Commitments and Contingent Liabilities

12 Months Ended

Dec. 31, 2013

Commitments and Contingent Liabilities

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.

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.

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 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. This 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.

The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2013 and 2012 are shown below:

	As of December 31, 2013		As of December 31, 2012
	Millions
Face Value of Outstanding Guarantees	$	1,639	$	1,508
Exposure under Current Guarantees	$	246	$	226
Letters of Credit Margin Posted	$	132	$	124
Letters of Credit Margin Received	$	25	$	69
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	—	$	15
Counterparty Cash Margin Received	$	—	$	(4	)
Net Broker Balance Deposited (Received)	$	80	$	26
In the Event Power were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	691	$	654
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,522	$	3,531
Additional Amounts Posted
Other Letters of Credit	$	45	$	45

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. 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 the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

The SEC and the Commodity Futures Trading Commission (CFTC) continue efforts to implement new rules to effect stricter regulation over swaps and derivatives, including imposing reporting and record-keeping requirements. In August 2013, PSEG began reporting its swap transactions to a CFTC-approved swap data repository. PSEG continues to monitor developments in this area, as the CFTC considers additional requirements such as a new position limits rule for energy commodity swaps.

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 table above.

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 below.

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

The EPA has determined that a 17-mile stretch of the Passaic River from Newark to Clifton, New Jersey is a “Super Fund” 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 has determined the 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.

Seventy-three Potentially Responsible Parties (PRPs), including Power and PSE&G, agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently 67 members, is presently conducting the RI/FS. Approximately seven percent of the RI/FS costs are currently attributable to PSE&G’s former MGP sites and approximately one percentto Power’s generating stations. Power has provided notice to insurers concerning this potential claim. The RI/FS is expected to be completed by the end of 2014 at an estimated cost of approximately $125 million.

In 2007, the EPA released a draft “Focused Feasibility Study” (FFS) that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The EPA estimated costs for the proposed remedy ranged from $1.3 billion to $3.7 billion. The work contemplated by the draft FFS is not subject to the cost sharing agreement discussed above. The EPA's revised proposed FFS is scheduled to be released for public comment in the first quarter of 2014.

In June 2008, an agreement was announced between the EPA and Tierra Solutions, Inc. and Maxus Energy Corporation (Tierra/Maxus) for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. Phase I of the removal work has been completed. Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

At the EPA's direction, the CPG, with the exception of Tierra and Maxus, which are no longer members, has commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. PSEG’s share of the cost of that effort is approximately three percent.

Except for the Passaic River 10.9 mile removal, Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to the Passaic River matters.

New Jersey Spill Compensation and Control Act (Spill Act)

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of a certain PRP’s discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. In 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances it allegedly discharged into the Passaic River and the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed to a total of 11 sites or facilities that impacted these water bodies. The third party complaints sought statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. In December 2013, the Court approved a settlement of the entire third party action. Power and PSE&G's contributions to the settlement, either individually or in the aggregate, were immaterial.

Natural Resource Damage Claims

In 2003, the 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 Spill 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 United States Department of Commerce and the United States 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 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 is unable to estimate its portion 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. Power and PSE&G are unable to estimate their portion 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 $445 million and $521 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $445 million as of December 31, 2013. Of this amount, $92 million was recorded in Other Current Liabilities and $353 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $445 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.

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.

Hazardous Air Pollutants Regulation

In accordance with a ruling of the U.S. Court of Appeals of the District of Columbia (D.C. Court), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the D.C. Court in support of the EPA's implementation of MATS. Oral arguments were held in December 2013. A final decision remains pending and the impact on the implementation schedule is unknown at this time.

Power believes that it will not be necessary to install any material controls at its New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulations, the co-owners group, including Power, agreed to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal-fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. Power's share of this investment is approximately $110 million.

NO_x Regulation

In 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 30, 2015. Retirement notifications for the combustion turbines have been submitted to PJM. PJM was notified that the Salem Unit 3 combustion turbine will no longer be available as a capacity resource and will be transitioned to an emergency generator for site use only. Based upon Power’s recently-completed evaluations of its steam electric generation units, a minimal investment will be required to consistently reduce NO_x emissions below required limits beginning on May 1, 2015.  

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System (NPDES) 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 New Jersey Department of Environmental Protection 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.

One of the most significant NJPDES permits governing cooling water intake structures at Power is for Salem. In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued.

In April 2011, the EPA published a proposed rule to establish marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. The EPA is currently scheduled to issue a final rule on April 17, 2014.

Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition, results of operations or cash flows. The results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

On October 1, 2013, the Delaware Riverkeeper Network and several other environmental groups filed a lawsuit in the Superior Court in New Jersey seeking to compel the NJDEP to take action on Power's pending application for permit renewal at Salem either by denying the application or issuing a draft for public comments. At the NJDEP's request, the case was transferred to the Appellate Division on December 16, 2013. Power is unable to predict the outcome of this proceeding.

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

PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. 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 Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

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 contracted for its anticipated BGS-Fixed Price eligible load, as follows:

	Auction Year
	2011	2012	2013	2014
36-Month Terms Ending	May 2014	May 2015	May 2016	May 2017	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per kWh	0.09430	0.08388	0.09218	0.09739

(A) Prices set in the 2014 BGS auction will become effective on June 1, 2014 when the 2011 BGS auction agreements expire.

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 24. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations and for supply of nuclear fuel for the Salem, Hope Creek and Peach Bottom nuclear generating stations and for firm transportation and storage capacity for natural gas.

Power’s 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 2015 and a portion through 2018 at Salem, Hope Creek and Peach Bottom.

Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.

As of December 31, 2013, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Power's Share of Commitments through 2018
	Millions
Nuclear Fuel
Uranium	$	532
Enrichment	$	454
Fabrication	$	137
Natural Gas	$	1,061
Coal	$	405

Regulatory Proceedings

New Jersey Clean Energy Program

In June 2013, the BPU established the funding level for fiscal 2014 applicable to its Renewable Energy and Energy Efficiency programs. The fiscal year 2014 aggregate funding for all EDCs is $345 million with PSE&G’s share of the funding at $200 million. PSE&G has a remaining current liability of $142 million as of December 31, 2013 for its outstanding share of the fiscal 2014 and remaining fiscal 2013 funding. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

Long-Term Capacity Agreement Pilot Program (LCAPP)

In 2011, New Jersey enacted the LCAPP Act that resulted in the selection of three generators to build a total of approximately 2,000 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the selected generators, providing for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement, but did so under protest preserving their legal rights. The SOCA contracts, which had a 15-year term, were for the aggregate notional amount of approximately 1,300 MW of installed capacity. PSE&G was to have been responsible for the positive difference of the contract price and the annual RPM clearing price for approximately 52% or 676 MW of this amount, assuming generator satisfaction of its contractual obligations.

In July 2013, one of the SOCA contracts was terminated early as a result of a default by the generator. In November 2013, as a result of a federal court decision finding (i) the LCAPP Act to be unconstitutional and (ii) the SOCA contracts to be void, invalid and unenforceable, and a subsequent decision denying a request to stay this decision pending appeal, PSE&G terminated the other two SOCA contracts by providing written notice to both counterparties. The SOCA generators have appealed the federal court decision and this appeal remains pending.

As a result of the federal court's decision and PSE&G's subsequent termination of the contracts, the estimated fair value of the SOCAs that had been recorded as a Derivative Asset or Liability with an offsetting Regulatory Asset or Liability on PSE&G’s Consolidated Balance Sheets were removed in the fourth quarter of 2013. See Note 17. Fair Value Measurements for additional information.

Superstorm Sandy

In late October 2012, Superstorm Sandy caused severe damage to PSE&G's transmission and distribution system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds and the resulting storm surge caused damage to switching stations, substations and generating infrastructure.

As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its infrastructure and return it to pre-storm conditions. Of the costs incurred, approximately $40 million was recognized in Operation and Maintenance (O&M) Expense, $75 million was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. PSE&G recognized $6 million of insurance proceeds. There were no significantchanges to these amounts in 2013. PSE&G made a filing with the BPU to review the prudency of unreimbursed incremental storm restoration costs, including O&M and capital expenditures associated with certain extreme weather events, for recovery in our next base rate case or sooner through a BPU-approved cost recovery mechanism. The BPU is currently conducting a review regarding the amount, prudency, cost effectiveness and cost efficiency of PSE&G's unreimbursed incremental storm restoration costs for extreme weather events from 2010-2012.

Power incurred $79 million of storm-related expense for the year ended December 31, 2013 primarily for repairs at certain generating stations in Power's fossil fleet. Power had incurred $85 million of costs in 2012. These costs were recognized in O&M Expense, offset by $25 million and $19 million of insurance recoveries in the second quarter of 2013 and the fourth quarter of 2012, respectively.

PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. PSEG is seeking recovery from its insurers for the property damage, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. PSEG has recorded proceeds of $50 million from its insurance carriers as advance payments, $25 million of which was recognized in 2013 and $25 million was recognized in 2012. PSEG does not believe that it has a basis for estimating additional probable insurance recoveries at this time. In June 2013, PSEG, Power and PSE&G filed suit in New Jersey state court against the insurance carriers seeking legal interpretation of certain terms in the insurance policies regarding losses resulting from damage caused by Superstorm Sandy's storm surge. The dispute concerns whether certain sub-limits in the policies apply to damage to property caused by Superstorm Sandy's storm surge. In that lawsuit, PSEG stated that its estimate of the total costs required to restore damaged facilities to their pre-Superstorm Sandy condition was approximately $426 million. Of these costs, $364 million and $62 million related to Power and PSE&G, respectively. In August 2013, the insurance carriers filed an answer in which they denied most of the allegations made in the Complaint. Discovery is ongoing.

Nuclear Insurance Coverages and Assessments

Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the primary property and decontamination liability insurance at Salem, Hope Creek and Peach Bottom. NEIL also provides excess property insurance through its decontamination liability, decommissioning liability and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power’s maximum potential liabilities under these assessments are included in the table and notes below. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

The American Nuclear Insurers (ANI) and NEIL policies both include coverage for claims arising out of acts of terrorism. NEIL makes a distinction between certified and non-certified acts of terrorism, as defined under the Terrorism Risk Insurance Act, and thus its policies respond accordingly. For non-certified acts of terrorism, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus any amounts available through reinsurance or indemnity for non-certified acts of terrorism. For any act of terrorism, Power’s nuclear liability policies will respond similarly to other covered events. For certified acts, Power’s nuclear property NEIL policies will respond similarly to other covered events.

The Price-Anderson Act sets the “limit of liability” for claims that could arise from an incident involving any licensed nuclear facility in the United States. The “limit of liability” is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current “limit of liability” is $13.6 billion. All owners of nuclear reactors, including Power, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by the Price-Anderson Act. Under the Price-Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $127 million per reactor per incident, payable at $19 million per reactor per incident per year. If the damages exceed the “limit of liability,” the President is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $401 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $60 million. Further, a decision by the U.S. Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.

Power’s insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:

Type and Source of Coverages	Total Site Coverage			Retrospective Assessments
	Millions
Public and Nuclear Worker Liability (Primary Layer):
ANI	$	375	(A)	$	—
Nuclear Liability (Excess Layer):
Price-Anderson Act	13,241		(B)	401
Nuclear Liability Total	$	13,616	(C)	$	401
Property Damage (Primary Layer):
NEIL Primary (Salem/Hope Creek/Peach Bottom)	$	500		$	24
Property Damage (Excess Layers)
NEIL II (Salem/Hope Creek/Peach Bottom)	750			8
NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom)	850		(D)	5
Property Damage Total (Per Site)	$	2,100	(E)	$	37
Accidental Outage:
NEIL I (Peach Bottom)	$	245	(F)	$	6
NEIL I (Salem)	281		(F)	7
NEIL I (Hope Creek)	490		(F)	6
Replacement Power Total	$	1,016		$	19

(A) The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit that is subject to reinstatement at ANI discretion.

(B) Retrospective premium program under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States that produces greater than 100 MW of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of September 10, 2013. The next adjustment is due on or before September 10, 2018. This retrospective program is in excess of the Public and Nuclear Worker Liability primary layers.

(C) Limit of liability under the Price-Anderson Act for each nuclear incident.

(D) For property limits in excess of $1.25 billion, Power participates in a Blanket Limit policy where the $850 million limit is shared by Power with Exelon Generation among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Exelon Generation and the Peach Bottom, Salem and Hope Creek facilities. This limit is not subject to reinstatement in the event of a loss. Participation in this program materially reduces Power’s premium and the associated potential assessment.

(E) Power's property limits provide a $2.1 billion limit for a nuclear event, but provide a sublimit of $1.5 billion for conventional property losses that do not involve a nuclear event.

(F) Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 72 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80%of the weekly indemnity for 71 weeks.

Minimum Lease Payments

The total future minimum payments under various operating leases as of December 31, 2013 are:

	Power		PSE&G		Services		Other
	Millions
2014	$	1	$	9	$	1	$	2
2015	1		7		4		2
2016	1		6		12		1
2017	1		5		13		1
2018	2		4		13		—
Thereafter	16		33		173		—
Total Minimum Lease Payments	$	22	$	64	$	216	$	6

Power [Member]

Commitments and Contingent Liabilities

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.

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.

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 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. This 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.

The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2013 and 2012 are shown below:

	As of December 31, 2013		As of December 31, 2012
	Millions
Face Value of Outstanding Guarantees	$	1,639	$	1,508
Exposure under Current Guarantees	$	246	$	226
Letters of Credit Margin Posted	$	132	$	124
Letters of Credit Margin Received	$	25	$	69
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	—	$	15
Counterparty Cash Margin Received	$	—	$	(4	)
Net Broker Balance Deposited (Received)	$	80	$	26
In the Event Power were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	691	$	654
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,522	$	3,531
Additional Amounts Posted
Other Letters of Credit	$	45	$	45

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. 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 the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

The SEC and the Commodity Futures Trading Commission (CFTC) continue efforts to implement new rules to effect stricter regulation over swaps and derivatives, including imposing reporting and record-keeping requirements. In August 2013, PSEG began reporting its swap transactions to a CFTC-approved swap data repository. PSEG continues to monitor developments in this area, as the CFTC considers additional requirements such as a new position limits rule for energy commodity swaps.

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 table above.

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 below.

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

The EPA has determined that a 17-mile stretch of the Passaic River from Newark to Clifton, New Jersey is a “Super Fund” 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 has determined the 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.

Seventy-three Potentially Responsible Parties (PRPs), including Power and PSE&G, agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently 67 members, is presently conducting the RI/FS. Approximately seven percent of the RI/FS costs are currently attributable to PSE&G’s former MGP sites and approximately one percentto Power’s generating stations. Power has provided notice to insurers concerning this potential claim. The RI/FS is expected to be completed by the end of 2014 at an estimated cost of approximately $125 million.

In 2007, the EPA released a draft “Focused Feasibility Study” (FFS) that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The EPA estimated costs for the proposed remedy ranged from $1.3 billion to $3.7 billion. The work contemplated by the draft FFS is not subject to the cost sharing agreement discussed above. The EPA's revised proposed FFS is scheduled to be released for public comment in the first quarter of 2014.

In June 2008, an agreement was announced between the EPA and Tierra Solutions, Inc. and Maxus Energy Corporation (Tierra/Maxus) for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. Phase I of the removal work has been completed. Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

At the EPA's direction, the CPG, with the exception of Tierra and Maxus, which are no longer members, has commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. PSEG’s share of the cost of that effort is approximately three percent.

Except for the Passaic River 10.9 mile removal, Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to the Passaic River matters.

New Jersey Spill Compensation and Control Act (Spill Act)

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of a certain PRP’s discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. In 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances it allegedly discharged into the Passaic River and the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed to a total of 11 sites or facilities that impacted these water bodies. The third party complaints sought statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. In December 2013, the Court approved a settlement of the entire third party action. Power and PSE&G's contributions to the settlement, either individually or in the aggregate, were immaterial.

Natural Resource Damage Claims

In 2003, the 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 Spill 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 United States Department of Commerce and the United States 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 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 is unable to estimate its portion 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. Power and PSE&G are unable to estimate their portion 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 $445 million and $521 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $445 million as of December 31, 2013. Of this amount, $92 million was recorded in Other Current Liabilities and $353 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $445 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.

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.

Hazardous Air Pollutants Regulation

In accordance with a ruling of the U.S. Court of Appeals of the District of Columbia (D.C. Court), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the D.C. Court in support of the EPA's implementation of MATS. Oral arguments were held in December 2013. A final decision remains pending and the impact on the implementation schedule is unknown at this time.

Power believes that it will not be necessary to install any material controls at its New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulations, the co-owners group, including Power, agreed to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal-fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. Power's share of this investment is approximately $110 million.

NO_x Regulation

In 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 30, 2015. Retirement notifications for the combustion turbines have been submitted to PJM. PJM was notified that the Salem Unit 3 combustion turbine will no longer be available as a capacity resource and will be transitioned to an emergency generator for site use only. Based upon Power’s recently-completed evaluations of its steam electric generation units, a minimal investment will be required to consistently reduce NO_x emissions below required limits beginning on May 1, 2015.  

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System (NPDES) 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 New Jersey Department of Environmental Protection 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.

One of the most significant NJPDES permits governing cooling water intake structures at Power is for Salem. In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued.

In April 2011, the EPA published a proposed rule to establish marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. The EPA is currently scheduled to issue a final rule on April 17, 2014.

Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition, results of operations or cash flows. The results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

On October 1, 2013, the Delaware Riverkeeper Network and several other environmental groups filed a lawsuit in the Superior Court in New Jersey seeking to compel the NJDEP to take action on Power's pending application for permit renewal at Salem either by denying the application or issuing a draft for public comments. At the NJDEP's request, the case was transferred to the Appellate Division on December 16, 2013. Power is unable to predict the outcome of this proceeding.

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

PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. 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 Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

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 contracted for its anticipated BGS-Fixed Price eligible load, as follows:

	Auction Year
	2011	2012	2013	2014
36-Month Terms Ending	May 2014	May 2015	May 2016	May 2017	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per kWh	0.09430	0.08388	0.09218	0.09739

(A) Prices set in the 2014 BGS auction will become effective on June 1, 2014 when the 2011 BGS auction agreements expire.

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 24. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations and for supply of nuclear fuel for the Salem, Hope Creek and Peach Bottom nuclear generating stations and for firm transportation and storage capacity for natural gas.

Power’s 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 2015 and a portion through 2018 at Salem, Hope Creek and Peach Bottom.

Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.

As of December 31, 2013, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Power's Share of Commitments through 2018
	Millions
Nuclear Fuel
Uranium	$	532
Enrichment	$	454
Fabrication	$	137
Natural Gas	$	1,061
Coal	$	405

Regulatory Proceedings

New Jersey Clean Energy Program

In June 2013, the BPU established the funding level for fiscal 2014 applicable to its Renewable Energy and Energy Efficiency programs. The fiscal year 2014 aggregate funding for all EDCs is $345 million with PSE&G’s share of the funding at $200 million. PSE&G has a remaining current liability of $142 million as of December 31, 2013 for its outstanding share of the fiscal 2014 and remaining fiscal 2013 funding. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

Long-Term Capacity Agreement Pilot Program (LCAPP)

In 2011, New Jersey enacted the LCAPP Act that resulted in the selection of three generators to build a total of approximately 2,000 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the selected generators, providing for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement, but did so under protest preserving their legal rights. The SOCA contracts, which had a 15-year term, were for the aggregate notional amount of approximately 1,300 MW of installed capacity. PSE&G was to have been responsible for the positive difference of the contract price and the annual RPM clearing price for approximately 52% or 676 MW of this amount, assuming generator satisfaction of its contractual obligations.

In July 2013, one of the SOCA contracts was terminated early as a result of a default by the generator. In November 2013, as a result of a federal court decision finding (i) the LCAPP Act to be unconstitutional and (ii) the SOCA contracts to be void, invalid and unenforceable, and a subsequent decision denying a request to stay this decision pending appeal, PSE&G terminated the other two SOCA contracts by providing written notice to both counterparties. The SOCA generators have appealed the federal court decision and this appeal remains pending.

As a result of the federal court's decision and PSE&G's subsequent termination of the contracts, the estimated fair value of the SOCAs that had been recorded as a Derivative Asset or Liability with an offsetting Regulatory Asset or Liability on PSE&G’s Consolidated Balance Sheets were removed in the fourth quarter of 2013. See Note 17. Fair Value Measurements for additional information.

Superstorm Sandy

In late October 2012, Superstorm Sandy caused severe damage to PSE&G's transmission and distribution system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds and the resulting storm surge caused damage to switching stations, substations and generating infrastructure.

As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its infrastructure and return it to pre-storm conditions. Of the costs incurred, approximately $40 million was recognized in Operation and Maintenance (O&M) Expense, $75 million was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. PSE&G recognized $6 million of insurance proceeds. There were no significantchanges to these amounts in 2013. PSE&G made a filing with the BPU to review the prudency of unreimbursed incremental storm restoration costs, including O&M and capital expenditures associated with certain extreme weather events, for recovery in our next base rate case or sooner through a BPU-approved cost recovery mechanism. The BPU is currently conducting a review regarding the amount, prudency, cost effectiveness and cost efficiency of PSE&G's unreimbursed incremental storm restoration costs for extreme weather events from 2010-2012.

Power incurred $79 million of storm-related expense for the year ended December 31, 2013 primarily for repairs at certain generating stations in Power's fossil fleet. Power had incurred $85 million of costs in 2012. These costs were recognized in O&M Expense, offset by $25 million and $19 million of insurance recoveries in the second quarter of 2013 and the fourth quarter of 2012, respectively.

PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. PSEG is seeking recovery from its insurers for the property damage, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. PSEG has recorded proceeds of $50 million from its insurance carriers as advance payments, $25 million of which was recognized in 2013 and $25 million was recognized in 2012. PSEG does not believe that it has a basis for estimating additional probable insurance recoveries at this time. In June 2013, PSEG, Power and PSE&G filed suit in New Jersey state court against the insurance carriers seeking legal interpretation of certain terms in the insurance policies regarding losses resulting from damage caused by Superstorm Sandy's storm surge. The dispute concerns whether certain sub-limits in the policies apply to damage to property caused by Superstorm Sandy's storm surge. In that lawsuit, PSEG stated that its estimate of the total costs required to restore damaged facilities to their pre-Superstorm Sandy condition was approximately $426 million. Of these costs, $364 million and $62 million related to Power and PSE&G, respectively. In August 2013, the insurance carriers filed an answer in which they denied most of the allegations made in the Complaint. Discovery is ongoing.

Nuclear Insurance Coverages and Assessments

Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the primary property and decontamination liability insurance at Salem, Hope Creek and Peach Bottom. NEIL also provides excess property insurance through its decontamination liability, decommissioning liability and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power’s maximum potential liabilities under these assessments are included in the table and notes below. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

The American Nuclear Insurers (ANI) and NEIL policies both include coverage for claims arising out of acts of terrorism. NEIL makes a distinction between certified and non-certified acts of terrorism, as defined under the Terrorism Risk Insurance Act, and thus its policies respond accordingly. For non-certified acts of terrorism, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus any amounts available through reinsurance or indemnity for non-certified acts of terrorism. For any act of terrorism, Power’s nuclear liability policies will respond similarly to other covered events. For certified acts, Power’s nuclear property NEIL policies will respond similarly to other covered events.

The Price-Anderson Act sets the “limit of liability” for claims that could arise from an incident involving any licensed nuclear facility in the United States. The “limit of liability” is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current “limit of liability” is $13.6 billion. All owners of nuclear reactors, including Power, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by the Price-Anderson Act. Under the Price-Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $127 million per reactor per incident, payable at $19 million per reactor per incident per year. If the damages exceed the “limit of liability,” the President is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $401 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $60 million. Further, a decision by the U.S. Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.

Power’s insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:

Type and Source of Coverages	Total Site Coverage			Retrospective Assessments
	Millions
Public and Nuclear Worker Liability (Primary Layer):
ANI	$	375	(A)	$	—
Nuclear Liability (Excess Layer):
Price-Anderson Act	13,241		(B)	401
Nuclear Liability Total	$	13,616	(C)	$	401
Property Damage (Primary Layer):
NEIL Primary (Salem/Hope Creek/Peach Bottom)	$	500		$	24
Property Damage (Excess Layers)
NEIL II (Salem/Hope Creek/Peach Bottom)	750			8
NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom)	850		(D)	5
Property Damage Total (Per Site)	$	2,100	(E)	$	37
Accidental Outage:
NEIL I (Peach Bottom)	$	245	(F)	$	6
NEIL I (Salem)	281		(F)	7
NEIL I (Hope Creek)	490		(F)	6
Replacement Power Total	$	1,016		$	19

(A) The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit that is subject to reinstatement at ANI discretion.

(B) Retrospective premium program under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States that produces greater than 100 MW of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of September 10, 2013. The next adjustment is due on or before September 10, 2018. This retrospective program is in excess of the Public and Nuclear Worker Liability primary layers.

(C) Limit of liability under the Price-Anderson Act for each nuclear incident.

(D) For property limits in excess of $1.25 billion, Power participates in a Blanket Limit policy where the $850 million limit is shared by Power with Exelon Generation among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Exelon Generation and the Peach Bottom, Salem and Hope Creek facilities. This limit is not subject to reinstatement in the event of a loss. Participation in this program materially reduces Power’s premium and the associated potential assessment.

(E) Power's property limits provide a $2.1 billion limit for a nuclear event, but provide a sublimit of $1.5 billion for conventional property losses that do not involve a nuclear event.

(F) Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 72 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80%of the weekly indemnity for 71 weeks.

Minimum Lease Payments

The total future minimum payments under various operating leases as of December 31, 2013 are:

	Power		PSE&G		Services		Other
	Millions
2014	$	1	$	9	$	1	$	2
2015	1		7		4		2
2016	1		6		12		1
2017	1		5		13		1
2018	2		4		13		—
Thereafter	16		33		173		—
Total Minimum Lease Payments	$	22	$	64	$	216	$	6

PSE&G [Member]

Commitments and Contingent Liabilities

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.

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.

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 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. This 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.

The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2013 and 2012 are shown below:

	As of December 31, 2013		As of December 31, 2012
	Millions
Face Value of Outstanding Guarantees	$	1,639	$	1,508
Exposure under Current Guarantees	$	246	$	226
Letters of Credit Margin Posted	$	132	$	124
Letters of Credit Margin Received	$	25	$	69
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	—	$	15
Counterparty Cash Margin Received	$	—	$	(4	)
Net Broker Balance Deposited (Received)	$	80	$	26
In the Event Power were to Lose its Investment Grade Rating
Additional Collateral that could be Required	$	691	$	654
Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral	$	3,522	$	3,531
Additional Amounts Posted
Other Letters of Credit	$	45	$	45

As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. 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 the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P, Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

The SEC and the Commodity Futures Trading Commission (CFTC) continue efforts to implement new rules to effect stricter regulation over swaps and derivatives, including imposing reporting and record-keeping requirements. In August 2013, PSEG began reporting its swap transactions to a CFTC-approved swap data repository. PSEG continues to monitor developments in this area, as the CFTC considers additional requirements such as a new position limits rule for energy commodity swaps.

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 table above.

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 below.

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

The EPA has determined that a 17-mile stretch of the Passaic River from Newark to Clifton, New Jersey is a “Super Fund” 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 has determined the 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.

Seventy-three Potentially Responsible Parties (PRPs), including Power and PSE&G, agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently 67 members, is presently conducting the RI/FS. Approximately seven percent of the RI/FS costs are currently attributable to PSE&G’s former MGP sites and approximately one percentto Power’s generating stations. Power has provided notice to insurers concerning this potential claim. The RI/FS is expected to be completed by the end of 2014 at an estimated cost of approximately $125 million.

In 2007, the EPA released a draft “Focused Feasibility Study” (FFS) that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The EPA estimated costs for the proposed remedy ranged from $1.3 billion to $3.7 billion. The work contemplated by the draft FFS is not subject to the cost sharing agreement discussed above. The EPA's revised proposed FFS is scheduled to be released for public comment in the first quarter of 2014.

In June 2008, an agreement was announced between the EPA and Tierra Solutions, Inc. and Maxus Energy Corporation (Tierra/Maxus) for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. Phase I of the removal work has been completed. Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

At the EPA's direction, the CPG, with the exception of Tierra and Maxus, which are no longer members, has commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. PSEG’s share of the cost of that effort is approximately three percent.

Except for the Passaic River 10.9 mile removal, Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to the Passaic River matters.

New Jersey Spill Compensation and Control Act (Spill Act)

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of a certain PRP’s discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. In 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances it allegedly discharged into the Passaic River and the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed to a total of 11 sites or facilities that impacted these water bodies. The third party complaints sought statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. In December 2013, the Court approved a settlement of the entire third party action. Power and PSE&G's contributions to the settlement, either individually or in the aggregate, were immaterial.

Natural Resource Damage Claims

In 2003, the 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 Spill 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 United States Department of Commerce and the United States 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 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 is unable to estimate its portion 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. Power and PSE&G are unable to estimate their portion 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 $445 million and $521 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $445 million as of December 31, 2013. Of this amount, $92 million was recorded in Other Current Liabilities and $353 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $445 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.

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.

Hazardous Air Pollutants Regulation

In accordance with a ruling of the U.S. Court of Appeals of the District of Columbia (D.C. Court), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the D.C. Court in support of the EPA's implementation of MATS. Oral arguments were held in December 2013. A final decision remains pending and the impact on the implementation schedule is unknown at this time.

Power believes that it will not be necessary to install any material controls at its New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulations, the co-owners group, including Power, agreed to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal-fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. Power's share of this investment is approximately $110 million.

NO_x Regulation

In 2009, the NJDEP finalized revisions to NO_x emission control regulations that impose new NO_x emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on Power’s generation fleet, as it imposes NO_x emissions limits that will require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 30, 2015. Retirement notifications for the combustion turbines have been submitted to PJM. PJM was notified that the Salem Unit 3 combustion turbine will no longer be available as a capacity resource and will be transitioned to an emergency generator for site use only. Based upon Power’s recently-completed evaluations of its steam electric generation units, a minimal investment will be required to consistently reduce NO_x emissions below required limits beginning on May 1, 2015.  

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System (NPDES) 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 New Jersey Department of Environmental Protection 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.

One of the most significant NJPDES permits governing cooling water intake structures at Power is for Salem. In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued.

In April 2011, the EPA published a proposed rule to establish marine life mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. The EPA is currently scheduled to issue a final rule on April 17, 2014.

Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition, results of operations or cash flows. The results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Power’s share would have been approximately $575 million. The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.

On October 1, 2013, the Delaware Riverkeeper Network and several other environmental groups filed a lawsuit in the Superior Court in New Jersey seeking to compel the NJDEP to take action on Power's pending application for permit renewal at Salem either by denying the application or issuing a draft for public comments. At the NJDEP's request, the case was transferred to the Appellate Division on December 16, 2013. Power is unable to predict the outcome of this proceeding.

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

PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. 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 Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

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 contracted for its anticipated BGS-Fixed Price eligible load, as follows:

	Auction Year
	2011	2012	2013	2014
36-Month Terms Ending	May 2014	May 2015	May 2016	May 2017	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per kWh	0.09430	0.08388	0.09218	0.09739

(A) Prices set in the 2014 BGS auction will become effective on June 1, 2014 when the 2011 BGS auction agreements expire.

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 24. Related-Party Transactions.

Minimum Fuel Purchase Requirements

Power has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations and for supply of nuclear fuel for the Salem, Hope Creek and Peach Bottom nuclear generating stations and for firm transportation and storage capacity for natural gas.

Power’s 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 2015 and a portion through 2018 at Salem, Hope Creek and Peach Bottom.

Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.

As of December 31, 2013, the total minimum purchase requirements included in these commitments were as follows:

Fuel Type	Power's Share of Commitments through 2018
	Millions
Nuclear Fuel
Uranium	$	532
Enrichment	$	454
Fabrication	$	137
Natural Gas	$	1,061
Coal	$	405

Regulatory Proceedings

New Jersey Clean Energy Program

In June 2013, the BPU established the funding level for fiscal 2014 applicable to its Renewable Energy and Energy Efficiency programs. The fiscal year 2014 aggregate funding for all EDCs is $345 million with PSE&G’s share of the funding at $200 million. PSE&G has a remaining current liability of $142 million as of December 31, 2013 for its outstanding share of the fiscal 2014 and remaining fiscal 2013 funding. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

Long-Term Capacity Agreement Pilot Program (LCAPP)

In 2011, New Jersey enacted the LCAPP Act that resulted in the selection of three generators to build a total of approximately 2,000 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the selected generators, providing for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement, but did so under protest preserving their legal rights. The SOCA contracts, which had a 15-year term, were for the aggregate notional amount of approximately 1,300 MW of installed capacity. PSE&G was to have been responsible for the positive difference of the contract price and the annual RPM clearing price for approximately 52% or 676 MW of this amount, assuming generator satisfaction of its contractual obligations.

In July 2013, one of the SOCA contracts was terminated early as a result of a default by the generator. In November 2013, as a result of a federal court decision finding (i) the LCAPP Act to be unconstitutional and (ii) the SOCA contracts to be void, invalid and unenforceable, and a subsequent decision denying a request to stay this decision pending appeal, PSE&G terminated the other two SOCA contracts by providing written notice to both counterparties. The SOCA generators have appealed the federal court decision and this appeal remains pending.

As a result of the federal court's decision and PSE&G's subsequent termination of the contracts, the estimated fair value of the SOCAs that had been recorded as a Derivative Asset or Liability with an offsetting Regulatory Asset or Liability on PSE&G’s Consolidated Balance Sheets were removed in the fourth quarter of 2013. See Note 17. Fair Value Measurements for additional information.

Superstorm Sandy

In late October 2012, Superstorm Sandy caused severe damage to PSE&G's transmission and distribution system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds and the resulting storm surge caused damage to switching stations, substations and generating infrastructure.

As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its infrastructure and return it to pre-storm conditions. Of the costs incurred, approximately $40 million was recognized in Operation and Maintenance (O&M) Expense, $75 million was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. PSE&G recognized $6 million of insurance proceeds. There were no significantchanges to these amounts in 2013. PSE&G made a filing with the BPU to review the prudency of unreimbursed incremental storm restoration costs, including O&M and capital expenditures associated with certain extreme weather events, for recovery in our next base rate case or sooner through a BPU-approved cost recovery mechanism. The BPU is currently conducting a review regarding the amount, prudency, cost effectiveness and cost efficiency of PSE&G's unreimbursed incremental storm restoration costs for extreme weather events from 2010-2012.

Power incurred $79 million of storm-related expense for the year ended December 31, 2013 primarily for repairs at certain generating stations in Power's fossil fleet. Power had incurred $85 million of costs in 2012. These costs were recognized in O&M Expense, offset by $25 million and $19 million of insurance recoveries in the second quarter of 2013 and the fourth quarter of 2012, respectively.

PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions and limitations, to the extent such property is usually insured and insurance is available at a reasonable cost. PSEG is seeking recovery from its insurers for the property damage, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. PSEG has recorded proceeds of $50 million from its insurance carriers as advance payments, $25 million of which was recognized in 2013 and $25 million was recognized in 2012. PSEG does not believe that it has a basis for estimating additional probable insurance recoveries at this time. In June 2013, PSEG, Power and PSE&G filed suit in New Jersey state court against the insurance carriers seeking legal interpretation of certain terms in the insurance policies regarding losses resulting from damage caused by Superstorm Sandy's storm surge. The dispute concerns whether certain sub-limits in the policies apply to damage to property caused by Superstorm Sandy's storm surge. In that lawsuit, PSEG stated that its estimate of the total costs required to restore damaged facilities to their pre-Superstorm Sandy condition was approximately $426 million. Of these costs, $364 million and $62 million related to Power and PSE&G, respectively. In August 2013, the insurance carriers filed an answer in which they denied most of the allegations made in the Complaint. Discovery is ongoing.

Nuclear Insurance Coverages and Assessments

Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the primary property and decontamination liability insurance at Salem, Hope Creek and Peach Bottom. NEIL also provides excess property insurance through its decontamination liability, decommissioning liability and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power’s maximum potential liabilities under these assessments are included in the table and notes below. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

The American Nuclear Insurers (ANI) and NEIL policies both include coverage for claims arising out of acts of terrorism. NEIL makes a distinction between certified and non-certified acts of terrorism, as defined under the Terrorism Risk Insurance Act, and thus its policies respond accordingly. For non-certified acts of terrorism, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus any amounts available through reinsurance or indemnity for non-certified acts of terrorism. For any act of terrorism, Power’s nuclear liability policies will respond similarly to other covered events. For certified acts, Power’s nuclear property NEIL policies will respond similarly to other covered events.

The Price-Anderson Act sets the “limit of liability” for claims that could arise from an incident involving any licensed nuclear facility in the United States. The “limit of liability” is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current “limit of liability” is $13.6 billion. All owners of nuclear reactors, including Power, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by the Price-Anderson Act. Under the Price-Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $127 million per reactor per incident, payable at $19 million per reactor per incident per year. If the damages exceed the “limit of liability,” the President is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $401 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $60 million. Further, a decision by the U.S. Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.

Power’s insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:

Type and Source of Coverages	Total Site Coverage			Retrospective Assessments
	Millions
Public and Nuclear Worker Liability (Primary Layer):
ANI	$	375	(A)	$	—
Nuclear Liability (Excess Layer):
Price-Anderson Act	13,241		(B)	401
Nuclear Liability Total	$	13,616	(C)	$	401
Property Damage (Primary Layer):
NEIL Primary (Salem/Hope Creek/Peach Bottom)	$	500		$	24
Property Damage (Excess Layers)
NEIL II (Salem/Hope Creek/Peach Bottom)	750			8
NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom)	850		(D)	5
Property Damage Total (Per Site)	$	2,100	(E)	$	37
Accidental Outage:
NEIL I (Peach Bottom)	$	245	(F)	$	6
NEIL I (Salem)	281		(F)	7
NEIL I (Hope Creek)	490		(F)	6
Replacement Power Total	$	1,016		$	19

(A) The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit that is subject to reinstatement at ANI discretion.

(B) Retrospective premium program under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States that produces greater than 100 MW of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of September 10, 2013. The next adjustment is due on or before September 10, 2018. This retrospective program is in excess of the Public and Nuclear Worker Liability primary layers.

(C) Limit of liability under the Price-Anderson Act for each nuclear incident.

(D) For property limits in excess of $1.25 billion, Power participates in a Blanket Limit policy where the $850 million limit is shared by Power with Exelon Generation among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Exelon Generation and the Peach Bottom, Salem and Hope Creek facilities. This limit is not subject to reinstatement in the event of a loss. Participation in this program materially reduces Power’s premium and the associated potential assessment.

(E) Power's property limits provide a $2.1 billion limit for a nuclear event, but provide a sublimit of $1.5 billion for conventional property losses that do not involve a nuclear event.

(F) Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 72 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80%of the weekly indemnity for 71 weeks.

Minimum Lease Payments

The total future minimum payments under various operating leases as of December 31, 2013 are:

	Power		PSE&G		Services		Other
	Millions
2014	$	1	$	9	$	1	$	2
2015	1		7		4		2
2016	1		6		12		1
2017	1		5		13		1
2018	2		4		13		—
Thereafter	16		33		173		—
Total Minimum Lease Payments	$	22	$	64	$	216	$	6