month Terms Ending	May 2016	May 2017	May 2018	May 2019	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$92.18	$97.39	$99.54	$96.38




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




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




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion)				Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)	Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	Three Months Ended					Three Months Ended					Three Months Ended
	September 30,					September 30,					September 30,
	2016		2015			2016		2015			2016		2015
	Millions
PSEG
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Interest Rate Swaps	1		—		Interest Expense	—		—		Interest Expense	—		—
Total PSEG	$	1	$	1		$	—	$	—		$	—	$	—
Power
Energy-Related Contracts	$	—	$	1	Operating Revenues	$	—	$	—	Operating Revenues	$	—	$	—
Total Power	$	—	$	1		$	—	$	—		$	—	$	—




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

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




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

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




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




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

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




	MTM VaR
	Three Months Ended September 30, 2016		Year Ended December 31, 2015
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	11	$	24
Average for the Period	$	13	$	17
High	$	16	$	40
Low	$	11	$	8
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	17	$	38
Average for the Period	$	21	$	26
High	$	25	$	63
Low	$	17	$	12