Note 13. 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.

The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2011 and 2010 are shown below:


	As of December 31,			As of December 31,
	2011			2010
	Millions
Face Value of Outstanding Guarantees	$	1,756		$	1,936
Exposure under Current Guarantees	$	315		$	330
Letters of Credit Margin Posted	$	135		$	137
Letters of Credit Margin Received	$	91		$	109
Cash Deposited and Received
Counterparty Cash Margin Deposited	$	20		$	0
Counterparty Cash Margin Received	$	(7	)	$	(2	)
Net Broker Balance Deposited (Received)	$	(92	)	$	(28	)
In the Event Power were to Lose its Investment Grade Rating:
Additional Collateral that could be Required	$	812		$	828
Liquidity Available under PSEG's and Power's Credit Facilities to Post Collateral	$	3,415		$	2,750
Additional Amounts Posted
Other Letters of Credit	$	52		$	98

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 our 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 is 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 two level downgrade from its current ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.

In addition, during 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. Power will carefully monitor these new rules as they are developed to analyze the potential impact on its swap and derivatives transactions, including any potential increase to collateral requirements.

In April 2011, PSEG and Power entered into new 5-year credit agreements resulting in an increase of $650 million in Power's total credit capacity.

In addition to amounts for outstanding guarantees, current exposure and margin positions, Power had posted letters of credit to support 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.

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

The United States Environmental Protection Agency (EPA) has determined that an eight-mile stretch of the Passaic River in the area of Newark, New Jersey is a "facility" within the meaning of that term under CERCLA. The EPA has determined the need to perform a study of the entire 17-mile tidal reach of the lower Passaic River.

PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to 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. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.

The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G's former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. The total cost of the study is now estimated at approximately $99 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 71 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G's former MGP sites and approximately one percent to Power's generating stations. Power has provided notice to insurers concerning this potential claim.

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 estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. The EPA is conducting a revised focused feasibility study which may be released as early as the third quarter of 2012.

In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.

The EPA has advised that the levels of contaminants at Passaic River mile 10.9 may require a pilot study and removal in advance of the completion of the Remedial Investigation and Feasibility Study or the issuance of a revised draft FFS. Preliminary cost estimates range from $20 million to $150 million.

Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to these matters.

New Jersey Spill Compensation and Control Act (Spill Act)

In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRP's discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed hazardous substances to a total of 11 sites or facilities that impacted these water bodies. In February 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 they allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaint in June 2010. A special master for discovery has been appointed by the court and document production has commenced. Power and PSE&G believe they have good and valid defenses to the allegations contained in the third party complaints and will vigorously assert those defenses. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.

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 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 and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study that OCC was conducting. 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 it is uncertain at this time whether the PSEG companies will consent 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 $635 million and $733 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $635 million as of December 31, 2011. Of this amount, $53 million was recorded in Other Current Liabilities and $582 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $635 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, 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 PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act 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 court ruling, the EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which was finalized on December 21, 2011. This regulation prescribes reduced levels of mercury and other hazardous air pollutants pursuant to the Clean Air Act. The impact to our fossil fleet is currently being determined; but Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rule's requirements. Some additional controls could be necessary at Power's Connecticut facilities and some of its other New Jersey facilities, pending engineering evaluation. In December 2011, a decision was reached 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 fourth quarter of 2014. PSEG's share of this investment is approximately $147 million.

New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.

With newly installed controls at its plants in New Jersey, Power expects to achieve the required mercury reductions that are part of Power's multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.

NO_x Regulation

In April 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 generating units. The rule will have a significant impact on Power's generation fleet, as it imposes NO_x emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and four older New Jersey steam electric generating units (approximately 400 MW) by May 30, 2015. Power is currently evaluating its compliance options and is unable to estimate the possible loss or range of loss related to this matter.

Under current Connecticut regulations, Power's Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NO_x emission limitations that were incorporated into the facilities' operating permits. In 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.

Cross-State Air Pollution Rule (CSAPR)

On July 6, 2011, the EPA issued the final CSAPR. The CSAPR limits power plant emissions in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone emission standards.

Technical revisions to the CSAPR were finalized on February 7, 2012. The EPA increased New Jersey's allocation of annual NO_x and ozone season NO_x allowances beyond what was proposed. The EPA also finalized the increase in New Jersey's allocation of SO₂ allowances from the October proposal.

On December 30, 2011, the United States Court of Appeals for the D.C. Circuit issued a ruling to stay CSAPR pending judicial review. Until a final decision is reached, the court has ordered that the Clean Air Interstate Rule (CAIR) requirements continue temporarily. PSEG has intervened in this litigation along with Calpine and Exelon in support of the rule.

The continuation of CAIR affects our generating stations in Connecticut, New Jersey and New York. The purpose of CAIR is to improve Ozone and Fine Particulate (PM2.5) air quality within states that have not demonstrated achievement of the National Ambient Air Quality Standards (NAAQS). CAIR was implemented through a cap-and-trade program and to date the impact has not been material to us as the allowances allocated to our stations were sufficient. If 2012 operations are similar to those in the past three years, it is expected that the impact to operations from the temporary implementation of CAIR in 2012 will not be significant.

PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. As Power has made major capital investments over the past several years to lower the SO₂ and NO_x emissions of its fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania), Power does not foresee the need to make significant additional expenditures to its generation fleet to comply with the regulation. As such, Power believes this rule will not have a material impact to its capital investment program or units' operations.

Clean Water Act Permit Renewals

Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NJPDES) 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.

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. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.

As a result of several legal challenges to the 2004 316(b) rule by certain northeast states, environmentalists and industry groups, the rule has been suspended and has been returned to the EPA to be consistent with a 2009 United States Supreme Court decision which concluded that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations.

In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. Power reviewed the proposed rule, assessed the potential impact on its generating facilities and used this information to develop its comments to the EPA which were filed in August 2011. Although the EPA has recently stated that a revision of the proposed rule to include an alternative framework for compliance is currently being considered, if the rule were to be adopted as proposed, the impact would be material since the majority of Power's electric generating stations would be affected. 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 or results of operations. 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. These cost estimates have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power's forecasted capital expenditures.

In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies may ultimately impact the EPA's rulemaking.

In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that company's nuclear generating station located in New Jersey. In December 2010, the NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit was issued by NJDEP on June 1, 2011. The permit was issued as final on December 21, 2011 incorporating the 316(b) requirements as defined in the ACO. In that permit, NJDEP defended its position that closed-cycle cooling was not the best technology available for that facility. Per that permit the facility will cease operations on December 31, 2019. Power cannot predict at this time the final outcome of the NJDEP decision and the impact, if any; such a decision would have on any of Power's once-through cooled generating stations.

New Generation and Development

Nuclear

Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed on schedule in October 2011. Unit 2 upgrades are expected to result in an increase of Power's share of nominal capacity by approximately 14 MW in 2012. Total expenditures through December 31, 2011 were $114 million and are expected to continue through 2012.

Power has begun expenditures in pursuit of additional output through an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power's share of the increased capacity is expected to be approximately 133 MW with an anticipated cost of approximately $400 million. Total expenditures through December 31, 2011 were $36 million and are expected to continue through 2016.

Connecticut

Power was selected by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be approximately $148 million, (not including the capitalized cost to finance during construction). Capitalized expenditures through December 31, 2011 were $129 million, which are included in Property, Plant and Equipment on the Consolidated Balance Sheets of PSEG and Power. The initial filing was submitted in December 2011 to the PURA. Costs for this project, including financing costs capitalized during the construction period, will be recovered subject to regulatory review and approval.

PJM Interconnection L.L.C. (PJM)

Power plans to construct gas fired peaking facilities at its Kearny site. Construction began in the second quarter of 2011. The projects are expected to be in service by June 2012. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Capacity in the amount of 267 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 and 2014-2015 periods. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through December 31, 2011 were $203 million which are included in Property, Plant and Equipment on Power's and PSEG's Consolidated Balance Sheets.

PSE&G—Solar

As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&G's commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units. PSE&G estimates the total cost of this project to be $265 million. Approximately 25 MW have been installed as of December 31, 2011. PSE&G's cumulative investments for these solar units were approximately $185 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available.

Another aspect of the Solar 4 All program is the installation of 40 MW of solar systems on land and buildings owned by PSE&G and third parties. PSE&G estimates the total cost of this phase of the program to be $186 million. Through December 31, 2011, 33 MW representing 19 projects had been placed into service with an investment of approximately $160 million.

Our Solar 4 All program is comprised, in part, of the installation of up to 200,000 pole mounted solar units within our service territory. On January 18, 2012, the BPU issued an order indicating that it will conduct a proceeding to address the proposed placement of solar panels on the poles. A negative determination by the BPU could impact on our ability to complete the Solar 4 All pole mounted installations.

Energy Holdings—Solar

In January 2012, Energy Holdings acquired a 25 MW solar project currently under construction in Arizona. Completion of this project is expected by the third quarter of 2012. Energy Holdings has issued guarantees of up to $71.5 million for payment of obligations related to the construction of the project. These guarantees will terminate upon successful completion of the project. The total investment for the project is expected to be approximately $75 million.

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. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.

PSE&G has contracted for its anticipated BGS-Fixed Price eligible load, as follows:

Auction Year

2009

2010

2011

2012

36-Month Terms Ending

May 2012

May 2013

May 2014

May 2015

(A)

Load (MW)

2,900

2,800

2,900

$ per kWh

0.10372

0.09577

0.09430

0.08388

(A)	Prices set in the 2012 BGS auction will become effective on June 1, 2012 when the 2009 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. The contract extends through March 31, 2012, and year-to-year thereafter. 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. For additional information, see Note 17. Related-Party Transactions. 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.

Minimum Fuel Purchase Requirements

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

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.

Power's strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below 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 for 2016 at Salem, Hope Creek and Peach Bottom.

As of December 31, 2011, the total minimum purchase requirements included in these commitments were as follows:


	Commitments through 2016
Fuel Type	Power's Share
		Millions
Nuclear Fuel
Uranium	$	529
Enrichment	$	492
Fabrication	$	166
Natural Gas	$	1,009
Coal	$	282

Regulatory Proceedings

Electric Discount and Energy Competition Act (Competition Act)

In 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G's electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.

Also in 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In October 2007, the Court granted PSE&G's motion to dismiss the amended Complaint and in November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court (Appellate Division). In February 2009, the Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division's decision.

In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G's recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&G's motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. In June 2011, the plaintiff/petitioner filed a notice of appeal of the BPU action with the Appellate Division. PSE&G is currently in the briefing stage of this appeal.

New Jersey Clean Energy Program

In 2008, the BPU approved funding requirements for each New Jersey EDC applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&G's share is $705 million. PSE&G has recorded a discounted liability of $253 million as of December 31, 2011. Of this amount, $214 million was recorded as a current liability and $39 million as a noncurrent liability. 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 expected to be recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).

The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. The proceeding has no impact on current SBC assessments.

Long-Term Capacity Agreement Pilot Program (LCAPP)

In January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of base load or mid-merit electric power generation. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of approximately 1,949 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, executed standard offer capacity agreements (SOCA) with each of the three selected generators in compliance with the BPU's directive, but did so under protest preserving its respective legal rights. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid set forth in the SOCA. The LCAPP Act and the BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. PSE&G will not make or receive payments under the three contracts unless (1) the plant successfully bids into and clears the capacity auction in accordance with the terms of the SOCA and (2) the proposed plant is constructed. In April 2011, the BPU approved the executed contracts; however, the EDCs appealed the BPU's orders. Additionally, Power and another generator challenged the BPU's implementation in a separate appeal. These two separate appeals are pending.

Leveraged Lease Investments

The IRS has issued reports with respect to its audits of PSEG's consolidated federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain cross-border lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.

On January 31, 2012, PSEG entered into a specific matter closing agreement settling the dispute with the IRS over the challenged lease transactions for all tax years. This agreement settles the leasing dispute with finality for all tax periods in which PSEG realized tax deductions from these transactions. In addition, PSEG signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. PSEG believes that there will be no material impact on earnings as a result of these settlement agreements.

Cash Impact

For tax years 1997 through 2003, the tax and interest PSEG owes the IRS as a result of this settlement will be completely defrayed by the $320 million PSEG has on deposit with the IRS for this matter. Based upon the closing agreement, for tax years from 2004 through 2008, PSEG owes the IRS approximately $1.0 billion in tax and interest. For tax years 2009 and 2010, the IRS owes PSEG approximately $1.0 billion. PSEG will attempt to work with the IRS to process these audit years simultaneously, so that the two refund and payment amounts can potentially be offset. No assurance can be given that the IRS will agree to this process. It is possible that PSEG would have to make several payments totaling $1.0 billion over the next year to the IRS and file claims for refunds for $1.0 billion which the IRS would process in the normal course; it could take several years for the IRS to process these claims. In addition to the above, PSEG will claim a tax deduction for the accrued deficiency interest associated with this settlement in 2012, which will give rise to a cash tax savings of approximately $100 million.

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 (TRIA), 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 U.S. 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 $12.6 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 $118 million per reactor per incident, payable at $18 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 $370 million (based on Power's ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $55 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	)	$	0
Nuclear Liability (Excess Layer):
Price-Anderson Act		12,219	(B	)		370

Nuclear Liability Total	$	12,594	(C	)	$	370


Property Damage (Primary Layer):
NEIL Primary (Salem/Hope Creek/Peach Bottom)	$	500			$	18
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			$	31


Accidental Outage:
NEIL I (Peach Bottom)	$	245	(E	)	$	6
NEIL I (Salem)		281	(E	)		7
NEIL I (Hope Creek)		490	(E	)		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 U.S. 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 October 29, 2008. The next adjustment is due on or before October 29, 2013. 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)

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 75 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

PSEG and Power have entered into capital leases for administrative office space. The total future minimum payments and present value of these capital leases as of December 31, 2011 are:


	Power			Other (A)
	Millions
2012	$	2		$	7
2013		2			7
2014		1			7
2015		1			6
2016		0			0
Thereafter		0			0

Total Minimum Lease Payments		6			27
Less: Imputed Interest		(1	)		(5	)

Present Value of Net Minimum Lease Payments	$	5		$	22

(A)	Other consists of PSEG (Parent Company) and Services

Power, PSE&G and Energy Holdings have entered into various operating leases. The total future minimum payments of these operating leases as of December 31, 2011 are:


	Power		PSE&G		Energy Holdings
2012	$	0	$	6	$	1
2013		0		5		1
2014		1		4		0
2015		1		3		0
2016		1		2		0
Thereafter		5		30		7

Total Minimum Lease Payments	$	8	$	50	$	9

Commitments And Contingent Liabilities