Load Zone ($/MWh)		2005-2008							2006-2009							2007-2010							2008-2011							2009-2012
PSE&G			$		65.41					$		102.51					$		98.88					$		111.50					$		103.72
Jersey Central Power and Light			$		65.70					$		100.44					$		99.64					$		114.09					$		103.51
Atlantic City Electric			$		66.48					$		103.99					$		99.59					$		116.50					$		105.36
Rockland Electric Company			$		71.79					$		111.14					$		109.99					$		120.49					$		112.70

A portion of our total generation capacity is allocated in the BGS contract through the BGS auctions. On average, tranches won in the BGS auctions require 100 MW to 120 MW of capacity on a daily basis. In addition, we hedged a portion of our generation capacity with forward capacity sales contracts.

The capacity prices we contracted for in the 2005-2008 BGS auctions and through some of the forward sales contracts were set prior to the implementation of RPM capacity auctions and therefore do not reflect the capacity prices determined more recently in the RPM capacity auctions. As a result, we were unable to fully realize such pricing for some of our generating capacity. As these older contracts expire, we expect revenues to increase as we realize the RPM auction pricing.

We have obtained price certainty for all of our PJM and New England capacity through May 2012 through these mechanisms.

To support our contracted sales of energy, we also entered into contracts for the future purchase and delivery of nuclear fuel and coal, which include some market-based pricing components. As of February 10, 2009, we had contracted for the following percentages of our nuclear and coal generation output and related fuel supplies for the next three years with modest amounts beyond 2011.

We take a more opportunistic approach in hedging our anticipated natural gas-fired generation. The generation from these units is less predictable, as these units are generally dispatched when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units have generally provided a lower contribution to our margin than either the nuclear or coal units. We purchase natural gas when gas-fired generation is required to supply forward sale commitments.

In a changing market environment, this hedging strategy may cause our realized prices to differ materially from current market prices. In a rising price environment, this strategy normally results in lower margins than would have been the case if little or no hedging activity had been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins higher than those implied by the then current market.

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PSE&G

Our regulated public utility, PSE&G, distributes electric energy and gas to customers within a designated service territory running diagonally across New Jersey where approximately 5.5 million people, or about 70% of the State’s population, reside.

Products and Services

Our utility operations primarily earn margins through the transmission and distribution of electricity and the distribution of gas.

We also earn margins through non-tariff competitive services, such as appliance repair services. The commodity supply portion of our utility business’ electric and gas sales are managed by BGS and BGSS suppliers. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for our utility operations.

In addition to our current utility products and services, we have proposed several programs to improve efficiencies in customer energy use and increase the level of renewable generation to be constructed and owned by us including:

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¡				a proposed energy efficiency stimulus initiative to encourage conservation and energy efficiency and to provide energy and money saving measures directly to businesses and families, and
¡				a small scale carbon abatement program designed to promote energy efficiency.

For additional information concerning these proposed programs and the components of our tariffs, see Regulatory Issues.

How PSE&G Operates

Transmission

In September 2008, we received FERC approval to use formula transmission rates, effective October 1, 2008, for our existing and future transmission investments. Formula-type rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula which considers Operations and Maintenance expenditures, Rate Base and capital investments and applies an approved return on equity (ROE). Currently, approved rates provide for a ROE of 11.68% on existing and new transmission investment. FERC has also approved incentive rate treatment for the Susquehanna-Roseland line, which when added to the approved base ROE, will yield a ROE of 12.93% for this particular project. We will also earn this ROE on Construction Work In Progress (CWIP) dollars spent on this project.

For more information on current transmission construction activities, see Regulatory Issues, Federal Regulation—Transmission Regulation.

Distribution

All electric and gas customers in New Jersey have the ability to choose their own electric energy and/or gas supplier. However, pursuant to BPU requirements, we serve as the supplier of last resort for electric and gas customers within our service territory who have no other supplier. As a practical matter, this means we are obligated to provide supply to a vast majority of residential customers and a smaller portion of commercial and industrial customers.

The percentage of customers we serve as compared to that served by third party suppliers has been reasonably stable over the past several years. As shown in the table below, we continue to provide the electric energy and gas supply for the majority of the customers in our service territory for the year ended December 31, 2008.

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Our load requirements were split during 2008 among residential, commercial and industrial customers, described below. We believe that we have all the non-exclusive franchise rights (including consents) necessary for our electric and gas distribution operations in the territory we serve.

We procure the supply to meet our BGS obligations through two concurrent auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Results of these auctions determine which energy suppliers are authorized to supply BGS to New Jersey’s electric distribution companies (EDCs). Once validated by the BPU, electricity prices for BGS service are set.

BGSS is the mechanism approved by the BPU designed to recover all gas costs related to the supply for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. PSE&G has a full requirements contract through 2012 with Power to meet the supply requirements of our default service gas customers. Gas commodity costs under this contract are recovered from our customers. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates.

While our customer base has remained steady, electric load has been fairly flat and gas load has declined, as illustrated:

Markets and Market Pricing

There continues to be significant volatility in commodity prices. Such volatility can have a considerable impact on us since a rising commodity price environment results in higher delivered electric and gas rates for customers. This may result in decreased demand for both electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs may be deferred under our regulated rate structure. For additional information see Item 7. MD&A.

Energy Holdings

Through Energy Holdings, we own domestic generation outside of the Mid Atlantic region and own and manage passive energy-related investments. We are also pursuing an offshore wind project and a modest amount of solar and other renewable projects, primarily in our core markets.

Products and Services

We own 2,395 MW of domestic capacity in areas outside of the Mid Atlantic region, of which 2,000 MW comes from two 1,000 MW gas-fired, combined cycle generation facilities in Texas. The majority of our investments in international generation and distribution projects have been sold.

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Our passive energy-related investments consist primarily of leveraged leases. As of December 31, 2008, the single largest lease investment represented 13% of total leveraged leases.

How Energy Holdings Operates

Approximately 37% of the expected output of our Texas facilities for 2009 has been sold via bilateral agreements. Additional bilateral sales for peak and off-peak services are expected to be signed as the year progresses. Any remaining uncommitted economic output will be offered in the Texas spot market. Included in these bilateral agreements is a 350 MW daily capacity call option at Odessa that expires on December 31, 2010.

In August 2008, we invested in a joint venture to further develop compressed air energy storage (CAES) technology. CAES technology stores energy in the form of compressed air by injection into underground caverns or above ground storage facilities which can then be released to generate electricity through specialized turbine equipment. This technology could be used to optimize an intermittent energy source, such as wind, by storing energy at night and releasing this stored energy during the day when customers need power. Our plan is to use the technology to develop CAES power plants and sell licenses to third parties to implement CAES technology.

In October 2008, the New Jersey Office of Clean Energy (OCE) awarded a $4 million grant to a joint venture owned equally by one of our subsidiaries and an unaffiliated private developer, to advance the development of a 350 MW wind farm to be located approximately 16 miles off the shore of southern New Jersey. An offshore wind farm has not yet been developed and constructed in the U.S. Numerous issues, including federal and state permitting, environmental impacts, power output sale arrangements, construction approach and expected maintenance costs, will need to be worked through in order to successfully develop such a project. If these issues are satisfactorily addressed and the joint venture decides to proceed, the wind farm could be fully operational in 2013.

Our leasing portfolio is designed to provide a fixed rate of return. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as Operating Revenues as these events occur in the ordinary course of business of managing the investment portfolio.

Leveraged lease investments involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and, with respect to our lease investments, is not presented in our Consolidated Balance Sheets.

The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under applicable federal and state tax guidelines. The lessor receives income from lease payments made by the lessee during the term of the lease and from tax benefits associated with interest and depreciation deductions with respect to the leased property. The ability to realize these tax benefits is dependent on operating gains generated by our other operating subsidiaries and allocated pursuant to the consolidated tax sharing agreement between us and our operating subsidiaries. During 2008, we recorded after-tax charges of $490 million related to tax deductions previously claimed for certain of these leases that were recently disallowed by the Internal Revenue Service (IRS). See Note 11. Commitments and Contingent Liabilities for further discussion.

Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under GAAP, the lease investment is recorded net of non-recourse debt and income is recognized as a constant return on the net unrecovered investment.

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For additional information on leases, including the credit, tax and accounting risks related to certain lessees, see Item 1A. Risk Factors, Item 7. MD&A—Results of Operations—Energy Holdings, Item 7A. Qualitative and Quantitative Disclosures About Market Risk—Credit Risk—Energy Holdings and Note 11. Commitments and Contingent Liabilities.

Markets and Market Pricing

Our generation business in Texas is a merchant generation business located in the Electric Reliability Council of Texas (ERCOT) market. In balancing energy and ancillary service markets, an ISO will generally dispatch the lowest bids first unless local transmission congestion requires units to be dispatched out of merit order. The price that all dispatched units receive is set by the last, or marginal bidder that is dispatched. Our Texas generation assets are combined cycle gas-fired generation units and generally have lower variable costs than less efficient single cycle gas and oil-fired generation units. As a result, during on-peak periods, the price of power in ERCOT is frequently set by generation units with higher variable costs than our Texas generation assets. Unlike the other markets in which we compete, ERCOT does not have a capacity market, and as a result, all generators are compensated solely through energy revenues and revenues for ancillary services, which are subject to substantial volatility as power prices fluctuate.

ERCOT has decided to delay a proposed transition from a zonal market to a nodal wholesale market until the fourth quarter of 2010 at the earliest. As proposed, the redesigned grid will consist of more than 4,000 nodes replacing the current four congestion management zones. The implementation of the new design is expected to deliver improved price signals, improved dispatch efficiencies and direct assignment of local congestion. We will continue to evaluate the potential impact this change will have on our Texas generation facilities once implemented.

COMPETITIVE ENVIRONMENT

Power

Various market participants compete with us and one another in buying and selling in wholesale power pools, entering into bilateral contracts and selling to aggregated retail customers. Our competitors include:

Our business is also under competitive pressure due to demand side management (DSM) and other efficiency efforts aimed at changing the quantity and patterns of usage by consumers which could result in a reduction in load requirements. A reduction in load requirements can also be caused by economic cycles and factors. It is also possible that advances in technology, such as distributed generation, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. To the extent that additions to the transmission system relieve or reduce congestion in eastern PJM where most of our plants are located, our revenues could be adversely affected. In addition, pressures from renewable resources, such as wind and solar, could increase over time, especially if government incentive programs continue to grow.

We are also at risk if one or more states in which we operate should decide to turn away from competition and allow regulated utilities to continue to own or reacquire and operate generating stations in a regulated and potentially uneconomical manner, or to encourage rate-based generation for the construction of new base load units. This has occurred in certain states. The lack of consistent rules in energy markets can negatively impact the competitiveness of our plants. Also, regional inconsistencies in environmental regulations, particularly those related to emissions, have put some of our plants which are located in the

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Northeast, where rules are more stringent, at an economic disadvantage compared to our competitors in certain Midwest states.

Also, environmental issues such as restrictions on carbon dioxide (CO ₂₎ emissions and other pollutants may have a competitive impact on us to the extent it is more expensive for our plants to remain compliant, thus affecting our ability to be a lower-cost provider compared to competitors without such restrictions.

PSE&G

The electric and gas transmission and distribution business has minimal risks from competitors. Our transmission and distribution business is minimally impacted when customers choose alternate electric or gas suppliers since we earn our return by providing transmission and distribution service, not by supplying the commodity. The demand for electric energy and gas by customers is affected by customer conservation, economic conditions, weather and other factors not within our control.

Energy Holdings

New additions of lower cost or more efficient generation capacity in Texas could make our plants in the region less economical in the future. A number of competitors have announced plans to build additional coal-fired and gas-fired generation capacity in ERCOT. Although it is not clear if this capacity will be built or, if so, what the economic impact will be, such additions could impact market prices and our competitiveness.

Over the past several years, substantial amounts of wind generation capacity have been constructed in ERCOT, particularly in western Texas, where our Odessa generation facility is located. At the end of 2008, ERCOT had approximately 8,000 MW of installed wind capacity. Given the favorable wind conditions in western Texas, these wind generation facilities are able to produce power during a substantial period of the year, resulting in an additional source of base load power in western Texas, especially during off-peak seasons.

While numerous competitors have announced plans to build substantial amounts of new wind generation capacity, an issue impacting the likelihood of these projects being built is the constrained amount of transmission capacity between western Texas, where wind generation units are typically sited but where power demand is relatively low, and the rest of Texas.

The Public Utility Commission of Texas (PUCT) has designated five Competitive Renewable Energy Zones in western Texas and the Texas Panhandle in an effort to address the constraint issue. The PUCT has requested that ERCOT develop transmission construction options within these zones that would allow for much greater levels of delivery of wind power from western Texas to customers throughout the ERCOT grid. Although it is not clear if these efforts at transmission expansion will be successful or, if so, what the economic impact will be, it is possible that substantial additional amounts of wind generation will be built in ERCOT as a result of such potential transmission expansion, which could impact market prices and our competitiveness.

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REGULATORY ISSUES

Federal Regulation

FERC

The FERC is an independent federal agency that regulates the transmission of electric energy and gas in interstate commerce and the sale of electric energy and gas at wholesale pursuant to the Federal Power Act (FPA) and the Natural Gas Act. PSE&G and certain subsidiaries of Power and Energy Holdings are public utilities as defined by the FPA. By virtue of its regulation of (a) interstate electric and gas transmission and (b) wholesale sales of electricity and gas, the FERC has extensive oversight over “public utilities” as defined by the FPA. FERC approval is usually required when a “public utility” company seeks to: sell or acquire an asset that is regulated by the FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal corporate reorganizations.

The FERC also regulates generating facilities known as qualifying facilities (QFs). QFs are cogeneration facilities that produce electricity and another form of useful thermal energy, or small power production facilities where the primary energy source is renewable, biomass, waste, or geothermal resources. QFs must meet certain ownership, operating and efficiency criteria established by the FERC. Through Energy Holdings, we own several QF plants. QFs are subject to many, but not all, of the same FERC requirements as public utilities.

For us, the major effects of FERC regulation fall into four general categories:

Regulation of Wholesale Sales — Generation/Market Issues

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				In NEPOOL, many owners of generation facilities have also filed for RMR treatment. We currently collect FERC-approved monthly payments for the Bridgeport Harbor Station Unit 2 and the New Haven Harbor Station. These agreements are scheduled to expire in June 2010.
				RMR treatment has enabled these units to continue to operate. Various parties have challenged the continuation of RMR payments in NEPOOL, and thus, there is risk that such payments may be terminated prior to the end of the contract terms.
•				Reactive Power —Reactive power encompasses certain ancillary services necessary to maintain voltage support and operate the system. In May 2008, we filed with FERC to increase our annual fixed revenues by $18 million to reflect our provision of reactive power support in PJM. In November 2008, FERC accepted our reactive power rate filing retroactive to May 2008.

Capacity Market Issues

RPM is a locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to locate in areas where generation capacity is most needed. PJM’s RPM has been challenged in court.

In early 2006, certain interested market participants in New England agreed to a settlement that establishes the design of the region’s market for installed capacity and which is being implemented gradually over four years. Commencing in December 2006, all generators in New England began receiving fixed capacity payments that escalate gradually over the transition period. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of generators on the system and contains incentive mechanisms to encourage generator availability during generation shortages. Capacity market rules in both PJM and in New England may change in the future.

Transmission Regulation

The FERC has exclusive jurisdiction to establish the rates and terms and conditions of service for interstate transmission. We currently have FERC-approved formula rates in effect to recover the costs of our transmission facilities. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are then trued up the following year to reflect actual annual expenses/capital expenditures. Our allowed ROE is 11.68% for both existing and new transmission investments, and we have received incentive rates—affording a higher return on equity—for specific transmission investments.

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				Jersey Division of Rate Counsel, have opposed the incentive rate filing and have requested that the FERC set the matter for hearing. This filing is pending at the FERC.
				In December 2008, PJM approved another transmission project, including two additional 500 kV transmission lines. The first would run from Branchburg to Roseland, and the second from Roseland to Hudson. These lines are still in the design phase.
				U.S. Department of Energy (DOE) Congestion Study — National Interest Electric Transmission Corridors and FERC Back-Stop Siting Authority —By virtue of the Energy Policy Act enacted by Congress in 2005, the DOE has the ability to designate transmission corridors in areas found to be critical congestion areas, which then gives the FERC the ability to site transmission projects within these corridors should certain events occur.
				In October 2007, the DOE acted to designate transmission corridors within these critical congestion areas. One of the designated corridors is the Mid-Atlantic Area National Corridor. Thus, entities seeking to build transmission within the Mid-Atlantic Area Corridor, which includes New Jersey, most of Pennsylvania and New York, may be able to use the FERC’s back-stop siting authority in the future under certain circumstances, if necessary, to site transmission, including with respect to the Susquehanna-Roseland line. On February 18, 2009, the United States Court of Appeals for the Fourth Circuit narrowed the scope of the FERC’s back-stop siting authority, which may lead to future legislative changes in this area.

Compliance

Nuclear Regulatory Commission (NRC)

Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure protection of public health and safety, as well as the security and protection of the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. We anticipate filing for

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extensions of operating licenses for the Salem and Hope Creek facilities in 2009. The current operating licenses of our nuclear facilities expire in the years shown below:

State Regulation

Since our operations are primarily located within New Jersey, our main state regulator is the BPU. The BPU is the regulatory authority that oversees electric and natural gas distribution companies in New Jersey. PSE&G is subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service and the issuance and sale of certain types of securities. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.

We are also subject to some state regulation in California, Connecticut, Hawaii, New Hampshire, New York, Pennsylvania and Texas due to our ownership of generation and transmission facilities in those states.

Rates

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				public policy determinations. The programs that are covered by the SBC (gas and electric) are energy efficiency and renewable energy programs, Manufactured Gas Plant RAC and the Universal Service Fund (USF). In addition, the electric SBC includes a Social Programs component. All components include interest on both over and under recoveries.
				Non-utility Generation Charge (NGC) —The NGC recovers the above market costs associated with the long-term power purchase contracts with non-utility generators approved by the BPU.
				Recent Rate Adjustments — USF/Lifeline —On October 21, 2008, we received an Order to reset rates for the USF and the Lifeline program to recover $85 million and $61 million for USF electric and gas, respectively and $28 million and $16 million for Lifeline electric and gas, respectively. The new rates were effective October 24, 2008.
				SBC/NGC —On December 8, 2008, the BPU issued its final order approving an electric SBC/NGC rate increase of $89.7 million on an annual basis and a gas SBC increase of $15.3 million. The new rates were effective December 9, 2008. As part of the order, we were required to write off $1.4 million of previously deferred SBC costs.
				On February 9, 2009, we filed a petition requesting a decrease in our electric SBC/NGC rates of $18.9 million and an increase in gas SBC rates of $3.7 million. This matter is expected to be transferred to the Office of Administrative Law (OAL) for potential evidentiary hearings.
				RAC —On October 3, 2008, the BPU issued an order approving a settlement and affirming recovery of our RAC 15 costs of $36 million incurred from August 1, 2006 through July 31, 2007.
				On December 1, 2008, we filed a RAC 16 petition with the BPU requesting an Order which would increase our current gas RAC rates by approximately $8.9 million on an annual basis and increase our current electric RAC rates by approximately $7.6 million on an annual basis. This matter has been transferred to the OAL for evidentiary hearings.

Energy Supply

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For additional information, see Note 5. Regulatory Assets and Liabilities and Note 11. Commitments and Contingent Liabilities.

Energy Policy

Consistent with the EMP, we have proposed several programs in filings with the BPU addressing different components of the EMP goals, and have submitted a number of strategies designed to improve efficiencies in customer use and increase the level of renewable generation in the State.

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				approximately $105 million over two years in a pilot program to help finance the installation of 30 MW of solar systems throughout its electric service area by providing loans to customers for the installation of solar photovoltaic systems on their premises. The borrowers can repay the loans over a period of either 10 years (for residential customer loans) or 15 years by providing us with solar renewable energy certificates. Borrowers will also have the option to repay the loans with cash. The program is designed to fulfill approximately 50% of the BPU’s Renewal Portfolio Standard requirements in our utility service area in May 2009 and May 2010.
				In February 2009, we filed a new solar initiative with the BPU. This initiative is called the Solar 4 All Program. Through this program, we seek to invest approximately $773 million to develop 120 MW of solar photovoltaic (PV) systems over a five year horizon. The program consists of four segments: a centralized PV system (35MW); solar systems installed in distribution system poles (40MW), roof-mounted systems installed on local government buildings in our electric service territory (43MW) and roof-mounted solar systems installed in New Jersey Housing and Mortgage Finance Agency affordable housing communities (2MW). This program is under review by the BPU.
•				Carbon Abatement Program —In June 2008, we filed a petition for approval for a small scale carbon abatement program with the BPU, under which we propose to invest up to $46 million over four years in programs across specific customer segments. The program is designed to support EMP goals and promote energy efficiency. The BPU approved a settlement with new rates going into effect on January 1, 2009.
•				Demand Response (DR) —In July 2008, the BPU directed that DR programs be implemented by each of New Jersey’s electric utilities beginning in June 2009. In its order, the BPU established target goals to increase DR by 300 MW for the first year of the program and a total increase of 600 MW by the end of the third year and stated that 55% of the target would be our responsibility. In response, we filed our program proposal and identified $93.4 million of demand response investment over a period of four years, seeking full recovery of the program costs, including a return on our investment, through rates.
				In September 2008, the BPU voted to defer action on our program (and the proposed programs of the other New Jersey utilities) and to reconvene its working group which will focus on enrolling, with additional incentives, more New Jersey-based demand response in already-existing programs of PJM, in which our role would be limited. It is possible that the BPU may still act to approve all, or at least a portion, of our filing, but the outcome of this proceeding cannot be predicted.
				On December 10, 2008, the BPU issued an order directing each of the State’s electric utilities to implement a one-year demand response program in their respective service territories. The targeted amount of demand response for this program is 600 MW statewide, with a budget of $4.9 million, which represents an incentive in addition to PJM’s existing DR service programs. The utilities’ role is limited to collecting the program costs, plus administrative costs, through rates, and making the incentive payment to the DR service providers after PJM and the BPU direct the utilities to do so.
•				Energy Efficiency Economic Stimulus Program —On January 21, 2009, we filed for approval of an energy efficiency economic stimulus program, under which we proposed to spend $190 million to encourage conservation and create green jobs. This filing is in direct response to a call from New Jersey’s Governor to invigorate the economy as part of the State’s economic assistance and recovery plan. The Economic Energy Efficiency Stimulus Program filing was made under New Jersey’s Regional Greenhouse Gas Initiative (RGGI) legislation, which encourages utilities to invest in conservation and energy efficiency programs as part of their regulated business.
				The new expanded energy efficiency initiative offers programs for various targeted customer segments. Sub-programs for residential homes and small businesses in Urban Enterprise Zone municipalities, multi-family buildings, hospitals, data centers and governmental entities provide audits at no cost to identify energy efficiency measures. Customers could be eligible for incentives toward the installation of the energy efficiency measures. Other components include a program that provides

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				funding for new technologies and demonstration projects, and a program to encourage non-residential customers to reduce energy use through improvements in the operation and maintenance of their facilities.
•				Capital Economic Stimulus Infrastructure Program —On January 21, 2009, we also filed for approval of a capital economic stimulus infrastructure investment program and an associated cost recovery mechanism. Under this initiative, we propose to undertake $698 million of capital infrastructure investments for electric and gas programs over a 24 month period. These investments would be subject to deferred accounting and recovered through a new Capital Adjustment Mechanism. The goal of these accelerated capital investments is to help improve the State’s economy through the creation of new employment opportunities. While this filing was made in response to the Governor of New Jersey’s proposal to help revive the economy through job growth and capital spending, the outcome of this filing cannot be predicted at this time.
•				Susquehanna-Roseland BPU Petition —In January 2009, we filed a Petition with the BPU seeking authorization from the BPU to construct the New Jersey portion of the Susquehanna-Roseland line. The New Jersey portion of the line spans approximately 45 miles and crosses through 16 municipalities. The Petition seeks a finding from the BPU that municipal land use and zoning ordinances of these municipalities do not apply to this line. In this Petition and accompanying testimony, we explain the need for the line—that it is required to address 23 PJM-identified reliability violations—and we address issues such as engineering and design, route selection, construction impacts, property rights, environmental impacts and public outreach. The first prehearing conference in this proceeding is scheduled for February 26, 2009, at which time a procedural schedule will be established.

Compliance

The BPU has statutory authority to conduct periodic audits of our utility’s operations and its compliance with applicable affiliate rules and competition standards. The BPU has retained consultants to conduct periodic combined management/competitive service audits of New Jersey utilities and we could be subject to various audits in 2009.

ENVIRONMENTAL MATTERS

Our operations are subject to environmental regulation by federal, regional, state and local authorities. These environmental laws and regulations impact the manner in which our operations currently are conducted as

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well as impose costs on us to address the environmental impacts of historical operations that may have been in full compliance with the legal requirements in effect at the time those operations were conducted.

Areas of regulation may include, but are not limited to:

To the extent that environmental requirements are more stringent and compliance more costly in certain states where we operate compared to other states that are part of the same market, such rules may impact our ability to compete within that market. Due to evolving environmental regulations, it is difficult to project expected costs of compliance and their impact on competition. For additional information related to environmental matters, including anticipated expenditures for installation of pollution control equipment, hazardous substance liabilities and fuel and waste disposal costs, see Item 1A. Risk Factors, Item 3. Legal Proceedings and Note 11. Commitments and Contingent Liabilities.

Air Pollution Control

The Clean Air Act and its regulations require controls of emissions from sources of air pollution and also impose record keeping, reporting and permit requirements. Facilities that we operate or in which we have an ownership interest are subject to these federal requirements, as well as requirements established under state and local air pollution laws applicable where those facilities are located. Capital costs of complying with air pollution control requirements through 2010 are included in our estimate of construction expenditures in Item 7. MD&A—Capital Requirements.

The New Jersey Air Pollution Control Act requires that certain sources of air emissions obtain operating permits issued by the New Jersey Department of Environmental Protection (NJDEP). All of our generating facilities in New Jersey are required to have such operating permits. Our generating facilities in New York, Connecticut, Pennsylvania and Texas are under jurisdiction of their respective state’s environmental agencies. The costs of compliance associated with any new requirements that may be imposed by these permits in the future are not known at this time and are not included in capital expenditures, but may be material.

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				The remand allows the NO x trading program in CAIR to commence in 2009, with the annual NO x cap-and-trade program starting on January 1, 2009 (NJ, NY, PA, TX), and the Ozone season NO x cap-and-trade program starting May 1, 2009 (NJ, NY, CT, PA) in a separate and distinct cap- and-trade program. It is anticipated that, in aggregate, we will be net buyers of annual NO x allowances but will likely be allocated sufficient allowances to satisfy Ozone season NO x emissions. At recent market prices of annual NO x allowances, the cost of our estimated shortfall requirement of 3,000 allowances is approximately $10 million for 2009. The future direction of the market is unclear due to the recent court ruling and pending new administration leadership. The final cost of compliance is uncertain due to market instability.
				If the SO 2 part of CAIR is initiated on January 1, 2010, the financial impact to us is anticipated to be minimal due to the surplus allowances banked from the acid rain program that can be used to satisfy CAIR obligations.

Water Pollution Control

The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to waters of the U.S. from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including those in New Jersey, New York, Connecticut and Texas, to administer the NPDES program through state acts. We also have ownership interests in facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters that directly govern our facilities in those jurisdictions.

The EPA promulgated regulations under FWPCA Section 316(b), which require that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. The Phase II rule covering large existing power plants became effective in 2004. The Phase II regulations provided five alternative methods by which a facility can demonstrate that it complies with the requirement for best technology available for minimizing adverse environmental impacts associated with cooling water intake structures.

In January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision that remanded major portions of the regulations and determined that Section 316(b) of the Clean Water Act does not support the use of restoration and the site-specific cost-benefit test. The court instructed the EPA to reconsider the definition of best technology available without comparing the costs of the best performing technology to its benefits. Prior to this decision, we had used restoration and/or a site-specific cost-benefit test in applications we had filed to renew the permits at our once-through cooled plants, including Salem, Hudson and Mercer. Although the rule applies to all of our electric generating units that use surface waters for once-through cooling purposes, the impact of the rule and the decision of the court cannot be determined at this time.

The U.S. Supreme Court granted the request of industry petitioners, including us, to review the question of whether Section 316(b) of the FWPCA allows the EPA to compare costs with benefits in determining the “best technology available” for minimizing adverse environmental impact at cooling water intake structures. It is anticipated that the U.S. Supreme Court will render a decision before the end of its 2008-2009 term.

The decision could have a material impact on our ability to renew NPDES permits at our larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to our existing intake structures and cooling systems. The costs of those upgrades to one or more of our once-through cooled plants could be material and would require economic review to determine whether to continue operations.

Hazardous Substance Liability

Because of the nature of our businesses, including the production and delivery of electricity, the distribution of gas and, formerly, the manufacture of gas, various by-products and substances are or were produced or

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handled that contain constituents classified by federal and state authorities as hazardous. Federal and state laws impose liability for damages to the environment from hazardous substances. This liability can include obligations to conduct an environmental remediation of discharged hazardous substances as well as monetary payments, regardless of the absence of fault and the absence of any prohibitions against the activity when it occurred, as compensation for injuries to natural resources.

Fuel and Waste Disposal

Climate Change

In response to global climate change, many states, primarily in the Northeastern U.S., have developed state-specific and regional legislative initiatives to stimulate national climate legislation through CO ₂ emission reductions in the electric power industry. Ten Northeastern states, including New Jersey, New York and Connecticut, have signed a memorandum of understanding establishing the RGGI intended to cap and reduce

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CO ₂ emissions in the region. A model rule to reflect the memorandum of understanding was established and, in general, states adopted the elements of the model rule into state-specific rules to enable the RGGI regulatory mandate in each state.

States’ rules require the creation of a CO ₂ allowance allocation and/or auction whereby generators would be expected to receive through allocation, or purchase through an auction, CO ₂ allowances corresponding to each facility’s emissions. The first two CO ₂ emissions allowance auctions under RGGI were held in September and December 2008, resulting in prices of $3.07 and $3.38 per allowance, respectively. We anticipate that our 2009 generation would require purchases of approximately 16 million allowances at a total estimated cost of approximately $60 million at recent market prices.

New Jersey adopted the Global Warming Response Act in 2007, which calls for stabilizing its greenhouse gas emissions to 1990 levels by 2020, followed by a further reduction of greenhouse emissions to 80% below 2006 levels by 2050. To reach this goal, the NJDEP, the BPU, other state agencies and stakeholders are required to evaluate methods to meet and exceed the emission reduction targets, taking into account their economic benefits and costs.

In January 2008, additional legislation was enacted authorizing the NJDEP to sell, exchange, retire, assign, allocate or auction allowances from greenhouse gas emission reductions and set forth the procedural requirements to be followed by the NJDEP if allowances are auctioned. Auction proceeds would be used to provide grants and other forms of assistance for the purpose of energy efficiency, renewable energy and new high efficiency generation to stimulate or reward investment in the development of innovative CO ₂ reduction or avoidance technologies and stewardship of New Jersey’s forests and tidal marshes. The BPU allows an electric or gas public utility to offer programs for energy efficiency, conservation and Class I renewables and to recover associated costs, as well as a return on investment, in rates. The law further provides that the BPU shall adopt an emissions portfolio standard or other regulatory mechanism, to mitigate “leakage” by July 1, 2009, unless New Jersey’s Attorney General determines that this will unconstitutionally burden interstate commerce or would be preempted by federal law.

Absent the implementation of any mitigation mechanisms, the operations of plants within the RGGI region are likely to be reduced since the added costs to reduce CO ₂ emissions would increase operating costs making the less expensive facilities outside the RGGI region more likely to be dispatched.

On January 29, 2009, an owner of an electric generating unit in New York filed a complaint in New York state court challenging the legality of New York’s implementation of RGGI under both State and Federal law. The outcome of this litigation cannot be predicted, but could impact the continued implementation of RGGI in New York and potentially the RGGI region.

The new legislation also authorizes the BPU to require the disclosure on customer bills of the environmental characteristics of the delivered energy, to develop an interim renewable energy portfolio standard, a requirement for net metering and electric and gas energy efficiency portfolio standards.

A federal program that would impose uniform requirements on all sources of greenhouse gas emissions has not been implemented, thereby allowing for state and regional programs that may establish requirements that impose different costs in the markets where we compete.

In 2007, the U.S. Supreme Court issued a decision stating that the EPA has authority to regulate greenhouse gas emissions from new motor vehicles as air pollutants. This decision could have a future impact on us if the Supreme Court’s opinion or the section of the Clean Air Act relied upon by the Supreme Court in its decision is found to be supportive of regulating CO ₂ from other sources, including generation units, and it was applied by the EPA to existing regulatory programs under the Clean Air Act applicable to air emissions from our facilities.

The outcome of global climate change initiatives cannot be determined; however, adoption of stringent CO ₂ emissions reduction requirements in the Northeast, including the potential allocation of allowances to our facilities and the prices of allowances available through auction, could materially impact our operations. The financial impact of a requirement to purchase allowances for emissions of CO ₂ would be greatest on coal-

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fired generating units because they typically have the highest CO ₂ emission rate and thereby the need to purchase the most allowances. Gas-fired units would require fewer allowances and nuclear units would not need any allowances. Further, any addition of CO ₂ limit requirements under a national program, either through existing authority under the Clean Air Act, or under other legislative authority, could impose an additional financial impact on our fossil generation activities beyond that imposed by state and regional programs, such as RGGI. It is premature to determine the positive or negative financial impact of a future federal climate change program because it is difficult to determine the effect of such program on the dispatch of our electric generation units compared to the dispatch of other power generating companies, particularly those which may have a larger carbon footprint.

SEGMENT INFORMATION

Financial information with respect to our business segments is set forth in Note 20. Financial Information by Business Segment.