ITEM 1. BUSINESS
GENERAL
PSEG, PSE&G, Power and Energy Holdings
PSEG was incorporated under the laws of the State of New Jersey in 1985 and has its principal executive offices located at 80 Park Plaza, Newark, New Jersey 07102. PSEG has four principal direct wholly owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services). The following organization chart shows PSEG and its principal subsidiaries, as well as the principal operating subsidiaries of Power: PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T); and of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C. (Resources):
PSEG is an energy company with a diversified business mix. PSEG’s operations are primarily in the Northeastern and Mid Atlantic United States (U.S.) and in other select markets. As the competitive portion of PSEG’s business has grown, the resulting financial risks and rewards have become greater, causing financial requirements to change and increasing the volatility of earnings and cash flows.
For additional information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)-Overview of 2006 and Future Outlook.
Termination of Merger Agreement
On December 20, 2004, PSEG entered into an Agreement and Plan of Merger (Merger Agreement) with Exelon Corporation (Exelon) providing for a merger of PSEG with and into Exelon (Merger). On September 14, 2006, PSEG received from Exelon a formal notice terminating the Merger under the provisions of the Merger Agreement.
PSE&G
PSE&G is a New Jersey corporation, incorporated in 1924, and has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSE&G is an operating public utility company engaged principally in the transmission and distribution of electric energy and gas in New Jersey. In addition, PSE&G owns PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which are bankruptcy-remote entities that purchased the irrevocable right to receive certain non-bypassable charges per Kilowatt-hour (kWh) of energy delivered to PSE&G customers and issued transition bonds secured by such property.
PSE&G provides electric and gas service in areas of New Jersey in which approximately 5.5 million people, about 70% of the state’s population, reside. PSE&G’s electric and gas service area is a corridor of approximately 2,600 square miles running diagonally across New Jersey from Bergen County in the northeast to an area below the city of Camden in the southwest. The greater portion of this area is served with both electricity and gas, but some parts are served with electricity only and other parts with gas only. This heavily populated, commercialized and industrialized territory encompasses most of New Jersey’s largest municipalities, including its six largest cities-Newark, Jersey City, Paterson, Elizabeth, Trenton and Camden-in addition to approximately 300 suburban and rural communities. This service territory contains a diversified mix of commerce and industry, including major facilities of many nationally prominent corporations. PSE&G’s load requirements are split among residential, commercial and industrial customers, described below under customers. PSE&G believes that it has all the non-exclusive franchise rights (including consents) necessary for its electric and gas distribution operations in the territory it serves.
Energy Supply
PSE&G distributes electric energy and gas to end-use customers within its designated service territory. All electric and gas customers in New Jersey have the ability to choose an electric energy and/or gas supplier. Pursuant to the New Jersey Board of Public Utilities (BPU) requirements, PSE&G serves as the supplier of last resort for electric and gas customers within its service territory. PSE&G earns no margin on the commodity portion of its electric and gas sales.
As shown in the table below, PSE&G continues to provide the electric energy and gas supply for the majority of the customers in its service territory for the year ended December 31, 2006.
New Jersey’s Electric Distribution Companies (EDCs), including PSE&G, provide two types of Basic Generation Service (BGS). BGS-Fixed Price (FP) provides supply for smaller commercial and residential customers at seasonally-adjusted fixed prices and BGS-Commercial and Industrial Energy Price (CIEP) provides supply for larger customers at hourly PJM Interconnection, L.L.C. (PJM) real- time market prices. BGS prices are determined through annual auctions conducted before the BPU.
PSE&G has a full requirements contract with Power to meet the Basic Gas Supply Service (BGSS) requirements of PSE&G’s gas customers. The contract term extends to March 31, 2012, and year-to-year thereafter. Power charges PSE&G for gas commodity costs which PSE&G recovers from its customers.
Any difference between the BGS and BGSS costs and revenues received from PSE&G’s residential customers are deferred and collected or refunded through adjustments in future rates.
Distribution Rates
PSE&G earns margins through the transmission and distribution of electricity and gas. PSE&G’s revenues for these services are based upon tariffs approved by the BPU and FERC. Approximately 98% of PSE&G’s 2006 revenues were covered by BPU tariffs. The demand for electric energy and gas by PSE&G’s customers is affected by customer conservation, economic conditions, weather and other factors not within PSE&G’s control.
On November 9, 2006 the BPU approved separate settlements providing for increases in PSE&G’s electric and gas base rates. The settlements include a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file a joint electric and gas petition for any future base rate increases. For additional information on these settlements, see Regulatory Issues-State Regulation.
Market Price Environment
Over the past few years, there has been a significant volatility in commodity prices, including fuel, emission allowances and electricity. Such volatility can have a considerable impact on PSE&G since a rising commodity price environment results in higher delivered electric and gas rates for end-use customers, and may result in decreased demand by end users of both electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs may be deferred under PSEG’s regulated rate structure. For additional information see Item 7. MD&A.
Competitive Environment
The electric and gas transmission and distribution business has minimal risks from competitors. PSE&G’s transmission and distribution business is minimally impacted when customers choose alternate electric or gas suppliers since PSE&G earns its return by providing transmission and distribution service, not by supplying the commodity.
Customers
As of December 31, 2006, PSE&G provided service to approximately 2.1 million electric customers and approximately 1.7 million gas customers, detailed below. In addition to its transmission and distribution business, PSE&G also offers appliance services and repairs to customers throughout its service territory.
Employee Relations
As of December 31, 2006, PSE&G had 6,154 employees. PSE&G has six-year collective bargaining agreements, which were ratified in 2005, with four unions representing 4,955 employees. PSE&G believes that it maintains satisfactory relationships with its employees.
Power
Power is a Delaware limited liability company, formed in 1999, and has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Power is a multi-regional, wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management functions through three principal direct wholly owned subsidiaries: Nuclear, Fossil and ER&T.
As of December 31, 2006, Power’s generation portfolio consisted of approximately 14,639 MW of installed capacity, which is primarily located in the Northeast and Mid Atlantic regions of the U.S. where
some of the nation’s largest and most developed energy markets are located. For additional information, see Item 2. Properties.
As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a series of energy-related products used to optimize the operation of the energy grid, known as ancillary services. Power’s revenues also include gas supply sales under the BGSS contract with PSE&G.
Nuclear
Nuclear has an ownership interest in five nuclear generating units: the Salem Nuclear Generating Station, Units 1 and 2 (Salem 1 and 2), each owned 57.41% by Nuclear and 42.59% by Exelon Generation; the Hope Creek Nuclear Generating Station (Hope Creek), which is owned 100% by Nuclear; and, the Peach Bottom Atomic Power Station Units 2 and 3 (Peach Bottom 2 and 3), each of which is operated by Exelon Generation and owned 50% by Nuclear and 50% by Exelon Generation. For additional information, see Item 2. Properties-Power.
Nuclear Operations
In January 2005, Nuclear entered into an Operating Service Contract (OSC) with Exelon Generation relating to the operation of the Hope Creek and Salem nuclear generating stations. The OSC requires Exelon Generation to provide key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement a management model that Exelon has used to manage its own nuclear facilities. Nuclear continues as the license holder with exclusive legal authority to operate and maintain the Salem and Hope Creek plants, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities. In October 2006, Nuclear informed Exelon Generation that it was electing to continue the OSC for up to two years beyond the initial January 2007 period.
In December 2006, Power announced its plans to resume direct management of the Salem and Hope Creek nuclear generating stations before the expiration of the OSC. As part of this plan, on January 1, 2007, the senior management team at Salem and Hope Creek, which consisted of three senior executives from Exelon Generation, became employees of Power.
During 2006, over half of Power’s generating output was from its nuclear generating stations. Nuclear unit capacity factors for 2006 were as follows:
For additional information on recent operational issues, see Regulatory Issues-Nuclear Regulatory Commission (NRC).
Nuclear Fuel
Nuclear has several long-term purchase contracts for the supply of nuclear fuel for the Salem and Hope Creek Nuclear Generating Stations which include:
The nuclear fuel markets are competitive and although prices for uranium, conversion and enrichment are increasing, Nuclear does not anticipate any significant problems in meeting its future requirements.
Nuclear has been advised by Exelon Generation that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom. For additional information, see Item 7. MD&A-Overview of 2006 and Future Outlook-Power and Note 12. Commitments and Contingent Liabilities of the Notes.
Fossil
Fossil has an ownership interest in 17 generating stations, primarily in the Northeast and Mid Atlantic U.S., including the Bethlehem Energy Center in New York and the Linden station in New Jersey, which were completed and placed in service in 2005 and 2006, respectively. Power’s facility in Indiana, the Lawrenceburg Energy Center, is currently under an agreement to be sold. For additional information, see Item 2. Properties-Power.
Fossil uses coal, natural gas and oil for electric generation. These fuels are purchased through various contracts and in the spot market and represent a significant portion of Power’s working capital requirements. In order to minimize emissions levels, the Bridgeport generating facility uses a specific type of coal, which is obtained from Indonesia through a fixed-price supply contract that runs through 2008. If the supply of coal from Indonesia or equivalent coal from other sources was not available for the Connecticut facilities, additional material capital expenditures could be required to modify the existing plants to enable their continued operation. In addition, the Hudson facility, under a consent decree with the New Jersey Department of Environmental Protection (NJDEP) and the U.S. Environmental Protection Agency (EPA), will also utilize this type of coal. Power believes it has access to sufficient fuel supply, including transportation, for its facilities over the next several years. For additional information, see Item 7. MD&A-Overview of 2006 and Future Outlook-Power and Note 12. Commitments and Contingent Liabilities of the Notes.
ER&T
ER&T purchases the capacity and energy produced by each of the generation subsidiaries of Power. In conjunction with these purchases, ER&T uses commodity and financial instruments designed to cover estimated commitments for BGS and other bilateral contract agreements. ER&T also markets electricity, capacity, ancillary services and natural gas products on a wholesale basis. ER&T is a fully integrated wholesale energy marketing and trading organization that is active in the long-term and spot wholesale energy and energy-related markets.
Electric Supply
Power’s generation capacity is comprised of a diverse mix of fuels of approximately 47% gas, 26% nuclear, 18% coal, 8% oil and 1% pumped storage. Power’s fuel diversity serves to mitigate risks associated with fuel price volatility and market demand cycles.
The following table indicates proportionate MWh output of Power’s generating stations by fuel type, based on actual 2006 output of approximately 54,000 MWhs, and its estimated 53,000 MWh output by fuel type for 2007.
For a discussion of Power’s management and hedging strategy relating to its energy sales supply and fuel needs, see Market Price Environment and Item 7A. MD&A-Overview of 2006 and Future Outlook-Power.
Gas Supply
As described above, Power sells gas to PSE&G under the BGSS contract. Additionally, based upon availability, Power sells gas to others. About 41% of PSE&G’s peak daily gas requirements are provided through firm transportation, which is available every day of the year. The remainder comes from field storage, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery and landfill gas. Power purchases gas for its gas operations directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipeline suppliers.
Power has approximately 1 billion cubic-feet-per-day of firm transportation capacity under contract to meet the primary needs of PSE&G’s gas consumers and the needs of its own generation fleet. In addition, Power supplements that supply with a total storage capacity of 78 billion cubic feet that provides a maximum of approximately 1 billion cubic feet-per-day of gas during the winter season.
Power expects to be able to meet the energy-related demands of its firm natural gas customers. However, the ability to maintain an adequate supply could be affected by several factors not within Power’s control, including curtailments of natural gas by its suppliers, severe weather and the availability of feedstocks for the production of supplements to its natural gas supply. In addition, supply of all types of gas is affected by the nationwide availability of all sources of fuel for energy production.
Market Price Environment
System operators in the electric markets in which Power participates will generally dispatch the lowest cost units in the system first, with higher cost units dispatched as demand increases. As such, nuclear units, with their low variable cost of operation, will generally be dispatched whenever they are available. Coal units generally follow next in the merit order of dispatch and gas and oil units generally follow to meet the total amount of demand. The price that all dispatched units receive is set by the last, or marginal unit that is dispatched.
This method of determining supply and pricing creates an environment where natural gas prices often have a major impact on the price that generators will receive for their output, especially in periods of relatively strong demand. As such, significant changes in the price of natural gas will often translate into significant changes in the price of electricity.
As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, commodity prices, such as electricity, gas, coal and emissions, as well as the availability of Power’s diverse fleet of generation units to produce these products, when necessary, have a considerable effect on Power’s profitability. There is significant volatility in commodity markets, including electricity, fuel and emission allowances. For example, the spot price of electricity at the quoted PJM West market has increased from an average of about $25 per MWh for 2002 to an average of about $60 per MWh in 2005 and then decreased to an average of about $50 per MWh in 2006. Similarly, the price of natural gas at the Henry Hub terminal has increased from an average of about $3 per one million British Thermal Units (MMBtu) in 2002 to about $9 per MMBtu in 2005 and then decreased to an average of about $7 per MMBtu in 2006. The prices at which transactions are entered into for future delivery of these products, as evidenced through the market for forward contracts at points such as PJM West, have escalated as well. The historical spot prices and forward prices as of year-end 2006 are reflected in the graphs below.
In the electricity markets where Power participates, the pricing of electricity can vary by location. For example, prices may be higher in congested areas due to transmission constraints during peak demand periods reflecting the bid prices of the higher cost units that are dispatched to supply demand. This typically occurs in the eastern portion of PJM, where many of Power’s plants are located. At various times, depending upon its production and its obligations, these price differentials can serve to increase or decrease Power’s profitability.
While the prices reflected in the tables above do not necessarily represent prices at which Power has contracted, they are representative of market prices at relatively liquid hubs, with nearer term forward pricing generally resulting from more liquid markets than pricing for later years. While they provide some perspective on past and future prices and recent prices are considerably higher than in prior years, the forward prices are highly volatile, and there is no assurance that such prices will remain in effect nor that Power will be able to contract its output at these forward prices.
Power is also provided with payments from the various markets for the capability to provide electricity, known as a capacity payments, which are reflective of the value to the grid for having the assurance of sufficient generating capacity to meet system reliability and energy requirements, and to encourage the future investment in adequate sources of new generation to meet system demand. While there is generally sufficient capacity in the markets in which Power operates, there are certain areas in these markets where there are constraints in the transmission system, causing concerns for reliability and a more acute need for capacity. Some generators, including Power, announced the retirement of certain older generating facilities in these constrained areas due to insufficient revenues to support their continued operation. In separate instances, both PJM and the New England Power Pool (NEPOOL) responded with Reliability-Must-Run (RMR) contracts for these units to enable their continued availability that provide their owners with fixed payments which, while not necessarily reflective of the full value of those units’ contribution to reliability (e.g. they are
cost-based), are nonetheless significant. Such payment structure by its nature acknowledges that these units provide a reliability service that is not compensated in the existing markets. It also suggests that fixed periodic payments, as would be provided in a capacity market, are an appropriate form of compensation for such units for this service. Power receives RMR payments in both PJM and NEPOOL.
In addition, FERC issued certain orders in 2006 related to market design that have changed the nature of capacity payments in the New England Power Pool (NEPOOL) and is scheduled to change the nature of payments in PJM. In PJM, a new capacity-pricing regime known as the Reliability Pricing Model (RPM) will provide generators with differentiated capacity payments based upon the location of their respective facilities. Similarly, the Forward Capacity Market (FCM) settlement in NEPOOL provides for locational capacity payments. Both market designs are based in part on the premise that a more structured, forward-looking, transparent pricing scheme will give prospective investors in new generating facilities more clarity on the future value of capacity, sending a pricing signal to encourage expansion of capacity for future market demands. FERC has approved the market changes in each of these markets, with the anticipated start date for RPM set for June 1, 2007 and FCM transition period having begun on December 1, 2006. Power believes that the majority of its generating capacity may experience changes in value from aspects of these market designs. While Power believes it may derive considerable additional revenue from these changes, it is difficult to predict the ultimate outcome of these changes.
For additional information on Power’s collection of RMR payments in PJM and NEPOOL and the RPM and FCM proposals, see Regulatory Issues-Federal Regulation.
Competitive Environment
Power’s competitors include merchant generators with or without trading capabilities, including banks, funds and other financial entities, utilities that have generating capability or have formed generation and/or trading affiliates, aggregators, wholesale power marketers and developers of transmission and Demand Side Management (DSM) projects and combinations thereof. These participants compete with Power and one another buying and selling in wholesale power pools, entering into bilateral contracts and/or selling to aggregated retail customers.
Power’s businesses are also under competitive pressure due to technological advances in the power industry and increased efficiency in certain energy markets. For example, it is 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.
There is also a risk to Power if states 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 already occurred in certain states. The lack of consistent rules in energy markets can negatively impact the competitiveness of Power’s plants. Also, regional inconsistencies in environmental regulations, particularly those related to emissions, have put some of Power’s plants which are located in the Northeast, where rules are more stringent, at an economic disadvantage compared to its competitors in certain Midwest states.
Also, environmental issues such as air pollution controls may have a competitive impact on Power to the extent its plants are more expensive to maintain in compliance, thus affecting its ability to be a lower cost provider compared to competitors without such restrictions.
In addition, as discussed in the Regulatory Issues section herein-specifically, in the discussion concerning (i) Transmission Rates and Cost Allocation and (ii) Transmission Infrastructure-current rules being developed at FERC, at DOE and at PJM with respect to the construction of transmission and the allocation of costs for such construction may have the effect of altering the level playing field between transmission options and generation options, which could have a competitive impact upon PSEG and Power.
Customers
As EWGs, Power’s subsidiaries do not directly serve retail customers. Power uses its generation facilities primarily for the production of electricity for sale at the wholesale level. Power’s customers consist mainly of wholesale buyers, primarily within PJM, but also in New York and Connecticut. Power is at times a direct or indirect supplier of New Jersey’s EDCs, including PSE&G, depending on the positions it takes in the New Jersey BGS auction. In prior years, Power had also been a bidder in the CIEP auction, which serves large
industrial and commercial customers at hourly PJM real-time market prices for a term of 12 months. Power’s three-year contract with a Connecticut utility ended on December 31, 2006. These contracts are full requirements contracts, where Power is responsible to serve a percentage of the full supply needs of the customer class being served, including energy, capacity, congestion and ancillary services. In addition, Power has four-year contracts with two Pennsylvania utilities expiring in 2008 and is considering pursuing similar opportunities in other states.
PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract term was originally through March 31, 2007, and year-to-year thereafter. In the settlement of the 2005/06 BGSS proceeding the Parties agreed to an amendment to the contract that changed the contract term to March 31, 2012, and year-to-year thereafter. Power charges PSE&G for gas commodity costs which PSE&G recovers from its customers. Any difference between the residential gas cost charged by Power under the BGSS contract and revenues received from PSE&G’s residential customers are deferred and collected or refunded through adjustments in future rates.
For the year ended December 31, 2006, approximately 46% of Power’s revenue was comprised of billings to PSE&G for BGS and BGSS. See Note 21. Related-Party Transactions of the Notes for additional information.
Employee Relations
As of December 31, 2006, Power had 2,538 employees, of which 1,414 employees (705 employees for Fossil and 708 employees for Nuclear) are represented by three union groups under six-year collective bargaining agreements, which were ratified in February, July and August 2005, respectively. Power believes that it maintains satisfactory relationships with its employees.
Energy Holdings
Energy Holdings is a New Jersey limited liability company and is the successor to PSEG Energy Holdings Inc., which was incorporated in 1989. Energy Holdings’ principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. Energy Holdings has two principal direct wholly owned subsidiaries, which are also its segments: Global and Resources.
Energy Holdings pursued investment opportunities in the domestic and international energy markets, with Global focused on the operating segments of the electric industries and Resources primarily made financial investments in these industries.
Global
Global owns investments in power producers and distributors that own and operate electric generation and distribution facilities in selected domestic and international markets. See Item 2. Properties-Energy Holdings for discussion of individual investments, including significant power purchase agreements (PPAs), fuel supply agreements, financing structures and other matters.
Global’s assets include consolidated projects and those accounted for under the equity method. As of December 31, 2006, Global’s share of project MW and number of customers by region are as follows:
(1)
Total Capital Invested represents Global’s equity invested in the projects, excluding currency translation adjustments.
Energy Holdings has reduced its international risk by opportunistically monetizing investments at Global that no longer had a strategic fit. During the past three years, Global has received proceeds of over $1 billion from sales of investments in China, Brazil, Poland, India, Africa and the Middle East. The decrease in Global’s portfolio size due to the above sales was partially offset by strong earnings from its Texas generation facilities and its electric distribution companies in Chile and Peru. As a result, Global’s current portfolio is primarily comprised of investments in Chile, Peru and the United States. Global also has modest sized investments in Italy, India and Venezuela totaling about 8% of Global’s total investment balance.
As a result of these sales, approximately 50% of Global’s future earnings is expected to be derived from its domestic generation business, of which, over half are from its 2,000 MW gas-fired combined cycle merchant generation business in Texas, with the balance from its 12 fully-contracted generating facilities in which Global’s ownership interests equate to nearly 400 MW. The other 50% of Global’s earnings is expected to be essentially from three electric distribution businesses in Chile and Peru and a 183 MW hydro generation facility in Peru. The regulatory environments in both Chile and Peru have been generally constructive since Global acquired these investments. Rate cases are held every four years (with the next rate case beginning in 2008) and the rate calculation methodologies are designed to achieve a reasonable return on the net replacement value of each system. See Regulation for additional information on the regulatory process in Chile and Peru. Chile also maintains an investment grade rating and Peru’s rating, although non-investment grade, has improved.
Energy Holdings continues to review Global’s portfolio, with a focus on its international investments. As part of this review, Energy Holdings considers the returns of its remaining investments against alternative investments across the PSEG companies, while considering the strategic fit and relative risks of these businesses.
Market Price Environment
Global’s projects in California, Hawaii and New Hampshire are fully contracted under long-term PPAs with the public utilities or power procurers in those areas. Therefore, Global does not have price risk with respect to the output of such assets, and generally, with respect to such assets, has limited risk with respect to fuel prices. Global’s risks related to these projects are primarily operational in nature and have historically been minimal.
Global’s generation business in Texas (Texas Independent Energy. L. P. (TIE)) is a merchant generation business with higher risks. TIE seeks to enter into a mix of contracts to sell its output-approximately 20% of its output is sold under a five-year contract, which expires in 2010, and another 10% to 20% is sold forward under one-year on-peak calendar or seasonal contracts and the balance is sold during the year. As a result, TIE’s business is subject to substantial volatility in earnings and cash flows as power prices fluctuate. Although Global’s business in Texas has performed very well as high natural gas prices and the resulting high energy prices led to strong margins in 2005 and 2006, there can be no assurances that such pricing in the market will continue at these levels.
Competitive Environment
Although TIE’s generating stations operate very efficiently relative to other gas-fired generating plants, new technology could make TIE’s plants less economical in the future. Also, several competitors have announced plans to build a substantial amount of capacity in the Electric Reliability Council of Texas (ERCOT) market. Although it is not clear if this capacity will be built or, if so, what the economic impact would be, such additions could impact market prices and TIE’s competitiveness. Also, as ERCOT transitions to nodal pricing from zonal pricing the competitiveness of TIE’s generating plants could be impacted. As TIE represents a substantial portion of Energy Holdings’ and Global’s business, volatility in that portion of the business will impact Global’s and Energy Holdings’ overall portfolio results.
Of the remaining portion of Global’s business, the majority of its earnings are generated by two major rate-regulated distribution businesses in Chile and one in Peru. Although these entities are not granted exclusive franchises, there is minimal competition for distribution companies. See Regulatory Issues-International Regulation for a discussion of the ratemaking process in Chile and Peru. Global also owns a
hydro generation facility in Peru. Although new generation capacity is being built in Peru, there are not many opportunities for hydro expansion, mitigating competition with Global’s hydro generation investment.
Customers
Global has ownership interests in three distribution companies in South America which serve approximately two million customers. Global also has ownership interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers through PPAs, as well as into the wholesale market. For additional information, see Item 2. Properties-Energy Holdings.
Resources
Resources has investments in energy-related financial transactions and manages a diversified portfolio of assets, including leveraged leases, operating leases, leveraged buyout funds, limited partnerships and marketable securities. Established in 1985, Resources has a portfolio of approximately 45 separate investments. Resources does not anticipate making significant additional investments in the near term.
Resources also owns and manages a Demand Side Management (DSM) business. DSM revenues are earned principally from monthly payments received from utilities, which represent shared electricity savings from the installation of the energy efficient equipment.
The major components of Resources’ investment portfolio as a percent of its total assets as of December 31, 2006 were:
As of December 31, 2006, no single investment represented more than 10% of Resources’ total assets.
Leveraged Lease Investments
Resources maintains a portfolio that 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.
In a leveraged lease, the lessor acquires an asset by investing equity representing approximately 15% to 20% of the cost of the asset and incurring non-recourse lease debt for the balance. 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. In addition, 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 of Resources to realize these tax benefits is dependent on operating gains generated by its affiliates and allocated pursuant to PSEG’s consolidated tax sharing agreement. The Internal Revenue Service (IRS) has recently disallowed certain tax deductions claimed by Resources for certain of these leases. See Note 12. Commitments and Contingent Liabilities of the Notes 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 generally accepted accounting principles in the U.S. (GAAP), the lease investment is recorded on a net basis and income is recognized as a constant return on the net unrecovered investment.
Resources has evaluated the lease investments it has made against specific risk factors. The assumed residual-value risk, if any, is analyzed and verified by third parties at the time an investment is made. Credit risk is assessed and, in some cases, mitigated or eliminated through various structuring techniques, such as defeasance mechanisms and letters of credit. As of December 31, 2006, the weighted average credit rating of the lessees in the portfolio was A-/A3. Resources has not taken currency risk in its cross-border lease investments. Transactions have been structured with rental payments denominated and payable in U.S. dollars. Resources, as a passive lessor or investor, has not taken operating risk with respect to the assets it owns, so leveraged leases have been structured with the lessee having an absolute obligation to make rental payments whether or not the related assets operate. The assets subject to lease are an integral element in Resources’ overall security and collateral position. If the value of such assets were to be impaired, the rate of return on a particular transaction could be affected. The operating characteristics and the business environment in which the assets operate are, therefore, important and must be understood and periodically evaluated. For this reason, Resources will retain, as necessary, experts to conduct appraisals on the assets it owns and leases.
On December 28, 2005, Resources sold its interest in the Seminole Generation Station Unit 2 in Palatka, Florida. For additional information relating to this disposition, see Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes.
Resources’ ten largest lease investments as of December 31, 2006 were as follows:
For additional information on leases, including credit, tax and accounting risk related to certain lessees, see Item 7. MD&A-Results of Operations-Energy Holdings, Item 7A. Qualitative and Quantitative Disclosures About Market Risk-Credit Risk-Energy Holdings and Note 12. Commitments and Contingent Liabilities of the Notes.
As of December 31, 2006, Resources has a remaining gross investment in three leased aircraft of approximately $41 million. On September 14, 2005, Delta Airlines (Delta) and Northwest Airlines (Northwest), the lessees for Resources’ four remaining aircraft at that time, filed for Chapter 11 bankruptcy protection. This had no material effect on Energy Holdings as it continues to believe that it will be able to recover the recorded amount of its investments in these aircraft as of December 31, 2006, although no assurances can be given. In 2004 and 2005, Resources successfully restructured the leases and converted the Delta and Northwest leases from leveraged leases to operating leases. The Delta aircraft was sold in January 2006 generating a small gain for Resources.
Other Subsidiaries
Enterprise Group Development Corporation (EGDC), a commercial real estate property management business, is conducting a controlled exit from its real estate business. Total assets of EGDC as of December 31, 2006 and 2005 were $70 million and $71 million, respectively, less non-recourse debt of $19 million and $21 million, respectively less minority interest of $6 million for each year, for a net investment of approximately $45 million and $44 million, respectively. These investments are composed of three properties in New Jersey, Maryland and Virginia and an 80% partnership interest in buildings and land in New Jersey.
Employee Relations
As of December 31, 2006, Energy Holdings had 53 direct employees. In addition, Energy Holdings’ subsidiaries had a total of 1,091 employees, of which 692 were represented by unions under collective bargaining agreements expiring between June 2007 and January 2010. Energy Holdings believes that it maintains satisfactory relationships with its employees.
Services
Services is a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Services provides management and administrative and general services to PSEG and its subsidiaries. These include accounting, treasury, financial risk management, law, tax, communications, planning, development, human resources, corporate secretarial, information technology, investor relations, stockholder services, real estate, insurance, library, records and information services, security and certain other services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements. As of December 31, 2006, Services had 932 employees, including 100 employees represented by a union group under a six-year collective bargaining agreement that was ratified in February 2005. Services believes that it maintains satisfactory relationships with its employees.
REGULATORY ISSUES
Federal Regulation
Public Utility Holding Company Act (PUHCA)
PSEG, PSE&G, Power and Energy Holdings
The Energy Policy Act (EP Act), which became law on August 8, 2005, repealed PUHCA as of February 8, 2006 and established PUHCA 2005, which grants to FERC “books and records” oversight of public utility holding companies. PSEG had historically claimed an exemption from regulation by the SEC as a registered holding company under PUHCA. As part of that exemption, Fossil, Nuclear, certain subsidiaries of Fossil and certain subsidiaries of Energy Holdings with domestic operations obtained EWG or Qualifying Facility (QF) status (the latter designation obtained under the Public Utility Regulatory Policies Act of 1978 (PURPA)), while most of Energy Holdings’ foreign investments obtained Foreign Utility Company (FUCO) status. Notwithstanding the repeal of PUHCA, these companies have retained their designations as EWGs, FUCOs or QFs, since such designation affords certain protections under FERC’s PUHCA 2005. Specifically, companies subject to the provisions of PUHCA 2005 must provide state regulators access to their books and records. PSEG, PSE&G, Power and Energy Holdings do not expect PUHCA 2005 to materially affect their respective businesses, prospects or properties, and in October 2006, PSEG obtained from FERC a waiver of
PUHCA 2005’s accounting, record retention and reporting requirements. For additional information on the impact of PUHCA repeal, see State Regulation.
Environmental
PSEG, PSE&G, Power and Energy Holdings
PSEG and its subsidiaries are subject to the rules and regulations relating to environmental issues promulgated by the EPA, the U.S. Department of Energy (DOE) and other regulators. For information on environmental regulation, see Environmental Matters.
FERC
PSEG, PSE&G, Power and Energy Holdings
FERC is an independent federal agency that regulates the transmission of electric energy and sale of electric energy at wholesale in interstate commerce pursuant to the Federal Power Act (FPA). FERC also regulates the interstate transportation of, as well as certain wholesale sales of, natural gas pursuant to the Natural Gas Act. FERC’s oversight includes: merger review, compliance, including Standards of Conduct issues, transmission rates and terms and conditions of service, and market power, market design and capacity design and rates. Several PSEG subsidiaries, including PSE&G, Fossil, Nuclear, and ER&T, as well as certain subsidiaries of Fossil and certain domestic subsidiaries of Energy Holdings are “public utilities” as defined by the FPA and subject to extensive regulation by FERC. FERC’s regulation of public utilities is comprehensive and governs such matters as rates, services, mergers, financings, affiliate transactions, market conduct and reporting. FERC is also responsible under PURPA for administering PURPA’s requirements for QFs. PSEG, through its subsidiaries, owns several QF plants. QFs are subject to many, but not all, of the same FERC requirements as public utilities.
Expanded Merger Review Authority
PSEG, PSE&G, Power and Energy Holdings
The EP Act expanded FERC’s authority to review mergers and acquisitions under the FPA. It extended the scope of FERC’s authority to require prior FERC approval regarding transactions involving certain transfers of generation facilities, certain holding company transactions, and utility mergers and consolidations having a value in excess of $10 million. The EP Act requires that FERC, when reviewing proposed transactions, examine cross-subsidization and pledges or encumbrances of utility assets. PSEG, PSE&G, Power and Energy Holdings are unable to predict the effect of this authority on any potential future transactions in which they may be involved.
Compliance
Reliability Standards
PSEG, PSE&G, Power and Energy Holdings
The EP Act required FERC to empower a single, national Electric Reliability Organization (ERO) to develop and enforce national and regional reliability standards for the U.S. bulk power system. FERC has designated the North American Electric Reliability Corporation (NERC) as this ERO. NERC has filed with FERC delegation agreements that would in turn delegate, to a significant degree, the enforcement of such reliability standards to eight regional reliability councils approved by NERC, such as ReliabilityFirst. Thus, the relationship between NERC and the regional reliability councils (responsible for reliability standards compliance within a particular geographic region) is a contractual one. PSE&G’s transmission assets, and most of Power’s generation assets, are located within the geographic scope of Reliability First, and PSEG’s remaining domestic assets, including the New York, Connecticut and Texas generating assets, are within the scope of other regional reliability councils such as NPCC and ERCOT.
After being designated as an ERO, NERC asked FERC to approve a set of proposed mandatory Reliability Standards, many of which mirrored existing, voluntary standards. On October 20, 2006, FERC issued a Notice of Proposed Rulemaking (NOPR), which proposed to approve 83 of the 107 filed standards and asked for additional information regarding the remaining 24 standards. Compliance with these 83
standards, enforcement of which will largely be delegated to the regional reliability councils such as Reliability First, is mandatory and sanctions may attach for non-compliance. Pursuant to the EP Act, FERC has the ability to impose penalties of up to $1 million a day for violations of these standards. Under the NOPR, which is not yet a Final Rule, compliance with these Standards will be required by the commencement of the 2007 summer peak season. These Standards are applicable to transmission owners and generation owners, and thus PSEG, PSE&G, Power and Energy Holdings (or their subsidiaries) will be obligated to comply with the Standards. PSEG, PSE&G, Power and Energy Holdings are currently evaluating all of the requirements imposed by the Standards and are preparing to ensure that they will be in compliance by FERC-required date. It should be noted in this regard that PSE&G’s local control center (LCC) was the first control center voluntarily audited by NERC in January 2006 with respect to LCC “readiness.” NERC concluded in this audit that PSE&G has adequate facilities, processes, plans, procedures, tools, and trained personnel to effectively operate as an LLC within PJM and found no significant operational problems.
FERC Standards of Conduct
PSEG, PSE&G, Power and Energy Holdings
On January 18, 2007, FERC issued a NOPR which proposes to make certain changes to its Standards of Conduct applicable to both electric and natural gas transmission providers. The NOPR was issued in response to a decision by the United States Court of Appeals of the District of Columbia, which vacated FERC’s existing Standards of Conduct as they applied to natural gas pipelines. The NOPR, however, proposes changes to the Standards of Conduct for both natural gas and electric providers Some of the proposed changes include modifying the definition of Energy Affiliate and thereby changing the scope of applicability of the Standards of Conduct, changing the regulations with respect to the permissible tasks of “shared” employees (employees that may be shared by both the Transmission Provider and the Energy Affiliates) and modifying the information disclosure regulations. PSE&G is currently subject to FERC’s Standards of Conduct as a Transmission Provider and subsidiaries of Power and Energy Holdings are subject to the Standards of Conduct as Energy Affiliates. Thus, FERC’s proposed changes may have an impact on PSEG, PSE&G, Power and Energy Holdings and the interactions between these entities, although its impact is not clear at this time. PSEG is currently evaluating the NOPR and will file comments to the same prior to FERC issuing a Final Rule. The outcome of this proceeding cannot be predicted at this time.
Transmission Rates and Cost Allocation
PSEG, PSE&G and Power
PJM Schedule 12 Cost Allocation for Regional Transmission Expansion Planning( RTEP) Projects
On January 5, 2006, PJM proposed cost allocation recommendations for new transmission projects pursuant to Schedule 6 of its FERC-approved Operating Agreement and Schedule 12 of its Open Access Transmission Tariff (Tariff). PJM identified the “Responsible Customers” that would be required to pay for certain transmission upgrades approved through PJM’s Regional Transmission Expansion Planning (RTEP) process and the percentage of the project cost that would be allocated to such Responsible Customers. This was the first filing by PJM pursuant to these new cost allocation mechanisms and it included (i) large cost allocations to eastern load as a result of proposed construction in the western and southern portions of PJM and (ii) allocations to merchant transmission projects such as Neptune Regional Transmission System, LLC. On May 26, 2006, FERC issued an order that accepted and suspended PJM’s cost allocation filing, made the filing effective subject to refund as of May 30, 2006 and established a hearing and settlement judicial procedure.
In addition, on May 4, 2006, PJM made a second RTEP cost allocation filing at FERC, addressing cost allocations to Responsible Customers associated with additional RTEP projects. PSEG protested the filing, objecting to, among other things, PJM’s netting of cost impacts within a PJM zone to allocate RTEP costs and PJM’s failure to consider the impact of certain adjustments in determining zonal cost allocation.
On July 19, 2006, FERC consolidated PJM’s January 5, 2006 and May 4, 2006 filings that propose to allocate the costs of new transmission projects that PJM has directed to be built through its RTEP process. On July 21, 2006, PJM submitted to FERC a further proposal to allocate the costs of an additional group of new transmission projects that PJM has directed be built through its RTEP. The July 21, 2006 filing includes
allocations for the $850 million, 200-mile 500 kV Loudon transmission line which runs from Allegheny Power’s service territory, through West Virginia to Northern Virginia, as well as many other transmission projects in the PJM region. This proceeding was consolidated with the other two PJM cost allocation filings and was then the subject of settlement proceedings before a ALJ. Settlement discussions terminated in November 2006 and, on November 7, 2006, the proceedings were set for hearing, with a hearing to commence no later than June 19, 2007. PJM has used the same allocation methodology to identify which load should pay for these new transmission projects through regulated transmission rates. PSEG is actively participating in this proceeding, as the cost allocation methodology used by PJM may result in a disproportionate allocation of costs to loads in the eastern portion of PJM. However, assuming continued pass-through of transmission charges to retail customers, neither Power nor PSE&G are expected to be impacted by the allocation of Schedule 12 charges. PSEG, PSE&G and Power are unable to predict the outcome of this hearing at this time.
Regional through and out rates (RTOR)
RTOR are separate transmission rates for transactions where electricity originated in one transmission control area is transmitted to a point outside that control area. Both the Midwest Independent Transmission System Operator, Inc. (MISO) and PJM charged RTORs through December 1, 2004. FERC approved a new regional rate design, which became effective December 1, 2004 for the entire PJM/MISO region and approved the continuation of license plate rates and a transitional Seams Elimination Charge/Cost Adjustment/Assignment (SECA) methodology effective from December 1, 2004 through March 2006.
On February 10, 2005, FERC issued an order that accepted various SECA filings, established December 2004 as the effective date for the SECA rates, made them subject to refund and surcharge, and established hearing procedures to resolve the outstanding factual issues raised in the filings and the responsive pleadings.
A trial-type hearing was held in May 2006, encompassing a review of the actual amount of lost revenues to be recovered via the SECA mechanism. On August 10, 2006, the ALJ issued an initial decision finding that the rate design for the recovery of SECA charges is flawed, and that the SECA rate charges are therefore unjust, unreasonable and unduly discriminatory. FERC has not yet issued an order on review of the ALJ initial decision. In addition, in March 2006, PSE&G and Power entered into a settlement with a limited group of parties in PJM, which settlement was certified to FERC, under which the parties have agreed to pay and collect reductions of SECA revenues. On October 12, 2006, the limited settlement agreement was expanded to include additional parties and on January 18, 2007, an additional settlement agreement was entered into with certain MISO parties. FERC has not yet acted to approve the March, October or January SECA settlements. Due to the uncertainty of this proceeding, PSE&G has continued to defer the collection of any SECA revenues on its books. At the present time, PSEG, PSE&G and Power do not anticipate any adverse impact as a result of the SECA decision.
PJM Long-Term Transmission Rate Design
On May 31, 2005, FERC issued an order addressing the recovery of costs for transmission upgrades designated through PJM’s RTEP process. Among other matters, FERC’s order responded to a proposal to continue PJM’s current rate design, under which transmission customers pay rates within the particular transmission zone in which they take service. FERC concluded that the existing rate design may not be just and reasonable and it established a hearing to examine the justness and reasonableness of continuing PJM’s modified zonal rate design. Certain entities filed proposals with FERC on September 30, 2005 for alternative rate designs for the PJM region. PSE&G, as part of a coalition of potentially affected PJM transmission owners, filed answering testimony on November 22, 2005 that supported continuation of the zonal rate design in PJM.
A hearing was held in April 2006 and on July 13, 2006, a FERC ALJ issued a decision concluding that the existing PJM modified zonal rate design for existing facilities has been shown to be unjust and unreasonable, and should be replaced with a postage stamp rate design (single “postage stamp” rate paid by all transmission customers in PJM) for such facilities to be effective April 1, 2006. To mitigate rate impacts, the ALJ determined that the rate design should be phased in, so that no customer receives greater than a 10% annual rate increase. The ALJ also determined that the existing process for allocating costs of new transmission projects pursuant to Schedule 6 of PJM’s Operating Agreement and Schedule 12 of the PJM Tariff was just and reasonable. Briefs on exceptions to the ALJ’s initial decision and reply briefs were filed in this proceeding challenging the decision to find the existing rate design unjust and unreasonable, the appropriateness of imposing a postage stamp rate design, the decision as to the appropriateness of applying
the current Schedule 6 and Schedule 12 process for allocating costs of new transmission projects and the phase-in of the new rate design. FERC has not yet issued a decision on review of the ALJ’s initial decision. Should FERC ultimately approve this postage stamp rate design on review of the ALJ’s initial decision, or adopt one or a combination of the alternative rate designs proposed, assuming continued pass-through of transmission charges to retail customers, PSEG’s and PSE&G’s results of operations could be adversely impacted with no adverse impact currently anticipated for Power.
Market Power, Market Design and Capacity Issues
PSEG, PSE&G and Power
Market Power
Under FERC regulations, public utilities may sell power at cost-based rates or apply to FERC for authority to sell at market-based rates (MBR). PSE&G, ER&T and certain other subsidiaries of Fossil and Energy Holdings have applied for and received MBR authority from FERC, which permits them to sell power into the wholesale market at market-based rates. FERC requires that holders of MBR tariffs file an update, on a triennial basis, demonstrating that they continue to lack market power. On November 30, 2006, PSE&G and ER&T filed their respective triennial updated market power reports with FERC. FERC has not yet acted on these updated market power reports.
On May 19, 2006, FERC issued a NOPR concerning the standards to be used by FERC in granting market-based rate authority. The proposed regulations would adopt, in most respects, FERC’s current standards. In its NOPR, FERC suggests certain changes, such as in the areas of cost-based market power mitigation, modifications to the horizontal (generation) market power screens, and clarifications to existing vertical market power screens. On September 20, 2006, PSE&G and Power submitted comments in this NOPR proceeding. FERC has not yet issued a Final Rule in this rulemaking proceeding. The outcome of this proceeding and its impact on PSEG, PSE&G, Power and Energy Holdings cannot be predicted at this time, but Power does not expect the new rules to disqualify its MBR authority. However, no assurances can be given.
FERC’s MBR policies and the wholesale electricity markets which they help support are evolving and subject to change. Specifically, on December 19, 2006, the United States Court of Appeals for the Ninth Circuit overturned certain FERC orders in a series of cases, to which PSEG was not a party, which involved long term wholesale contracts entered into during the California Energy Crisis and, by so doing, seriously undermined the “contract sanctity” doctrine that had previously been applied to preserve these contracts. Moreover, the court held that FERC’s MBR policies are insufficient to establish that agreements reached under MBR tariffs are just and reasonable at the outset. Thus, the fact that a contract is entered into under a MBR tariff may not render it immune from “just and reasonable” review by FERC. This case will likely be appealed to the U.S. Supreme Court but represents a significant development and is one that will be monitored for its impact on the wholesale electric market in the future.
RMR Status
PJM
Although applicable tariff provisions differ from region to region, RMR tariff provisions provide compensation to a generation owner when a unit proposed for retirement must continue operating for reliability purposes. In September 2004, Power filed notice with PJM that it was considering the retirement of seven generating units in New Jersey, effective December 7, 2004, due to concerns about the economic viability of the units under the then current market structure. The units that were being considered for retirement were Sewaren 1, 2, 3 and 4, Kearny 7 and 8 and Hudson 1. Kearny 7 and 8 were retired in 2005. In response to Power’s filed notice, PJM identified certain system reliability concerns associated with the proposed retirements.
Effective February 24, 2005, subject to refund and hearing, Power began to collect a monthly fixed payment of $3.3 million, pre-tax, net of operating margins for the Sewaren 1, 2, 3 and 4 and Hudson 1 units. A detailed settlement was filed with FERC on September 23, 2005 that permits Power to recover annual fixed costs of approximately $19 million and $14.5 million, pre-tax, for the Sewaren and Hudson units, respectively, plus reimbursements of Power’s expenditures in connection with certain construction at the units that are necessary to maintain reliability, offset by certain revenues earned in PJM’s energy market.
FERC accepted this settlement retroactive to February 24, 2005. On March 28, 2006, Power filed a refund report with FERC pursuant to which Power refunded $11 million to PJM, although most of this refund related to the timing of payments under the settlement agreement and thus will be repaid to Power, with carrying charges, at a later date. FERC did not issue a public notice requesting comments on the report and no party has made any objections or other comments with respect to the report. Power is in the process of extending its RMR contract for Hudson Unit 1 through September 2010. For additional information, see Note 12. Commitments and Contingent Liabilities of the Notes.
New England
In the New England electricity market, many owners of generation facilities have filed with FERC for RMR treatment under the NEPOOL Open Access Transmission Tariff. If FERC grants RMR status for a generation facility located in the New England market, the owner is entitled to receive cost-of-service treatment for its facility for the duration of an RMR contract that it enters into with ISO New England Inc. On November 17, 2004, PSEG Power Connecticut LLC (Power Connecticut), a wholly owned indirect subsidiary of Power, filed a request for RMR treatment for the New Haven Harbor generation station and Unit 2 at the Bridgeport Harbor generation station. FERC issued an order on January 14, 2005, subject to refund and hearing which allowed Power Connecticut to begin collecting monthly fixed payments of approximately $1.6 million and $3.9 million, pre-tax, for reliability services provided by the Bridgeport Harbor Station, Unit 2 and the New Haven Harbor Station, respectively, net of operating margins. On June 17, 2005, Power Connecticut filed revised studies supporting monthly recovery of $1.3 million and $3.3 million, pre-tax, for the Bridgeport Harbor and New Haven Harbor units, respectively.
On April 21, 2006, Power Connecticut, the Connecticut Department of Public Utility Control, the Connecticut Office of Consumer Counsel and ISO New England Inc. filed with FERC a Joint Stipulation and Settlement Agreement and Motion for Expedited Consideration. The Joint Stipulation and Settlement settled all matters associated with the RMR agreements filed by Power Connecticut for its Bridgeport Harbor 2 and New Haven Harbor stations. Among other things, the settlement provides for monthly fixed payments of approximately $1 million for Bridgeport Harbor and $3 million for New Haven Harbor. The only disputed issues concern the standard of review applicable to certain types of potential tariff changes that could be filed in the future. No party has challenged the settlement rates proposed to become effective. The ALJ certified the settlement to FERC on June 21, 2006 as a contested offer of settlement. It is anticipated that the settlement will be approved as certified or, if modified, will not be modified in a manner that adversely affects the settlement rates. However, Power Connecticut cannot predict a final outcome at this time, as FERC has not yet acted to approve the settlement.
PJM Reliability Pricing Model (RPM)
On August 31, 2005, PJM filed its RPM with FERC. The RPM constitutes a locational installed capacity market design for the PJM region, including a forward auction for installed capacity priced according to a downward-sloping demand curve and a transitional implementation of the market design. FERC issued an order on April 20, 2006 that accepted most of the core concepts of the RPM filing with an implementation date of June 1, 2007. The April 20, 2006 order set certain details of the filing for paper hearing and technical conference procedures including the slope of the demand curve and the mechanism for identification of the locational capacity zones. Such hearing and technical conference procedures have now been completed. Also, commencing in June 2006, settlement discussions mediated by a FERC ALJ commenced at the request of certain intervenors. A final settlement was filed with FERC on September 29, 2006 with a requested approval date of no later than December 22, 2006. PSE&G and Power filed comments to the settlement supporting the basic structural elements of the RPM proposal but nonetheless requesting certain modifications which, in their view, would better promote the adequacy of generation reserves on a cost-effective basis. On December 22, 2006, FERC issued an order approving the September 29 settlement, with certain conditions. FERC’s approval of this settlement is expected to have a favorable impact on generation facilities located in constrained locational zones. The final revenue impact on Power of the settlement approved in the December 22, 2006 FERC order could result in incremental margin of $100 million to $150 million in 2007, with higher increases in future years as the full year impact is realized and existing capacity contracts expire. The April 20, 2006 order remains subject to rehearing requests filed by several parties. Moreover, on January 22, 2007, PSEG as well as other parties to the proceeding filed for rehearing of the December 22, 2006 order.
Given the pending rehearing requests and the likelihood of eventual judicial appeals, PSEG, PSE&G and Power are unable to predict the outcome of this proceeding.
Forward Capacity Market (FCM) Settlement in New England
On January 31, 2006, certain interested market participants in New England agreed to a settlement in principle of litigation regarding the design of the region’s market for installed capacity, which would institute a transition period leading to the implementation of a new market design for capacity as early as 2010. Commencing in December 2006, all generators in New England began receiving fixed capacity payments that escalate gradually over the transition period. RMR contracts, such as Power’s, would continue to be effective until the implementation of the new market design. The new market design is expected to consist of a forward auction for installed capacity that is intended to recognize the locational value of generators on the system, and is expected to contain incentive mechanisms to encourage generator availability during generation shortages. During the transition period, these payments are expected to benefit Power’s Bridgeport Harbor 2 plant. The final version of the settlement was filed with FERC on March 6, 2006 and was approved by order dated June 16, 2006 finding that, as a package, the settlement represents a just and reasonable outcome. The settlement was contested by certain parties and a rehearing was sought of the June 16, 2006 order. On October 31, 2006, FERC denied rehearing and accepted the FCM settlement in a final order; the order, however, remains subject to judicial challenge.
Transmission Infrastructure
PSEG, PSE&G, and Power
RTEP
On September 8, 2006, PJM filed with FERC a proposal that would significantly modify its regional transmission planning process for economic transmission planning. Currently, the PJM RTEP identifies transmission that is needed to address reliability, operational performance and economic needs of the PJM region based on historic congestion. The PJM proposal sought to expand the economic portion of the RTEP by forecasting economic congestion over its transmission planning horizon, which, in 2006, PJM modified from five to 15 years. PSE&G and Power filed a protest to the PJM proposal requesting that FERC reject PJM’s proposal or set it for hearing. On November 21, 2006, FERC issued an order conditionally accepting PJM’s proposed changes to the RTEP for economic transmission planning. FERC directed PJM to make certain modifications to its proposal, including requiring PJM to make a compliance filing within 120 days identifying how it will weigh and/or combine the metrics it proposes for determining the net benefits of a particular project and to make a compliance filing within 90 days elaborating on the criteria it will use to determine if an alternative project is more “economic” than an RTEP project. Nonetheless, PJM’s changes to its economic transmission planning process may result in the establishment of a preference for rate-based transmission solutions to address congestion, as opposed to reliance on private investment and competitive non-transmission market solutions. PSE&G and Power filed for rehearing of the November 21, 2006 FERC order on December 21, 2006. FERC has not yet issued an order on rehearing. PSEG, PSE&G and Power are unable to predict the final outcome of this proceeding.
DOE Congestion Study
On August 8, 2006, the DOE issued a National Electric Transmission Congestion Study (Congestion Study), as directed by Congress in the EP Act. This Congestion Study identified two areas in the U.S. as “critical congestion areas;” one of the areas is the region between New York and Washington, D.C. Under the EP Act, the DOE has the ability to designate transmission corridors in these “critical congestion areas,” to which FERC back-stop transmission siting authority will attach. Thus, corridor designation may facilitate the construction of rate-based transmission projects to address congestion in these corridors. The DOE has not yet designated any transmission corridors as a result of this Congestion Study but will likely do so in the first quarter of 2007. PSE&G and Power filed comments to the Congestion Study, in which they contended that the Congestion Study contained several analytical flaws. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding at this time.
LDV Complaint Proceeding
On December 30, 2004, Jersey Central Power & Light Company (JCP&L) filed a complaint at FERC against the other four signatories, including PSE&G, to the Lower Delaware Valley (LDV) Transmission System Agreement, which expires in 2027 and governs the construction of, and investment in, certain 500 kV transmission facilities in New Jersey. In the complaint proceeding, JCP&L seeks to terminate its payment obligations to the other contract signatories. A hearing was conducted in this proceeding in November 2006 and an initial decision is expected by the ALJ in March 2007. In this litigation, JCP&L is not only seeking to terminate its payment obligations to PSE&G of approximately $3 million per year through 2027, but also to receive credit from PSE&G and the other LDV Agreement parties for transmission facilities previously constructed by JCP&L in New Jersey; if the ALJ were to accept all of JCP&L’s crediting arguments, an outcome that is unlikely, PSE&G would owe approximately $5 million to JCP&L under the LDV Agreement. PSE&G cannot predict the outcome of this proceeding at this time.
PJM Strategic Initiative
In the fourth quarter of 2006, PJM launched a “strategic initiative” to more specifically define its role in the evolving wholesale energy markets. As part of this initiative, PJM sought comments from its members, including PSEG, on a number of items, including whether PJM should consider splitting its wholesale market operations from its transmission grid operations and whether PJM should consider changes to its current corporate governance structure. PJM has since pulled back from its idea of splitting market and grid operations but continues to consider whether there is a need to modify aspects of its current market and governance structure. PSEG will continue to actively participate in these discussions.
NRC
PSEG and Power
Nuclear’s operation of nuclear generating facilities is subject to continuous 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. Power has recently commenced the process to extend the operating licenses for the Salem and Hope Creek facilities. The current operating licenses of Power’s nuclear facilities expire in the years shown below:
Nuclear Safety Issues
In January 2004, the NRC issued a letter requesting Power to conduct a review of its Salem and Hope Creek nuclear generation facilities to assess the workplace environment for raising and addressing safety issues. Power responded to the letter in February 2004 and had independent assessments of the work environment at both facilities performed which concluded that Salem and Hope Creek were safe for continued operations, but also identified issues that needed to be addressed. These facilities were under enhanced oversight by the NRC related to the work environment until August 31, 2006, at which time the NRC provided a letter informing Power that its mid-cycle performance review had concluded that the substantive cross-cutting issue in the safety-conscious work environment area at Salem and Hope Creek was closed. The NRC has restored Salem and Hope Creek to normal oversight levels.
Recirculation Pump
In a letter to the NRC dated January 9, 2005, Power committed to install vibration-monitoring equipment on Hope Creek’s “B” Reactor Recirculation Pump prior to the unit’s return to service to address pump vibration concerns and replace the pump’s shaft during the next refueling outage or any sooner outage of sufficient duration. This commitment was the subject of a January 11, 2005 Confirmatory Action Letter
from the NRC. The shaft was replaced during the Hope Creek outage in April 2006. On April 20, 2006, the NRC issued a Closure of Confirmatory Action Letter indicating that all of the commitments were completed.
Other
PSE&G
Investment Tax Credits (ITC)
As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings (PLRs) that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets’ regulatory lives, which were terminated upon New Jersey’s electric industry deregulation. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC liability relating to PSE&G’s generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry in New Jersey. PSE&G was directed by the BPU to seek a PLR from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the tax normalization rules of the Internal Revenue Code. PSE&G filed a PLR request with the IRS in 2002.
On December 21, 2005, the U.S. Department of the Treasury (Treasury) proposed new regulations for comment addressing the normalization of ITC, replacing regulations originally proposed in 2003. The new proposed regulations, if finalized, would not permit retroactive application. Accordingly, the IRS’s conclusions in the above referenced PLRs would continue to remain in effect for all industry deregulations prior to December 21, 2005.
On April 26, 2006, the BPU issued an order to PSE&G revoking its previous instruction and directing PSE&G to withdraw its request for a PLR by April 27, 2006. The BPU asserted that the Treasury’s proposed regulation project was the more appropriate authority to rely upon in deciding the ITC issue.
On May 1, 2006, PSE&G filed a motion for reconsideration with the BPU requesting that it modify its April 26, 2006 order to PSE&G to withdraw the PLR request. On May 5, 2006, the BPU denied PSE&G’s motion for reconsideration and reiterated its order to withdraw the PLR request. On May 8, 2006, PSE&G filed a petition with the Appellate Court of New Jersey challenging the BPU’s order to withdraw the PLR. On May 11, 2006, the IRS issued a PLR to PSE&G. The PLR concluded that none of the generation ITC could be passed to utility customers without violating the normalization rules. While the holding in the PLR is a favorable development for PSE&G, the outstanding Treasury regulation project could overturn the holding in the PLR if the Treasury were to alter the position set out in the December 21, 2005 proposed regulations. The issue cannot be fully resolved until the final Treasury regulations are issued.
On May 16, 2006, the BPU voted in favor of a special investigation and hearing before the BPU concerning PSE&G’s actions leading up to receiving the PLR, specifically its failure to abide by the BPU order to withdraw the request. An order detailing such special investigation has not yet been issued and no investigation has begun.
On October 13, 2006, the Appellate Division of the Superior Court of New Jersey granted PSE&G’s motion to dismiss PSE&G’s appeal of the BPU’s order to withdraw the PLR since PSE&G has already received the PLR. The court also determined that if the BPU seeks to take future action against PSE&G based on the alleged violation of its order, PSE&G can restart the appeal.
State Regulation
PSEG, PSE&G, Power and Energy Holdings
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 securities. Power’s partial ownership of generating facilities in Pennsylvania, as well as PSE&G’s ownership of certain transmission facilities in Pennsylvania, are subject to regulation by the Pennsylvania Public Utility Commission (PAPUC), which oversees retail electric and natural gas service in Pennsylvania. PSE&G and Power are also subject to rules and regulations of the NJDEP and the New Jersey Department of Transportation (NJDOT).
As discussed below, various Power subsidiaries and Energy Holdings’ subsidiaries are subject to some state regulation in other individual states where they operate facilities, including New York, Connecticut, Indiana, Texas, California, Hawaii and New Hampshire.
PUHCA Repeal
On August 1, 2005, the BPU initiated a proceeding to consider whether additional ratepayer protections were necessary in light of the repeal of PUHCA by the EP Act. The proceeding considered the BPU’s current authority to protect utility ratepayers from risks associated with a utility being part of a holding company structure. The BPU determined that additional protections were necessary and commenced a two phase rulemaking to address its view of potential risks associated with a utility being part of a holding company structure. Phase I of the rulemaking effort resulted in the adoption of new regulations effective October 2, 2006, addressing the diversification activities of New Jersey utilities and their holding companies. These new rules impose a requirement that each New Jersey public utility and its holding company ensure that the aggregate assets of all nonutility activities in the holding company system do not exceed a defined percentage (25%) of the aggregate assets of the utility and utility- related assets in the holding company system without BPU consent. The rules broadly define utility-related activities to include such things as the production, generation, transmitting, delivering, storing, selling, marketing of natural gas, propane, electricity and other fuels to wholesale or retail customers, energy management services and sale of energy appliances. Both PSE&G and PSEG currently satisfy these requirements and expect to continue to satisfy them based on the companies’ current business plans. However, constant monitoring will be required to ensure that the regulation is satisfied and to meet the annual certification process. The BPU is currently developing Phase II of the rulemaking in a stakeholder process. In Phase II the BPU is proposing new regulations that would increase the BPU’s access to books and records, impose restrictions on service agreements between utilities and their affiliated service companies and impose additional requirements on utility board of director composition, utility participation in money pools and additional reporting obligations.
New Jersey Energy Master Plan
The Governor of New Jersey has recently directed the BPU, in partnership with other New Jersey agencies, to develop an energy master plan. State law in New Jersey requires that an energy master plan be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. In the Governor’s directive regarding the energy master plan, the Governor established three specific goals: (1) reduce the State’s projected energy use by 20% by the year 2020; (2) supply 20% of the State’s electricity needs with certain renewable energy sources by 2020; and (3) emphasize energy efficiency, conservation and renewable energy resources to meet future increases in New Jersey electric demand without increasing New Jersey’s reliance on non-renewable resources. In November, PSEG submitted a number of strategies designed to improve efficiencies in customer use and increase the level of renewable generation. During January and February 2007, PSEG has been actively involved in the broad-based constituent working groups created to develop specific strategies to achieve the goals and objectives. Public meetings on the energy master plan are expected take place during the first and second quarters of 2007, and a final plan is expected to be completed by October 2007. The outcome of this proceeding and its impact on PSEG, PSE&G and Power cannot be predicted at this time.
PSE&G and Power
BGS Auctions
All of New Jersey’s EDCs jointly procure the supply to meet their BGS obligations through two concurrent auctions authorized by the BPU for New Jersey’s total BGS requirement. Results of these auctions determine which energy suppliers are authorized to supply BGS to New Jersey’s EDCs. Certain conditions are required to participate in these auctions. Energy suppliers must agree to execute the BGS Master Service Agreement, provide required security within three days of BPU certification of auction results and satisfy certain creditworthiness requirements.
In 2006, the BPU initiated a proceeding to review the annual BGS procurement process as well as the policy issues thereto for all of the New Jersey EDCs. In June 2006, the BPU ruled on certain issues regarding the acquisition of BGS for the period beginning in June 2007. The BPU agreed that a descending clock auction format should be used for the procurement of BGS-FP supply for 2007.
On July 10, 2006, PSE&G filed the Joint EDC proposal for the procurement of BGS for the period beginning June 1, 2007. This proposal includes a descending clock auction format to be held in February 2007 for the procurement of all BGS supply. On October 28, 2006, the BPU approved a descending clock auction format for BGS-FP and BGS-CIEP supply for the period beginning June 1, 2007. On December 22, 2006, the BPU approved the remainder of the items in the EDCs filing, without material changes. The BPU also directed the EDCs to remit all remaining retail margin monies previously collected from larger customers to the State Treasurer in January 2007, and to remit any future collections of the retail margin to the State Treasurer on a quarterly basis. In 2003, the BPU directed the EDCs to collect a 0.5 per kWh retail adder from all BGS customers greater than 750 kW. These monies were held in a regulatory liability account. For additional information see Note 5 Regulatory Matters and Note 12. Commitments and Contingent Liabilities of the Notes.
PSE&G
Electric Distribution Financial Review
Based on the Electric Base Rate Case approved in July 2003, PSE&G recorded a regulatory liability in the second quarter of 2003 by reducing its depreciation reserve for its electric distribution assets by $155 million and amortized this liability from August 1, 2003 through December 31, 2005. The $64 million annual amortization of this liability resulted in a reduction of Depreciation and Amortization expense. PSE&G filed for a $64 million (based on 2003 test year sales volumes) annual increase in electric distribution rates effective January 1, 2006, subject to BPU approval, including a review of PSE&G’s earnings and other relevant financial information. Based on current sales volumes, the amount approximates $69 million.
On November 9, 2006, the BPU approved a settlement agreement reached by the parties to the proceeding authorizing a $22 million reduction to electric distribution rates, resulting in additional revenue to PSE&G of approximately $47 million annually based on current sales volumes.
The settlement includes a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file a joint electric and gas petition for any future base rate increases.
BGSS Filings
The parties to the 2005/2006 BGSS proceeding entered into a Stipulation in which the parties agreed that the BGSS Commodity Charge increases of September 1, 2005 and December 15, 2005 that were previously approved by the BPU on a provisional basis should become final. The BPU approved the Stipulation. In addition, all the remaining gas contract issues were also resolved and an amended Gas Requirements Contract was attached to the Stipulation and also approved by the BPU. The primary changes were the term was extended by five years and the default provision was changed from three days to one day.
PSE&G made its 2006/2007 BGSS filing on May 26, 2006. In this filing, PSE&G requested a reduction in annual BGSS gas revenues of approximately $19.7 million (excluding losses and New Jersey Sales and Use Tax) or approximately a 1.0% decrease to be implemented for service rendered on and after October 1, 2006 or earlier. Additionally, PSE&G requested an increase in its Balancing Charge. The combined impact of both changes for the class average residential heating customer is an increase in the winter monthly bills of approximately 0.1%; however, on an annual basis the impact is a decrease of approximately 0.2%.
The parties entered into a Stipulation to make the filed BGSS rate effective October 1, 2006 on a provisional basis. However, since the time of the filing, prices of gas futures have dropped significantly and as a result, additional BGSS data has been requested by and provided to the BPU. Settlement discussions with the BPU Staff were completed and a new Stipulation, dated October 27, 2006, was executed by the parties. This new Stipulation was approved by the BPU and results in a decrease in annual BGSS revenues of approximately $120 million, which is approximately a 6% reduction in a typical residential gas customer’s bill. The new BGSS rate became effective on November 9, 2006. The Stipulation did not include any change in the Balancing Charge.
The parties entered into a second Stipulation, which addresses the Balancing Charge only. The BPU Staff recommended a lower Balancing Charge than proposed by the Company and received agreement from Rate Counsel. The parties executed the Stipulation for the lower rate and BPU approval was received on January 17, 2007.
Remediation Adjustment Clause (RAC) Filing
PSE&G is engaged in a program to address potential environmental concerns regarding its former Manufactured Gas Plant (MGP) properties in cooperation with and under the supervision of NJDEP. The costs of the program are recovered through the Remediation Adjustment Clause (RAC). The RAC addresses costs in annual periods ending July 31st of each year. The expenditures in each RAC period are recovered over seven years. The costs of the program, including interest, are deferred and amortized as collected in revenues.
On December 5, 2005 the BPU approved for recovery $18 million for the RAC-12 remediation expenditures incurred from August 1, 2003 through July 31, 2004. No change in the RAC recovery factor was required.
In February 2007, PSE&G submitted its RAC-13 and RAC-14 filings with the BPU. In these filings, PSE&G seeks an order finding that the $71 million of RAC program costs incurred during the two-year period, August 1, 2004 through July 31, 2006, are reasonable and are available for recovery. PSE&G proposes that the current gas and electric RAC rates be reduced by approximately $18 million annually, effective July 1, 2007.
Gas Base Rate Case
On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78% increase in its gas base rates to cover the cost of gas delivery to be effective June 30, 2006. Approximately $55 million of the $133 million request was for an increase in book depreciation rates.
On November 9, 2006, the BPU approved a settlement agreement reached by the parties to the proceeding. The agreement provides for an annual increase in gas revenues of $40 million or approximately 1.1%. In addition, the settlement provides for an adjustment to lower book depreciation and amortization expense for PSE&G by approximately $26 million annually and the amortization of accumulated cost of removal that will further reduce depreciation and amortization expense by $13 million annually for five years.
The settlement includes a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file a joint electric and gas petition for any future base rate increases.
Societal Benefits Clause (SBC) Filing
On August 12, 2005, PSE&G filed a motion with the BPU seeking approval of changes in its electric and gas SBC rates and its electric non-utility generation transition charge (NTC) rates. For electric customers, the rates proposed were designed to recover approximately $106 million in SBC revenues offset by lower NTC rates of $93 million beginning January 1, 2006. For gas, the rates proposed were designed to recover approximately $10 million in SBC revenues. In 2006, PSE&G filed updates to its filing, modifying its requested changes to electric SBC/NTC rates and gas SBC rates. Public hearings were held and settlement discussions began on outstanding issues. On January 19, 2007, settlement documents were filed with the ALJ, which upon approval, would result in an annual increase of approximately $16 million in electric SBC/NTC revenues and $12 million in gas SBC revenues.
Deferral Audit
The BPU Energy and Audit Division conducts audits of deferred balances. A draft Deferral Audit-Phase II report relating to the 12-month period ended July 31, 2003 was released by the consultant to the BPU in April 2005. The draft report addressed the SBC, Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances. The consultant to the BPU found that the Phase II deferral balances complied in all material respects with the BPU orders regarding such deferrals, the consultant noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. For additional information regarding PSE&G’s Deferral Audit, see Note 12. Commitments and Contingent Liabilities of the Notes.
Gas Purchasing Strategies Audit
In January 2007, the BPU has issued an RFP to solicit bid proposals to engage a contractor to perform an analysis of the gas purchasing practices and hedging strategies of the four New Jersey gas distribution companies (GDC’s), including PSE&G. The primary focus will be to examine and compare the financial and physical hedging policies and practices of each GDC and to provide recommendations for improvements to these policies and practices. PSE&G cannot predict the outcome of this process.
New Jersey Clean Energy Program
In December 2004, the BPU has approved a funding requirement for each New Jersey utility applicable to Renewable Energy and Energy Efficiency programs for the years 2005 through 2008. The State of New Jersey has awarded contracts to two market managers, TRC Energy Services and Honeywell Utility Solutions to take over program management functions from the utilities. This transition is now expected to take place in the first half of 2007. For additional information regarding PSE&G’s Clean Energy Program, see Note 12. Commitments and Contingent Liabilities of the Notes.
Power
Connecticut
Legislation has been introduced in the Connecticut General Assembly that would impose a tax on electric generators of 50% on earnings above a 20% return on equity. Proceeds from this proposed “windfall profits tax” would be used to provide consumer rate relief. Legislation also has been introduced that would allow the state’s electric utility companies to build and place into rate base up to 300 megawatts of peaking electric generation.
Neither PSEG nor Power is able to predict whether any of such proposals will be enacted into law or their impact, if any, or whether similar initiatives may be considered in other jurisdictions.
Connecticut Department of Public Utility Control (DPUC)
To reduce the impact of federally-mandated congestion charges on Connecticut ratepayers, Connecticut has launched a procurement process to facilitate the development of incremental generation capacity, as authorized by legislation which permits the DPUC to establish a competitive procurement process intended to encourage new supply-side and demand-side resources. Specifically, the DPUC is required to develop and issue a request for proposals (RFP) to solicit the development of long-term projects, with local distribution companies serving as the counterparties to these contracts. The impact of this RFP process on Power Connecticut’s assets is unclear at the present time.
Energy Holdings
Texas
Global’s generation business in Texas (TIE) is a merchant generation business that participates, through its subsidiaries, Odessa-Ector Power Partners, L.P. (Odessa) and Guadalupe Power Partners, LP (Guadalupe), in the Texas wholesale energy market administered by ERCOT. Under the regulation of the Public Utility Commission of Texas, ERCOT performs three main roles in managing the electric power grid and marketplace: ensuring that the grid can accommodate scheduled energy transfers, ensuring grid reliability, and overseeing retail transactions. While neither TIE, Odessa nor Guadalupe are public utilities subject to the jurisdiction of FERC, they are subject to FERC jurisdiction for purposes of complying with NERC’s Reliability Standards (see discussion in Federal Regulation-Compliance-Reliability Standards).
Like other energy markets, energy prices in ERCOT have risen over the past few years due, in large measure, to higher fuel costs. In an attempt to lower electricity prices, the legislature in Texas is currently examining proposals for draft legislation that could affect the Texas market. PSEG does not know at this time if any legislation will ultimately pass, or if it does, what its effect will be on Global’s generation business in Texas.
International Regulation
Energy Holdings
Global
Global’s electric distribution facilities in South America are rate-regulated enterprises. Rates charged to customers are established by government authorities and are viewed by Global as currently sufficient to cover operating costs and provide a return on its investments. Global can give no assurances that future rates will be established at levels sufficient to cover such costs, provide a return on its investments or generate adequate cash flow to pay principal and interest on its debt or to enable it to comply with the terms of its debt agreements.
Chile
Distribution companies in Chile, including Chilquinta Energia S.A. (Chilquinta) and associated companies, Sociedad Austral de Electricidad S.A. (SAESA) and other members of the SAESA Group, are subject to rate regulation by the Comision Nacional de Energia (CNE), a national governmental regulatory authority. The Chilean regulatory framework has been in existence since 1982, with rates set every four years based on a model company for each typical concession area. The tariff which distribution companies charge to regulated customers consists of two components: the actual cost of energy purchased and an additional amount to compensate for the value added in distribution (DVA tariff). The DVA tariff considers allowed losses incurred in the distribution of electricity, administrative costs of providing service to customers, costs of maintaining and operating the distribution systems and an annual return on investment between 6% to 14% over inflation applied to the replacement cost of distribution assets. Changes in electricity distribution companies’ cost of energy are passed through to customers, with no impact on the distributors’ margins (equal to the DVA tariff). Therefore, distributors, including members of the SAESA Group and Chilquinta, should not be affected by changes in the generation sector which affect prices. The most recent tariff adjustments for members of the SAESA Group and Chilquinta occurred in 2004 and have been reviewed and approved by the CNE.
In addition, the first auction for long-term supply contracts for Chilean distribution companies was simultaneously conducted during 2006. SAESA and Chilquinta were successful in contracting for approximately 2,900 Gwh/yr and 800 Gwh/yr, respectively from various generation companies to supply their regulated customers needs starting in 2010 and continuing through 2020 and 2025 for SAESA and Chilquinta, respectively. A second auction process for additional needs for Chilquinta (approximately 1,800 Gwh/year) will be held during 2007.
Peru
Distribution companies in Peru, including Luz del Sur S.A.A. (LDS), are subject to tariff regulation by the Organismo Supervisor de la Inversion en Energia, a national governmental regulatory authority. The Peruvian regulatory framework has been in existence since 1992, with tariffs set every four years based on a model company. The tariff which distribution companies charge to regulated customers consists of two components: the actual cost of energy purchased plus an additional amount to compensate for the DVA tariff. The DVA tariff considers allowed losses incurred in the distribution of electricity, administrative costs of providing service to customers, costs of maintaining and operating the distribution systems and an annual return on investment of 8% to 16% over inflation, based on the replacement cost of distribution assets. Changes in electricity distribution companies’ cost of energy are passed through to customers, with no impact on the distributors’ margins (equal to the DVA tariff). Therefore, distributors, including LDS, should not be affected by changes in the generation sector, which affect prices. The most recent tariff adjustments for LDS occurred in connection with the 2005 tariff-setting process. New tariffs were effective as of November 1, 2005.
In addition, in accordance with local regulations, an auction was conducted at the end of December 2006 for prospective energy supply requirements for LDS. The total amount bid by Peruvian power producers was 650 MW of capacity. This supply combined with the contracts still in force are expected to be sufficient to meet LDS’s energy supply needs for 2007. In order to secure the growing supply needs for 2008 and beyond, management plans to conduct additional energy supply auctions, as necessary, during 2007. Management is concurrently exploring the feasibility of other forms of bilateral supply contracts, as well as advocating the extension of a law beyond December 2007, which currently allows LDS and other distribution companies without supply contracts, to draw energy from the grid, as required, at regulated prices to satisfy the regulated market’s demand.
SEGMENT INFORMATION
Financial information with respect to the business segments of PSEG, PSE&G, Power and Energy Holdings is set forth in Note 18. Financial Information by Business Segment of the Notes.
ENVIRONMENTAL MATTERS
PSEG, PSE&G, Power and Energy Holdings
Federal, regional, state and local authorities regulate the environmental impacts of PSEG’s operations within the U.S. Laws and regulations particular to the region, country or locality where PSEG’s operations are located govern the environmental impacts associated with its foreign operations. For both domestic and foreign operations, areas of regulation may include air quality, water quality, site remediation, land use, waste disposal, aesthetics, impact on global climate and other matters.
To the extent that environmental requirements are more stringent and compliance more costly in certain states where PSEG operates compared to other states that are part of the same market, such rules may impact its ability to compete within that market. Due to evolving environmental regulations, it is difficult to project expected costs of compliance and its impact on competition. For additional information related to environmental matters, see Item 3. Legal Proceedings.
PSEG, Power and Energy Holdings
Air Pollution Control
The Federal Clean Air Act (CAA) and its implementing regulations require controls of emissions from sources of air pollution and also impose record keeping, reporting and permit requirements. Facilities in the U.S. that Power and Energy Holdings operate or in which they 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 Power’s estimate of construction expenditures in Item 7. MD&A-Capital Requirements.
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The Federal government may order companies not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties of up to approximately $27,500 for each day of continued violation.
The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-burning units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to requests for information and, in January 2002, reached an agreement with the NJDEP and the EPA to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur Dioxide (SO2), Nitrogen Oxide (NOx), particulate matter and mercury from the coal-burning units at the Mercer and Hudson generating stations to ensure compliance with PSD/NSR. Power also agreed to spend at least $6 million on supplemental environmental projects and pay a $1 million civil penalty. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operations to commence.
Power notified the EPA and the NJDEP that it was evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution control equipment and other necessary modifications to the unit. On November 30, 2006, Power, reached an agreement with the EPA and NJDEP on an amendment to its 2002 agreement intended to achieve the emissions reductions targets of this agreement while providing more time to assess the feasibility of installing additional advanced emissions controls at Hudson.
The amended agreement with the EPA and the NJDEP will allow Power to continue operating Hudson and extend for four years the deadline for installing environmental controls beyond the previous December 31, 2006 deadline. Power will be required to undertake a number of technology projects (SCRs, scrubbers, baghouses, and carbon injection), plant modifications, and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of NOx, SO2, particulate matter, and mercury. In addition, Power has agreed to notify the EPA and NJDEP by the end of 2007 whether it will install the additional emissions controls at Hudson by the end of 2010, or plan for the orderly shut down of the unit.
Under the program to date, Power has installed Selective Catalytic Reduction Systems (SCRs) at Mercer at a cost of approximately $113 million. The cost of implementing the balance of the amended agreement at Mercer and Hudson is estimated at $400 million to $500 million for Mercer and at $600 million to $750 million for Hudson and will be incurred in the 2007-2010 timeframe. As part of the agreement, Fossil has agreed to purchase and retire emissions allowances, contribute approximately $3 million for programs to reduce particulate emissions from diesel engines in New Jersey, and pay a $6 million civil penalty.
SO2 / NOx
To reduce emissions of SO2 for acid rain prevention, the CAA sets a cap on total SO2 emissions from affected units and allocates SO2 allowances (each allowance authorizes the emission of one ton of SO2) to those units. Generation units with emissions greater than their allocations can obtain allowances from sources that have excess allowances. At this time, Power does not expect to incur material expenditures to continue complying with the acid rain SO2 emissions program.
The EPA has issued regulations (commonly known as the NOx State Implementation Plan (SIP) Call) requiring 19 states in the eastern half of the U.S. and the District of Colombia to reduce and cap NOx emissions from power plant and industrial sources. The NOx reduction requirements are consistent with requirements already in place in New Jersey, New York, Connecticut and Pennsylvania, and therefore have not had an additional impact on the capacity available from Power’s facilities in those states. Power has been implementing measures to reduce NOx emissions at several of its units (including the installation of selective catalytic reduction systems at the Mercer Generating Station), which has reduced the impact of any further increases to the costs of allowances.
In 1997, the EPA adopted a new air quality standard for fine particulate matter and a revised air quality standard for ozone. In 2004, the EPA identified and designated areas of the U.S. that fail to meet the revised federal health standard for ozone or the new federal health standard for fine particulates. States are expected to develop regulatory measures necessary to achieve and maintain the health standards, which may require reductions in NOx and SO2 emissions. Additional NOx and SO2 reductions also may be required to satisfy requirements of an EPA rule protecting visibility in many of the nation’s Class 1 (pristine) environmental areas. Most of Power’s fossil facilities would be affected by this initiative.
In May 2005, the EPA published the final Clean Air Interstate Rule (CAIR) that identifies 28 states and the District of Columbia as contributing significantly to the levels of fine particulates and/or eight-hour ozone in downwind states. New Jersey, New York, Pennsylvania, Indiana, Texas and Connecticut are among the states the EPA lists in the CAIR. Based on state obligations to address interstate transport of pollutants under the CAA, the EPA has proposed a two-phased emission reduction program for NOx and SO2, with Phase 1 beginning in 2009 (NOx) and 2010 (SO2) and Phase 2 beginning in 2015. The EPA is recommending that the program be implemented through a cap-and-trade program, although states are not required to proceed in this manner.
In December 2005, the EPA proposed new National Ambient Air Quality Standards for particulate matter.
Power is unable to determine whether any costs it may incur to comply with the above standards would be material.
Carbon Dioxide (CO2) Emissions
Several states, primarily in the Northeastern U.S., are developing state-specific or regional legislative initiatives to stimulate CO2 emissions reductions in the electric power industry. New York initiated the Regional Greenhouse Gas Initiative (RGGI) in April 2003. Currently, in the RGGI, seven Northeastern states have signed a memorandum of understanding (MOU) intended to cap and reduce CO2 emissions from the electric power sector in the RGGI region. A final model rule was issued on August 15, 2006 that includes
MOU commitments and makes recommendations for states to move forward. The model rule contemplates the creation of a CO2 allowance allocation and auction whereby CO2 generators in the electric power industry would be expected to acquire through allocation, or purchase through an auction, CO2 allowances in an amount corresponding to each facility’s emissions. Facilities with an insufficient number of allowances would be required to purchase additional allowances. New York has publicly announced its intent to subject 100% of the allowances to auction, and other states, including New Jersey, may do the same. States are expected to enact legislation and/or regulation representing, at least, the minimum requirements stipulated in the MOU. The RGGI program is scheduled to start in 2009. The NJDEP in 2005 finalized amendments to its regulations governing air pollution control that would designate CO2 as an air contaminant subject to regulation. In February 2007, the Governor of New Jersey issued an executive order committing the State to reduce emissions of greenhouse gasses 20% by 2020 and 80% by 2050. The outcome of this initiative cannot be determined at this time; however, adoption of stringent CO2 emissions reduction requirements in the Northeast, including the allocation of allowances to PSEG’s facilities and the prices of allowances available through auction, could materially impact Power’s operation of its fossil fuel-fired electric generating units.
Other Air Pollutants
In March 2005, the EPA promulgated two rules: one revising its December 2000 determination that Hazardous Air Pollutants from coal-fired and oil-fired Electric Generating Units (EGUs) should be regulated under section 112 of the CAA and, on that basis, removing those units from the section 112(c) source category list (known as the delisting rule); the second establishing a New Source Performance Standard limit for nickel emissions from oil-fired EGUs, and a cap-and-trade program for mercury emissions from coal-fired EGUs, with a first phase cap of 38 tons per year (tpy) in 2010 and a second phase cap of 15 tpy in 2018 (the ‘cap-and-trade rule’). The EPA determined that it would not regulate other emissions from coal-fired and oil-fired EGUs.
A number of environmental and medical groups, the city of Baltimore and a total of 16 states (all six New England states, New Jersey, California, Delaware, Illinois, New Mexico, New York, Minnesota, Pennsylvania, Michigan and Wisconsin) have sued the EPA challenging that the rules should be more restrictive. The environmental petitioners, but not the states, also sought a stay of the rules from both the agency and the court, but the request was denied. The outcome of these litigations cannot be determined at this time.
New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The Connecticut legislation requires coal-fired power plants in Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions effective in July 2008. The regulations in New Jersey require coal-fired electric generating units in New Jersey to meet certain emission limits or reduce emissions by 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012. Power has a multi-pollutant reduction agreement with the NJDEP as a result of a consent decree that resolved issues arising out of the PSD and NSR air pollution control programs at the Hudson, Mercer and Bergen facilities. Substantial uncertainty exists regarding the feasibility of achieving the reductions in mercury emissions required by the New Jersey regulations and Connecticut statute; however, the estimated costs of technology believed to be capable of meeting these emissions limits at Power’s coal-fired unit in Connecticut by July 2008 and at its Mercer Station by December 15, 2007 are included in Power’s capital expenditure forecast.
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 the NJDEP, to administer the NPDES program through state acts. The New Jersey Water Pollution Control Act (NJWPCA) authorizes the NJDEP to implement regulations and to administer the NPDES program with EPA oversight, and to issue and enforce New Jersey Pollutant Discharge Elimination System (NJPDES) permits. Power and Energy Holdings also have ownership interests in domestic 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 Power’s or Energy Holdings’ facilities in these jurisdictions.
The EPA promulgated regulations under FWPCA Section 316(b), which requires that cooling water intake structures reflect the best technology available (BTA) for minimizing ‘adverse environmental impact.’ Phase I of the rule covering new facilities became effective on January 17, 2002. None of the projects that Power currently has under construction or in development is subject to the Phase I rule. The Phase II rule covering large existing power plants became effective on September 7, 2004. The Phase II regulations provided five alternative methods by which a facility can demonstrate that it complies with the requirement for BTA for minimizing adverse environmental impacts associated with cooling water intake structures.
On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its decision in litigation of the Phase II rule brought by several environmental groups, the Attorneys General of six Northeastern states, the Utility Water Act Group and several of its members, including Power. The court remanded major portions of the rule 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. Among the provisions the court remanded back to EPA for further consideration and rulemaking, the court instructed EPA to reconsider the definition of BTA without comparing the costs of the best performing technology to its benefits. Prior to this decision, Power has used restoration and site-specific cost benefit tests in applications it has filed to renew the NJPDES permits at its once-though cooled plants, including Salem, Hudson and Mercer. Although the rule applies to all of Power’s 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 for all of Power’s facilities. Depending on the outcome of any appeals, or actions by EPA to repromulgate the rule, this decision could have a material impact on Power’s ability to renew its NPDES permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, New Haven and Bridgeport, without making significant upgrades to their existing intake structures and cooling systems. The costs of those upgrades could be material to one or more of Power’s once-through cooled plants.
Power
Permit Renewals
For information on permit renewals for Salem, see Note 12, Commitments and Contingent Liabilities of the Notes.
PSE&G and Power
Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and New Jersey Spill Compensation and Control Act (Spill Act)
CERCLA and the Spill Act authorize Federal and state trustees for natural resources to assess damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. In 2003, the NJDEP issued a policy directive memorializing its efforts to recover natural resource damages and its intent to continue to pursue the recovery of natural resource damages. The NJDEP also issued guidance to assist parties in calculating their natural resource damage liability for settlement purposes, but has stated that those calculations are applicable only for those parties that volunteer to settle a claim for natural resource damages before a claim is asserted by the NJDEP. PSE&G and Power cannot assess the magnitude of the potential financial impact of this regulatory change. See Note 12. Commitments and Contingent Liabilities of the Notes for additional information.
Because of the nature of PSE&G’s and Power’s respective 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 handled that contain constituents classified by Federal and state authorities as hazardous. For discussions of these hazardous substance issues and a discussion of potential liability for remedial action regarding the Passaic River, see Note 12. Commitments and Contingent
Liabilities of the Notes. For a discussion of remediation/clean-up actions involving PSE&G and Power, see Item 3. Legal Proceedings.
Uranium Enrichment Decontamination and Decommissioning Fund
In accordance with the EP Act, domestic entities that own nuclear generating stations are required to pay into a decontamination and decommissioning fund, based on their past purchases of U.S. government enrichment services. Since these amounts are being collected from PSE&G’s customers over a period of 15 years, this obligation remained with PSE&G following the generation asset transfer to Power in 2000. PSE&G’s obligation for the nuclear generating stations in which it had an interest was $76 million (adjusted for inflation). As of December 31, 2006, PSE&G and Power had both paid their remaining obligations.
New Jersey Operating Permits
The New Jersey Air Pollution Control Act requires that certain sources of air emissions obtain operating permits issued by NJDEP. All of Power’s generating facilities in New Jersey are required to have such operating permits. 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.
Power
Nuclear Fuel Disposal
Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per kWh of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility for such purpose to be available earlier than 2017.
Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from- reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). Adequate spent fuel storage capacity is estimated to be available through 2011 for Salem 1 and 2015 for Salem 2. Power completed, in August 2006, construction of an on-site storage facility that will satisfy the spent fuel storage needs of Hope Creek through the end of its current license. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach Bottom’s spent fuel storage requirements until at least 2014.
Exelon Generation had previously advised Power that it had signed an agreement with the DOE, applicable to Peach Bottom, under which Exelon Generation would be reimbursed for costs incurred resulting from the DOE’s delay in accepting spent nuclear fuel for permanent storage. Future costs incurred resulting from the DOE delays in accepting spent fuel will be reimbursed annually until the DOE fulfills its obligation to accept spent nuclear fuel. In addition, Exelon Generation and Nuclear are required to reimburse the DOE for the previously received credits from the Nuclear Waste Fund, plus lost earnings. Under this settlement, Power received approximately $27 million for its share of previously incurred storage costs for Peach Bottom, $22 million of which was used for the required reimbursement to the Nuclear Waste Fund. Exelon Generation paid Power approximately $5.4 million for its portion of the spent fuel storage costs reimbursed by the DOE in 2005 for costs incurred between October 1, 2003 and June 30, 2005.
In September 2001, Power filed a complaint in the U.S. Court of Federal Claims seeking damages for Salem and Hope Creek caused by the DOE not taking possession of spent nuclear fuel in 1998. On October 14, 2004, an order to show cause was issued regarding whether the U.S. Court of Federal Claims has jurisdiction over the matter. Power responded to this order in November 2004. On January 31, 2005, the Court dismissed the breach-of-contract claims of Power and three other utilities. Power moved for reconsideration in the U.S. Court of Federal Claims and jointly petitioned for permission to appeal the January 31, 2005 order to the U.S. Court of Appeals for the Federal Circuit. On September 29, 2006, the U.S. Court of Appeals for the Federal Circuit reversed the adverse U.S. Court of Federal Claims jurisdictional
ruling and reinstated Power’s claims in the U.S. Court of Federal Claims. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.
Spent Fuel Pool
The spent fuel pool at each Salem unit has an installed leakage collection system. This system was found to be obstructed at Salem Unit 1. Power developed a solution to maintain the design function of the leakage collection system at Salem Unit 1 and investigated the existence of any structural degradation that might have been caused by the obstruction. The concrete and reinforcing steel laboratory tests results were completed in March 2006. Test results that have been collected as part of the ongoing testing indicate that no repairs are anticipated. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Power cannot predict what further actions the NRC may take on this matter.
Elevated concentrations of tritium in the shallow groundwater at Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Power conducted a comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power is conducting remedial actions to address the contamination in accordance with a remedial action workplan approved by the NJDEP in November 2004. The remedial actions are expected to be ongoing for several years. The costs necessary to address this on-site groundwater contamination issue are not expected to be material.
Low Level Radioactive Waste (LLRW)
As a by-product of their operations, nuclear generation units produce LLRW. Such wastes include paper, plastics, protective clothing, water purification materials and other materials. LLRW materials are accumulated on-site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear generators, including Power, continued access to the Barnwell LLRW disposal facility which is owned by South Carolina. Power believes that the Atlantic Compact will provide for adequate LLRW disposal for Salem and Hope Creek through the end of their current licenses, although no assurances can be given. Both Power and Exelon have on-site LLRW storage facilities for Salem, Hope Creek and Peach Bottom, which have the capacity for at least five years of temporary storage for each facility. For information regarding Nuclear Spent Fuel Pool, see Note 12. Commitments and Contingent Liabilities of the Notes.
PSE&G
MGP Remediation Program
For information regarding PSE&G’s MGP Remediation Program, see Note 12. Commitments and Contingent Liabilities of the Notes.
ITEM 1A.
ITEM 1A. RISK FACTORS
PSEG, PSE&G, Power and Energy Holdings
The following factors should be considered when reviewing the businesses of PSEG, PSE&G, Power and Energy Holdings. These factors could significantly impact the businesses and cause results to differ materially from those expressed in any statements made by, or on behalf of PSEG, PSE&G, Power or Energy Holdings herein. Some or all of these factors may apply to each of PSEG, PSE&G, Power, Energy Holdings and their respective subsidiaries.
Generation operating performance may fall below projected levels
Power and Energy Holdings
Operating generating stations below expected capacity levels, especially at low-cost nuclear and coal facilities, may result in lost revenues and increased expenses, including replacement power costs. Factors that could cause generating station operations to fall below expected levels include, but are not limited to, the following:
•
labor disputes;
•
fuel supply interruptions or transportation constraints;
•
limitations which may be imposed by environmental or other regulatory requirements;
•
permit limitations; and
•
operator error or catastrophic events such as fires, earthquakes, explosions, floods, acts of terrorism or other similar occurrences.
The potential lost revenues and increased expenses could result in a case where sufficient cash may not be available to service debt. In addition, any prolonged operating performance issues could potentially result in an impairment of the value of the affected facility.
Failure to obtain adequate and timely rate relief could negatively impact results
PSE&G
As a public utility, PSE&G’s rates are regulated. These rates are designed to allow PSE&G the opportunity to recover its operating expenses and earn a fair return on its rate base, which primarily consists of its property, plant and equipment. These rates include its electric and gas tariff rates that are subject to regulation by the BPU as well as its transmission rates that are subject to regulation by FERC. PSE&G’s base rates are set by the BPU for electric distribution and gas distribution and are effective until the time a new rate case is brought to the BPU. These base rate cases generally take place when equity returns fall below reasonable levels. Some categories of costs, such as energy costs, are recovered through adjustment charges that are periodically reset to reflect actual costs. If these costs exceed the amount included in PSE&G’s adjustment charges, there may be a negative impact on cash flows.
If PSE&G does not obtain adequate rate treatment on a timely basis in order to meet its operating expenses, there may be a negative impact on earnings and operating cash flows. PSE&G can give no assurances that tariff relief will be timely or sufficient for it to recover its costs and provide a sufficient return for its investors.
Energy Holdings
Global’s distribution facilities are rate-regulated enterprises. Governmental authorities establish rates charged to customers. While these rates are designed to cover all operating costs and provide a return on investment, Energy Holdings can give no assurances that rates will, in the future, be sufficient to cover Global’s costs and provide a sufficient return on its investments. In addition, future rates may not be adequate to provide cash flow to pay principal and interest on the debt of Global’s subsidiaries and affiliates or to enable its subsidiaries and affiliates to comply with the terms of debt agreements.
Inability to balance energy obligations, available supply and trading risks could negatively impact results
Power and Energy Holdings
The revenues generated by the operation of the generating stations are subject to market risks that are beyond each company’s control. Generation output will either be used to satisfy wholesale contract requirements, other bilateral contracts or be sold into other competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments through recovery of mandated rates payable by purchasers of electricity.
Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served.
Power
Power’s energy trading and marketing activities frequently involve the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that Power has produced or purchased energy in excess of its contracted obligations a reduction in market prices could reduce profitability.
Conversely, to the extent that Power has contracted obligations in excess of energy it has produced or purchased, an increase in market prices could reduce profitability.
If the strategy Power utilizes to hedge its exposures to these various risks is not effective, it could incur significant losses. Power’s substantial market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas, short-term supply and demand imbalances and pricing differentials at various geographic locations, which cannot be predicted with any certainty.
Increases in market prices also affect Power’s ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices and, resultingly, could require the maintenance of liquidity resources that would be prohibitively expensive.
Environmental regulations could limit operations
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings are required to comply with numerous statutes, regulations and ordinances relating to the safety and health of employees and the public, the protection of the environment and land use. These statutes, regulations and ordinances are constantly changing. While management believes that PSEG, PSE&G, Power and Energy Holdings have obtained all material approvals currently required to own and operate their respective facilities and that approvals will be issued in a timely manner, significant additional costs could be incurred in order to comply with these requirements. In some cases, the cost of compliance could exceed the marginal value of the facility. Failure to comply with environmental statutes, regulations and ordinances could have a material effect on PSEG, PSE&G, Power and Energy Holdings, including potential civil or criminal liability, the imposition of clean-up liens or fines and expenditures of funds to bring facilities into compliance or possible impairment of the value of the affected facility.
PSEG, PSE&G, Power and Energy Holdings can give no assurance that they will be able to:
•
obtain all required environmental approvals not yet received or that may be required in the future;
•
obtain any necessary modifications to existing environmental approvals;
•
maintain compliance with all applicable environmental laws, regulations and approvals; or
•
recover any resulting costs through future sales.
Delay in obtaining or failure to obtain and maintain in full force and effect any environmental approvals, or delay or failure to satisfy any applicable environmental regulatory requirements, could prevent construction of new facilities, operation of existing facilities or sale of energy from these facilities or could result in significant additional costs.
Power
Many of Power’s generating facilities are located in the State of New Jersey where environmental programs are generally considered to be more stringent in comparison to similar programs in other states. As such, there may be instances where the facilities located in New Jersey are subject to more stringent and, therefore, more costly pollution control requirements than competitive facilities in other states.
Regulatory issues significantly impact operations and profitability
PSEG, PSE&G, Power and Energy Holdings
Federal, state and local authorities impose substantial regulation and permitting requirements on the electric power generation business. Power and Energy Holdings are required to comply with numerous laws and regulations and to obtain numerous governmental permits in order to operate generation stations. In addition, PSE&G’s and certain of Global’s distribution facilities could be subject to financial penalties if reliability performance standards are not met.
PSEG, PSE&G, Power and Energy Holdings can give no assurance that existing regulations will not be revised or reinterpreted, that new laws and regulations will not be adopted or become applicable or that future changes in laws and regulations, including the possibility of reregulation in some deregulated markets, will not have a detrimental effect on their respective businesses.
Power and Energy Holdings
Power and Energy Holdings believe that they have obtained all material energy-related federal, state and local approvals currently required to operate their respective generation stations and sell energy output, including MBR authority from FERC. Although not currently required, additional regulatory approvals may be required in the future due to changes in laws and regulations or for other reasons. No assurance can be given that Power and Energy Holdings will be able to obtain any required regulatory approval in the future, or that they will be able to obtain any necessary extensions in receiving any required regulatory approvals.
Power is also subject to pervasive regulation by the NRC with respect to the operation of nuclear generation stations. This regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety, environmental and personnel management requirements. The NRC also requires continuous demonstrations that plant operations meet applicable requirements. The NRC has the ultimate authority to determine whether any nuclear generation unit may operate.
Any failure to obtain or comply with any required regulatory approvals could materially adversely affect Power’s and Energy Holdings’ ability to operate generation stations or sell electricity to third parties.
In addition, there is also a risk to Power and Energy Holdings if states 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 treatment for the construction of new base-load generating units. This has already occurred in certain states. The lack of consistent rules in markets outside of PJM can negatively impact the competitiveness of Power’s plants.
Moreover, current rules being developed at FERC, at DOE and at PJM with respect to the access to and construction of transmission and the allocation of costs for such construction may have the effect of altering the level playing field between transmission options and generation options, which could have a competitive impact upon PSEG and Power.
Availability of adequate power transmission facilities
PSEG, PSE&G, Power and Energy Holdings
The ability to sell and deliver electric energy products may be adversely impacted and the ability to generate revenues may be limited if:
Inability to access sufficient capital in the amounts and at the times needed
PSEG, PSE&G, Power and Energy Holdings
Capital for projects and investments has been provided by internally-generated cash flow, equity issuances by PSEG and borrowings by PSEG, PSE&G, Power, Energy Holdings and their respective subsidiaries. Continued access to debt capital from outside sources is required in order to efficiently fund the cash flow needs of the businesses. The ability to arrange financing and the costs of capital depend on numerous factors including, among other things, general economic and market conditions, the availability of credit from banks and other financial institutions, investor confidence, the success of current projects and the quality of new projects.
The ability to access sufficient capital in the bank and debt capital markets is dependent upon current and future capital structure, performance, financial condition and the availability of capital at a reasonable economic cost. As a result, no assurance can be given that PSEG, PSE&G, Power or Energy Holdings will be successful in obtaining financing for projects and investments or funding the equity commitments required for such projects and investments in the future.
Counterparty credit risks or a deterioration of credit quality
PSEG, PSE&G, Power and Energy Holdings
As market prices for energy and fuel fluctuate, Power’s forward energy sale and forward fuel purchase contracts could require substantial collateral requiring Power to source additional liquidity during periods when Power’s ability to source such liquidity may be limited. Also, in connection with its energy trading
activities, Power must meet credit quality standards required by counterparties. Standard industry contracts generally require trading counterparties to maintain investment grade ratings. These same contracts provide reciprocal benefits to Power. If Power loses its investment grade credit rating, ER&T would have to provide additional collateral in the form of letters of credit or cash, which would significantly impact the energy trading business. This would increase Power’s costs of doing business and limit its ability to successfully conduct energy trading operations.
Power sells generation output through the execution of bilateral contracts. These contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual obligations. Any failure to perform on the part of these counterparties could have a material impact on PSEG’s and Power’s results of operations, cash flows and financial position. As market prices rise above contracted price levels, Power is required to post collateral with purchasers. Collateral posting requirements for BGS contracts in particular are one-sided. If market prices fall below BGS contracted price levels for a single contract, power purchasers are not required to post collateral with Power. However, such margin positions can be netted against margin due from Power in other BGS contracts with the same counterparty.
Substantial competition from well-capitalized participants in the worldwide energy markets
PSEG, PSE&G, Power and Energy Holdings
Restructuring of worldwide energy markets is creating opportunities for, and substantial competition from, well-capitalized entities that may adversely affect the ability of PSEG, PSE&G, Power and Energy Holdings to make investments on favorable terms and achieve growth objectives. Increased competition could contribute to a reduction in prices offered for power and could result in lower returns which may affect PSEG’s, PSE&G’s, Power’s and Energy Holdings’ ability to service their respective outstanding indebtedness, including short-term debt. Some of the competitors include:
As a holding company, the ability to service debt could be limited
PSEG and Energy Holdings
PSEG and Energy Holdings are holding companies with no material assets other than the stock or membership interests of their subsidiaries and project affiliates. As such, PSEG and Energy Holdings depend on their respective subsidiaries’ and project affiliates’ cash flow and their respective access to capital in order to service their indebtedness. Each of PSEG’s and Energy Holdings’ respective subsidiaries and project affiliates are separate and distinct legal entities that have no obligation, contingent or otherwise, to pay any amounts when due on PSEG’s or Energy Holdings’ debt or to make any funds available to pay such amounts. As a result, PSEG’s and Energy Holdings’ debt will effectively be subordinated to all existing and future debt, trade creditors, and other liabilities of their respective subsidiaries and project affiliates and PSEG’s and Energy Holdings’ rights and hence the rights of their respective creditors to participate in any distribution of assets of any subsidiary or project affiliate upon its liquidation or reorganization or otherwise would be subject to the prior claims of that subsidiary’s or project affiliate’s creditors, except to the extent that PSEG’s or Energy Holdings’ claims as a creditor of such subsidiary or project affiliate may be recognized.
In addition, Energy Holdings’ subsidiaries’ project-related debt agreements generally restrict the subsidiaries’ ability to pay dividends, make cash distributions or otherwise transfer funds. These restrictions may include achieving and maintaining financial performance or debt coverage ratios, absence of events of default, or priority in payment of other current or prospective obligations. Also, Energy Holdings is structurally designed to be able to meet its obligations without any support from its parent, PSEG. These restrictions could further restrict Energy Holdings’ ability to service its outstanding indebtedness.
Adverse international developments could negatively impact results
Energy Holdings
A component of PSEG’s and Energy Holdings business is international distribution and generation, primarily in Chile and Peru. The economic and political conditions in certain countries where Global has interests present risks that may be different than those found in the U.S. which could affect the value of its investments, cash flows from projects and make it more difficult to obtain non-recourse project refinancing on suitable terms or could impair Global’s ability to enforce its rights under agreements relating to such projects. Such risks include:
Operations in foreign countries also present risks associated with currency exchange rates and convertibility, inflation and repatriation of earnings. In some countries, economic and monetary conditions and other factors could affect Global’s ability to convert its cash distributions to U.S. Dollars or other freely convertible currencies, or to move funds offshore from these countries. Furthermore, the central bank of any of these countries may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to approve distributions to foreign investors.
Inability to realize tax benefits
Energy Holdings
Through its leveraged lease investments, Resources acquired an asset by investing equity representing approximately 15% to 20% of the cost of the asset and incurring non-recourse lease debt for the balance. As the owner, Resources is entitled to depreciate the asset under applicable federal and state tax guidelines and receives income from the tax benefits associated with interest and depreciation deductions with respect to the leased property. The ability of Resources to realize these tax benefits is dependent on operating income generated by its affiliates and allocated pursuant to PSEG’s consolidated tax sharing agreement. A reduction of operating income could impair Resources’ ability to receive such benefits, which would result in a reduction of earnings and cash flows. In addition, during 2006, the IRS disallowed certain deductions associated with some of the leveraged leases which have been designated by the IRS as listed transactions. For additional information see Note 12. Commitments and Contingent Liabilities of the Notes. Any material disallowance of deductions could impact Energy Holdings’ earnings and ability to service its outstanding indebtedness.
Decreases in the value of the pension and other postretirement assets could require additional funding
PSEG, PSE&G, Power and Energy Holdings
Adverse changes in the rates of return or performance of the investments in which the pension and other postretirement trust assets are held could lower the value of the funds and the trust assets. Such a decline in value could result in additional funding obligations to meet the applicable legal and regulatory requirements. To the extent that these additional funding obligations are significant, this could impact PSEG’s, PSE&G’s, Power’s and Energy Holdings’ ability to service debt.
Changes in technology may make power generation assets less competitive
Power and Energy Holdings
A key element of the business plan is that generating power at central power plants produces electricity at relatively low cost. There are alternative technologies to produce electricity that continue to attract capital for research and development, most notably fuel cells, microturbines, windmills and photovoltaic (solar) cells. It is possible that advances in technology will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. If this were to happen, Power’s and Energy Holdings’ market share could be eroded and the value of their respective power plants could be significantly impaired. Changes in technology could also alter the channels through which retail electric customers buy electricity, which could affect financial results.
Insurance coverages may not be sufficient
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings have insurance for their respective facilities, including:
•
all-risk property damage insurance;
•
commercial general public liability insurance;
•
boiler and machinery coverage;
•
nuclear liability; and
•
for nuclear generating units, replacement power and business interruption insurance in amounts and with deductibles that management considers appropriate.
PSEG, PSE&G, Power and Energy Holdings can give no assurance that this insurance coverage will be available in the future on commercially reasonable terms or that the insurance proceeds received for any loss of or any damage to any of their respective facilities will be sufficient to fund future payments on debt. Additionally, some properties may not be insured in the event of an act of terrorism.
Recession, acts of war or terrorism
PSEG, PSE&G, Power and Energy Holdings
The consequences of a prolonged recession and adverse market conditions may include the continued uncertainty of energy prices and the capital and commodity markets. Management cannot predict the impact of any continued economic slowdown, reduced growth rate in energy usage or fluctuating energy prices; however, such impact could have a material adverse effect on PSEG’s, PSE&G’s, Power’s and Energy Holdings’ financial condition, results of operations and net cash flows.
Major industrial facilities, generation plants, fuel storage facilities and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of PSE&G’s, Power’s or Energy Holdings’ ability to produce or distribute some portion of their respective energy products. Any such disruption could result in a significant decrease in revenues and/or significant additional costs to repair, which could have a material adverse impact on the financial condition, results of operation and net cash flows of PSEG, PSE&G, Power and Energy Holdings.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
PSEG
None.
PSE&G, Power and Energy Holdings
Not Applicable.
ITEM 2.
ITEM 2. PROPERTIES
PSEG and Services
PSEG does not own any property. All property is owned by PSEG’s subsidiaries.
Services leases a 25-story office tower for PSEG’s corporate headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining three-story building. In addition, Services owns the Maplewood Test Services Facility in Maplewood, New Jersey.
PSEG believes that it and its subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost.
PSE&G
PSE&G’s First and Refunding Mortgage (Mortgage), securing the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property.
PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. These easements and other rights are deemed by PSE&G to be adequate for the purposes for which they are being used.
PSE&G believes that it maintains adequate insurance coverage against loss or damage to its principal properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost.
Electric Transmission and Distribution Properties
As of December 31, 2006, PSE&G’s transmission and distribution system included approximately 21,745 circuit miles, of which approximately 7,710 circuit miles were underground, and approximately 804,936 poles, of which approximately 538,811 poles were jointly-owned. Approximately 99% of this property is located in New Jersey.
In addition, as of December 31, 2006, PSE&G owned four electric distribution headquarters and five subheadquarters in four operating divisions, all located in New Jersey.
Gas Distribution Properties
As of December 31, 2006, the daily gas capacity of PSE&G’s 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum air gas (LPG) and liquefied natural gas (LNG) and aggregated 2,973,000 therms (approximately 2,886,000 cubic feet on an equivalent basis of 1.030 Btu/cubic foot) as shown in the following table:
As of December 31, 2006, PSE&G owned and operated approximately 17,556 miles of gas mains, owned 12 gas distribution headquarters and two subheadquarters, all in three operating regions located in New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, PSE&G operated 62 natural gas metering or regulating stations, all located in New Jersey, of which 28 were located on land owned by customers or natural gas pipeline suppliers and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the metering and regulating facilities.
Office Buildings and Facilities
PSE&G rents office space from Services as its headquarters in Newark, New Jersey. PSE&G also leases office space at various locations throughout New Jersey for district offices and offices for various corporate groups and services. PSE&G also owns various other sites for training, testing, parking, records storage, research, repair and maintenance, warehouse facilities and for other purposes related to its business.
In addition to the facilities discussed above, as of December 31, 2006, PSE&G owned 42 switching stations in New Jersey with an aggregate installed capacity of 22,809 megavolt-amperes and 244 substations with an aggregate installed capacity of 7,790 megavolt-amperes. In addition, four substations in New Jersey having an aggregate installed capacity of 109 megavolt-amperes were operated on leased property.
Power
Power rents office space from Services as its headquarters in Newark, New Jersey. Other leased properties include office, warehouse, classroom and storage space, primarily located in New Jersey. Power also owns the Central Maintenance Shop at Sewaren, New Jersey.
Power has a 57.41% ownership interest in approximately 13,000 acres in the Delaware River Estuary region to satisfy the condition of the NJPDES permit issued for Salem. Power also owns several other facilities, including the on-site Nuclear Administration and Processing Center buildings.
Power has a 13.91% ownership interest in the 650-acre Merrill Creek Reservoir in Warren County, New Jersey and approximately 2,158 acres of land surrounding the reservoir. The reservoir was constructed to store water for release to the Delaware River during periods of low flow. Merrill Creek is jointly-owned by seven companies that have generation facilities along the Delaware River or its tributaries and use the river water in their operations.
Power believes that it maintains adequate insurance coverage against loss or damage to its plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Note 12. Commitments and Contingent Liabilities of the Notes.
As of December 31, 2006, Power’s share of installed generating capacity was 14,639 MW, as shown in the following table:
OPERATING POWER PLANTS
(A)
Power’s share of jointly-owned facility.
(B)
Operated by Reliant Energy.
(C)
Operated by Exelon Generation.
(D)
Operated by JCP&L.
(E)
Excludes energy for pumping and synchronous condensers.
(F)
On December 29, 2006, Power entered into an agreement to sell Lawrenceburg. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes.
As of December 31, 2006, Power had generating capacity in construction or advanced development, as shown in the following table:
POWER PLANTS IN ADVANCED DEVELOPMENT
Energy Holdings
Energy Holdings rents office space from Services as its headquarters in Newark, New Jersey.
Energy Holdings believes that it maintains adequate insurance coverage for properties in which its subsidiaries have an equity interest, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost.
Global has invested in the following generation facilities that were in operation as of December 31, 2006:
OPERATING POWER PLANTS
Domestic Generation
TIE
Global owns 100% of TIE which owns and operates two electric generation facilities, one in Guadalupe County in south central Texas (Guadalupe) and one in Odessa in western Texas (Odessa). Approximately 30% of the total expected output of TIE for 2007 has been sold via bilateral agreements and additional bilateral sales for peak and off-peak services will be signed as the year progresses. Any remaining uncommitted output is sold in the Texas spot market. Included in the amounts above is a 350 MW daily capacity call option at Odessa that expires on December 31, 2010.
Kalaeloa
Global’s 50% partner in Kalaeloa is a power fund managed by Harbert Power Corporation (Harbert). All of the electricity generated by the Kalaeloa power plant is sold to the Hawaiian Electric Company, Inc. (HECO) under a PPA expiring in May 2016. Under a steam purchase and sale agreement expiring in May 2016, the Kalaeloa power plant supplies steam to the adjacent Tesoro refinery. The primary fuel, low sulfur fuel oil, is provided from the adjacent Tesoro refinery under a long-term all requirements contract. The refinery is interconnected to the power plant by a pipeline and preconditions the fuel oil prior to delivery. Back-up fuel supply is provided by HECO.
The two combustion turbines of Kalaeloa were upgraded in 2004 resulting in both an increase in the net plant output by approximately 20 MW and an improvement in the efficiency of consuming fuel. As a result of the upgrades, Kalaeloa and HECO entered into two amendments to the PPA. The amendments were effective upon final approval from the Public Utility Commission of the State of Hawaii in September 2005. The amendments increased Kalaeloa’s firm capacity and associated energy sales to HECO from 180 MW to 208 MW.
GWF and Hanford
Global and an affiliate of Harbert each own 50% of GWF. PPAs for the five GWF Bay Area plants’ net output are in place with Pacific Gas and Electric Company (PG&E) ending in 2020 and 2021. GWF acquires the petroleum coke used to fuel its plants through contracts with three local oil refineries with minimum volumes nominated by GWF annually and price negotiated between the parties either semi-annually or annually. Three of the five GWF plants have been modified to burn a wider variety of petroleum coke products to mitigate fuel supply and pricing risk.
Global and an affiliate of Harbert each own 50% of Hanford. A PPA for the plant’s net output is in place with PG&E ending in August 2011. Hanford acquires the petroleum coke fired in its plant through a contract with a refinery with price negotiated semi-annually.
Hanford, Henrietta and Tracy Peaker Plants
GWF Energy, which is 60% owned by Global and 40% owned by a power fund managed by Harbert, owns and operates three peaker plants in California. Global owned approximately 75% of GWF Energy until February 2004 when it sold a 14.9% interest to Harbinger for approximately $14 million. The output of these plants is sold under a PPA with the California Department of Water Resources (DWR) with maturities in 2011 and 2012. DWR has the right to schedule energy and/or reserve capacity from each unit of the three plants for a maximum of 2,000 hours each year. Energy and capacity not scheduled by DWR is available for sale by GWF Energy. DWR supplies the natural gas when the units are scheduled for dispatch by DWR. GWF Energy obtains the natural gas used to fuel its plants for non-DWR sales from the spot market on a non-firm basis.
International Generation
India
PPN
Global owns a 20% interest in PPN located in Tamil Nadu, India. Global’s partners include the Apollo Infrastructure Company Ltd., with a 46.9% interest, Marubeni Corporation, with a 26% interest, Housing
Development Finance Corporation (HDFC) and HDFC Life Insurance Corporation, with a 5% and 2.1% interest respectively. PPN has entered into a PPA for the sale of 100% of its output to the State Electricity Board of Tamil Nadu (TNEB) for 30 years, with an agreement to take-or-pay equal to a plant load factor of at least 68.5%.
Italy
Prisma
Global owns an 85% interest in Prisma which indirectly owns and operates three biomass generation plants in Italy through its ownership of 100% of San Marco Bioenergie S.p.A., which owns a 20 MW plant, and 50% of Biomasse, a partnership with Api Holding S.p.A., which owns two plants totaling 60 MW. Global records Prisma’s investment in Biomasse as an equity method investment due to Global’s approximate 43% indirect ownership in Biomasse. The output of the plants is sold under power purchase agreements with the Italian national grid (CIP contracts), which include a premium for the renewable energy output. These contracts expire from 2009 through 2012. For additional information relating to Prisma, see Note 12. Commitments and Contingent Liabilities of the Notes.
Peru
Electroandes
Global owns a 100% interest in Electroandes located in Peru. Electroandes’ main assets include four hydroelectric facilities with a combined installed capacity of 180 MW and 437 miles of transmission lines located in the central Andean region east of Lima. Electroandes’ revenues were obtained through various PPAs, denominated in U.S. Dollars. Electroandes has contracted for 95% and 91% in 2007 and 2008, respectively, and over 50% for 2009 and 2010. Approximately 75% of the PPAs in 2007 are with unregulated customers with a more balanced split between regulated and unregulated in 2008 and beyond.
Venezuela
Turboven
The facilities in Maracay and Cagua are owned and operated by Turboven, an entity which is jointly-owned by Global (50%) and Corporacion Industrial de Energia (CIE). PPAs expiring between 2007 and 2011 have been entered into for the sale of approximately 40% of the output of Maracay and Cagua to various industrial customers. The PPAs are structured to provide energy only with minimum take provisions. Fuel costs are passed through directly to customers and the energy tariffs are calculated in U.S. Dollars and paid in local currency. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes for a discussion of recent events in Venezuela.
TGM
Global has a 9% indirect interest in TGM through a partnership with CIE. TGM sells all of the energy produced under a PPA with Manufacturas del Papel (MANPA), a paper manufacturing concern located in Maracay. MANPA and CIE have common controlling shareholders. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes for a discussion of recent events in Venezuela.
Electric Distribution Facilities
Global has invested in the following major distribution systems:
Chile and Peru
SAESA Group
Global owns a 99.99% equity interest in SAESA, 98.99% of Empresa Electrica de la Frontera S.A. (Frontel) and 100% of PSEG Generacion y Energia Chile Limitada (Generacion), collectively known as the SAESA Group. The SAESA Group consists of four distribution companies and one transmission company that provide electric service to 390 cities and towns over 900 miles in southern Chile and a generating company. The SAESA Group has 120 MW of installed generating capacity in operation (46 MW of natural gas-fired peaker capacity, 51 MW oil-fired, 21 MW hydro and 2 MW wind). The transmission company, Sistema de Transmision del Sur S.A. (STS), provides transmission services to electric generation facilities that have PPAs with distributors in Regions VIII, IX and X and has installed transformation capacity of 918 megavolt-amperes.
The SAESA Group also owned a 50% interest in an Argentine distribution company, Empresa de Energia Rio Negro S.A., which provides generation, transmission and distribution services to approximately 147,000 customers in the Province of Rio Negro, Argentina, but was sold in the last quarter of 2006. The management of the SAESA Group is organized and administered according to a centralized administrative structure designed to maximize operational synergies. For additional information related to the SAESA Group, see Item 1. Business-Regulatory Issues.
Chilquinta and LDS
Global and Sempra Energy (Sempra), each own 50% of the shares of Chilquinta, an energy distribution company with numerous energy holdings, based in Valparaiso, Chile. Following the sale in 2004 of 12% of the shares of LDS to the public, Global and Sempra own 75.9% of LDS, an electric distribution company located in Lima, Peru. As part of the Chilquinta and LDS investments, Global and Sempra also own Tecnored and Tecsur, located in Chile and Peru, respectively. These companies provide procurement and contracting services to Chilquinta, LDS and others.
As equal partners, Global and Sempra share in the management of Chilquinta and LDS. However, Sempra has assumed lead operational responsibilities at Chilquinta, while Global has assumed lead operational responsibilities at LDS. The shareholders’ agreement provides for important veto rights over major partnership decisions including dividend policy, budget approvals, management appointments and indebtedness.
Chilquinta operates under a non-exclusive perpetual franchise within Chile’s Region V which is located just north and west of Santiago. Global believes that direct competition for distribution customers would be uneconomical for potential competitors. LDS operates under an exclusive, perpetual franchise in the southern portion of the city of Lima and in an area just south of the city along the coast serving a population of approximately 3.2 million. Both Chilquinta and LDS purchase energy for distribution from generators in their respective markets on a contract basis. For additional information related to Chilquinta and LDS, see Item 1. Business-Regulatory Issues.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
PSE&G
In November 2001, Consolidated Edison Company of New York, Inc. (Con Edison) filed a complaint against PSE&G, PJM and NYISO with FERC asserting a failure to comply with agreements between PSE&G and Con Edison covering 1,000 MW of transmission. PSE&G denied the allegations set forth in the complaint. An Initial Decision issued by an ALJ in April 2002 upheld PSE&G’s claim in part but also accepted Con Edison’s contentions in part. In December 2002, FERC issued an order modifying the Initial Decision and remanding a number of issues to the ALJ for additional hearings, including issues related to the development of protocols to implement the findings of the order and regarding Phase II of the complaint. The ALJ issued an Initial Decision on the Phase II issues in June 2003 and in August 2004, FERC issued its decision on Phase II issues. While those decisions were largely favorable to PSE&G, PSE&G sought rehearing as to certain issues, as did Con Edison. Those rehearing applications are currently pending.
The August 2004 order required that PJM, NYISO, Con Edison and PSE&G meet for the purpose of developing operational protocols to implement FERC’s directives. On February 18, 2005, NYISO, PJM and
PSE&G submitted a joint compliance filing pursuant to FERC’s August 2004 decision. FERC approved the joint proposals on May 18, 2005 and they took effect on July 1, 2005. In subsequent filings to FERC regarding the efficacy of these protocols, Con Edison continues to claim that the obligations under the agreements as interpreted by the FERC’s orders are not being met. In December 30, 2005 and January 19, 2007 filings with FERC, Con Edison claims to have incurred $111 million in damages, and has requested FERC to require refunds of this amount. To the extent that this claim is directed at PSE&G, PSE&G believes that the claim has no legal basis and that, in any event, PSE&G has meritorious defenses to the claim. PJM, NYISO, Con Edison and PSE&G have agreed to a work plan under which they will attempt, during the Spring of 2007, to address operational issues associated with the protocols and to address Con Edison’s refund claim. Con Edison has also requested that, if these settlement discussions are not successful, that FERC convene judge-mediated settlement discussions, to be followed by hearings if necessary. The scope of the discussions envisioned under the work plan are not currently expected, however, to encompass a comprehensive review of all matters raised in the November 2001 complaint or the pending rehearing requests of the FERC’s orders. As this matter is currently pending before FERC, PSEG and PSE&G are unable to predict the outcome of this proceeding.
Energy Holdings
India
Global has a 20% ownership interest in PPN, which sells its output under a long-term PPA with the TNEB. TNEB has not made full payment to PPN for the purchase of energy under the PPA. Resolution of the past due receivables against which PPN has established reserves was expected to be achieved in 2005 by a joint working group including the Central Electric Authority (CEA), PPN and TNEB. However, in the latter part of 2005, the CEA reportedly stated that it had no jurisdiction in the matter and referred the parties to the Tamil Nadu Electric Regulatory Commission (TNERC). Neither PPN nor Global believe that TNERC has jurisdiction over Capital Cost Approval, a significant component of the receivables reserve. An adverse outcome concerning the disputed Capital Cost Approvals could result in impairment of this investment.
On March 26, 2004, Global and El Paso Energy Corporation (which sold its ownership interest in PPN in 2005) filed a notice of arbitration on behalf of PPN against TNEB under the arbitration clause of the PPA, asserting that they have the right as minority shareholders to protect the contractual rights of PPN where PPN has failed to exercise those rights itself. In response, PPN filed a petition for an anti-suit injunction against the arbitration. Global successfully defended against the petition in two lower courts. PPN has filed its final appeal in the Supreme Court of India (SLP Civil No. 23169). Hearings that began on January 24, 2005 have resulted in a stay of PSEG’s continued actions in the arbitral court pending a decision by the Indian Supreme Court, which is expected in due course.
On December 30, 2006, Global petitioned the Company Law Board (Law Board) in Chennai, India to withdraw, without prejudice, its case against certain other members of PPN’s Board of Directors, PPN management and certain other PPN shareholders for failure to act in PPN’s best interest and other assertions. The Law Board issued the order as requested and the other parties did not object. The withdrawal of the Law Board case is expected to result in an eventual dismissal of the injunction against the arbitration described above.
As of December 31, 2006, Global’s total investment in PPN was approximately $34 million.
Turkey
From about 1995 through 2001, Global and its partners expended approximately $12 million towards the construction of a power plant in the Konya-Ilgin region of Turkey. In 2001, Turkey passed legislation and otherwise deprived Global of rights and fair and equitable treatment and expropriated Global’s Concession contract for the power plant project without compensation, despite the Turkish Government’s obligation to compensate Global for its costs under the existing contract and Turkish law. In 2002, Global initiated arbitration before the International Centre for Settlement of International Disputes seeking return of sunk costs, lost profits, interest and attorney fees and costs. A decision in this matter was made in January 2007 under which the Turkish Government will be required to pay Global and its partners approximately $20 million for sunk costs, interest and arbitration fees. After legal contingency fees, Global expects to receive approximately $7 million, after tax, for its share of the project. Global expects to receive payment in the second quarter of 2007.
PSEG, PSE&G, Power and Energy Holdings
In addition to matters discussed above, see information on the following proceedings at the pages indicated for PSEG and each of PSE&G, Power and Energy Holdings as noted:
PSE&G and Power
In addition, see the following environmental related matters involving governmental authorities. PSE&G and Power do not expect expenditures for any such site relating to the items listed below, individually or for all such current sites in the aggregate, to have a material effect on their respective financial condition, results of operations and net cash flows.
(1) Claim made in 1985 by the U.S. Department of the Interior under CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue municipal landfills in Brooklyn, New York, for damages to
natural resources. The U.S. Government alleges damages of approximately $200 million. To PSE&G’s knowledge there has been no action on this matter since 1988.
(2) Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. The EPA had named PSE&G as one of several potentially responsible parties (PRPs) through a series of administrative orders between December 1984 and March 1985. Following work performed by the PRPs, the EPA declared on May 20, 1987 that all of its administrative orders had been satisfied. The NJDEP, however, named PSE&G as a PRP and issued its own directive dated October 21, 1987. Remediation is currently ongoing.
(3) Various Spill Act directives were issued by NJDEP to PRPs, including PSE&G with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with operation and maintenance, interim remedial measures and a Remedial Investigation and Feasibility Study (RI/FS) in excess of $25 million. The directives also sought reimbursement of NJDEP’s past and future oversight costs and the costs of any future remedial action.
(4) Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and other companies are alleged to be liable for contamination at the site and PSE&G has been named as a PRP. A Final Remedial Design Report was submitted to the EPA in September of 2002. This document presents the design details that will implement the EPA’s selected remediation remedy. The costs of remedy implementation are estimated to range from $14 million to $24 million. PSE&G’s share of the remedy implementation costs are estimated between $4 million and $8 million.
(5) The Klockner Road site is located in Hamilton Township, Mercer County, New Jersey, and occupies approximately two acres on PSE&G’s Trenton Switching Station property. PSE&G entered into a memorandum of agreement with the NJDEP for the Klockner Road site pursuant to which PSE&G conducted an RI/FS and remedial action at the site to address the presence of soil and groundwater contamination at the site.
(6) The NJDEP assumed control of a former petroleum products blending and mixing operation and waste oil recycling facility in Elizabeth, Union County, New Jersey (Borne Chemical Co. site) and issued various directives to a number of entities, including PSE&G, requiring performance of various remedial actions. PSE&G’s nexus to the site is based upon the shipment of certain waste oils to the site for recycling. PSE&G and certain of the other entities named in NJDEP directives are members of a PRP group that have been working together to satisfy NJDEP requirements including: funding of the site security program; containerized waste removal; and a site remedial investigation program.
(7) The EPA sent PSE&G, Power and approximately 157 other entities a notice that the EPA considered each of the entities to be a potentially responsible party (PRP) with respect to contamination in Berry’s Creek in Bergen County, New Jersey and requesting that the PRPs perform a Remedial Investigation/Feasibility Study (RI/FS) on Berry’s Creek and the connected tributaries and wetlands. Berry’s Creek flows through approximately 6.5 miles of areas that have been used for a variety of industrial purposes and landfills. The EPA estimates that the study could be completed in approximately five years at a total cost of approximately $18 million. PSE&G and Power are unable to predict the outcome of this matter; however, the related costs of this study are not expected to be material.
(8) The EPA sent PSE&G and three other entities a notice that the EPA considered each of the entities to be a PRP with respect to contamination in the Newark Bay Study Area, which it defined as Newark Bay and portions of the Hackensack River, the Arthur Kill, and the Kill Van Kull. The notice letter requested that PSE&G participate and fund the EPA-approved study in the Newark Bay Study Area and encouraged PSE&G to contact Occidental Chemical Corporation (OCC) to discuss participating in the RI/FS that OCC is conducting in the Newark Bay Study Area. EPA considers the Newark Bay Study Area, along with the Passaic River Study Area, to be part of the Diamond Alkali Superfund Site. The notice states EPA’s belief that hazardous substances were released from sites owned by PSE&G and located on the Hackensack River. The sites included two operating electric generating stations (Hudson and Kearny Sites), and one former MGP. PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. The Hudson and Kearny Sites were transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Hudson and Kearny Sites. Power has provided notice to insurers concerning this potential claim. PSE&G and Power are unable to estimate the cost of the investigation at this time.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PSEG’s Annual Meeting of Stockholders was held on November 21, 2006. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Act of 1934. There was no solicitation of proxies in opposition to management’s nominees as listed in the proxy statement and all of management’s nominees were elected to the Board of Directors. Details of the voting are provided below:
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
PSEG
PSEG’s Common Stock is listed on the New York Stock Exchange, Inc. As of December 31, 2006, there were 94,972 holders of record.
The graph below shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2001 in PSEG common stock, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.
The following table indicates the high and low sale prices for PSEG’s Common Stock and dividends paid for the periods indicated:
In January 2007, PSEG’s Board of Directors approved a one and one half-cent increase in its quarterly common stock dividend, from $0.57 to $0.585 per share, for the first quarter of 2007. This increase reflects an indicated annual dividend rate of $2.34 per share. For additional information concerning dividend payments, dividend history, policy and potential preferred voting rights, restrictions on payment and common stock repurchase programs, see Item 7. MD&A-Overview of 2006 and Future Outlook and Liquidity and Capital Resources and Note 9. Schedule of Consolidated Capital Stock and Other Securities of the Notes.
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2006:
(A)
Shares issuable under the PSEG Employee Stock Purchase Plan, Compensation Plan for Outside Directors and Stock Plan for Outside Directors.
For additional discussion of specific plans concerning equity-based compensation, see Note 17. Stock Options and Employee Stock Purchase Plan of the Notes.
PSE&G
All of the common stock of PSE&G is owned by PSEG. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A-Overview of 2006 and Future Outlook.
Power
All of Power’s outstanding limited liability company membership interests are owned by PSEG. For additional information regarding Power’s ability to pay dividends, see Item 7. MD&A-Overview of 2006 and Future Outlook.
Energy Holdings
All of Energy Holdings’ outstanding limited liability company membership interests are owned by PSEG. For additional information regarding Energy Holdings’ ability to pay dividends, see Item 7. MD&A-Overview of 2006 and Future Outlook.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
PSEG
The information presented below should be read in conjunction with the Management’s Discussion and Analysis (MD&A) and the Consolidated Financial Statements and Notes to Consolidated Financial Statements (Notes).
PSE&G
The information presented below should be read in conjunction with the MD&A, the Consolidated Financial Statements and the Notes.
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no other representations whatsoever as to any other company.
OVERVIEW OF 2006 AND FUTURE OUTLOOK
PSEG, PSE&G, Power and Energy Holdings
PSEG’s business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C. (Resources). The following discussion relates to the markets in which PSEG’s subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets and significant events that have occurred during 2006 and expectations for 2007 for PSE&G, Power and Energy Holdings, as well as the key factors that will drive the future performance of these businesses.
Termination of Merger Agreement
On December 20, 2004, PSEG entered into an Agreement and Plan of Merger (Merger Agreement) with Exelon Corporation (Exelon) providing for a merger of PSEG with and into Exelon (Merger). On September 14, 2006, PSEG received from Exelon a formal notice terminating the Merger under the provisions of the Merger Agreement.
PSE&G
PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and by the Federal Energy Regulatory Commission (FERC) for its electric transmission and wholesale sales operations.
Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. In February 2007, the BPU approved the results of New Jersey’s annual Basic Generation Service (BGS)-Fixed Price (FP) and BGS-Commercial and Industrial Energy Price (CIEP) auctions and PSE&G successfully secured contracts to provide the electricity requirements for the majority of its customers’ needs.
Overview of 2006
During 2006 PSE&G:
•
reached a settlement agreement in the Gas Base Rate Case with the BPU Staff, New Jersey Public Ratepayer Advocate (RPA) and other intervening parties which was approved by the BPU on November 9, 2006 and provides for an annual increase in gas revenues of $40 million, an adjustment to lower book depreciation expense for PSE&G by approximately $26 million annually and the amortization of accumulated cost of removal that will further reduce depreciation and amortization expense by $13 million annually for five years.
•
reached a settlement agreement in the Electric Distribution Financial Review with the BPU Staff, RPA and other intervening parties concerning the excess depreciation rate credit which was approved by the BPU on November 9, 2006 and authorizes a reduction in the credit to $22 million, resulting in additional revenue to PSE&G of approximately $47 million annually based on current sales volumes.
Future Outlook
PSE&G believes that the decisions in November 2006 for both gas and electric base rates positions it to earn reasonable returns on investment in the future. The full year impact of these decisions combined with an anticipated return to more normal weather conditions is expected to improve PSE&G’s margins for 2007 and beyond.
The risks to PSE&G’s business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically the BPU and FERC. PSE&G’s success will depend, in part, on its ability to attain a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels and continued recovery, with an adequate return, of the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution system. Since PSE&G earns no margin on the commodity portion of its electric and gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G.
Power
Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market in the Northeast and Mid Atlantic U.S. Power’s principal operating subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Through its subsidiaries, Power seeks to balance its generation production, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear and coal operations and pursue modest growth based on market conditions. Changes in the operation of Power’s generating facilities, fuel and capacity prices, expected contract prices, capacity factors or other assumptions could materially affect its ability to meet earnings targets and/or liquidity requirements. In addition to the electric generation business described above, Power’s revenues include gas supply sales under the Basic Gas Supply Service (BGSS) contract with PSE&G.
As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits, and a series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, the prices of commodities, such as electricity, gas, coal and emissions, as well as the availability of Power’s diverse fleet of generation units to produce these products, can have a material effect on Power’s profitability. In recent years, the prices at which transactions are entered into for future delivery of these products, as evidenced through the market for forward contracts at points such as PJM Interconnection, L.L.C. (PJM) West, have escalated considerably over historical prices. Broad market price increases such as these are expected to have a positive effect on Power’s results. Historically, Power’s nuclear and coal-fired facilities have produced over 50% and 25% of Power’s production, respectively. With the vast majority of its power sourced from lower-cost units, the rise in electric prices is anticipated to yield higher near-term margins for Power. Power anticipates recognizing these higher near-term margins, especially on the portion of its output that was more recently contracted or sold on the spot market. Over a longer-term horizon, if these higher prices are sustained at prices reflective of what the current forward markets indicate, it would yield an attractive environment for Power to contract the sale of its anticipated output, allowing for potentially sustained higher profitability than recognized in prior years. These escalated prices also increase the cost of replacement power, thereby placing incremental risk on the operations of the generating units to produce these products.
Power seeks to mitigate volatility in its results by contracting in advance for a significant portion of its anticipated electric output and fuel needs. Power believes this contracting strategy increases stability of earnings and cash flow. By keeping some portion of its output uncontracted, Power is able to retain some exposure to market changes as well as provide some protection in the event of unexpected generation outages.
Power seeks to sell a portion of its anticipated low-cost nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of approximately two to four years. As of February 14, 2007, Power has contracted for approximately 100% of its anticipated 2007 nuclear and coal-fired generation, with 90% to 100% contracted for 2008 and 35% to 50% contracted for 2009, with a modest amount contracted beyond 2009.
Power has also entered into contracts for the future delivery of nuclear fuel and coal to support its contracted sales discussed above. As of February 1, 2007, Power had contracted for 100% of its anticipated nuclear uranium fuel needs through 2011, and approximately 70% of its average anticipated coal needs, including transportation, through 2009. These estimates are subject to change based upon the level of operation, and in particular for coal, are subject to market demands and pricing.
By contrast, Power takes a more opportunistic approach in hedging its anticipated natural gas-fired generation. The generation from these units is less predictable, as these units are generally dispatched only
when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units generally provide a lower contribution to the margin of Power than either the nuclear or coal units. Power will generally purchase natural gas as gas-fired generation is required to supply forward sale commitments.
In a changing market environment, this hedging strategy may cause Power’s realized prices to be materially different than current market prices. At the present time, some of Power’s existing contractual obligations, entered into during lower-priced periods, are anticipated to result in lower margins than would have been the case if no or little hedging activity had been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins in excess of those implied by the then current market.
Overview of 2006
During 2006, FERC issued certain orders related to market design that have changed the nature of capacity payments in the New England Power Pool (NEPOOL) and are scheduled to change the nature of payments in PJM. In PJM, the Reliability Pricing Model (RPM) will provide generators with differentiated capacity payments based upon the location of their respective facilities. Similarly, the Forward Capacity Market (FCM) settlement in NEPOOL provides for locational capacity payments. FERC has approved the market changes in each of these markets, with the anticipated start date for RPM set for June 1, 2007 and FCM transition period having begun on December 1, 2006. Power currently receives fixed Reliability-Must-Run (RMR) payments in PJM and NEPOOL for certain of its facilities which are provided to ensure the continued availability of those facilities.
Also during 2006 Power:
•
commenced commercial operations of its 1,186 MW, natural gas-fired combined cycle power generation plant in Linden, New Jersey;
•
reached an agreement with the EPA and NJDEP that will allow the continued operation of the Hudson facility and extends for four years the deadline for installing environmental controls beyond the previous December 31, 2006 deadline;
•
announced its plans to resume direct management of the Salem and Hope Creek facilities before the expiration of the Operating Service Contract with Exelon Generation and to have the senior management team at those facilities to become employees of Power effective January 1, 2007; and
•
entered into an agreement to sell its Lawrenceburg Energy Center, a 1,080 MW gas-fired combined cycle electric generating plant in Lawrenceburg, Indiana.
Future Outlook
Power expects margin improvements in 2007 as higher prices for its nuclear and coal output are realized due to the rolling nature of its forward hedge positions and the expiration of its contract in Connecticut. The sale of Lawrenceburg and anticipated improvements in margins on serving the BGSS contract are also expected to benefit future results.
In addition, Power believes that the redesign in capacity markets, discussed above, could lead to changes in the value of the majority of its generating capacity and result in incremental margin of $100 million to $150 million in 2007, with higher increases in future years as the full year impact is realized and existing capacity contracts expire.
A key factor in Power’s ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to satisfy its obligations. Power’s ability to achieve its objectives will also depend on the implementation of reasonable capacity markets. Power must also be able to effectively manage its construction projects and continue to economically operate its generation facilities under increasingly stringent environmental requirements. In addition, with an increase in competition and market complexity and constantly changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While these increases may have a potentially significant beneficial impact on margins, they could also raise any replacement power costs that Power may incur in the event of unanticipated outages, and could also further increase liquidity requirements as a result of contract obligations. Power could also be impacted by the lack of consistent rules in markets outside of PJM, including rate-regulated utility ownership of generation and other regulatory
actions favoring non-competitive markets. For additional information on liquidity requirements, see Liquidity and Capital Resources.
Energy Holdings
Energy Holdings’ operations are principally conducted through its subsidiaries Global, which has invested in international, rate-regulated distribution companies and domestic and international generation companies, and Resources, which primarily invests in energy-related leveraged leases.
Global
Global has reduced its international risk by opportunistically monetizing investments that no longer had a strategic fit. During the past three years, Global has reduced its overall investments from $2.6 billion to $1.9 billion, driven by sales of over $1 billion of investments in China, Brazil, Poland, India, Africa and the Middle East. See Note 4. Discontinued Operations, Acquisitions, Dispositions and Impairments of the Notes, for a discussion of these sales. The decrease in Global’s portfolio size due to the above sales was partially offset by strong earnings from its Texas merchant generation business and its electric distribution companies in Chile and Peru. Approximately 65% of Global’s remaining investments are in Chile and Peru with another 27% in the United States. Other modest sized investments in Italy, India and Venezuela comprise the remaining 8% of Global’s portfolio.
As a result of the investment sales, approximately 50% of Global’s future earnings is expected to be derived from its domestic generation business, of which over half is from its 2,000 MW gas-fired combined cycle merchant generation business in Texas with the balance from its 12 fully contracted generating facilities in which Global’s ownership percentage equates to nearly 400 MW. The other 50% of Global’s earnings is expected to be essentially from three rate-regulated electric distribution businesses in Chile and Peru which serve approximately two million customers and a 183 MW hydro generation facility in Peru. The regulatory environment in both Chile and Peru has generally been constructive since Global acquired these investments. Chile maintains an investment grade rating and Peru’s rating, although non-investment grade, has improved.
Energy Holdings continues to review Global’s portfolio, with a focus on its international investments. As part of this review, Energy Holdings considers the returns of its remaining investments against alternative investments across the PSEG companies, while considering the strategic fit and relative risks of these businesses. Energy Holdings is also considering the impact of any potential sales of its investments on its targeted credit metrics and debt service requirements and at present, Global anticipates that it will take into consideration an appropriate balance of the use of proceeds from any sales with returns of equity to PSEG and debt repayments.
Resources
Resources primarily has invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments.
Overview of 2006
During 2006, Energy Holdings had over $600 million of proceeds from the sales of Global’s investments in two generating stations in Poland, the sale of its interest in RGE, a distribution company in Brazil and from its sale of its remaining 46% interest in Dhofar Power.
Energy Holdings used this cash as well as funds on hand at December 31, 2005 and cash from operations to return $520 million of capital to PSEG, redeem all $309 million of its 7.75% 2007 Senior Notes in January 2006 and redeem $300 million of its 8.625% 2008 Senior Notes in October 2006.
Future Outlook
Energy Holdings expects decreased margins at Global in 2007 primarily relating to the absence of mark-to-market gains, a slight reduction in spark spreads and anticipated maintenance outages at Texas Independent Energy L.P. (TIE)’s plants. Also contributing to the expected decrease are higher taxes, the impact of adopting FIN 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB
Statement 109” (FIN 48) and related standards and lower earnings due to asset sales partly offset by the impact of early adoption of FAS 157.
As discussed above, Global’s earnings are primarily derived from its investments in the United States, Chile and Peru. As such, Global’s success will depend on continued strong energy markets in Texas and the economic and efficient operation of its electric distribution companies in Chile and Peru, including its ability to achieve reasonable rates and meeting expected growth in usage. The success of Global’s foreign investments will also depend on stable political, regulatory and economic policies, including foreign currency exchange rates and interest rates, particularly for Chile and Peru.
Resources’ ability to realize tax benefits associated with its leveraged lease investments is dependent upon taxable income generated by its affiliates. Resources’ earnings and cash flows are expected to decrease in the future as the investment portfolio matures. Resources faces risks with regard to the creditworthiness of its counterparties; the weighted average credit rating of its lessees at December 31, 2006 was A-/A3. Certain lessees’ ratings are below investment grade. The lease structures have various credit enhancement mechanisms. Resources monitors the credit rating of the lessees very closely, calling letters of credit and taking other measures when appropriate.
Energy Holdings also faces risks related to the tax treatment of uncertain tax positions which will be impacted by new accounting guidance under FIN 48 and FASB Staff Position No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction”, both of which are effective as of January 1, 2007. Based on its evaluation of this new guidance, Energy Holdings estimates that it will record a reduction to Retained Earnings of approximately $190 million to $215 million, effective January 1, 2007. In addition, this new guidance will have an impact on Energy Holdings’ future revenues and earnings, including an anticipated earnings reduction of $25 million to $35 million in 2007, as compared to 2006, which represents the majority of the anticipated impact on PSEG. See Note 2. Recent Accounting Standards of the Notes for further discussion.
RESULTS OF OPERATIONS
PSEG, PSE&G, Power and Energy Holdings
Net Income for the year ended December 31, 2006 was $739 million or $2.93 per share of common stock, diluted, based on approximately 252 million average shares outstanding. Net Income for the year ended December 31, 2005 was $661 million or $2.71 per share of common stock, diluted, based on approximately 244 million average shares outstanding. Included in 2006 Net Income was a $208 million after-tax estimated loss on disposal related to an agreement to sell Lawrenceburg. Included in 2005 Net Income was a $178 million after-tax loss from the sale of Power’s Waterford generation facility. See Note 4. Discontinued Operations, Acquisitions, Dispositions and Impairments of the Notes. Net Income for the year ended December 31, 2004 was approximately $726 million or $3.05 per share of common stock, diluted, based on approximately 238 million average shares outstanding.
(A)
Other activities include non-segment amounts of Energy Holdings and its subsidiaries and intercompany eliminations. Non-segment amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings.
(B)
Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include interest on certain financing transactions, Merger expenses and certain administrative and general expenses at PSEG (as parent company).
(C)
Global’s Income from Continuing Operations for 2006 includes the $178 million after-tax loss on the sale of Rio Grande Energia S.A. (RGE) in June 2006.
The year over year changes in PSEG’s Net Income primarily relates to changes in Net Income for PSE&G, Power and Energy Holdings, discussed below. Also included in PSEG’s results for each of the periods were financing costs at the parent level and Merger and Merger-related costs. For the year ended December 31, 2006, PSEG’s after-tax costs were $77 million, a decrease $18 million as compared to 2005. For the year ended December 31, 2005, PSEG’s after-tax costs were $95 million, an increase of $26 million as compared to 2004. The primary reason for these changes was the change in after-tax Merger and Merger-related costs which amounted to $8 million, $32 million and $4 million for the years ended December 31, 2006, 2005 and 2004, respectively.
PSEG
PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings, excluding changes related to intercompany transactions, which are eliminated in consolidation. It also includes certain financing costs at the parent company. For additional information on intercompany transactions, see Note 21. Related-Party Transactions of the Notes. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for PSE&G, Power and Energy Holdings that follow.
PSE&G
For the year ended December 31, 2006, PSE&G had Net Income of $265 million, a decrease of $83 million as compared to the year ended December 31, 2005. This decrease was primarily due to delayed decisions in its electric and gas base rate cases combined with the decline in electric and gas delivery volumes. Gas delivery volumes dropped 10% in 2006 as compared with 2005 and electric delivery volumes were down 3%. The weather was the primary cause of these declines with a drop of 16% in the number of degree days impacting gas. Gas commodity prices were extremely high early in 2006, which also contributed
to a decline in weather normalized sales. THI hours were normal in 2006 but 18% less than 2005 negatively impacting electric sales.
For the year ended December 31, 2005, PSE&G had Net Income of $348 million, a $2 million increase as compared to the year ended December 31, 2004. This slight increase resulted primarily from higher margins, due to favorable weather conditions, and reduced interest expense being substantially offset by higher Operation and Maintenance costs.
The year-over-year detail for these variances for these periods are discussed in more detail below:
Operating Revenues
PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM spot market; delivery revenues from the transmission and distribution of energy through its system; and other operating revenues from the provision of various services.
PSE&G makes no margin on gas commodity sales as the costs are passed through to customers. The difference between the gas costs paid under the requirements contract for residential customers and the revenues received from residential customers is deferred and collected from or returned to customers in future periods. Gas commodity prices fluctuate monthly for commercial and industrial customers and annually through the BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual BGSS proceedings.
PSE&G makes no margin on electric commodity sales as the costs are passed through to customers. PSE&G secures its electric commodity through the annual BGS auction. Electric commodity supply prices are set based on the results of these auctions for residential and smaller industrial and commercial customers, and are translated into seasonally-adjusted fixed rates. Electric supply for larger industrial and commercial customers is provided at a rate principally based on the hourly PJM real-time energy price. Customers may obtain their electric supply through either the BGS default electric supply service or through competitive third-party electric suppliers, and the majority of the customers subject to hourly pricing are currently receiving electric supply from third-party suppliers. Any differences between amounts paid by PSE&G to BGS suppliers for electric commodity, and the amounts of electric commodity revenue collected from customers is deferred and collected or returned to customers in subsequent months.
The $55 million increase for the year ended December 31, 2006, as compared to 2005 was due to increases of $78 million in commodity revenues and $3 million in other operating revenues offset by a decrease of $26 million in delivery revenues.
The $704 million increase for the year ended December 31, 2005, as compared to 2004 was due to increases of $624 million in commodity revenues, $74 million in delivery revenues and $6 million in other operating revenues.
Commodity
The $78 million increase in commodity revenues for the year ended December 31, 2006, as compared to 2005, was due to an increase in electric commodity revenues of $213 million offset by a decrease of $135 million in gas commodity revenues. The increase in electric revenues was primarily due to $299 million in higher BGS revenues (higher auction prices of $346 million offset by reduced sales of $47 million) offset by $85 million in lower Non-Utility Generation (NUG) revenues (lower prices of $82 million and by $3 million
for lower volumes). The decrease in gas revenues was primarily due to $317 million in lower volumes due to weather and $58 million due to the expiration of the Third Party Shopping Incentive Clause in July 2005. There is a corresponding $58 million increase in delivery revenues. These were offset by $240 million in higher BGSS prices.
The $624 million increase in commodity revenues for the year ended December 31, 2005, as compared to 2004, was due to increases in electric and gas revenues of $313 million and $311 million, respectively. The increase in electric revenues was primarily due to $216 million in higher BGS revenues (higher auction prices of $148 million and increased sales of $68 million) and $97 million in higher NUG revenues (higher prices of $98 million offset by $1 million for lower volumes). The increase in gas revenues was primarily due to $291 million in higher BGSS prices and $62 million in higher volumes due to weather offset by the decrease of $42 million due to the expiration of the Third Party Shopping Incentive Clause in July 2005. There is a corresponding $42 million increase in delivery revenues.
Delivery
The $26 million decrease in delivery revenues for the year ended December 31, 2006, as compared to 2005, was due to a $27 million decrease in gas and a $1 million increase in electric revenues. The gas decrease was due to $101 million in lower volumes primarily due to weather offset by $74 million in increased prices, $58 million of which was due to the expiration of the Third Party Shopping Incentive Clause in July 2005, described above in commodity revenues, $8 million due to rate relief effective November 9, 2006 and $8 million due to the Societal Benefits Clause (SBC) November 1, 2006 rate increase. The electric increase was due primarily to $13 million in higher securitization tariff rates and $8 million from a rate increase effective November 9, 2006, offset by $20 million in lower volumes due to weather.
The $74 million increase in delivery revenues for the year ended December 31, 2005, as compared to 2004, was due to increases in electric and gas revenues of $67 million and $7 million, respectively. The electric increase was due primarily to $55 million in higher volumes due to weather and $12 million in higher rates. The gas increase was due to the expiration of the Third Party Shopping Incentive in July 2005, resulting in an increase of $42 million in delivery revenues with a corresponding offset in commodity revenues, described above, and a $12 million increase in SBC revenues (offset in Operation and Maintenance Costs below). This was offset by $9 million in lower volume and demand revenues due to weather and $37 million due to the expiration of the Gas Cost Underrecovery Adjustment (GCUA) clause in January 2005.
Operating Expenses
Energy Costs
The $128 million increase for the year ended December 31, 2006, as compared to 2005, was comprised of an increase of $211 million in electric costs offset by a decrease of $83 million in gas costs. The increase in electric costs was caused by $255 million or 16% in higher prices for BGS and NUG purchases offset by $47 million in lower BGS volumes due to weather. The decrease in gas costs was caused by a $362 million or 17% decrease in sales volumes due primarily to weather and $8 million due to the expiration of the GCUA clause in January 2005, offset by $287 million or 11% in higher prices.
The $634 million increase for the year ended December 31, 2005, as compared to 2004, was comprised of increases of $319 million in electric costs and $315 million in gas costs. The increase in electric costs was caused by a $264 million or 8% increase due to higher prices for BGS and NUG purchases and a $67 million increase due to higher BGS volumes, partially offset by a decrease of $12 million due to lower NUG volumes. The increased gas costs were due to a $271 million or 16% increase in gas prices and an $81 million increase in sales volumes due primarily to higher sales to cogenerators. These were offset by a $37 million decrease due to the expiration of the GCUA clause in January 2005.
Operation and Maintenance
The $9 million increase for the year ended December 31, 2006, as compared to 2005, was due primarily to $9 million in increased labor and fringe benefits due to increased wages and Other Postretirement Benefits (OPEB) costs and $7 million in increased bad debt expense. These increases were offset by decreases of $3 million in injuries and damage claims and $2 million in write offs and $2 million in Net Operating Loss (NOL) purchases.
The $68 million increase for the year ended December 31, 2005, as compared to 2004, was due to increased SBC expenses of $27 million ($15 million electric, $12 million gas); $23 million in labor and fringe benefits; $6 million for increased injuries and damages reserves; $4 million for Merger-related expenses; $3 million for higher regulatory commission expenses; $2 million for higher bad debt expenses and $2 million for the purchase of NOL. SBC costs are deferred when incurred and amortized to expense when recovered in revenues.
Depreciation and Amortization
The $67 million increase for the year ended December 31, 2006, as compared to 2005, was comprised of increases of $70 million from the expiration of an excess depreciation credit, $6 million due to amortization of regulatory assets and $3 million due to additional plant in service. These increases were offset by decreases of $5 million due to revised plant depreciation and cost of removal rates, $3 million due to software amortization and $3 million due to the amortization of the Remediation Adjustment Clause (RAC).
The $30 million increase for the year ended December 31, 2005, as compared to 2004, was due primarily to a $33 million increase in the amortization of securitized regulatory assets, a $4 million increase due to additional plant in service and a $4 million increase in the amortization of the RAC. These were offset by an $8 million decrease in software amortization and a $3 million increase in excess depreciation reserve amortization.
Other Income and Deductions
The $10 million increase for the year ended December 31, 2006, as compared to 2005, was primarily due to an $8 million income tax gross-up on contributions in aid of construction (CIAC) in 2006. CIAC are taxable and PSE&G recognizes the gross-up as income when collected. Also included are increases of $1 million of short-term interest income and $1 million in gains on the sale of excess property.
Interest Expense
The $20 million decrease for the year ended December 31, 2005, as compared to 2004, was primarily due to decreases of $22 million due to lower average interest rates and lower amounts of long-term debt outstanding, primarily offset by $5 million in higher short-term debt balances outstanding and higher interest rates.
Income Taxes
The $52 million decrease for the year ended December 31, 2006, as compared to 2005, was primarily due to $55 million in lower pre-tax income offset by $3 million in various flow-through adjustments.
The $11 million decrease for the year ended December 31, 2005, as compared to 2004, was primarily due to decreases of $4 million in prior period adjustments, $3 million in various flow-through benefits and $3 million in lower pre-tax income.
Power
For the year ended December 31, 2006, Power had Net Income of $276 million, an increase of $84 million as compared to the year ended December 31, 2005. The increase primarily resulted from higher BGS contract prices and higher sales volumes in the various power pools, supported by improved nuclear operations and the commencement of commercial operations at Linden in May 2006 and at the Bethlehem Energy Center (BEC) in July 2005 and lower generation costs due to lower pool prices and lower demand under the BGS contract. Power also had lower non-trading mark-to-market losses, which were approximately $1 million, after-tax, in 2006 as compared to $8 million, after-tax, in 2005. Power’s increased earnings were partially offset by reduced margins on BGSS, as market prices for natural gas declined from historically high price levels experienced in the second half of 2005 while the cost of gas in inventory was reasonably stable, and lower demand in 2006 due to a warmer winter heating system and customer conservation. Power’s earnings were also offset by a $44 million write-down of four gas engine turbines which are planned for sale in 2007, a $30 million after-tax decrease in Income from the NDT Funds and higher Operation and
Maintenance Costs, Depreciation and Amortization and Interest Expense related to operation of the Linden and BEC facilities.
For the year ended December 31, 2005, Power had Net Income of $192 million, a decrease of $116 million as compared to the year ended December 31, 2004. The primary reason for the decrease was the $178 million Loss on Disposal of Waterford and the $16 million Cumulative Effect of a Change in Accounting Principle recorded in 2005. Power’s Income from Continuing Operations for the year ended December 31, 2005 was $434 million, an increase of $67 million as compared to 2004. This increase reflected higher pricing and increased sales in the various power pools and new wholesale contracts and reduced Operation and Maintenance costs associated with the outage at Hope Creek in 2004. Marked improvement in Power’s nuclear operations provided additional low-cost energy to satisfy Power’s contractual obligations and to sell into the market at higher prices. The increases at Power were partially offset by interest and depreciation costs related to facilities in Albany, New York, which commenced operation in July 2005 and Lawrenceburg, Indiana, which commenced operation in June 2004.
The year-over-year detail for these variances for these periods are discussed in more detail below:
Operating Revenues
The $30 million increase for the year ended December 31, 2006 as compared to 2005 was due to increases of $239 million in generation revenues and $27 million in trading revenues, which were partially offset by a decrease of $236 million in gas supply revenues.
The $861 million increase for the year ended December 31, 2005, as compared to 2004, was due to increases of $543 million in generation revenues and $368 million in gas supply revenues, which were partially offset by a decrease of $50 million in trading revenues.
Generation
The $239 million increase in generation revenues for the year ended December 31, 2006, as compared to 2005, was primarily due to an increase of $238 million from higher sales volumes in the various power pools, supported by improved nuclear operations and the commencement of the commercial operations of Linden in May 2006 and BEC in July 2005, partially offset by lower pool prices. Also contributing to the increase was $92 million of higher BGS contract revenues due to higher contract prices which were partly offset by a reduction in load being served under the fixed-price BGS contracts and termination of BGS hourly contracts in May 2006. The increases were partially offset by a decrease of $58 million due to certain wholesale contracts ending in 2005 and early 2006 and $33 million of unrealized losses on asset-backed electric forward contracts.
The $543 million increase in generation revenues for the year ended December 31, 2005, as compared to 2004, was primarily due to higher revenues of $226 million from higher pricing and increased sales in the various power pools supported by improved nuclear capacity, partially offset by reduced load being served under the fixed-priced BGS contracts. Also contributing to the increase were increases of $103 million from new wholesale contracts, $74 million from operations in New York, largely due to the commencement of
BEC’s operations, $65 million from RMR revenues, which Power began receiving in 2005 for certain of its generating facilities, and $75 million from increased ancillary services and operating reserves.
Gas Supply
The $236 million decrease in gas supply revenues for the year ended December 31, 2006, as compared to 2005, was primarily due to decreases of $334 million due to lower demand under the BGSS contract in 2006 due to a warmer winter heating season and improved customer conservation in 2006 and a $94 million in decreased prices and gas volumes and pipeline capacity sold to other gas distributors. The decreases were partially offset by an increase of $188 million due to higher prices under the BGSS contract.
The $368 million increase in gas supply revenues for the year ended December 31, 2005, as compared to 2004, was principally due to higher prices under the BGSS contract for gas and pipeline capacity partially offset by lower demand, largely resulting from a warmer winter heating season in 2005 as compared to 2004.
Trading
The $27 million increase in trading revenues for the year ended December 31, 2006, as compared to 2005, was principally due to higher realized gains related to emissions credits.
The $50 million decrease in trading revenues for the year ended December 31, 2005, as compared to 2004, resulted principally from reductions in realized gains related to emission credits.
Operating Expenses
Energy Costs
Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G.
The $311 million decrease for the year ended December 31, 2006, as compared to 2005, was primarily due to decreases of $267 million from lower pool prices and lower demand under the BGS contract, $144 million from a reduced volume of gas purchased to satisfy Power’s BGSS obligations, somewhat offset by higher gas prices related to inventory for the 2005/2006 winter heating season, and $58 million due to favorable pricing of fuel-related asset-backed transactions in 2006. These decreases were partially offset by $80 million of losses realized on gas hedges in 2006, an increase of $42 million in fuel costs and an increase of $35 million in transmission fees. The increase in fuel costs was largely due to higher volumes of gas purchased to meet increased production by the gas-fired plants, including Linden and BEC, and higher oil prices, partially offset by lower gas prices during 2006 and a lower volume of oil purchases due to reduced running times of certain of the oil-fired plants in 2006.
The $713 million increase for the year ended December 31, 2005, as compared to 2004, was primarily due to increased generation costs, reflecting higher fossil fuel prices and higher prices on an increased volume of purchased power for new contracts and higher prices for gas purchased to satisfy Power’s BGSS obligations.
Operation and Maintenance
The $19 million increase for the year ended December 31, 2006, as compared to 2005, was principally due to higher maintenance costs of $60 million related to certain of the fossil plants and scheduled outages at the nuclear units. These increases were partially offset by the absence of a $14 million restructuring charge recorded in 2005 related to Nuclear’s workforce realignment plan, a decrease of $10 million in payroll and benefits due to a reduction in employees and a decrease of $14 million in fees paid to Services for information technology and various administrative services.
The $9 million decrease for the year ended December 31, 2005, as compared to 2004, was primarily due to a decrease of $36 million in equipment repair costs related to outages at the nuclear facilities, $9 million of lower real estate taxes, $5 million of lower transmission fees in the power pools, $4 million of lower expenses related to reduced trading activities in 2005 and an $8 million settlement of co- owner billings in 2004 related to Power’s jointly-owned facilities. The decreases were substantially offset by an increase of $11 million in pension, postretirement and other employee benefits, a $16 million increase attributable to repairs for
outages at the fossil generation plants, the aforementioned $14 million restructuring charge and a $12 million settlement with the U.S. Department of Energy (DOE) in 2004.
Write-Down of Assets
The $44 million write-down of assets recorded in 2006 related to four turbines for which Power has no immediate use and intends to sell. For additional information, see Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes.
Depreciation and Amortization
The $26 million increase for the year ended December 31, 2006, as compared to 2005, was primarily due to the Linden and BEC plants being placed into service in May 2006 and July 2005, respectively.
The $16 million increase for the year ended December 31, 2005, as compared to 2004, was primarily due to the BEC facility being placed into service and a higher depreciable asset base in 2005 at Nuclear.
Other Income and Deductions
The $78 million decrease for the year ended December 31, 2006, as compared to 2005, was primarily due to decreased net realized income of $29 million and increased realized losses of $19 million related to the NDT Funds. Also contributing to the decrease were charges recorded in 2006 of $14 million for an other-than-temporary impairment of certain NDT Fund securities and $14 million for penalties related to negotiations concerning environmental concerns and an alternate pollution reduction plan for Power’s Hudson unit.
The $27 million increase for the year ended December 31, 2006, as compared to 2004, was primarily due to increased realized gains and income of $13 million related to the NDT Funds, lower realized losses of $8 million in 2005 on NDT Funds and a $5 million gain from the sale in September 2005 of four gas turbine generators located in Burlington, New Jersey.
Interest Expense
The $48 million increase for the year ended December 31, 2006, as compared to 2005, was due primarily to lower capitalized interest costs in 2006 related to commencement of operations of the Linden and BEC facilities.
The $10 million increase for the year ended December 31, 2005, as compared to 2004, was due primarily to $8 million of lower capitalized interest costs in 2005 related to commencement of operations of BEC.
Income Taxes
The $45 million increase for the year ended December 31, 2006, as compared to 2005, was primarily due to higher pre-tax income.
The $91 million increase for the year ended December 31, 2005, as compared to 2004, was primarily due to an increase of $63 million in taxes on pre-tax income, the recording in 2005 of $15 million of taxes for the NDT Funds and the reversal in 2004 of $16 million of contingency reserves and other prior period adjustments.
Loss from Discontinued Operations, including Loss on Disposal, net of tax
On December 29, 2006, Power entered into an agreement to sell its Lawrenceburg generation facility for approximately $325 million and recognized an estimated loss on disposal of $208 million, net of tax, in December 2006, for the initial write-down of its carrying amount of Lawrenceburg to its fair value less cost to sell. The transaction is anticipated to close in the second quarter of 2007. Losses from Discontinued Operations of Lawrenceburg, not including the estimated Loss of Disposal, were $31 million, $28 million and $25 million for the years ended December 31, 2006, 2005 and 2004, respectively.
On May 27, 2005, Power reached an agreement to sell its Waterford generation facility for approximately $220 million and recognized an estimated loss on disposal of $177 million, net of tax, for the initial write-down of its carrying amount of Waterford to its fair value less cost to sell. On September 28,
2005, Power completed the sale of Waterford and recognized an additional loss of $1 million. Losses from Discontinued Operations of Waterford, not including the Loss of Disposal, were $20 million and $34 million for the years ended December 31, 2005 and 2004, respectively.
See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes for additional information.
Cumulative Effect of a Change in Accounting Principle
For the year ended December 31, 2005, Power recorded an after-tax loss in the amount of $16 million due to the required recording of a liability for the fair value of asset-retirement costs primarily related to its generation plants under FIN 47, which was adopted in December 2005. See Note 3. Asset Retirement Obligations of the Notes for additional information.
Energy Holdings
For the year ended December 31, 2006, Energy Holdings had Net Income of $275 million, an increase of $58 million as compared to the year ended December 31, 2005. Included in Energy Holdings’ Net Income for 2006 was a $178 million after-tax loss on the sale of RGE, which was more than offset by the $226 million after-tax gain on disposal of Elcho and Skawina. Strong operations combined with approximately $29 million of after-tax mark-to-market gains on forward gas contracts in 2006 as compared to $3 million of after-tax mark-to-market losses in 2005 at TIE and higher sales volumes at Sociedad Austral de Electricidad S.A. (SAESA) also contributed to the increase. The increases were partially offset by the absence of an after-tax gain of $43 million from the sale of Resources’ leveraged lease investment in Generation Station Unit 2 (Seminole) in December 2005.
For the year ended December 31, 2005, Energy Holdings had Net Income of $217 million, an increase of $76 million as compared to the year ended December 31, 2004. This increase was primarily due to higher earnings due to improved operations at TIE and in South America and the aforementioned gain on the sale of Seminole in December 2005.
The year-over-year detail for these variances for these periods are discussed in more detail below:
The classification of the results of Global’s investments on Energy Holdings’ Consolidated Financial Statements is dependent upon Global’s ownership percentage in the underlying investment which determines whether the investment is consolidated into Energy Holdings’ Consolidated Financial Statements or if it is accounted for under the equity method of accounting. Global owns 100% of TIE, SAESA and Electroandes S.A. (Electroandes) and 85% of Prisma 2000 S.p.A. (Prisma). As a result, the revenues, expenses, assets and liabilities of those investments are reflected on Energy Holdings’ Consolidated Financial Statements. Global’s investments in Chilquinta Energia (Chilquinta), Luz del Sur S.A.A. (LDS), GWF, Kalaeloa Partners L.P. ( Kalaeloa) and several other smaller investments are accounted for under the equity method of accounting. Therefore, Energy Holdings only records its share of the net income from these projects as Income from Equity Method Investments on its Consolidated Statements of Operations.
The variances in Operating Revenues, Energy Costs, Operation and Maintenance, Depreciation and Amortization and Income from Equity Method Investments were primarily attributed to Global’s increased revenues at TIE in 2006, as compared to same period in 2005, primarily due to unrealized gains on forward contracts and a stronger market and stronger spark spread (the difference between the market price of electricity and the cost of natural gas fuel), the consolidation of Prisma in May 2006, which generated $32 million of revenue, and Global’s sale of a 35% interest in Dhofar Power Company S.A.O.C. (Dhofar Power) through a public offering on the Omani Stock Exchange in April 2005 and sale of its remaining interest of 46% in November 2006, receiving net proceeds after-tax of approximately $31 million, the approximate book value of the investment. The variances are also related to favorable foreign currency exchange rates and higher energy sales volumes at SAESA.
Operating Revenues
The increase of $55 million for the year ended December 31, 2006, as compared to 2005, was due to higher revenues at Global of $128 million, which was primarily related to a $79 million increase at TIE due to higher unrealized gains on forward contracts which were slightly offset by a reduction in gas sales. Also contributing to the increase at Global was a $78 million increase at SAESA in Chile due to higher energy sales volumes as well as tariff increases and favorable foreign currency exchange rates, a $24 million increase due to the consolidation of Prisma and $10 million of increased revenue from Electroandes due to volume and price increases. These increases were partly offset by a $37 million decrease due to the absence of a gain from withdrawal from the Eagle Point Cogeneration Partnership in the prior year and the absence of $20 million of revenue due to the deconsolidation of Dhofar Power. Offsetting the increases at Global were lower revenues at Resources of $73 million primarily due to the absence of a $71 million pre-tax gain from the sale of Resources’ interest in Seminole Generation in December 2005 coupled with the absence of $20 million of leveraged lease income in 2006 due to the Seminole sale, partially offset by a $21 million write-off of a leveraged lease investment with United Airlines in 2005.
The increase of $466 million for the year ended December 31, 2005, as compared to 2004, was due to higher revenues at Global of $406 million, including a $279 million increase related to the consolidation of TIE commencing July 1, 2004 and $136 million due to higher revenues at TIE in the second half of 2005 and a $62 million increase related to SAESA due to higher energy sales volumes offset by a $43 million decrease related to the deconsolidation of Dhofar Power and the absence of a $35 million gain on the sale of Meiya Power Company Limited (MPC) in 2004. Also contributing to the increase were higher revenues at Resources of $60 million primarily due to the $71 million pre-tax gain recognized in 2005 from the sale of its interest in Seminole offset by the absence of an $11 million pre-tax charge recorded due to the termination of the lease investment in the Collins generating facility in 2004.
Energy Costs
The increase of $64 million for the year ended December 31, 2006, as compared to 2005, was primarily due to a $59 million increase at SAESA due to increased volume and higher spot prices for energy and an $8 million increase due to the consolidation of Prisma in May 2006, partially offset by a $5 million decrease related to the deconsolidation of Dhofar Power.
The increase of $353 million for the year ended December 31, 2005, as compared to 2004, was primarily due to a $219 million increase related to the consolidation of TIE commencing July 1, 2004, a $99 million increase in energy costs at TIE in the second half of 2005 and a $44 million increase related to SAESA due to significant increases in Energy Costs, offset by a $13 million decrease related to the deconsolidation of Dhofar Power.
Operation and Maintenance
The decrease of $7 million for the year ended December 31, 2006, as compared to 2005, was primarily due to a reduction of $9 million at Resources mainly due to a reduction of operating lease expense. The decrease is also due to a $4 million reduction in administrative expenses related to lower corporate assessments, wages and benefits, and legal and consulting expense. These decreases are offset by an $8 million increase at Global due to a $17 million increase related to the operations of SAESA, $5 million increase due to the consolidation of Prisma partially offset by a $9 million decrease at TIE and a $4 million decrease from the deconsolidation of Dhofar Power.
The increase of $44 million for the year ended December 31, 2005, as compared to 2004, was primarily due to a $41 million increase related to the consolidation of TIE commencing July 1, 2004 and a $14 million increase related to SAESA offset by a $6 million decrease related to the deconsolidation of Dhofar Power and a $7 million decrease in energy costs at TIE in the second half of 2005.
Write-Down of Assets
The $274 million write-down of assets is primarily related to a $263 million pre-tax loss on Global’s sale of its 32% indirect ownership interest in RGE, $4 million pre-tax loss related to the sale of Global’s interest in Magellan Capital Holdings Corporation (MCHC), and a $7 million pre-tax loss on the impairment of Global’s generation projects in Venezuela. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes.
Depreciation and Amortization
The increase of $6 million for the year ended December 31, 2006, as compared to 2005, was primarily due to a $3 million increase at Resources and a $3 million increase at Global due to a $4 million increase related to the consolidation of Prisma and an increase of $3 million at SAESA, offset by a $4 million decrease resulting from the deconsolidation of Dhofar Power.
The increase of $2 million for the year ended December 31, 2005, as compared to 2004, was primarily due to an $8 million increase related to the consolidation of TIE commencing July 1, 2004 and a $2 million increase related to Resources due to the conversion of the Delta and Northwest leases from leveraged leases to operating leases, offset by a $9 million decrease related to the deconsolidation of Dhofar Power.
Income from Equity Method Investments
The decrease of $4 million for the year ended December 31, 2006, as compared to 2005, was primarily driven by the absence of $12 million of earnings due to the sale of RGE in 2006 partially offset by the absence of foreign currency losses in 2005 from Prisma of $8 million.
The increase of $5 million for the year ended December 31, 2005, as compared to 2004, was primarily due to a $20 million increase due to stronger results in South America (RGE and Chilquinta) offset by an $11 million decrease related to the loss of earnings associated with the sale of Global’s equity interest in MPC in December 2004 and a $3 million decrease related to Global’s investment in Prisma.
Other Income and Deductions
The increase of $19 million for the year ended December 31, 2006, as compared to 2005, was primarily due to an increase in interest and dividend income of approximately $10 million and lower losses in foreign currency transactions due to favorable currency fluctuations mainly for Prisma operations in Italy.
The decrease of $11 million for the year ended December 31, 2005, as compared to 2004, was primarily due to a loss on early extinguishment of debt of $7 million and foreign currency transaction losses of $9 million primarily on notes receivables from Prisma, partially offset by interest income from PSEG related to inter-company loans.
Interest Expense
The decrease of $10 million for the year ended December 31, 2006, as compared to 2005, was mainly due to a decrease in Energy Holdings’ debt outstanding and a net decrease of $2 million resulting from the consolidation of Prisma and the deconsolidation of Dhofar Power.
The $10 million decrease for the year ended December 31, 2005, respectively, as compared to 2004, was primarily due an $11 million decrease related to the deconsolidation of Dhofar Power in May 2005 and an $8 million decrease related to Resources due to a reduction in intercompany interest charges offset by a $9 million increase related to the consolidation of TIE commencing on July 1, 2004.
Income Taxes
The decrease of $108 million for the year ended December 31, 2006, as compared to 2005, was primarily attributable to a tax benefit resulting from Global’s sale of its 32% indirect ownership interest in RGE and sale of SAESA’s 50% interest in Empresa de Energia Rio Negro S.A. (Argentine utility operation).
The $24 million increase for the year ended December 31, 2005, as compared to 2004, was primarily due to the recording of $11 million of U.S. tax associated with repatriation of funds under the American Jobs Creation Act of 2004 (Jobs Act), an increase in the mix of domestic earnings for Global due to improved results at TIE, taxes recognized of $28 million from the sale of Seminole and additional benefits resulting from revisions to Resources’ lease runs performed in the fourth quarter of 2005. For further information on lease runs, see below in Resources’ forecast of state taxable income and tax liability over the relevant lease terms. This forecast was embedded in the lease reruns and led to an income tax benefit of $43 million in 2004 to reflect the cumulative benefit of this adjustment. This benefit was largely offset by the tax impact associated with a $31 million decrease in leveraged lease revenue.
Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax
Elcho and Skawina
In 2006, Global sold its interest in two coal-fired plants in Poland, Elcho and Skawina. Proceeds, net of transaction costs, were $476 million, resulting in a gain of $227 million net of tax expense of $142 million. Income (Loss) from Discontinued Operations related to Elcho and Skawina for the years ended December 31, 2006, 2005 and 2004 was $227 million, $18 million and $(10) million, respectively. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes for additional information.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, PSE&G, Power and Energy Holdings.
Financing Methodology
PSEG, PSE&G, Power and Energy Holdings
Capital requirements for PSE&G, Power and Energy Holdings are met through liquidity provided by internally generated cash flow and external financings. PSEG expects to be able to fund existing commitments, reduce debt and meet dividend requirements using internally generated cash. PSEG, Power and Energy Holdings from time to time make equity contributions or otherwise provide credit support to their respective direct and indirect subsidiaries to provide for part of their capital and cash requirements, generally relating to long-term investments. PSEG does not intend to contribute additional equity to Energy Holdings.
At times, PSEG utilizes intercompany dividends and intercompany loans (except however, that PSE&G may not, without prior BPU approval, and Fossil, Nuclear and ER&T may not without prior FERC approval make loans to their affiliates) to satisfy various subsidiary or parental needs and efficiently manage short-term cash. Any excess funds are invested in short-term liquid investments.
External funding to meet PSEG’s, PSE&G’s and Power’s needs and a majority portion of the requirements of Energy Holdings consist of corporate finance transactions. The debt incurred is the direct obligation of those respective entities. Some of the proceeds of these debt transactions may be used by the respective obligor to make equity investments in its subsidiaries.
As discussed below, depending on the particular company, external financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loans, commercial paper and/or project financings. Some of these transactions involve special purpose entities (SPEs), formed in accordance with applicable tax and legal requirements in order to achieve specified financial advantages, such as favorable legal liability treatment. PSEG consolidates SPEs, as applicable, in accordance with FIN No. 46, “Consolidation of Variable Interest Entities (VIEs)” (FIN 46). See Note 2. Recent Accounting Standards of the Notes.
The availability and cost of external capital is affected by each entity’s performance, as well as by the performance of their respective subsidiaries and affiliates. This could include the degree of structural separation between PSEG and its subsidiaries and the potential impact of affiliate ratings on consolidated and unconsolidated credit quality. Additionally, compliance with applicable financial covenants will depend upon future financial position, earnings and net cash flows, as to which no assurances can be given.
Over the next several years, PSEG, PSE&G, Power and Energy Holdings may be required to extinguish or refinance maturing debt and, to the extent there is not sufficient internally generated funds, may incur additional debt and/or provide equity to fund investment activities. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at current levels and reasonable interest rates may adversely affect PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective financial condition, results of operations and net cash flows.
From time to time, PSEG, PSE&G, Power and Energy Holdings may repurchase portions of their respective debt securities using funds from operations, asset sales, commercial paper, debt issuances, equity issuances and other sources of funding and may make exchanges of new securities, including common stock, for outstanding securities. Such repurchases may be at variable prices below, at or above prevailing market prices and may be conducted by way of privately negotiated transactions, open-market purchases, tender or exchange offers or other means. PSEG, PSE&G, Power and Energy Holdings may utilize brokers or dealers or effect such repurchases directly. Any such repurchases may be commenced or discontinued at any time without notice.
Energy Holdings
A portion of the financing for Global’s investments is normally provided by non-recourse financing transactions. These consist of loans from banks and other lenders that are typically secured by project assets and cash flows. Non-recourse transactions generally impose no material obligation on the parent-level investor to repay any debt incurred by the project borrower. The consequences of permitting a project-level default include the potential for loss of any invested equity by the parent. However, in some cases, certain obligations relating to the investment being financed, including additional equity commitments, may be guaranteed by Global and/or Energy Holdings for their respective subsidiaries. PSEG does not provide guarantees or credit support to Energy Holdings or its subsidiaries.
Operating Cash Flows
PSEG, PSE&G, Power and Energy Holdings
PSEG expects strong cash from operations primarily driven by earnings from Power supported by improved energy margins and capacity markets. Operating cash flows are expected to be sufficient to fund capital expenditures and shareholder dividend payments, with excess cash available to invest in the business, reduce debt and/or repurchase common stock.
PSEG
For the year ended December 31, 2006, PSEG’s operating cash flow increased by approximately $959 million from $970 million to $1.9 billion, as compared to 2005, due to net increases from its subsidiaries as discussed below.
For the year ended December 31, 2005, PSEG’s operating cash flow decreased by approximately $635 million from $1.6 billion to $970 million, as compared to 2004, primarily due to net decreases at Power for its working capital requirements, discussed below.
PSE&G
PSE&G’s operating cash flow increased approximately $115 million from $689 million to $804 million for the year ended December 31, 2006, as compared to 2005, primarily due to a decrease in customer receivables, reflecting lower sales volumes due to a warmer winter heating season and lower gas prices in 2006.
PSE&G’s operating cash flow decreased approximately $7 million from $696 million to $689 million for the year ended December 31, 2005, as compared to 2004.
Power
Power’s operating cash flow increased approximately $907 million from $136 million to $1 billion for the year ended December 31, 2006, as compared to 2005, due to a significant reduction in margin requirements and fuel inventories, largely resulting from decreases in commodity prices.
Power’s operating cash flow decreased approximately $371 million from $507 million to $136 million for the year ended December 31, 2005, as compared to 2004 primarily due to increased margin requirements and an increase in fuel inventory because of significantly increased commodity prices.
Energy Holdings
Energy Holdings’ operating cash flow decreased approximately $114 million from $273 million to $159 million for the year ended December 31, 2006, as compared to 2005. The decrease was mainly due to taxes paid related to the sale of Elcho, Skawina and RGE in 2006. The proceeds from the these sales are included in Cash Flows from Investing Activities on Energy Holdings’ Consolidated Statements of Cash Flows.
Energy Holdings’ operating cash flow decreased approximately $130 million from $403 million to $273 million for the year ended December 31, 2005, as compared to 2004, due primarily to a decrease in Resources’ cash flows, which was driven by the timing of receipt of tax benefits, and the monetization of the remaining receivables of PETAMC in 2004.
Common Stock Dividends
Dividend payments on common stock for the year ended December 31, 2006 were $2.28 per share and totaled approximately $574 million. Dividend payments on common stock for the year ended December 31, 2005 were $2.24 per share and totaled approximately $541 million. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. On January 17, 2007, PSEG announced an increase in its dividend from $0.57 to $0.585 per share for the first quarter of 2007. This quarterly increase reflects an indicated annual dividend rate of $2.34 per share.
Short-Term Liquidity
PSEG, PSE&G, Power and Energy Holdings
In December 2006, PSEG and Power established new credit facilities, which are available for letters of credit and short-term funding, replacing their previous credit facilities. PSEG’s new facility also provides liquidity backup for its $1 billion commercial paper program. Also in December 2006, PSE&G amended its $600 million credit facility to update the terms and extend the expiration date to June 2011.
PSEG, PSE&G, Power and Energy Holdings each believe that sufficient liquidity exists to fund their respective short-term cash needs.
As of December 31, 2006, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $3.3 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted to availability and use to the specific companies as listed below. As of December 31, 2006, PSEG has no loans outstanding under its uncommitted facility and PSE&G had $31 million of loans outstanding under its uncommitted facility.
(A)
PSEG/Power joint and several co-borrower facilities.
(B)
Energy Holdings/Global/Resources joint and several co-borrower facility.
(C)
These amounts relate to letters of credit outstanding.
Power
As of December 31, 2006, Power had borrowed $54 million from PSEG in the form of an intercompany loan.
During the year ending December 31, 2006, Power’s required margin postings for sales contracts entered into in the normal course of business decreased as commodity prices declined. The required margin postings will fluctuate based on volatility in commodity prices. Should commodity prices rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract obligations are fulfilled, liquidity requirements are reduced.
In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit rating to below investment grade, which represents at least a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide performance assurance, generally in the form of a letter of credit or cash. Providing this support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset portfolio. Power believes it has sufficient liquidity to meet any required posting of collateral resulting from a credit rating downgrade. See Note 12. Commitments and Contingent Liabilities of the Notes for further information.
Energy Holdings
Energy Holdings and its subsidiaries had $98 million in cash, including $38 million invested offshore as of December 31, 2006. In addition, as of December 31, 2006, Energy Holdings had an outstanding demand loan receivable from PSEG of $28 million. See External Financings-Energy Holdings below for Energy Holdings’ additional use of its excess cash.
External Financings
PSEG
On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Prior to September 1, 2006, PSEG had purchased shares on the open market to meet the exercise of stock options. As of December 31, 2006, PSEG issued 410,365 shares of its common treasury stock in connection with settling stock options for approximately $15 million.
For the year ended December 31, 2006, PSEG issued approximately 1 million shares of its common stock under its Dividend Reinvestment Program and its Employee Stock Purchase Program for approximately $68 million.
In October 2006, PSEG repaid $49 million of its 6.89% Senior Notes which are due in equal installment payments through 2009.
In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity investment in the trust.
PSE&G
On June 23, 2006, PSE&G repaid at maturity $175 million of its Floating Rate Series A First and Refunding Mortgage Bonds.
On March 1, 2006, PSE&G repaid at maturity $147 million of its 6.75% Series UU First and Refunding Mortgage Bonds.
In December 2006, PSE&G issued $250 million of 5.70% Secured Medium Term Notes Series D due 2036. The proceeds were used to replace in part the aforementioned matured Floating Rate Series A and 6.75% Series UU First and Refunding Mortgage Bonds.
For the year ended December 31, 2006, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II) repaid approximately $155 million and $8 million, respectively, of their transition bonds.
On January 2, 2007, PSE&G repaid at maturity $113 million of its 6.25% Series WW First and Refunding Mortgage Bonds.
Power
In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes.
Energy Holdings
In January 2006, Energy Holdings redeemed all $309 million of its 7.75% Senior Notes due in 2007.
On February 17, 2006, the maturity of the Odessa-Ector Power Partners, L.P. (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above LIBOR. On September 29, 2006, an interest rate swap took effect which converted the floating LIBOR interest rate on approximately 80% of Odessa’s debt to a fixed rate of 5.4275% through December 31, 2009.
On October 23, 2006, Energy Holdings redeemed $300 million of its $507 million outstanding 8.625% Senior Notes due in 2008.
During 2006, Energy Holdings made cash distributions to PSEG totaling $520 million in the form of returns of capital.
Also during 2006, Energy Holdings’ subsidiaries repaid approximately $51 million of non-recourse debt, of which $43 million primarily related to SAESA and TIE, $6 million by Resources and $2 million by EGDC.
Debt Covenants
PSEG, PSE&G, Power and Energy Holdings
PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective credit agreements may contain maximum debt to equity ratios, minimum cash flow tests and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon the respective future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to which no assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as financial performance or liquidity measures. The debt
underlying the preferred securities of PSEG, which is presented in Long-Term Debt in accordance with FIN 46, is not included as debt when calculating these ratios, as provided for in the various credit agreements.
Energy Holdings’ credit agreement also contains customary provisions under which the lender could refuse to advance loans in the event of a material adverse change in the borrower’s business or financial condition.
PSEG
Financial covenants contained in PSEG’s credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans, certain letters of credit not related to collateral postings for commodity/energy contracts and similar instruments) to total capitalization (including preferred securities outstanding and excluding any impacts for Accumulated Other Comprehensive Income adjustments related to marking energy contracts to market and equity reductions from the funded status of pensions or benefit plans associated with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”) covenant. This covenant requires that such ratio not be more than 70.0%. As of December 31, 2006, PSEG’s ratio of debt to capitalization (as defined above) was 51.6%.
PSE&G
Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total capitalization covenant. This covenant requires that such ratio will not be more than 65.0%. As of December 31, 2006, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 48.5%.
In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2006, PSE&G’s Mortgage coverage ratio was 4.1 to 1 and the Mortgage would permit up to approximately $2.1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements.
Power
Financial covenants contained in Power’s credit facility include a ratio of debt to total capitalization covenant. The Power ratio is the same debt to total capitalization calculation as set forth above for PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets). This covenant requires that such ratio will not exceed 65.0%. As of December 31, 2006, Power’s ratio of debt to total capitalization (as defined above) was 38.4%.
Energy Holdings
Energy Holdings’ bank revolving credit agreement has a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than or equal to 1.75. As of December 31, 2006, Energy Holdings’ coverage of this covenant was 3.53. Additionally, Energy Holdings must maintain a ratio of net debt (recourse debt offset by funds loaned to PSEG) to EBITDA of less than 5.25. As of December 31, 2006, Energy Holdings’ ratio under this covenant was 2.59. Energy Holdings is a co-borrower under this facility with Global and Resources, which are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfaction of certain financial covenants. Net cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts under the credit agreement. Net cash proceeds from asset sales during any 12-month period in excess of 10% of total assets must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources.
Energy Holdings’ indenture with respect to its senior notes does not permit liens securing indebtedness in excess of 10% of consolidated net tangible assets as calculated under the terms of the indenture. The terms of Energy Holdings’ Senior Notes allow the holders to demand repayment if a transaction or series of related transactions causes the assets of Resources to be reduced by 20% or more and as a direct result there is a downgrade of ratings.
Cross Default Provisions
PSEG, PSE&G, Power and Energy Holdings
The PSEG bank credit agreement contains default provisions under which a default by it in an aggregate amount of $50 million or greater would result in the potential acceleration of payment under this agreement. Under certain conditions, a default by PSE&G or Power in an aggregate amount of $50 million or greater would also result in potential acceleration of payment under this agreement. PSEG has removed Energy Holdings from all cross default provisions.
PSEG’s bank credit agreement and note purchase agreements related to private placement of debt (collectively, Credit Agreements) contain cross default provisions under which certain payment defaults by PSE&G or Power, certain bankruptcy events relating to PSE&G or Power, the failure by PSE&G or Power to satisfy certain final judgments or the occurrence of certain events of default under the financing agreements of PSE&G or Power, would each constitute an event of default under the PSEG Credit Agreements. Under the note purchase agreements, it is also an event of default if PSE&G or Power ceases to be wholly-owned by PSEG. Under the bank credit agreement, both PSE&G and Power would have to cease to be wholly-owned by PSEG before an event of default would occur.
PSE&G
PSE&G’s Mortgage has no cross defaults. The PSE&G Medium-Term Note Indenture has a cross default to the PSE&G Mortgage. The PSE&G credit agreement has a provision under which a default by PSE&G in the aggregate of $50 million or greater would result in an event of default and the potential acceleration of payment under that agreement.
Power
The Power Senior Debt Indenture contains a default provision under which a default by Power, Nuclear, Fossil or ER&T in an aggregate amount of $50 million or greater would result in an event of default and the potential acceleration of payment under the indenture. There are no cross defaults within Power’s indenture from PSEG, Energy Holdings or PSE&G.
The Power credit agreement also has a provision under which a default by Power, Nuclear, Fossil or ER&T in an aggregate amount of $50 million or greater would result in an event of default and the potential acceleration of payment under that agreement.
Energy Holdings
Energy Holdings’ credit agreement and Senior Note Indenture contain default provisions under which a default by it, Resources or Global in an aggregate amount of $25 million or greater would result in an event of default and the potential acceleration of payment under that agreement or the Indenture.
Ratings Triggers
PSEG, PSE&G, Power and Energy Holdings
The debt indentures and credit agreements of PSEG, PSE&G, Power and Energy Holdings do not contain any material ‘ratings triggers’ that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements.
PSE&G
In accordance with the BPU approved requirements under the BGS contracts that PSE&G enters into with suppliers, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, PSE&G would be required to file with the BPU a plan to assure continued payment for the BGS requirements of its customers.
PSE&G is the servicer for the bonds issued by Transition Funding and Transition Funding II. If PSE&G were to lose its investment grade rating, PSE&G would be required to remit collected cash daily to the bond trustee. Currently, cash is remitted monthly.
Power
In connection with the management and optimization of Power’s asset portfolio, ER&T maintains underlying agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit rating to below an investment grade rating, many of these agreements allow the counterparty to demand that ER&T provide performance assurance, generally in the form of a letter of credit or cash. As of December 31, 2006, if Power were to lose its investment grade rating and assuming all the counterparties to agreements in which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post collateral in an amount equal to approximately $578 million. See Note 12. Commitments and Contingent Liabilities of the Notes.
Credit Ratings
PSEG, PSE&G, Power and Energy Holdings
Following the termination of the Merger Agreement in September 2006, credit ratings remained unchanged as shown in the table below. Standard & Poor’s (S&P) affirmed its “BBB” corporate credit rating for PSEG, Power, and PSE&G. S&P revised its outlook from watch developing to negative. Moody’s Investors Service (Moody’s) affirmed its credit ratings for PSEG and PSE&G while revising the outlooks from stable to negative. The ratings and outlooks for Power and Energy Holdings were unchanged by Moody’s. Fitch Ratings (Fitch) announced there would be no immediate impact on ratings and outlooks for PSEG and its subsidiaries. At that time, the agencies noted that the ratings below were predicated on continued improvement in financial metrics, specifically operating cash flows and ongoing deleveraging, as well as continued strong operating performance from Power’s generating units and reasonable outcomes to PSE&G’s pending electric and gas rate cases.
If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities and serve to materially increase those companies’ cost of capital and limit their access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
(A)
Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. /I 8iuok 0p
(B)
S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.
(C)
Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and (highest) to D (lowest) for short-term securities.
Other Comprehensive Income
PSEG, Power and Energy Holdings
For the year ended December 31, 2006, PSEG, PSE&G, Power and Energy Holdings had Other Comprehensive Income of $706 million, $5 million, $483 million and $217 million, respectively, due primarily to a reduction in the net unrealized losses on derivatives accounted for as hedges in accordance with SFAS 133 at Power and foreign currency translation adjustments at Energy Holdings.
During the year ended December 31, 2006, Power’s Accumulated Other Comprehensive Loss decreased from $487 million to $177 million. The primary cause was a decrease of approximately $310 million related to energy and related contracts that qualify for hedge accounting that were entered into by Power in the normal course of business. During the year ended December 31, 2006, the decrease in gas and electric prices resulted in a reduction in unrealized losses on many of those contracts, which are recorded in Accumulated Other Comprehensive Loss. This decrease was partially offset by a $173 million adjustment recorded at Power in connection with the adoption of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158).
As of December 31, 2006, Energy Holdings had Accumulated Other Comprehensive Income of $103 million. The primary reasons for the improvement, as compared to the Accumulated Other Comprehensive Loss of $110 million as of December 31, 2005, were the realization of losses on Brazilian currency as a result of the sale of RGE and the unwinding of an interest rate swap due to the sale of Global’s facilities in Poland.
CAPITAL REQUIREMENTS
PSEG, PSE&G, Power and Energy Holdings
It is expected that the majority of each subsidiary’s capital requirements over the next five years will come from internally generated funds. Projected construction and investment expenditures, excluding nuclear fuel purchases, for PSEG’s subsidiaries for the next five years are presented in the table below. These amounts are subject to change, based on various factors.
PSE&G
In 2006, PSE&G made approximately $528 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $528 million does not include approximately $33 million spent on cost of removal. PSE&G’s projections for future capital expenditures include additions and replacements to its transmission and distribution systems to meet expected growth and to manage reliability. The current projections do not include investments required as a result of PJM’s approval of the Regional Transmission Expansion Plan (RTEP) in December 2006. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments.
Power
In 2006, Power made approximately $325 million of capital expenditures (excluding $93 million for nuclear fuel), primarily related to installation of emissions control equipment at the Bridgeport Harbor and Mercer stations, completion of construction at the Linden station, in New Jersey and various other projects at Nuclear and Fossil. The projections above include estimates for Hudson and Mercer related to the agreement reached with the EPA and the NJDEP. They do not include the costs, if any, associated with cooling towers for Salem, if required. For additional discussion of the potential costs related Hudson, Mercer and Salem, see Note 12. Commitments and Contingent Liabilities of Notes.
Energy Holdings
In 2006, Energy Holdings incurred approximately $64 million of capital expenditures, primarily related to upgrades and expansion of SAESA’s transmission and distribution systems.
Energy Holdings’ capital needs in 2007 will be limited to fulfilling existing contractual and potential contingent commitments. The balance of the forecasted expenditures relates to capital requirements of consolidated subsidiaries, which will primarily be financed from internally generated cash flow within the projects and from local sources on a non-recourse basis or limited discretionary investments by Energy Holdings. Such capital requirements include organic growth in SAESA’s service territory and other capital improvements at Global’s consolidated subsidiaries.
Disclosures about Long-Term Maturities, Contractual and Commercial Obligations and Certain Investments
The following table reflects PSEG’s and its subsidiaries’ contractual cash obligations and other commercial commitments in the respective periods in which they are due. In addition, the table summarizes anticipated recourse and non-recourse debt maturities for the years shown. The table below does not reflect any anticipated cash payments for pension obligations. The table also does not reflect debt maturities of Energy Holdings’ non-consolidated investments. If those obligations were not able to be refinanced by the project, Energy Holdings may elect to make additional contributions in these investments. For additional information, see Note 10. Schedule of Consolidated Debt of the Notes.
See Note 12. Commitments and Contingent Liabilities of the Notes for a discussion of contractual commitments for a variety of services for which annual amounts are not quantifiable.
OFF-BALANCE SHEET ARRANGEMENTS
Power
Power issues guarantees in conjunction with certain of its energy trading activities. See Note 12. Commitments and Contingent Liabilities of the Notes for further discussion.
PSEG and Energy Holdings
Global has certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the United States (GAAP). Accordingly, amounts recorded on the Consolidated Balance Sheets for such investments represent Global’s equity investment, which is increased for Global’s pro-rata share of earnings less any dividend distribution from such investments. The companies in which Global invests that are accounted for under the equity method have an aggregate $878 million of debt on their combined, consolidated financial statements. PSEG’s pro-rata share of such debt is $414 million. This debt is non-recourse to PSEG, Energy Holdings and Global. PSEG is generally not required to support the debt service obligations of these companies. However, default with respect to this non-recourse debt could result in a loss of invested equity.
Resources has investments in leveraged leases that are accounted for in accordance with SFAS No. 13, “Accounting for Leases.” Leveraged lease investments generally 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 is not presented on Energy Holdings’ Consolidated Balance Sheets. In the event of default, the leased asset, and in some cases the lessee, secure the loan. As a lessor, Resources has ownership rights to the property and rents the property to the lessees for use in their business operation. As of December 31, 2006, Resources’ equity investment in leased assets was approximately $924 million, net of deferred taxes of approximately $1.9 billion. For additional information, see Note 8. Long-Term Investments of the Notes.
In the event that collectibility of the minimum lease payments to be received by the lessor is no longer reasonably assured, the accounting treatment for some of the leases may change. In such cases, Resources may deem that a lessee has a high probability of defaulting on the lease obligation, and would reclassify the lease from a leveraged lease to an operating lease and would consider the need to record an impairment of its investment. Should Resources ever directly assume a debt obligation, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.
Energy Holdings has guaranteed certain obligations of its subsidiaries or affiliates related to certain projects. See Note 12. Commitments and Contingent Liabilities of the Notes for additional information.
CRITICAL ACCOUNTING ESTIMATES
PSEG, PSE&G, Power and Energy Holdings
Under GAAP, many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. The managements of PSEG, PSE&G, Power and Energy Holdings have each determined that the following estimates are considered critical to the application of rules that relate to their respective businesses.
Accounting for Pensions
PSEG, PSE&G, Power and Energy Holdings account for pensions under SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87). Pension costs under SFAS 87 are calculated using various economic and demographic assumptions. Economic assumptions include the discount rate and the long-term rate of return on trust assets. Demographic assumptions include projections of future mortality rates, pay increases and retirement patterns. In 2006, PSEG and its subsidiaries recorded pension expense of $97 million, compared to $109 million in 2005 and $102 million in 2004. Additionally, in 2006, PSEG and its respective
subsidiaries contributed cash of approximately $50 million, compared to cash contributions of $155 million in 2005 and $96 million in 2004.
PSEG’s discount rate assumption, which is determined annually, is based on the rates of return on high-quality fixed-income investments currently available and expected to be available during the period to maturity of the pension benefits. The discount rate used to calculate pension obligations is determined as of December 31 each year, PSEG’s SFAS 87 measurement date. The discount rate used to determine year-end obligations is also used to develop the following year’s net periodic pension cost. The discount rates used in PSEG’s 2005 and 2006 net periodic pension costs were 6.00% and 5.75%, respectively. PSEG’s 2007 net periodic pension cost was developed using a discount rate of 6.00%.
PSEG’s expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class using input from PSEG’s actuary and investment advisors, as well as long-term inflation assumptions. For 2005 and 2006, PSEG assumed a rate of return of 8.75% on PSEG’s pension plan assets. For 2007, PSEG will continue the rate of return assumption of 8.75%.
Based on the above assumptions, PSEG has estimated net period pension costs of approximately $43 million and contributions of up to approximately $66 million in 2007. As part of the business planning process, PSEG has modeled its future costs assuming an 8.75% rate of return and a 6.0% discount rate for 2008 and beyond. Actual future pension expense and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to PSEG’s projected benefit obligation and accumulated benefit obligation (ABO) and various other factors related to the populations participating in PSEG’s pension plans.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.
Accounting for Deferred Taxes
PSEG, PSE&G, Power and Energy Holdings provide for income taxes based on the liability method required by SFAS No. 109, “Accounting for Income Taxes” (SFAS 109). Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, as well as net operating loss and credit carryforwards.
PSEG, PSE&G, Power and Energy Holdings evaluate the need for a valuation allowance against their respective deferred tax assets based on the likelihood of expected future taxable income. PSEG, PSE&G, Power and Energy Holdings do not believe a valuation allowance is necessary; however, if the expected level of future taxable income changes or certain tax planning strategies become unavailable, PSEG, PSE&G, Power and Energy Holdings would record a valuation allowance through income tax expense in the period the valuation allowance is deemed necessary. Resources’ and Global’s ability to realize their deferred tax assets are dependent on PSEG’s subsidiaries’ ability to generate ordinary income and capital gains.
Hedge and Mark-to-Market (MTM) Accounting
SFAS 133 requires an entity to recognize the fair value of derivative instruments held as assets or liabilities on the balance sheet. SFAS 133 applies to all derivative instruments held by PSEG, PSE&G, Power and Energy Holdings. The fair value of most derivative instruments is determined by reference to quoted market prices, listed contracts, or quotations from brokers. Some of these derivative contracts are long term and rely on forward price quotations over the entire duration of the derivative contracts.
In the absence of the pricing sources listed above, for a small number of contracts, PSEG and its subsidiary companies utilize mathematical models that rely on historical data to develop forward pricing information in the determination of fair value. Because the determination of fair value using such models is
subject to significant assumptions and estimates, PSEG and its subsidiary companies developed reserve policies that are consistently applied to model-generated results to determine reasonable estimates of value to record in the financial statements.
PSEG and its subsidiaries have entered into various derivative instruments in order to hedge exposure to commodity price risk, interest rate risk and foreign currency risk. Many such instruments have been designated as cash flow hedges. For a cash flow hedge, the change in the value of a derivative instrument is measured against the offsetting change in the value of the underlying contract or business condition the derivative instrument is intended to hedge. This is known as the measure of derivative effectiveness. In accordance with SFAS 133, the effective portion of the change in the fair value of a derivative instrument designated as a cash flow hedge is reported in Accumulated Other Comprehensive Loss, net of tax, or as a Regulatory Asset (Liability). Amounts in Accumulated Other Comprehensive Loss are ultimately recognized in earnings when the related hedged forecasted transaction occurs. During periods of extreme price volatility, there will be significant changes in the value recorded in Accumulated Other Comprehensive Loss. The changes in the fair value of the ineffective portions of derivative instrument designated as cash flow hedges are recorded in earnings.
For Power’s and Holdings’ wholesale energy businesses, many of the forward sale, forward purchase and other option contracts are derivative instruments that hedge commodity price risk, but for which the businesses are not able to apply the hedge accounting guidance in SFAS 133. The changes in value of such derivative contracts are marked to market through earnings as commodity prices fluctuate. As a result, the earnings of PSEG, Power and Holdings may experience significant fluctuations depending on the volatility of commodity prices.
For Power’s energy trading activities, all changes in the fair value of energy trading derivative contracts are recorded in earnings.
For additional information regarding Derivative Financial Instruments, see Note 11. Financial Risk Management Activities of the Notes.
PSE&G
Unbilled Revenues
Electric and gas revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. Unbilled usage is calculated in two steps. The initial step is to apply a base usage per day to the number of unbilled days in the period. The second step estimates seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. The resulting usage is priced at current rate levels and recorded as revenue. A calculation of the associated energy cost for the unbilled usage is recorded as well. Each month the prior month’s unbilled amounts are reversed and the current month’s amounts are accrued. Using benchmarks other than those used in this calculation could have a material effect on the amounts accrued in a reporting period. The resulting revenue and expense reflect the service rendered in the calendar month.
PSE&G
SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71)
PSE&G prepares its Consolidated Financial Statements in accordance with the provisions of SFAS 71, which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or recognize obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or PSE&G’s competitive position, the associated regulatory asset or liability is charged or credited to income. See Note 5. Regulatory Matters of the Notes for additional information related to these and other regulatory issues.
Power
NDT Funds
Power accounts for the assets in the NDT Funds under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115). The assets in the NDT Funds are classified as available-for-sale securities and are marked to market with unrealized gains and losses recorded in Accumulated Other Comprehensive Loss unless securities with such unrealized losses are deemed to be other-than-temporarily-impaired. Realized gains, losses and dividend and interest income are recorded on Power’s and PSEG’s Statements of Operations under Other Income and Other Deductions. Unrealized losses that are deemed to be other than temporarily impaired, as defined under SFAS 115, and related interpretive guidance, are charged against earnings rather than Accumulated Other Comprehensive Loss.
Power and Energy Holdings
Accounting for Goodwill
Power and Energy Holdings evaluate their respective goodwill for impairment at least annually or when indications of impairment exist. An impairment may exist when the carrying amount of goodwill exceeds its implied fair value.
Accounting estimates related to goodwill fair value are highly susceptible to change from period to period because they require management to make cash flow assumptions about future sales, operating costs, economic conditions and discount rates over an indefinite life. The impact of recognizing an impairment could have a material impact on financial position and results of operations.
Power and Energy Holdings perform annual goodwill impairment tests and continuously monitor the business environment in which they operate for any impairment issues that may arise. As indicated above, certain assumptions are used to arrive at a fair value for goodwill testing. Such assumptions are consistently employed and include, but are not limited to, free cash flow projections, interest rates, tariff adjustments, economic conditions prevalent in the geographic regions in which Power and Energy Holdings do business, local spot market prices for energy, foreign exchange rates and the credit worthiness of customers. If an adverse event were to occur, such an event could materially change the assumptions used to value goodwill and could result in impairments of goodwill.
PSEG and Energy Holdings
Foreign Currency Translation
Energy Holdings’ financial statements are prepared using the U.S. Dollar as the reporting currency. In accordance with SFAS No. 52, “Foreign Currency Translation”, for foreign operations whose functional currency is deemed to be the local (foreign) currency, asset and liability accounts are translated into U.S. Dollars at current exchange rates and revenues and expenses are translated at average exchange rates prevailing during the period. Translation gains and losses (net of applicable deferred taxes) are not included in determining Net Income but are reported in Other Comprehensive Income. Gains and losses on transactions denominated in a currency other than the functional currency are included in the results of operations as incurred.
The determination of an entity’s functional currency requires management’s judgment. It is based on an assessment of the primary currency in which transactions in the local environment are conducted, and whether the local currency can be relied upon as a stable currency in which to conduct business. As economic and business conditions change, Energy Holdings is required to reassess the economic environment and determine the appropriate functional currency. The impact of foreign currency accounting could have a material adverse impact on Energy Holdings’ results of operations.
ITEM 7A.
ITEM 7A.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
PSEG, PSE&G, Power and Energy Holdings
The market risk inherent in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ market-risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements (Notes). It is the policy of each entity to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings have a Risk Management Committee (RMC) comprised of executive officers who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.
Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non- performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG and its subsidiaries’ financial condition, results of operations or net cash flows.
Foreign Exchange Rate Risk
Energy Holdings
Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. Primarily, Global is impacted by changes in the U.S. Dollar to Peruvian Nuevo Sol and the Chilean Peso exchange rates and to a much lesser extent, the Euro. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange impacts by entering into revenue contracts that adjust to changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to certain foreign currency transactions, when appropriate.
Global’s investment balances are also impacted by foreign currency changes through translation adjustments. Foreign currency has strengthened on a net basis since Global’s acquisitions and investments in Chile and Peru. A foreign currency fluctuation of 10% in such foreign currencies would result in an aggregate change in Accumulated Other Comprehensive Income of $92 million. As of December 31, 2006, Energy Holdings’ net gain in Accumulated Other Comprehensive Income from currency fluctuations was approximately $111 million.
Commodity Contracts
PSEG and Power
The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with demand obligations help reduce risk and optimize the value of owned electric generation capacity.
Normal Operations and Hedging Activities
Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to reduce risk associated with volatile commodity prices. Commodity price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors.
Under SFAS 133, changes in the fair value of qualifying cash flow hedge transactions are recorded in Accumulated Other Comprehensive Loss, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings.
Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and are accounted for upon settlement.
Trading
Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. In addition, Power has non-asset based trading activities, which have significantly decreased. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to market in accordance with SFAS 133 with gains and losses recognized in earnings.
Value-at-Risk (VaR) Models
Power
Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR model for Power includes its owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses.
Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and its hedges. Non-trading MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading VaR.
The VaR models used by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for the MTM trading and non- trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively manages its portfolio.
Reduced trading activities by Power during 2006 have resulted in less trading risk. As of December 31, 2006, trading VaR was immaterial. As of December 31, 2005, trading VaR was approximately $1 million.
Interest Rates
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. It is the policy of PSEG, PSE&G, Power and Energy Holdings to manage interest
rate risk through the use of fixed and floating rate debt, interest rate swaps and interest rate lock agreements. PSEG, PSE&G, Power and Energy Holdings manage their respective interest rate exposures by maintaining a targeted ratio of fixed and floating rate debt. As of December 31, 2006, a hypothetical 10% change in market interest rates would result in a $7 million, $3 million, $1 million and an insignificant change (less than $500 thousand) in annual interest costs related to debt at PSEG, PSE&G, Power and Energy Holdings, respectively. In addition, as of December 31, 2006, a hypothetical 10% change in market interest rates would result in a $7 million, $77 million, $105 million and $32 million change in the fair value of the debt of PSEG, PSE&G, Power and Energy Holdings, respectively.
Debt and Equity Securities
PSEG, PSE&G, Power and Energy Holdings
PSEG has approximately $3.4 billion invested in its pension plans. Although fluctuations in market prices of securities within this portfolio do not directly affect PSEG’s earnings in the current period, changes in the value of these investments could affect PSEG’s future contributions to these plans, its financial position if its ABO under its pension plans exceeds the fair value of its pension funds and future earnings as PSEG could be required to adjust pension expense and its assumed rate of return.
Power
Power’s NDT Funds are comprised of both fixed income and equity securities totaling $1.3 billion as of December 31, 2006. The fair value of equity securities is determined independently each month by the Trustee. As of December 31, 2006, the portfolio was comprised of approximately $785 million of equity securities and approximately $471 million in fixed income securities. The fair market value of the assets in the NDT Funds will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2006, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Funds by approximately $79 million.
Power uses duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Funds is the Lehman Brothers Aggregate Bond Index, which currently has duration of 4.46 years and a yield of 5.34%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2006, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $7.8 million.
Credit Risk
PSEG, PSE&G, Power and Energy Holdings
Credit risk relates to the risk of loss that PSEG, PSE&G, Power and Energy Holdings would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG, PSE&G, Power and Energy Holdings have established credit policies that they believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single counterparty.
PSE&G
BGS suppliers expose PSE&G to credit losses in the event of non-performance or non-payment upon a default of the BGS supplier. Credit requirements are governed under BPU approved BGS contracts.
Power
Counterparties expose Power’s trading operation to credit losses in the event of non-performance or non-payment. Power has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. Power’s counterparty credit limits are based on a
scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Power’s trading operations have entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Power’s exposure to counterparty risk by providing the offset of amounts payable to the counterparty against amounts receivable from the counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and its subsidiaries’ financial condition, results of operations or net cash flows. As of December 31, 2006, approximately 97% of the credit exposure (MTM plus net receivables and payables, less cash collateral) for Power’s trading operations was with investment grade counterparties. The majority of the credit exposure with non-investment grade counterparties was with certain companies that supply fuel (primarily coal) to Power. Therefore, this exposure relates to the risk of a counterparty performing under its obligations rather than payment risk. As of December 31, 2006, Power’s trading operations had over 121 active counterparties.
Energy Holdings
Global
Global has credit risk with respect to its counterparties to power purchase agreements (PPAs) and other parties.
Resources
As of December 31, 2006, Resources has a remaining gross investment in three leased aircraft of approximately $41 million, all with Northwest airlines. Resources successfully restructured the leases and converted them from leveraged leases to operating leases. Energy Holdings expects to recover its investment through cash flows from the operating leases.
Resources has credit risk related to its investments in leveraged leases, totaling $924 million, which is net of deferred taxes of $1.9 billion, as of December 31, 2006. These investments are largely concentrated in the energy industry. As of December 31, 2006, 67% of counterparties in the lease portfolio were rated investment grade by both S&P and Moody’s. As of December 31, 2006, the weighted average credit rating of the lessees in Resources’ leasing portfolio was A-/A3 by S&P and Moody’s respectively.
Resources is the lessor of domestic generating facilities in several U.S. energy markets. Several of these lessees have credit ratings below investment grade. Resources’ investment in such transactions was approximately $264 million, net of deferred taxes of $510 million as of December 31, 2006. The credit exposure to the lessees is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met and similar cash flow restrictions if ratings are not maintained at stated levels. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased assets.
In any lease transaction, in the event of a default, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. Under a worst-case scenario, if a foreclosure were to occur, Resources would record a pre-tax write-off up to its gross investment, including deferred taxes, in these facilities. Also, in the event of a potential foreclosure, the net tax benefits generated by Resources’ portfolio of investments could be materially reduced in the period in which gains associated with the potential forgiveness of debt at these projects occurs. The amount and timing of any potential reduction in net tax benefits is dependent upon a number of factors including, but not limited to, the time of a potential foreclosure, the amount of lease debt outstanding, any cash trapped at the projects and negotiations during such potential foreclosure process. The potential loss of earnings, impairment and/or tax payments could have a material impact to PSEG’s and Energy Holdings’ financial position, results of operations and net cash flows.
Other Supplemental Information Regarding Market Risk
Power
The following table describes the drivers of Power’s energy trading and marketing activities and Operating Revenues included in its Consolidated Statement of Operations for the year ended December 31, 2006. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale market. As the information in this table highlights, MTM activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices. For additional information, see Note 11. Financial Risk Management Activities of the Notes.
Operating Revenues
For the Year Ended December 31, 2006
(A)
Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset backed transactions (ABT) and hedging activities, but excludes owned and contracted generation assets.
The following table indicates Power’s energy trading assets and liabilities, as well as Power’s hedging activity related to ABTs and derivative instruments that qualify for hedge accounting under SFAS 133. This table presents amounts segregated by portfolio which are then netted for those counterparties with whom Power has the right to set off and therefore, are not necessarily indicative of amounts presented on the Consolidated Balance Sheets since balances with many counterparties are subject to offset and are shown net on the Consolidated Balance Sheets regardless of the portfolio in which they are included.
Energy Contract Net Assets/Liabilities
As of December 31, 2006
The following table presents the maturity of net fair value of MTM energy trading contracts.
Maturity of Net Fair Value of MTM Energy Trading Contracts
As of December 31, 2006
Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.
PSEG, Power and Energy Holdings
The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. The table also provides an estimate of the losses, net of taxes that are expected to be reclassified out of Accumulated Other Comprehensive Loss and into earnings over the next twelve months.
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
As of December 31, 2006
Power
Credit Risk
The following table provides information on Power’s credit exposure, net of collateral, as of December 31, 2006. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties.
Schedule of Credit Risk Exposure on Energy Contracts Net Assets
As of December 31, 2006
The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding exposure, in which case there would not be exposure.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This combined Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no representations as to any other company.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors of
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED:
We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, on December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans.
As discussed in Note 3 to the consolidated financial statements, on December 31, 2005, the Company adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 27, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Sole Stockholder and Board of Directors of
PUBLIC SERVICE ELECTRIC AND GAS COMPANY:
We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, common stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, on December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans.
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 27, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Sole Member and Board of Directors of
PSEG POWER LLC:
We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, capitalization and member’s equity and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and the consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, on December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.
As discussed in Note 3 to the consolidated financial statements, on December 31, 2005, the Company adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 27, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Sole Member and Board of Directors of
PSEG ENERGY HOLDINGS L.L.C.:
We have audited the accompanying consolidated balance sheets of PSEG Energy Holdings L.L.C. and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, member’s equity and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 27, 2007
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions, except for share data)
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
(Millions)
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
(Millions)
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(Millions)
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(Millions)
See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(Millions)
See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(Millions)
See disclosures regarding Public Service Electric and Gas Company
included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
(Millions)
See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CAPITALIZATION AND MEMBER’S EQUITY
(Millions)
See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
See disclosures regarding PSEG Energy Holdings L.L.C. included in the
Notes to Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
CONSOLIDATED BALANCE SHEETS
(Millions)
See disclosures regarding PSEG Energy Holdings L.L.C. included in the
Notes to Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
CONSOLIDATED BALANCE SHEETS
(Millions)
See disclosures regarding PSEG Energy Holdings L.L.C. included in the
Notes to Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
See disclosures regarding PSEG Energy Holdings L.L.C. included in the
Notes to Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
(Millions)
See disclosures regarding PSEG Energy Holdings L.L.C. included in the
Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Summary of Significant Accounting Policies
Organization
Public Service Enterprise Group Incorporated (PSEG)
PSEG has four principal direct wholly owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings L.L.C. (Energy Holdings) and PSEG Services Corporation (Services).
As previously disclosed, on December 20, 2004, PSEG entered into an agreement and plan of merger (Merger Agreement) with Exelon Corporation (Exelon), a public utility holding company headquartered in Chicago, Illinois, providing for a merger of PSEG with and into Exelon. On September 14, 2006, PSEG received from Exelon a formal notice of termination of the Merger under the provisions of the Merger Agreement.
PSE&G
PSE&G is an operating public utility engaged principally in the transmission of electric energy and distribution of electric energy and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC).
PSE&G also owns PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), bankruptcy-remote entities that purchased certain transition property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the rights to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G’s transition costs related to deregulation, as approved by the BPU.
Power
Power is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management function through three principal direct wholly owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Nuclear and Fossil own and operate generation and generation-related facilities. ER&T is responsible for the day-to-day management of Power’s portfolio. Fossil, Nuclear and ER&T are subject to regulation by FERC and Nuclear is also subject to regulation by the Nuclear Regulatory Commission (NRC).
Energy Holdings
Energy Holdings has two principal direct wholly owned subsidiaries: PSEG Global L.L.C. (Global), which owns and operates international and domestic projects engaged in the generation and distribution of energy and PSEG Resources L.L.C. (Resources), which has invested primarily in energy-related leveraged leases. Energy Holdings also owns Enterprise Group Development Corporation (EGDC), a commercial real estate property management business.
Services
Services provides management and administrative and general services to PSEG and its subsidiaries. These include accounting, treasury, financial risk management, law, tax communications, planning, development, human resources, corporate secretarial, information technology, investor relations, stockholder services, real estate, insurance, library, records and information services, security and certain other services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Principles of Consolidation
PSEG, PSE&G, Power and Energy Holdings
PSEG’s, PSE&G’s, Power’s and Energy Holdings’ consolidated financial statements include their respective accounts and consolidate those entities in which they have a controlling interest or are the primary beneficiary, except for certain of PSEG’s capital trusts which were deconsolidated in accordance with Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46 (revised December 2003), “Consolidation of Variable Interest Entities (VIE)” (FIN 46). Entities over which PSEG, PSE&G, Power and Energy Holdings exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation.
PSE&G and Power
PSE&G and Power each have undivided interests in certain jointly-owned facilities and each is responsible for paying their respective ownership share of additional construction costs, fuel inventory purchases and operating expenses. All revenues and expenses related to these facilities are consolidated at their respective pro-rata ownership share in the appropriate revenue and expense categories on the Consolidated Statements of Operations. For additional information regarding these jointly-owned facilities, see Note 19. Property, Plant and Equipment and Jointly-Owned Facilities of the Notes.
Accounting for the Effects of Regulation
PSE&G
PSE&G prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or record the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or PSE&G’s competitive position, the associated regulatory asset or liability is charged or credited to income. Management believes that PSE&G’s transmission and distribution businesses continue to meet the requirements for application of SFAS 71. For additional information, see Note 5. Regulatory Matters of the Notes.
Derivative Financial Instruments
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings use derivative financial instruments to manage risk from changes in interest rates, congestion credits, emission credits, commodity prices and foreign currency exchange rates, pursuant to their business plans and prudent practices.
PSEG, PSE&G, Power and Energy Holdings recognize derivative instruments on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a fair value hedge (including foreign currency fair value hedges), along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current-period earnings. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a cash flow hedge (including foreign currency cash flow hedges) are recorded in Accumulated Other Comprehensive Income / Loss until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current-period earnings. In certain circumstances, PSEG, PSE&G, Power and/or Energy Holdings enter into derivative contracts that do not qualify as hedges
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
or choose not to designate them as normal purchases or sales or as fair value or cash flow hedges; in such cases, changes in fair value are recorded in current-period earnings.
Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted (SFAS 133) and are accounted for upon settlement.
For additional information regarding derivative financial instruments, see Note 11. Financial Risk Management Activities of the Notes.
Revenue Recognition
PSE&G
PSE&G’s Operating Revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.
Power
The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in value of non trading energy derivative contracts that are not designated as normal purchases or sales or as hedges of other positions. Power records margins from energy trading on a net basis pursuant to accounting principles generally accepted in the U.S. (GAAP). See Note 11. Financial Risk Management Activities for further discussion.
Energy Holdings
Certain of Global’s investments are majority owned, controlled and consolidated. Global records revenues from its consolidated investments in generation and distribution facilities based on services rendered to customers during each accounting period. Revenues from these projects are included in Operating Revenues. Global’s Operating Revenue also includes changes in value of non trading energy derivative contracts that are not designated as normal purchases or sales or as hedges of other positions and includes margins from energy trading recorded on a net basis pursuant to GAAP. See Note 11. Financial Risk Management Activities for further discussion. Other investments are less than majority owned and are accounted for under the equity or cost methods as appropriate. Income from these investments is recorded as a component of Operating Income. Gains or losses incurred as a result of exiting one of these businesses are typically recorded as a component of Operating Income.
The majority of Resources’ revenues relates to its investments in leveraged leases and is accounted for under SFAS No. 13, “Accounting for Leases” (SFAS 13). Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net 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 revenues as these events occur in the ordinary course of business of managing the investment portfolio. See Note 8. Long-Term Investments for further discussion.
Depreciation and Amortization
PSE&G
PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU. The depreciation rate stated as a percentage of original cost of depreciable property was 2.84% for 2006, 3.00% for 2005 and 3.07% for 2004.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power
Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives which are determined based on planned operations. The estimated useful lives are from three years to 20 years for general plant assets. The estimated useful lives are 30 years to 55 years for fossil production assets, 49 years to 56 years for nuclear generation assets and 45 years for pumped storage facilities. As of January 1, 2007 the company changed certain of the estimated useful lives for certain fossil production assets to 67 years, for pumped storage assets to 76 years and for nuclear generation assets to 58 years.
Energy Holdings
Energy Holdings calculates depreciation on property, plant and equipment under the straight-line method with estimated useful lives ranging from three years to 40 years.
Taxes Other Than Income Taxes
PSE&G
Excise taxes, transitional energy facilities assessment (TEFA) and gross receipts tax (GRT) collected from PSE&G’s customers are presented on the financial statements on a gross basis. As a result of New Jersey energy tax reform, effective January 1, 1998, TEFA and GRT are the residual of the prior excise tax, the New Jersey gross receipts and franchise taxes. For the years ended December 31, 2006, 2005 and 2004, combined TEFA and GRT of approximately $146 million, $155 million and $153 million, respectively, are reflected in Operating Revenues and $132 million, $141 million and $139 million, respectively, are included in Taxes Other Than Income Taxes on the Consolidated Statements of Operations.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)
PSE&G
AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets under the guidance of SFAS 71. The amount of AFUDC capitalized is reported in the Consolidated Statements of Operations as a reduction of interest charges. PSE&G’s average rate used for calculating AFUDC in 2006, 2005 and 2004 was 4.99%, 3.17% and 1.33%, respectively. For the years ended December 31, 2006, 2005 and 2004, PSE&G’s AFUDC amounted to $2.0 million, $1.2 million and $0.1 million, respectively.
Power and Energy Holdings
IDC represents the cost of debt used to finance construction at Power and Energy Holdings. The amount of IDC capitalized is reported in the Consolidated Statements of Operations as a reduction of interest charges and is included in Property, Plant and Equipment on the Consolidated Balance Sheets. Power’s average rate used for calculating IDC in 2006, 2005 and 2004 was 6.81%, 6.74% and 6.81%, respectively. For the years ended December 31, 2006, 2005 and 2004, Power’s IDC amounted to $41 million, $95 million and $107 million, respectively. Energy Holdings’ average rate used for calculating IDC in 2006, 2005 and 2004 was 6.72%, 7.81% and 8.37%, respectively. For the years ended December 31, 2006, 2005 and 2004, Energy Holdings’ IDC amounted to approximately $1 million, $3 million and $4 million, respectively.
Income Taxes
PSEG, PSE&G, Power and Energy Holdings
PSEG and its subsidiaries file a consolidated Federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary. Investment tax credits were deferred in prior years and are being amortized over the useful lives of the related property.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Foreign Currency Translation/Transactions
Energy Holdings
A business’ functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. In accordance with SFAS No. 52, “Foreign Currency Translation,” the assets and liabilities of foreign operations of Energy Holdings, with a functional currency other than the U.S. Dollar, are translated into U.S. Dollars at the current exchange rates in effect at the end of the reporting period. The translation differences that result from this process, and gains and losses on intercompany foreign currency transactions, which are long-term in nature and that Energy Holdings does not intend to settle in the foreseeable future, are recorded in Accumulated Other Comprehensive Loss as a separate component of member’s equity. U.S. deferred taxes are not provided on translation gains and losses where Energy Holdings expects earnings of a foreign operation to be permanently reinvested. The revenue and expense accounts of such foreign operations are translated into U.S. Dollars at the average exchange rates that prevail during the period.
Gains and losses that arise from exchange rate fluctuations on monetary assets and monetary liabilities denominated in a currency other than the functional currency are included in Other Income or Other Deductions. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in Currency Translation Adjustment, a separate component of Accumulated Other Comprehensive Loss.
The determination of an entity’s functional currency requires management’s judgment. It is based on an assessment of the primary currency in which transactions in the local environment are conducted, and whether the local currency can be relied upon as a stable currency in which to conduct business. As economic and business conditions change, Energy Holdings is required to reassess the economic environment and determine the appropriate functional currency. The impact of foreign currency accounting could have a material effect on Energy Holdings’ financial statements.
Cash and Cash Equivalents
PSEG, PSE&G, Power and Energy Holdings
Cash and cash equivalents consist primarily of working funds and highly liquid marketable securities (commercial paper and money market funds) with an original maturity of three months or less.
Materials and Supplies and Fuel
PSE&G
PSE&G’s materials and supplies are carried at average cost consistent with the rate-making process.
Power and Energy Holdings
Materials and supplies and fuel for Power and Energy Holdings are valued at the lower of average cost or market.
Property, Plant and Equipment
PSE&G
PSE&G’s additions and replacements to property, plant and equipment that are either retirement units or property record units are capitalized at original cost. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power and Energy Holdings
Power and Energy Holdings only capitalize costs which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Certain subsidiaries of Energy Holdings that are in the distribution business capitalize all incremental costs associated with construction activities. These construction costs meet the capitalization criteria described above.
Other Special Funds
PSEG, PSE&G, Power and Energy Holdings
Other Special Funds represents amounts deposited to fund the qualified pension plans and to fund a Rabbi Trust which was established to meet the obligations related to three non-qualified pension plans and a deferred compensation plan.
Nuclear Decommissioning Trust (NDT) Funds
Power
As required under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115), realized gains and losses on securities in the NDT Funds are recorded in earnings and unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Loss unless securities with such unrealized losses are deemed to be other-than- temporarily-impaired. See Note 3. Asset Retirement Obligations for a discussion of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) and the impact of its adoption on the nuclear decommissioning liability and associated asset retirement costs related to the NDT Funds.
Investments in Corporate Joint Ventures and Partnerships
Energy Holdings
Generally, Global’s interests in active joint ventures and partnerships are accounted for under the equity method of accounting where its respective ownership interests are 50% or less, it is not the primary beneficiary, as defined under FIN 46, and significant influence over joint venture or partnership operating and management decisions exists. For investments in which significant influence does not exist and Global is not the primary beneficiary, the cost method of accounting is applied.
Deferred Project Costs and Development Costs
Power
Power capitalizes all incremental and direct external and direct internal costs related to project development once a project reaches certain milestones. On Power’s Consolidated Balance Sheets, deferred project costs are recorded in Construction Work in Progress. These costs are amortized on a straight-line basis over the lives of the related project assets. Such amortization commences upon the date of commercial operation. Development costs related to unsuccessful projects are charged to expense.
Basis Adjustment
PSE&G and Power
PSE&G and Power have recorded a Basis Adjustment on their Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, PSE&G and Power, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
transfer price and the net book value of the generation-related assets and liabilities, approximately $986 million, net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is a reduction of Power’s Member’s Equity and an addition to PSE&G’s Common Stockholder’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.
Use of Estimates
PSEG, PSE&G, Power and Energy Holdings
The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may materially differ from estimated amounts.
Reclassifications
PSEG, PSE&G, Power and Energy Holdings
Certain reclassifications have been made to the prior years financial statements to conform to the current year presentation. The reclassifications relate primarily to recording revenue and related expenses on certain transactions on a net basis versus gross.
During the fourth quarter of 2006, based upon the provisions of EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent”, PSE&G determined that the revenues and expenses related to one of its contracts that had been recorded on a gross basis would more appropriately be recorded on a net basis in Operating Revenues. Therefore, prior year amounts have been reclassified resulting in a reduction of $214 million and $162 million in both Operating Revenues and Energy Costs for the years ended December 31, 2005 and 2004, respectively, for PSEG and PSE&G, with no impact on Operating Income.
Note 2. Recent Accounting Standards
The following accounting standards were issued by the Financial Accounting Standards Board (FASB), or the SEC but have not yet been adopted by PSEG, PSE&G, Power and Energy Holdings.
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)
PSEG, PSE&G, Power and Energy Holdings
In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. An entity would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The decision about whether to elect the fair value option is applied instrument by instrument, with a few exceptions; the decision is irrevocable; and it is applied only to entire instruments and not to portions of instruments.
The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and (b) between assets and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities.
SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year provided the entity also elects to apply the provisions of SFAS 157. Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative-effect adjustment to the opening balance of Retained Earnings. Since the provisions of SFAS 159 are applied prospectively, any potential impact will depend on the instruments selected for fair value measurement at the time of implementation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SFAS No. 157, “Fair Value Measurements” (SFAS 157)
PSEG, PSE&G, Power and Energy Holdings
In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Prior to SFAS 157, guidance for applying fair value was incorporated into several accounting pronouncements. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources (observable inputs) and those based on an entity’s own assumptions (unobservable inputs). Under SFAS 157, fair value measurements are disclosed by level within that hierarchy, with the highest priority being quoted prices in active markets. While this statement does not require any new fair value measurements, the application of this statement will change current practice for some fair value measurements.
This statement also nullifies the guidance in footnote 3 of Emerging Issues Task Force Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” The guidance in footnote 3 applied for derivatives (and other) instruments measured at fair value at initial recognition under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.” That guidance precluded immediate recognition in earnings of an unrealized gain or loss, measured as the difference between the transaction price and the fair value of the instrument at initial recognition, if the fair value of the instrument was determined using significant unobservable inputs. Under this guidance, an entity could not recognize an unrealized gain or loss at inception of a derivative instrument unless the fair value of that instrument was obtained from a quoted market price in an active market or was otherwise evidenced by comparison to other observable current market transaction or based on a valuation technique incorporating observable market data. At December 31, 2006, Energy Holdings has a deferred inception loss of approximately $45 million, which was being amortized at $11 million pre-tax per year through 2010.
SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007; however, earlier application is encouraged. PSEG early adopted this statement effective January 1, 2007. Early adoption resulted in recording the remaining Energy Holdings deferred inception loss in Retained Earnings and eliminating any future amortization of the loss.
FIN 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement 109” (FIN 48)
PSEG, PSE&G, Power and Energy Holdings
In July 2006, the FASB issued FIN 48, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return. Under FIN 48, the financial statements will reflect expected future tax consequences of such positions presuming the tax authorities’ full knowledge of the position and all relevant facts. FIN 48 permits recognition of the benefit of tax positions only when it is “more likely-than-not” that the position is sustainable based on the merits of the position. It further limits the amount of tax benefit to be recognized to the largest amount of benefit that is greater than 50% likely of being realized. FIN 48 also requires explicit disclosures about uncertainties in income tax positions, including a detailed roll-forward of unrecognized tax benefits taken that do not qualify for financial statement recognition.
FIN 48 is effective as of the beginning of fiscal years that start after December 15, 2006. In general, companies will record the change in net assets that result from the application of FIN 48 as an adjustment to Retained Earnings. However, for PSE&G, because any charges to income arising from the adoption of FIN 48 would be recoverable in future rates, the offset to any incremental PSE&G liability would be recorded as a Regulatory Asset rather than Retained Earnings. The following table presents the estimated ranges of impact on the Consolidated Balance Sheets for PSEG and its subsidiaries as a result of implementing FIN 48:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FASB Staff Position (FSP) No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP 13-2)
PSEG and Energy Holdings
In July 2006, the FASB issued FSP 13-2, which addresses how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the accounting by a lessor for that lease. The FSP amends SFAS 13, “Accounting for Leases,” stating that a change in the timing of the above referenced cash flows must be reviewed at least annually or more frequently, if events or circumstances indicate a change in timing is probable. If a change in timing has occurred, or is projected to occur, the rate of return and the allocation of income to positive investment years must be recalculated from the inception of the lease.
The guidance in this FSP is to be applied to fiscal years beginning after December 15, 2006. The cumulative effect of applying the provisions of this FSP is to be reported as an adjustment to the beginning balance of Retained Earnings as of the beginning of the period in which this FSP is adopted. As a result of implementing FSP 13-2, upon adoption PSEG and Energy Holdings estimate that they will each recognize on their Balance Sheets a reduction in their Investment in Leveraged Leases of approximately $70 million with an offsetting reduction in Retained Earnings.
The following new accounting standards were adopted by PSEG, PSE&G, Power and Energy Holdings during 2006.
SFAS No. 123R, “Share-Based Payment, revised 2004” (SFAS 123R)
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2006, PSEG adopted SFAS 123R, which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123) and supersedes Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25). SFAS 123R focuses primarily on accounting for share-based awards to employees in exchange for services, and it requires entities to recognize compensation expense for these awards. The cost for equity-based awards is expensed over the requisite service period based on their grant date fair value, and liability awards are expensed based on their fair value, which is re-measured each reporting period. The pro forma disclosure previously permitted under SFAS 123 is no longer an alternative to financial statement recognition.
Prior to January 1, 2006, PSEG accounted for stock-based awards under the intrinsic value method of APB 25. In accordance with APB 25, PSEG did not record compensation expense related to its stock option grants because the strike price was equal to the fair value of the underlying stock on the grant date; however, it did record compensation expense over the requisite service period for restricted stock grants and performance unit awards.
SFAS 123R is applicable to all of PSEG’s outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective method. Accordingly, the financial results for prior periods were not retroactively adjusted to reflect the effects of SFAS 123R. The compensation expense recorded as a result of adopting SFAS 123R was not material. For additional information, see Note 17. Stock-Based Compensation.
The anticipated combined earnings impact on PSEG of adopting FIN 48 and FSP 13-2 is a reduction of $25 million to $35 million in 2007, as compared to 2006, primarily related to the impact on Energy Holdings.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158)
PSEG, PSE&G, Power and Energy Holdings
Effective December 31, 2006, PSEG adopted SFAS 158, which requires that companies record the under or over funded positions of defined benefit pension and Other Postretirement Benefits (OPEB) plans on the balance sheet. In addition, the statement requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income, a separate component of Stockholder’s Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset.
Prior to SFAS 158, accounting guidance required that unrecognized costs be presented in a footnote to the financial statements as part of a reconciliation of a plan’s funded status to amounts recorded in the financial statements.
SFAS 158 is applied prospectively and the incremental impact on the individual Balance Sheet line items is disclosed in Note 16. Pension, OPEB and Savings Plans. Under SFAS 158 there is no change to the calculation of annual pension or OPEB expense.
Note 3. Asset Retirement Obligations (AROs)
PSEG, PSE&G, Power and Energy Holdings
On December 31, 2005, PSEG, PSE&G, Power and Energy Holdings completed their analyses under FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47) which was issued in March 2005 to clarify certain guidance set forth in SFAS 143 and quantified conditional AROs identified that were previously not estimable. As a result of adopting FIN 47, PSEG recorded an additional ARO liability of approximately $246 million, including $210 million at PSE&G and $35 million at Power. PSEG also recorded a charge for a Cumulative Effect of a Change in Accounting Principle of $(17) million, after-tax, $(16) million of which relates to Power, with the remainder at Energy Holdings and Services.
During 2006, PSE&G incurred and recorded less than $1 million related to new liabilities under FIN 47. On December 31, 2006, Power made revisions to certain AROs previously recorded under SFAS 143 and FIN 47, resulting in a decrease to the ARO liability and ARO asset of $119 million.
The following table reflects pro forma results for the years ended December 31, 2005 and 2004, excluding the Cumulative Effect of a Change in Accounting Principle recorded upon the adoption in 2005, and including accretion and depreciation expense relating to the additional AROs identified under FIN 47, as if it had always been in effect.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG
In addition to amounts recorded at PSE&G, Power and Energy Holdings, discussed below, Services has an immaterial conditional ARO related to its obligation to restore a leased office space to rentable condition upon lease termination.
PSE&G
PSE&G has a conditional ARO for legal obligations identified under FIN 47 related to the removal of asbestos and underground storage tanks at certain industrial establishments, removal of wood poles, leases and licenses, and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G did not record an ARO for PSE&G’s protected steel and poly based natural gas transmission lines, as management believes that these categories of transmission lines have an indeterminable life.
Power
Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants. Power maintains an independent external trust to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 13. Nuclear Decommissioning. Power also identified conditional AROs under FIN 47, primarily related to Power’s fossil generation units, including liabilities for the removal of asbestos, stored hazardous liquid material and underground storage tanks from industrial power sites, restoration of leased office space to rentable condition upon lease termination, permits and authorizations, the restoration of an area occupied by a reservoir when the reservoir is no longer needed, the demolition of certain plants and the restoration of the sites at which they reside when the plants are no longer in service.
Energy Holdings
Energy Holdings had identified an immaterial legal obligation under FIN 47 for Electroandes S.A.’s (Electroandes) water and infrastructure easement rights recognition agreement that expired in December 2006.
PSEG, PSE&G and Power
On December 31, 2006, under SFAS 143, Power recorded a decrease to the ARO liability and asset of $117 million related to revisions in assumptions regarding the timing of the decommissioning of its nuclear facilities and estimated decommissioning cash flows. Also on December 31, 2006, under FIN 47, Power recorded a decrease to the ARO liability and asset of $2 million to reflect an expected life extension of certain fossil plants. The impact of these revisions, as well as other changes to the ARO liabilities for PSEG, PSE&G and Power during 2006, are presented in the following table:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)
Accretion expense is not reflected on PSE&G’s Consolidated Statements of Operations as it is deferred and recovered in rate base.
Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments
Discontinued Operations
Power
Lawrenceburg Energy Center (Lawrenceburg)
On December 29, 2006, Power entered into an agreement to sell its Lawrenceburg facility located in Lawrenceburg, Indiana to AEP Generating Company, a subsidiary of American Electric Power Company, Inc. (AEP). The facility is a 1,080-megawatt, gas-fired combined cycle electric generating plant that entered commercial operation in the summer of 2004.
The sale price for the facility and inventory is $325 million. The proceeds, together with anticipated reduction in tax liability, is expected to be approximately $425 million and will be used to retire debt. Power and PSEG have determined the transaction will result in an after-tax charge to PSEG and Power earnings of approximately $208 million, or about $0.82 cents per share of PSEG common stock and it is reflected as a charge in Discontinued Operations.
The sale is subject to approval by FERC, the U.S. Securities Exchange Commission, compliance with the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and may also require certain state regulatory approvals in Indiana. It is anticipated that the transaction will close in the second quarter of 2007.
Lawrenceburg’s operating results for the years ended December 31, 2006, 2005 and 2004, which were reclassified to Discontinued Operations, are summarized below:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The carrying amounts of the assets of Lawrenceburg as of December 31, 2006 and 2005 are summarized in the following table:
Waterford Generation Facility (Waterford)
In September 2005, Power completed the sale of its electric generation facility located in Waterford, Ohio to a subsidiary of AEP. In May 2005, Power recognized an estimated loss on disposal of $177 million, net of tax benefit of $123 million. In the third quarter of 2005, Power completed the sale of Waterford and recognized an additional loss on disposal of $1 million, net of tax. The proceeds of the sale, together with the anticipated reduction in tax liability, were approximately $320 million and were used to retire debt at Power.
Waterford’s operating results for the years ended December 31, 2005 and 2004, which were reclassified to Discontinued Operations, are summarized below:
Energy Holdings
Elektrocieplownia Chorzow Elcho Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina)
On January 31, 2006, Global entered into an agreement with CEZ a.s. to sell its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale was completed on May 29, 2006. Proceeds, net of transaction costs, were $476 million, resulting in a gain of $227 million net of tax expense of $142 million. This gain is included in Discontinued Operations. The 2006 operating results for Global’s assets in Poland have been reclassified to Discontinued Operations.
Elcho’s and Skawina’s operating results for the years ended December 31, 2006, 2005 and 2004 are summarized below:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The carrying amounts of the assets of Elcho and Skawina as of December 31, 2005 are summarized in the following table:
Carthage Power Company (CPC)
In December 2003, Global entered into a definitive purchase and sale agreement related to the sale of its majority interest in CPC, which owns and operates a power plant located in Rades, Tunisia. In December 2003, Global recognized an estimated loss on disposal of $23 million. In May 2004, Global completed the sale of CPC for approximately $43 million in cash and recognized a net gain on disposal of $3 million.
The operating results of CPC for the year ended December 31, 2004 are summarized below:
Dispositions
Energy Holdings
Global
Thermal Energy Development Partnership, L.P. (Tracy Biomass)
On December 22, 2006, Global entered into an agreement to sell its 34.5% interest in Tracy Biomass for approximately $7 million. The sale closed on January 26, 2007 and resulted in a 2007 pre-tax gain of approximately $7 million ($6 million after-tax).
Empresa de Energia Rio Negro S.A. (Edersa)
On December 21, 2006, SAESA group completed the sale of its 50% indirect interest in Edersa (an Argentinian utility company) for an insignificant amount, and realized an after-tax benefit of $18 million.
Magellan Capital Holdings Corporation (MCHC)
During the fourth quarter of 2006, Global sold its interest in the MCHC generation development project for $1 million, resulting in a pre-tax loss of approximately $4 million ($2 million after-tax).
Rio Grande Energia S. A. (RGE)
On May 10, 2006, Global entered into an agreement with Companhia Paulista de Force Luz (CPFL) to sell its 32% ownership interest in RGE, a Brazilian electric distribution company. The transaction closed on June 23, 2006 and gross proceeds of $185 million were received. The transaction resulted in a pre-tax write-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
down of $263 million ($178 million after-tax), primarily related to the devaluation of the Brazilian Real subsequent to Global’s acquisition of its interests in RGE in 1997.
Dhofar Power Company S.A.O.C. (Dhofar Power)
In April 2005, Global sold a 35% interest in Dhofar Power through a public offering on the Omani stock exchange as required under its Concession Agreement for the project, reducing Global’s ownership in Dhofar Power from 81% to 46%. Net proceeds from the sale were approximately $25 million, resulting in a pre-tax gain of approximately $3 million ($1 million after-tax). As a result, Global’s investment in Dhofar Power was accounted for under the equity method following the sale.
On May 15, 2006, Global signed an agreement to sell its remaining 46% interest in Dhofar Power to Oman Technical Partners Ltd. (Oman). Global closed the sale in November 2006 and received net proceeds after-tax of approximately $31 million, the approximate book value of the investment.
Solar Electric Generating Systems (SEGS) Projects
In January 2005, Resources and Global sold their minority limited partner interests in three SEGS projects for proceeds of approximately $7 million resulting in a pre-tax gain of $7 million ($4 million after-tax).
Meiya Power Company Limited (MPC)
In December 2004, Global closed on the sale of its 50% equity interest in MPC to BTU Power Company for approximately $236 million resulting in a pre-tax gain of $35 million ($6 million loss after- tax).
Luz del Sur S.A.A. (LDS)
In April 2004, Global sold a portion of its indirect ownership in LDS in the Lima stock exchange, reducing its ownership from 44% to 38% and received gross proceeds of approximately $31 million and realized a pre-tax gain of approximately $7 million ($5 million after-tax).
GWF Energy LLC (GWF Energy)
In February 2004, Harbinger GWF LLC (Harbinger) purchased a 14.9% ownership interest in GWF Energy from Global for approximately $14 million, resulting in a pre-tax gain of $2 million ($1 million after-tax). As a result of the sale, Global has a 60% interest in GWF Energy.
Resources
On October 16, 2006, Resources entered into an agreement under which Puget Sound Energy, Inc. will purchase Whitehorn Units Nos. 2 and 3 from Resources on the current lease expiration date of February 2, 2009 for a cash price of approximately $23 million. This transaction is expected to produce approximately $3 million of incremental after-tax income and $3 million of incremental cash flow for Resources, at such time.
On December 28, 2005, Resources sold its interest in the Seminole Generation Station Unit 2 (Seminole), a 659 MW coal-fired facility in Palatka, Florida, to Seminole Electric Cooperative Inc. for $286 million, resulting in a pre-tax gain of $71 million ($43 million after-tax).
Resources was the equity investor in a Boeing B767 leased to United Airlines (UAL). In December 2002, UAL filed for Chapter 11 bankruptcy protection. In 2005, Resources received a notice from the Trustee under the UAL lease that the lenders had terminated the lease and repossessed the aircraft. Upon receipt of this notice, Resources recorded a $21 million pre-tax ($15 million after-tax) charge to write-off the carrying value of this investment.
Resources was also the equity investor in two operating leases with Northwest Airlines (Northwest) B 757-200 and Delta Airlines (Delta) B 737-200. On September 14, 2005 both Northwest and Delta filed for protection under Chapter 11 of the US Bankruptcy Code, as anticipated. In 2004 and 2005, Resources successfully restructured the leases and converted the Delta and Northwest leases from leveraged leases to operating leases. The Delta aircraft was sold in January 2006 generating a small gain for Resources.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In January 2005, a KKR Fund, in which Resources had invested, sold its investment in KinderCare Learning Centers, Inc. and Resources received proceeds of approximately $17 million resulting in a pre-tax gain of approximately $1 million ($1 million after-tax).
In March 2004, Resources entered into an agreement with Midwest Generation LLC, an indirect subsidiary of Edison Mission Energy, to terminate its lease investment in the Collins generating facility in Illinois. Resources received gross proceeds of approximately $184 million, $84 million after taxes, and recorded a pre-tax loss of $17 million ($11 million after-tax).
In 2004, Resources terminated two lease transactions with Qantas Airways and China Eastern Airlines Co., Ltd resulting from the lessees exercising their respective purchase options. Resources received aggregate gross cash proceeds of approximately $45 million ($9 million after-tax) and recorded a pre-tax gain of $0 ($4 million after-tax).
Acquisitions
Energy Holdings
Prisma 2000 S.p.A. (Prisma)
In May 2006, Global forgave the guarantees of its partner in the Prisma investment of certain loans Global had made to Prisma and converted such loans totaling $38 million into additional equity in Prisma, thereby increasing its ownership interest from 50% to 85% and giving Global voting control of the project. As a result, Energy Holdings began consolidating this investment in May 2006 and reclassified the investment balance to Property, Plant and Equipment of approximately $62 million, Long-Term Investments of approximately $13 million, Capital Lease Obligations of approximately $40 million and certain other assets and liabilities on Energy Holdings’ Consolidated Balance Sheet. Energy Holdings recorded certain immaterial purchase accounting adjustments to reflect the plant, contracts and investment in Biomasse Italia S.p.A. (Biomasse) at fair value. The purchase price allocation has not yet been finalized since, due to recent events, Global has not been able to complete its appraisal of the land or finalize certain legal contingencies for the pre-acquisition period. For additional information, see Note 12. Commitments and Contingent Liabilities.
Impairments
Power
Power owns four turbines for which it has no immediate use. Power believes that newer technology would be more flexible and efficient for use in new projects. In addition, potential buyers have expressed interest in purchasing the turbines from Power. For these reasons, in December 2006, Power recorded a pre-tax impairment loss of $44 million to write-down the turbines to their estimated realizable value and has reclassified them to Assets Held For Sale on Power’s Consolidated Balance Sheet as of December 31, 2006.
Energy Holdings
Venezuela
During Energy Holdings’ review of its equity method investments, management concluded that due to the current political situation in Venezuela, it is probable that Energy Holdings would not be able to recover its capitalized costs associated with the investments in Venezuela. Therefore, Energy Holdings recorded a pre-tax impairment loss of approximately $7 million to write-down these investments in the fourth quarter of 2006. As of December 31, 2006, the book value of these investments was approximately $35 million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Regulatory Matters
Regulatory Assets and Liabilities
PSE&G
PSE&G prepares its financial statements in accordance with the provisions of SFAS 71. A regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs, which will be amortized over various future periods. These costs are deferred based on rate orders issued by the BPU or FERC or PSE&G’s experience with prior rate cases. All of PSE&G’s regulatory assets and liabilities at December 31, 2006 and 2005 are supported by written rate orders, either explicitly or implicitly through the BPU’s treatment of various cost items. Regulatory assets are subject to prudence reviews and can be disallowed in the future by regulatory authorities. PSE&G believes that all of its regulatory assets are probable of recovery. To the extent that collection of any regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.
PSE&G had the following regulatory assets and liabilities on the Consolidated Balance Sheets:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All regulatory assets and liabilities are excluded from PSE&G’s rate base unless otherwise noted. The descriptions below define certain regulatory items.
Securitized Costs: This reflects deferred costs, which are being recovered through the securitization transition charge authorized by the BPU. Funds collected through the securitization transition charge are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs and taxes.
Pension and Other Post Retirement Plans: Pursuant to the adoption of SFAS 158, PSE&G recorded the unrecognized costs for defined benefit pension and OPEB plans on the balance sheet as a regulatory asset. These costs represent actuarial gains or losses, prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs will be amortized and recovered in future rates.
SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act (EDECA), includes costs related to PSE&G’s electric and gas business as follows: 1) the universal service fund; 2) Demand Side Management (DSM) programs; 3) social programs which include bad debt expense; 4) the New Jersey Clean Energy Program costs payable in 2007 through 2008, recorded at discounted present value; and 5) the Remediation Adjustment Clause for incurred MGP remediation expenditures. All components except for Clean Energy accrue interest.
MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program costs that are probable of recovery in future rates.
Deferred Income Taxes: This amount represents the portion of deferred income taxes that will be recovered through future rates, based upon established regulatory practices, which permit the recovery of current taxes. Accordingly, this regulatory asset is offset by a deferred tax liability and is expected to be recovered, without interest, over the period the underlying book-tax timing differences reverse and become current taxes.
Gas Contract Mark-to-Market: The fair value of gas hedge contracts and gas cogeneration supply contracts. This asset is offset by derivative liability and an intercompany payable on the balance sheet.
OPEB-Related Costs: Includes costs associated with the adoption of SFAS No. 106 “Employers’ Accounting for Benefits Other Than Pensions” which were deferred in accordance with EITF Issue No. 92- 12, “Accounting for OPEB Costs by Rate Regulated Enterprises.”
Unamortized Loss on Reacquired Debt: Represents losses on reacquired long-term debt, which are recovered through rates over the remaining life of the debt.
Conditional Asset Retirement Obligation: These costs represent the differences between rate regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates.
Repair Allowance: This represents tax, interest and carrying charges relating to disallowed tax deductions for repair allowance as authorized by the BPU with recovery over 10 years effective August 1, 2003.
Regulatory Restructuring Costs: These are costs related to the restructuring of the energy industry in New Jersey through EDECA and include such items as the system design work necessary to transition PSE&G to a transmission and distribution only company, as well as costs incurred to transfer and establish the generation function as a separate corporate entity with recovery over 10 years beginning August 1, 2003.
Plant and Regulatory Study Costs: These are costs incurred by PSE&G and required by the BPU which are related to current and future operations, including safety, planning, management and construction.
Gas Margin Adjustment Clause: PSE&G defers the margin differential received from Transportation Gas Service Non-Firm Customers versus bill credits provided to BGSS-Firm customers.
Asbestos Abatement Costs: Represents costs incurred to remove and dispose of asbestos insulation at PSE&G’s fossil generating stations. Per a BPU order dated December 9, 1992, these costs are treated as Cost of Removal for ratemaking purposes.
Unrealized Losses on Interest Rate Swap: This represents the costs related to Transition Funding’s interest rate swap that are being recovered without interest over the life of Transition Funding’s transition bonds. This asset is offset by a derivative liability on the balance sheet.
Decontamination and Decommissioning Costs: These costs are related to PSE&G’s obligation for nuclear decontamination and decommissioning costs of U.S. Department of Energy enrichment sites prior to the generation asset transfer to Power in 2000.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Regulatory Assets: This includes deferred consolidated billing start-up and deferred Energy Information Control Network program costs.
Cost of Removal: PSE&G accrues and collects for Cost of Removal in rates. Pursuant to the adoption of SFAS 143, the liability for Cost of Removal was reclassified as a regulatory liability. This liability is reduced as removal costs are incurred. Cost of removal is a reduction to the rate base.
Overrecovered Electric Energy Costs: This clause was established by the EDECA to account for above market costs related to Non-Utility Generation (NUG) contracts, as approved by the BPU. Costs or benefits associated with the restructuring of these contracts are deferred. This clause also includes Basic Generation Service (BGS) costs in excess of current rates, as approved by the BPU.
Overrecovered Gas Costs: Represents PSE&G’s gas costs in excess of the amount included in rates and probable of refund in the future.
Excess Cost of Removal: The BPU directed PSE&G to refund $66M of excess gas cost of removal accruals over a 5 year period ending November 2011.
Other Regulatory Liabilities: This includes the following: 1) a retail adder included in the BGS charges beginning on August 1, 2003 that are now paid on a quarterly basis to the State of New Jersey; 2) amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds; and 3) Third party billing discounts related to the EDECA.
Note 6. Earnings Per Share (EPS)
PSEG
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under PSEG’s stock option plans, upon payment of performance units and upon conversion of Participating Units. The following table shows the effect of these stock options, performance units and Participating Units on the weighted average number of shares outstanding used in calculating diluted EPS:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
There were approximately 2.9 million stock options excluded from the weighted average common shares calculation used for diluted EPS due to their antidilutive effect for the year ended December 31, 2004. No stock options or Participating Units had an antidilutive effect for the year ended December 31, 2006.
Dividend payments on common stock for the year ended December 31, 2006 were $2.28 per share and totaled approximately $574 million. Dividend payments on common stock for the year ended December 31, 2005 were $2.24 per share and totaled approximately $541 million. Dividend payments on common stock for the year ended December 31, 2004 were $2.20 per share and totaled approximately $522 million.
Note 7. Goodwill and Other Intangibles
PSEG, Power and Energy Holdings
PSEG, Power and Energy Holdings conducted an annual review for goodwill impairment as of November 30, 2006 and concluded that goodwill was not impaired. There were no events that occurred subsequent to November 30, 2006 that required a further review of goodwill for impairment.
Power and Energy Holdings
As of December 31, 2006 and 2005, Power’s and Energy Holdings’ goodwill and pro-rata share of goodwill in equity method investments were as follows:
(A)
Changes relate to changes in foreign exchange rates.
(B)
RGE was sold in June 2006. For additional information relating to the sale see Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG, PSE&G, Power and Energy Holdings
In addition to goodwill, as of December 31, 2006 and 2005, PSEG, PSE&G, Power, Energy Holdings and Services had the following recorded intangible assets:
Note 8. Long-Term Investments
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings had the following Long-Term Investments as of December 31, 2006 and 2005:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Energy Holdings
Leveraged Leases
Energy Holdings’ net investment, through Resources, in leveraged leases was comprised of the following elements:
Resources’ pre-tax income and income tax effects related to investments in leveraged leases were as follows:
The $23 million decrease in income tax effect on pre-tax income of leveraged leases in 2006 as compared to 2005, was primarily due to the absence of the tax expense resulting from the sale of Resources’ interest in Seminole in 2005. For additional information regarding the sale of Seminole, see Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments.
The $52 million increase in income tax effect on pre-tax income of leveraged leases in 2005 as compared to 2004, was primarily due to the sale of Resources’ interest in Seminole in 2005 and additional benefits resulting from revisions to the revenue and tax calculations of certain of Resources’ leveraged lease investments performed in the fourth quarter of 2005 resulting from changes in certain lease forecast assumptions pertaining to state income taxes. A change in a key assumption which affects the estimated total net income over the life of a leveraged lease requires a recalculation of the leveraged lease, from inception, using the revised information. Any change in the net investment in the leveraged leases is recognized as a gain or loss in the year the assumption is changed. For additional information regarding the sale of Seminole, see Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments.
Partnership Investments and Corporate Joint Ventures
Energy Holdings’ partnership investments and corporate joint ventures are primarily accounted for under the equity method of accounting.
Investments in and Advances to Affiliates
Investments in net assets of affiliated companies accounted for under the equity method of accounting by Global amounted to $818 million and $1 billion as of December 31, 2006 and 2005, respectively. During the three years ended December 31, 2006, 2005 and 2004, the amount of dividends from these investments was $72 million, $70 million and $89 million, respectively. Global’s share of income and cash flow distribution percentages ranged from 35% to 60% as of December 31, 2006. Interest is also earned on loans made to various projects. Such loans earn interest that ranged from 5% to 7.5% during 2006.
As of December 31, 2006, Global’s recorded investment in equity method subsidiaries was $818 million as compared to $711 million of underlying equity in net assets of such investments. The difference primarily relates to an approximate $100 million investment in a foreign subsidiary which is classified as an equity
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
investment on Global’s financial statements and recorded as a loan on the equity method subsidiary. Investment classification is appropriate due to its long-term investment nature.
Global had the following equity method investments as of December 31, 2006:
(A)
In January 2007, Global sold its 34.5% interest in Thermal Energy Development Partnership, L.P. which owns the 21 MW biomass-fueled Tracy project in California. For additional information, see Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized results of operations and financial position of affiliates in which Global applied the equity method of accounting are presented below:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The differences in the results of operations and the financial position as of and for the year ended December 31, 2006, as compared to 2005, were due to Global’s sale of a 35% interest in Dhofar Power in 2005, the sale of Global’s 32% ownership interest in RGE and the consolidation of Prisma in 2006. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments for further details of these transactions.
Global also has investments in certain companies in which it does not have the ability to exercise significant influence. Such investments are accounted for under the cost method. As of December 31, 2006 and 2005, the carrying value of these investments aggregated $37 million and $39 million, respectively. Global periodically reviews these cost method investments for impairment and adjusts the values of these investments accordingly.
Note 9. Schedule of Consolidated Capital Stock and Other Securities
PSEG and PSE&G
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value of Preferred Securities
The estimated fair value of PSE&G’s Cumulative Preferred Stock was $72 million and $68 million as of December 31, 2006 and 2005, respectively. The estimated fair value was determined using market quotations.
Note 10. Schedule of Consolidated Debt
Long-Term Debt
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)
As of each of the years ended December 31, 2006 and 2005, the annual dividend requirement of PSEG’s Trust Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures), including those issued in connection with the Participating Units, and their embedded costs was approximately $18 million and $96 million, respectively. Enterprise Capital Trust I, Enterprise Capital Trust II, Enterprise Capital Trust III, Enterprise Capital Trust IV and PSEG Funding Trust II were formed and are controlled by PSEG for the purpose of issuing Quarterly Trust Preferred Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures). The proceeds were loaned to PSEG and are evidenced by Deferrable Interest Subordinated Debentures. If and for as long as payments on the Deferrable Interest Subordinated Debentures have been deferred, or PSEG had defaulted on the indentures related thereto or its guarantees thereof, PSEG may not pay any dividends on its common and preferred stock. The Subordinated Debentures support the following Preferred Securities issued by the trusts:
PSEG recorded interest expense of $43 million, $80 million and $83 million for the years ended December 31, 2006, 2005 and 2004, respectively.
In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity investment in the trust.
(B)
Represents fair value of interest rate swaps.
(C)
The aggregate principal amounts of maturities for each of the five years following December 31, 2006 are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Short-Term Liquidity
PSEG, PSE&G, Power and Energy Holdings
As of December 31, 2006, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $3.3 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted to availability and use to the specific companies as listed below. As of December 31, 2006, PSEG had no loans outstanding under its uncommitted facility and PSE&G had $31 million loans outstanding under its uncommitted facility.
(A)
PSEG/Power joint and several co-borrower facility.
(B)
Energy Holdings/Global/Resources joint and several co-borrower facility supported with a pledge of Energy Holdings’ membership interest in Global.
(C)
These amounts relate to letters of credit outstanding.
Energy Holdings
As of December 31, 2006, Energy Holdings had loaned $28 million of excess cash to PSEG. For information regarding affiliate borrowings, see Note 21. Related-Party Transactions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value of Debt
The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of December 31, 2006 and 2005, respectively.
Because their maturities are less than one year, fair values approximate carrying amounts for cash and cash equivalents, short-term debt and accounts payable. For additional information related to interest rate derivatives, see Note 11. Financial Risk Management Activities.
Note 11. Financial Risk Management Activities
PSEG, PSE&G, Power and Energy Holdings
The operations of PSEG, PSE&G, Power and Energy Holdings are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their results of operations and financial conditions. PSEG, PSE&G, Power and Energy Holdings manage exposure to these market risks through their regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, PSE&G, Power and Energy Holdings use the term ‘hedge’ to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the gains or losses on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings uses derivative instruments as risk management tools consistent with its respective business plan and prudent business practices.
Derivative Instruments and Hedging Activities
Energy Trading Contracts
Power
Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil and emission allowances in the spot, forward and futures markets, primarily in PJM Interconnection, L.L.C (PJM), but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana, and natural gas in the producing region.
Power maintains a strategy of entering into positions to optimize the value of its portfolio and reduce earnings volatility of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy seeking to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options and futures. There have been significant decreases in commodity prices over the last year. The resultant changes in market values for
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
energy and related contracts that qualify for hedge accounting have resulted in significant decreases to Accumulated Other Comprehensive Loss. For additional information, see Note 12. Commitments and Contingent Liabilities. Power marks its derivative energy trading contracts to market in accordance with SFAS 133, with changes in fair value charged to the Consolidated Statements of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.
Commodity Contracts
Power
The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale contracts, swaps, options, futures and FTRs.
Cash Flow Hedges
Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of December 31, 2006, the fair value of these hedges was $(166) million. These hedges, along with realized losses on hedges of $(19) million retained in Accumulated Other Comprehensive Loss, resulted in a $(108) million after-tax impact on Accumulated Other Comprehensive Loss. As of December 31, 2005, the fair value of these hedges was $(951) million. These hedges, along with realized gains on hedges of $11 million retained in Accumulated Other Comprehensive Loss, resulted in a $(558) million after-tax impact on Accumulated Other Comprehensive Loss. During 2007, $27 million (after-tax) of net unrealized and realized losses on these commodity derivatives is expected to be reclassified to earnings. Approximately $92 million of after-tax unrealized losses on these commodity derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified to earnings for the year ending December 31, 2008. Ineffectiveness associated with these hedges, as defined in SFAS 133, was $(3) million at December 31, 2006. The expiration date of the longest dated cash flow hedge is in 2009.
Other Derivatives
Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs or Operating Revenues, as appropriate, on the Consolidated Statements of Operations. The net fair value of these instruments as of December 31, 2006 was $1 million. The net fair value of these instruments as of December 31, 2005 was not material.
Energy Holdings
Other Derivatives
TIE enters into electricity forward and capacity sale contracts to sell its 2,000 MW capacity for portions of the current calendar year, with the balance sold into the daily spot market. TIE also enters into gas purchase contracts to specifically match the generation requirements to support the electricity forward sales contracts. Although these contracts fix the amount of revenue, fuel costs and cash flows, and thereby provide financial stability to TIE, these contracts are, based on their terms, derivatives that do not meet the specific accounting criteria in SFAS 133 to qualify for the normal purchases and normal sales exception, or to be designated as a hedge for accounting purposes. As a result, these contracts must be recorded at fair value.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The net fair value of the open positions was approximately $38 million and $(7) million as of December 31, 2006 and December 31, 2005, respectively.
Interest Rates
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed and floating rate debt and interest rate derivatives.
Fair Value Hedges
PSEG and Power
In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009. PSEG used an interest rate swap to convert Power’s fixed-rate debt into variable-rate debt. The interest rate swap is designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of December 31, 2006 and December 31, 2005, the fair value of the hedge was $(9) million and $(10) million, respectively.
Cash Flow Hedges
PSEG, PSE&G and Energy Holdings
PSEG, PSE&G and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives used are designated and effective as cash flow hedges. Except for PSE&G’s cash flow hedges, the fair value changes of these derivatives are initially recorded in Accumulated Other Comprehensive Loss. As of December 31, 2006, the fair value of these cash flow hedges was $(4) million, primarily at PSE&G. As of December 31, 2005, the fair value of these cash flow hedges was $(17) million, including $(11) million and $(6) million at PSE&G and Energy Holdings, respectively. The $(4) million and $(11) million at PSE&G as of December 31, 2006 and December 31, 2005, respectively, is not included in Accumulated Other Comprehensive Loss, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G’s customers. During the next 12 months, approximately $1 million of unrealized losses (net of taxes) on interest rate derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified at PSEG. As of December 31, 2006, there was no hedge ineffectiveness associated with these hedges. The amounts above do not include the fair value of approximately $(60) million as of December 31, 2005 for the cash flow hedges at Elcho, which had been reclassified into Discontinued Operations.
Foreign Currencies
Energy Holdings
Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of its risks is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, Global and certain of its foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to changes in the Peruvian Nuevo Sol and the Chilean Peso and to a lesser extent, the Euro. Changes in valuation of these currencies can impact the value of Global’s investments, results of operations, financial condition and cash flows. Global has attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Although the Chilean Peso and the Peruvian Nuevo Sol had originally depreciated relative to the U.S. Dollar after Global’s initial investments, the currencies have appreciated significantly over the past few years. The net cumulative foreign currency revaluations had increased the total amount of Energy Holdings’ Member’s Equity by $134 million as of December 31, 2006.
Hedges of Net Investments in Foreign Operations
Energy Holdings
In March 2004 and April 2004, Energy Holdings entered into four cross currency interest rate swap agreements. The swaps are designed to hedge the net investment in a foreign subsidiary associated with the exposure in the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross currency swaps was $(25) million and $(33) million as of December 31, 2006 and December 31, 2005, respectively. The change in fair value of the majority of the swaps is recorded in Cumulative Translation Adjustment within Accumulated Other Comprehensive Loss. As a result, Energy Holdings’ Member’s Equity was reduced by $23 million as of December 31, 2006. A portion of the swap, $(38) million, was dedesignated as a hedge in December 2006.
Note 12. Commitments and Contingent Liabilities
Nuclear Insurance Coverages and Assessments
Power
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 Nuclear Generating Station (Salem), Hope Creek Nuclear Generating Station (Hope Creek) and Peach Bottom Atomic Power Station (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. Both ANI and NEIL make a distinction between certified and non-certified acts of terrorism, as defined under the Terrorism Risk Insurance Act (TRIA), and thus their policies respond accordingly. For non-certified acts of terrorism, ANI policies are subject to an industry aggregate limit of $300 million, subject to reinstatement at ANI discretion. Similarly, 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 certified acts, Power’s nuclear liability ANI and 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 $10.8 billion. All utilities owning a nuclear reactor, 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 $101 million per reactor per incident, payable at $15 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 $317 million (based on Power’s ownership interests in Hope Creek, Peach Bottom
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and Salem) and its maximum aggregate annual assessment per incident is $48 million. This does not include the $11 million that could be assessed under the nuclear worker policies. 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:
(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 and has an assessment potential under former canceled policies.
(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 megawatts (MW) of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of August 20, 2003. 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 $1.1 billion, Power participates in a Blanket Limit policy where the $1.0 billion limit is shared by Power with Amergen Energy Company, LLC and Exelon Generation Company, LLC (Exelon Generation) among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Amergen and Exelon 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Guaranteed Obligations
Power
Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York) in commodity-related transactions in the ordinary course of business. These payment guarantees are provided to counterparties in order to obtain credit under physical and financial agreements for gas, power, pipeline capacity, transportation, oil, electricity and related commodities and services. These payment guarantees support the current exposure, interest and other costs on sums due and payable by ER&T and Power New York. Under these agreements, guarantees offered for trading and marketing cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. The face value of the guarantees outstanding as of December 31, 2006 and 2005 was approximately $1.6 billion. In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T and Power New York would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T’s and Power New York’s contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). The probability of all contracts at ER&T and Power New York being simultaneously “out-of-the-money” is highly unlikely due to offsetting positions within the portfolio. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability to Power under these guarantees. The current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $518 million and $549 million as of December 31, 2006 and 2005, respectively.
Power is subject to collateral calls related to commodity contracts that are bilateral and are subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s agreements. Changes in commodity prices, including fuel, emissions allowances and electricity, can have a material impact on margin requirements under such contracts that are entered into in the normal course of business. As of December 31, 2006, Power had posted margin of approximately $40 million, primarily in the form of letters of credit, and received margin of approximately $86 million, including approximately $82 million in the form of letters of credit, to satisfy collateral obligations and support various contractual and environmental obligations. As of December 31, 2005, Power had posted margin of approximately $1.2 billion, including approximately $1 billion in the form of letters of credit, and received margin of approximately $168 million, including approximately $115 million in the form of letters of credit.
In the event of a deterioration of Power’s credit rating to below investment grade, which represents a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide further performance assurance, generally in the form of a letter of credit or cash. As of December 31, 2006, if Power were to lose its investment grade rating and, assuming all counterparties to which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to approximately $578 million. Power believes that it has sufficient liquidity to post such collateral, if necessary.
Power also routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, such future contracts require a deposit of cash margin, the amount of which is subject to change based on market movement and in accordance with exchange rules. As of December 31, 2006 and 2005, Power had deposited margin of approximately $89 million and $176 million, respectively, related to exchange-traded transactions that are margined and monitored separately from physical trading activity.
Energy Holdings
Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The contingent obligations as of December 31, 2006 and December 31, 2005 are as follows:
(a)
Global sold its investments in Poland in 2006. Global’s obligation for Elcho was terminated as a result of the sale, however, it is still obligated for the equity commitment guarantee at Skawina. If payments are required, such payments are guaranteed by CEZ in accordance with the purchase agreement.
In September 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies) and nearly all of its assets. However, Energy Holdings retained certain outstanding construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance companies for which exposure is adequately supported by the outstanding letters of credit shown in the table above for PSEG Energy Technologies Asset Management Company LLC. As of December 31, 2006, there were $14 million of such bonds outstanding, which are related to uncompleted construction projects. These performance bonds are not included in the $82 million of guaranteed obligations above.
Environmental Matters
PSEG, PSE&G and Power
Hazardous Substances
The New Jersey Department of Environmental Protection (NJDEP) has regulations in effect concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. These regulations may substantially increase the costs of environmental investigations and necessary remediation, particularly at sites situated on surface water bodies. PSE&G, Power and respective predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities.
The U.S. Environmental Protection Agency (EPA) has determined that a six-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the Passaic River facility. The operations included one operating electric generating station (Essex Site), one former generating station and four former manufactured gas plants (MGPs). PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilities arising out of the site in connection with the sale. The Essex Site was transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Essex Site.
In 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G and Power, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances had been released from the Essex Site and a former MGP located in Harrison, New Jersey (Harrison Site), which also includes facilities for PSE&G’s ongoing gas operations. The EPA estimated that its study would require five to eight years to complete and would cost approximately $20 million, of which it would seek to recover $10 million from the PRPs, including PSE&G and Power. Power has provided notice to insurers concerning this potential claim.
Also, in 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that directed the PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP announced that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million.
PSE&G and Power have indicated to both the EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their respective claims and, along with approximately 65 other PRPs, have entered into an agreement with the EPA or have indicated their intention to enter an agreement that provides for sharing the costs of the $20 million study between the government organizations and the PRPs. The EPA recently has notified the PRPs that the cost of the study will greatly exceed the $20 million initially estimated and offered to the PRPs the opportunity to conduct the study themselves rather than reimburse the government for the additional costs it incurs. The PRP group is considering the offer and has engaged in discussions with the EPA. Whether the PRP group, or some number of the PRPs, agree to assume responsibility for the study will depend upon many factors, including a revised estimated cost of the study, the number of parties who agree to participate and the manner in which the parties divide the costs among themselves. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River or natural resource damages. However, such costs could be material.
PSE&G
MGP Remediation Program
PSE&G is currently working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites (Remediation Program). To date, 38 sites have been identified as sites requiring some level of remedial action. In addition, the NJDEP has announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface water bodies that have been impacted by hazardous substances from adjoining sites. Specifically, in 2005 the NJDEP initiated a program on the Delaware River aimed at identifying the ten most significant sites for cleanup. One of the sites identified is a former MGP facility located in Camden. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based on regulatory requirements, experience with the program and available remediation technologies. Since the inception of the Remediation Program in 1988 through December 31, 2006, PSE&G had expenditures of approximately $384 million.
During the fourth quarter of 2006, PSE&G refined the detailed site estimates. The cost of remediating all sites to completion, as well as the anticipated costs to address MGP-related material discovered in two rivers adjacent to former MGP sites, could range between $798 million and $838 million. No amount within the range was considered to be most likely. Therefore, $414 million was accrued at December 31, 2006, which represents the difference between the low end of the total program cost estimate of $798 million and the total incurred costs through December 31, 2006 of $384 million. Of this amount, approximately $47 million was recorded in Other Current Liabilities and $367 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $414 million Regulatory Asset was recorded.
Costs for the MGP Remediation Program were approximately $42 million in 2006. PSE&G anticipates spending $47 million in 2007, $50 million in 2008, and an average of approximately $40 million per year each year thereafter through 2016.
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Power
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The Federal government may order companies not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties of up to approximately $27,500 for each day of continued violation.
The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-burning units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to requests for information and, in January 2002, reached an agreement with the NJDEP and the EPA to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur Dioxide (SO2), Nitrogen Oxide (NOx), particulate matter and mercury from the coal-burning units at the Mercer and Hudson generating stations to ensure compliance with PSD/NSR. Power also agreed to spend at least $6 million on supplemental environmental projects and pay a $1 million civil penalty. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operations to commence.
Power subsequently notified the EPA and the NJDEP that it was evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution control equipment and other necessary modifications to the unit. On November 30, 2006, Power, reached an agreement with the EPA and NJDEP on an amendment to its 2002 agreement intended to achieve the emissions reductions targets of this agreement while providing more time to assess the feasibility of installing additional advanced emissions controls at Hudson.
The amended agreement with the EPA and the NJDEP will allow Power to continue operating Hudson and extend for four years the deadline for installing environmental controls beyond the previous December 31, 2006 deadline. Power will be required to undertake a number of technology projects (SCRs), scrubbers, baghouses, and carbon injection, plant modifications, and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of NOx, SO2, particulate matter, and mercury. In addition, Power has agreed to notify the EPA and NJDEP by the end of 2007 whether it will install the additional emissions controls at Hudson by the end of 2010, or plan for the orderly shut down of the unit.
Under the program to date, Power has installed SCRs at Mercer at a cost of approximately $113 million. The cost of implementing the balance of the amended agreement at Mercer and Hudson is estimated at $400 million to $500 million for Mercer and at $600 million to $750 million for Hudson and will be incurred in the 2007-2010 timeframe. As part of the agreement, Fossil has agreed to purchase and retire emissions allowances, contribute approximately $3 million for programs to reduce particulate emissions from diesel engines in New Jersey, and pay a $6 million civil penalty.
As a result of the agreement, Power has increased its environmental reserves by approximately $14 million to account for civil penalties associated with the amendment to the agreement and other costs. PSEG and Power recorded the charge in Other Deductions on their respective Consolidated Statements of Operations.
Mercury Regulation
New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. In February 2007, Pennsylvania also issued new requirements for the reduction of mercury emissions from coal-fired power plants. Connecticut requires coal-fired power plants in Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions effective in July 2008. The regulations in New Jersey require coal-fired electric generating units in New Jersey to meet certain emissions limits or reduce emissions by 90% by December 15, 2007. Under the New Jersey regulations, companies that are parties to multi-pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating
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capacity until December 15, 2012. Power has a multi-pollutant reduction agreement with the NJDEP as a result of a consent decree that resolved issues arising out of the PSD and the NSR air pollution control programs at the Hudson, Mercer and Bergen facilities. The estimated costs of technology believed to be capable of meeting these emissions limits at Power’s coal-fired unit in Connecticut and at its Mercer Station are included in Power’s capital expenditures forecast. Total estimated costs for each project are between $150 million and $200 million. The Mercer expenditures are included in the PSD/NSR discussion above.
On September 12, 2006, Connecticut released proposed revisions to mercury regulations that encompass “Permit Requirements for Mercury Emissions from Coal-Fired Electric Generating Units”. Also, Pennsylvania has proposed mercury regulations that would require reductions in mercury emissions at each facility as well as cap on total emissions. As proposed, the regulations do not impose requirements that would materially affect the costs already identified in Power’s capital expenditures forecast. Impact of any final regulations cannot be determined at this time.
New Jersey Industrial Site Recovery Act (ISRA)
Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applies to the sale of certain assets. Power had a $51 million liability as of December 31, 2006 and December 31, 2005 related to these obligations, which is included in Other Noncurrent Liabilities on Power’s Consolidated Balance Sheets and Environmental Costs on PSEG’s Consolidated Balance Sheets.
Permit Renewals
In June 2001, the NJDEP issued a renewed New Jersey Pollutant Discharge Elimination System (NJPDES) permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. A renewal application prepared in accordance with FWPCA Section 316(b) and the new Phase II 316(b) rule was filed in February 2006 with the NJDEP, which allows the station to continue operating under its existing NJPDES permit until a new permit is issued. Power’s application to renew Salem’s NJPDES permit demonstrates that the station satisfies FWPCA 316(b) and meets the Phase II 316(b) rule’s performance standards for reduction of impingement and entrainment through the station’s existing cooling water intake technology and operations plus implemented restoration measures. The application further demonstrates that even without the benefits of restoration the station meets the Phase II 316(b) rule’s site-specific determination standards, both on a comparison of the costs and benefits of new intake technology as well as a comparison of the costs to implement the technology at the facility to the cost estimates prepared by EPA. The U.S. Court of Appeals for the Second Circuit issued a decision after Power filed its application that rejected the use of restoration and the site-specific cost-benefit test under the Phase II 316(b) rule. If NJDEP were to require the installation of structures at the Salem facility to reduce cooling water intake flow commensurate with closed cycle cooling as a result of the unfavorable decision in the Phase II litigation, discussed, or otherwise, Power’s application to renew the permit estimated that the costs associated with cooling towers for Salem are approximately $1 billion, of which Power’s share would be approximately $575 million. If NJDEP and the Connecticut Department of Environmental Protection (CTDEP) were to require installation of closed-cycle cooling or its equivalent at Power’s five once- through cooled facilities, compliance with that requirement could have a significant impact on the facilities. These costs are not included in Power’s currently forecasted capital expenditures.
Energy Holdings
Prisma
In May 2006, Global became the majority shareholder of Prisma, which holds 100% of the stock of San Marco S.p.A (San Marco), owner of a 20 MW biomass generation facility in Italy. Global also assumed operational responsibility for the facility in May 2006. Global’s total investment in Prisma is approximately $84 million.
In August 2006, Global became aware that the Italian government was conducting a criminal investigation regarding allegations of violations of the facility’s air permit. The scope of the investigation was
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subsequently expanded to include alleged violations of the facility’s waste recycling and waste storage permits. Until May 2006, the facility was operated by Carlo Gravazzi Green Power (CGGP) pursuant to a Services Agreement with a Global subsidiary. Alleged violations include exceedances of permit limits for regulated pollutants, manipulation of the facility’s continuous monitoring systems, false reporting and the use of fuels not authorized by the permit. The government has seized records from the facility in connection with the investigation including plant design documents and plant operating records. The Italian government has named five individuals as targets of the criminal investigation, including three current and former San Marco employees and members of the facility’s board of directors. While San Marco has not been named as a target, there is a potential risk that it could be so named. Global has retained separate counsel for San Marco and the named Global employees.
In December 2006 and January 2007, the facility was served with an Order and a Decree, respectively, that prohibit it from conducting operations to prevent recurring violations and the destruction of evidence. Counsel for San Marco has advised the prosecuting attorney that it will fully cooperate with the ongoing investigation and will implement the corrective actions required to prevent recurrence of the violations. Counsel recently filed an application, that was not objected to by the Prosecuting Attorney, to convert the investigatory proceeding to one supervised by an Investigating Court. The application was filed to expedite efforts by Global to obtain relief from the Sequestration Orders. Counsel anticipates that the Court will issue orders shortly approving the application and naming a court expert to complete the investigation.
Counsel advises that the court expert will inspect the facility to determine whether the design and construction are appropriate to enable it to operate in compliance with the terms of its air permit. Once the inspection is complete, the expert will issue a report to the Court presenting findings on this issue. Counsel advises that this process can take from 60 to 90 days to complete. The Deputy Prosecutor recently advised counsel that she will work collaboratively with the Global to expedite the inspections and, once they are complete, to work collaboratively to obtain interim relief from the Sequestration Orders in advance of the final report to complete required maintenance. Assuming interim relief is obtained, Global anticipates that the facility will be authorized to resume commercial operations around June 2007, however no assurances can be given.
Global is currently evaluating a potential claim against CGGP under the Services Agreement for damages arising from the alleged wrongdoing.
Electroandes
In July 2005, Electroandes received a notice from Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, claiming past due taxes for 2002 totaling approximately $2 million related to certain interest deductions. Electroandes has taken similar interest deductions subsequent to 2002. The total cumulative estimated potential amount for past due taxes, including associated interest and penalties, is approximately $9 million through December 31, 2006. Electroandes believes it has valid legal defenses to these claims, and has filed an appeal with SUNAT to which it has not yet received a response; however, no assurances can be given regarding the outcome of this matter.
Luz del Sur
In January 2007, SUNAT filed two tax assessments against LDS totaling approximately $18 million, of which Global’s share would be approximately $7 million based on its 38% interest of LDS. The assessments related to deductions LDS claimed beginning in 2000 for certain operating fees it paid to International Technical Operators under a technical services agreement, for certain bad debt deductions, and certain other matters. The above assessments include interest and penalties claimed by SUNAT. LDS believes that all such deductions were appropriate and filed an appeal in February 2007. LDS has obtained a legal opinion that it could be successful in most of the major matters, while in some relatively smaller items SUNAT’s views could prevail which could lead to an immaterial amount of exposure. However, no assurances can be given and negative outcomes in any of the major matters could have a material adverse impact on Global’s results of operations and cash flows.
New Generation and Development
Power
Power has contracts with outside parties to purchase upgraded turbines for Salem Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek to modestly increase its generating capacity. Phase II of the Salem Unit 2 turbine replacement is currently scheduled for 2008 concurrent with steam generator replacement and is anticipated to increase capacity by 26 MW. Phase II of the Hope Creek turbine replacement is expected to be completed in 2007 along with the thermal power uprate and is expected to add approximately 125 MW. Power’s expenditures to date approximate $220 million (including Interest Capitalized During Construction (IDC) of $21 million) with an aggregate estimated share of total costs for these projects of $245 million (including IDC of $24 million). Timing, costs and results of these
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projects are dependent on timely completion of work, timely approval from the NRC and various other factors.
Completion of the projects discussed above within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes in the operational dates or ultimate costs to complete.
Power entered into a long-term contractual services agreement with a vendor in September 2003 to provide the outage and service needs for certain of Power’s generating units at market rates. The contract covers approximately 25 years and could result in annual payments ranging from approximately $10 million to $50 million for services, parts and materials rendered.
BGS and Basic Gas Supply Service (BGSS)
PSE&G and Power
PSE&G is required to obtain all electric supply requirements for customers who do not purchase electric supply from third-party suppliers through the annual New Jersey BGS auctions. PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions within three business days following the BPU’s approval. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s anticipated load requirements. The winners of the auction are responsible for fulfilling all the requirements of a PJM Interconnection, L.L.C. (PJM) Load Serving Entity (LSE) including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume any migration risk and must satisfy New Jersey’s renewable portfolio standards.
Through the BGS auctions, PSE&G has contracted for its anticipated BGS-Fixed Price load, as follows:
Power seeks to mitigate volatility in its results by contracting in advance for 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 enters into firm supply contracts with EDCs, as well as other firm sales and trading positions and commitments.
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 its anticipated BGSS obligations, as permitted by the BPU. The BPU permits recovery of the cost of gas hedging up to 115 billion cubic feet or approximately 80% of PSE&G’s residential gas supply annually through the BGSS tariff. For additional information, see Note 21. Related-Party Transactions.
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Minimum Fuel Purchase Requirements
Power
Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. The total minimum purchase requirements included in these commitments amount to approximately $733 million through 2012.
Power has several long-term purchase contracts for the supply of nuclear fuel for the Salem and Hope Creek Nuclear Generating Stations which include:
The nuclear fuel markets are competitive, and although prices for uranium, conversion and enrichment are increasing, Power does not anticipate any significant problems in meeting its future requirements.
Uranium concentrates and hexafluoride
Power has commitments and inventory to supply sufficient quantities of uranium (concentrates and uranium hexafluoride) to meet 100% of its total requirements through 2011. Additionally, Power has commitments covering approximately 55% of its requirements for 2012 and 15% from 2013 through 2016. These commitments total approximately $464 million through the period of which Power’s share is approximately $332 million. Power has decided to maintain strategic levels of concentrates and uranium hexafluoride in inventory and may make periodic purchases to support such levels.
Power also has commitments that provide 100% of its uranium enrichment requirements through 2010. These commitments total approximately $198 million through the period of which Power’s share is $146 million.
Power has commitments for the fabrication of fuel assemblies for reloads required through 2011 for Salem and through 2012 for Hope Creek. These commitments total approximately $122 million through the period of which Power’s share is $93 million.
Power has been advised by Exelon Generation that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom Atomic Power Station.
Natural Gas
In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G. As of December 31, 2005, the total minimum requirements under these contracts were approximately $1.2 billion through 2016.
These purchase obligations are in keeping with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.
Energy Holdings
The Guadalupe and Odessa plants of Texas Independent Energy, L.P. (TIE), an indirect, wholly owned subsidiary of Energy Holdings, have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of December 31, 2006, the Guadalupe and Odessa plants, which total approximately 2,000 MW of capacity, had forward energy sales contracts in place for approximately 30% of their expected output for 2007 and the sale of approximately 20% of their aggregate capacity for 2008 through 2010. The plants had fuel purchase commitments totaling $64 million to support all of their contracted energy sales.
Operating Services Contract (OSC)
Power
On January 17, 2005, Nuclear entered into an OSC with Exelon Generation relating to the operation of the Hope Creek and Salem nuclear generating stations. The OSC requires Exelon Generation to provide key
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personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement a management model that Exelon has used to manage its own nuclear facilities. Nuclear continues as the license holder with exclusive legal authority to operate and maintain the plants, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities. Exelon Generation is entitled to receive reimbursement of its costs in discharging its obligations, an annual operating services fee of $3 million and incentive fees up to $12 million annually based on attainment of goals relating to safety, capacity factor and operation and maintenance expenses. On October 27, 2006, Nuclear informed Exelon Generation that it was electing to continue to OSC for up to two years beyond the initial January 2007 period.
In December 2006, Power announced its plans to resume direct management of the Salem and Hope Creek nuclear generating stations before the expiration of the OSC. As part of this plan, on January 1, 2007, the senior management team at Salem and Hope Creek, which consisted of three senior executives from Exelon Generation, became employees of Power.
Other
PSEG and PSE&G
BPU Deferral Audit
The BPU Energy and Audit Division conducts audits of deferred balances. A draft Deferral Audit-Phase II report relating to the 12-month period ended July 31, 2003 was released by the consultant to the BPU in April 2005. The draft report addresses the SBC, Market Transition Charge (MTC) and NUG deferred balances. The BPU released the report on May 13, 2005.
While the consultant to the BPU found that the Phase II deferral balances complied in all material respects with the BPU Orders regarding such deferrals, the consultant noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. The amount in dispute is approximately $130 million. PSE&G and the BPU Staff are continuing discussions to resolve these questions and, if a resolution cannot be achieved, a BPU proceeding may be instituted to consider the issues raised.
On January 31, 2007 PSE&G requested that the matter be transmitted to the Office of Administrative Law for the development of an evidentiary record and an initial decision. The BPU granted the request on February 7, 2007.
While PSE&G believes the MTC methodology it used was fully litigated and resolved, without exception, by the BPU and other intervening parties in its previous electric base rate case, deferral audit and deferral proceeding that were approved by the BPU in its order on April 22, 2004, and that such order is non-appealable, PSE&G cannot predict the impact of the outcome of any such proceeding.
New Jersey Clean Energy Program
The BPU has approved a funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The sum of PSE&G’s electric and gas funding requirement was $82 million and $96 million for the years 2005 and 2006 respectively. The remaining liability, $119 million for 2007 and $137 million for 2008, has been recorded at a discounted present value with an offsetting regulatory asset. The costs associated with this program will be recovered from PSE&G ratepayers through the SBC over a period of four years and, therefore, a Regulatory Asset was also recorded. The liability for the funding requirement as of December 31, 2006 and December 31, 2005 was $253 million and $329 million, respectively.
PSEG and Energy Holdings
Leveraged Lease Investments
On November 16, 2006, the IRS issued its Revenue Agents report for tax years 1997 through 2000, which disallowed all deductions associated with certain of lease transactions that are similar to a type that the IRS
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publicly announced its intention to challenge. In addition, the IRS imposed a 20% penalty for substantial understatement of tax liability. In February 2007, PSEG filed a protest to the Office of Appeals of the IRS. As of each of December 31, 2006 and December 31, 2005, Resources’ total gross investment in such transactions was approximately $1.5 billion and $1.4 billion, respectively.
If all deductions associated with these lease transactions, entered into by PSEG between 1997 and 2002, are successfully challenged by the IRS, it could have a material adverse impact on PSEG’s and Energy Holdings’ financial position, results of operations and net cash flows and could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law and will aggressively contest the IRS’s disallowance. PSEG believes that it is more likely than not that it will prevail with respect to the IRS’s challenge, although no assurances can be given.
If the IRS’s disallowance of tax benefits associated with all of these lease transactions were sustained, approximately $773 million of PSEG’s deferred tax liabilities that have been recorded under leveraged lease accounting through December 31, 2006 would become currently payable. In addition, interest of approximately $124 million, after-tax would be charged, and penalties of $155 million may become payable. Management assessed the probability of various outcomes to this matter and recorded appropriate reserves in accordance with SFAS No. 5 “Accounting for Contingencies.” Management has also prepared various sensitivity analyses regarding potential payment obligations, including scenarios that consider the current position of the IRS regarding these types of listed transactions, and believes that Energy Holdings has the financial capacity to meet such potential obligations, if required.
The FASB recently issued additional guidance for leveraged leases. See Note 2. Recent Accounting Standards for additional information.
Power
Restructuring Charge
In June 2005, Power implemented a plan, approved by management, to reduce its Nuclear workforce by approximately 200 positions. The plan includes voluntary and involuntary separations offered to both represented and non-represented employees. The major cost associated with the restructuring relates to payments to the employees who are terminated. Power’s $14 million share of the estimated total cost was recorded in 2005, substantially all of which had been paid as of December 31, 2006.
Minimum Lease Payments
PSEG, PSE&G Power and Energy Holdings
PSE&G and Energy Holdings lease administrative office space under various operating leases. Total future minimum lease payments as of December 31, 2006 are:
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Power and Services 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, 2006 are:
Note 13. Nuclear Decommissioning
Power
In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning.
Power maintains the external master nuclear decommissioning trust previously established by PSE&G. This trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a “qualified” fund. In the most recent study of the total cost of decommissioning, Power’s share related to its five nuclear units was estimated at approximately $2.1 billion, including contingencies.
Power’s policy is that, except for investments tied to market indexes or other non-nuclear sector common trust funds or mutual funds (e.g., an S&P 500 mutual fund), assets of the trust shall not be invested in the securities or other obligations of PSEG or its affiliates, or its successors or assigns; and assets shall not be invested in securities of any entity owning one or more nuclear power plants.
Power classifies investments in the NDT Funds as available-for-sale under SFAS 115. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Funds.
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In 2006, other-than-temporary impairments of $8 million and $6 million were recognized on $59 million of equity and $152 million of debt securities, respectively, that were included in the Estimated Fair Value of NDT Funds as of December 31, 2006.
Net realized gains of $44 million were recognized in Other Income and Other Deductions on Power’s Consolidated Statement of Operations for the year ended December 31, 2006. Net unrealized gains of $108 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on Power’s Consolidated Balance Sheet as of December 31, 2006. The $3 million of gross 2006 unrealized losses has been in an unrealized loss position for less than twelve months. The available-for-sale debt securities held as of December 31, 2006, had the following maturities: $18 million less than one year, $108 million one to five years, $97 million five to 10 years, $48 million 10 to 15 years, $21 million 15 to 20 years, and $140 million over 20 years. The cost of these securities was determined on the basis of specific identification.
The fair value of securities in an unrealized loss position as of December 31, 2006 was approximately $39 million. If the fair market value of the securities falls below cost, the investments are considered to be other-than-temporarily impaired. The difference between the fair market value and cost is immediately recorded as a charge to earnings since Power does not definitely have the ability and intent to hold the securities for a reasonable time to permit recovery. Any subsequent recoveries in the value of these securities are recognized in OCI. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost detail of the securities.
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Note 14. Other Income and Deductions
Other Income
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Other Deductions
(A)
Other primarily consists of activity at PSEG (parent company), Services and intercompany eliminations.
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Note 15. Income Taxes
A reconciliation of reported income tax expense with the amount computed by multiplying pre-tax income by the statutory Federal income tax rate of 35% is as follows:
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PSEG, PSE&G, Power and Energy Holdings
Each of PSEG, PSE&G, Power and Energy Holdings provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from PSE&G’s customers in the future. Accordingly, an offsetting regulatory asset was established. As of December 31, 2006, PSE&G had a regulatory asset of $412 million representing the tax costs expected to be recovered through rates based upon established regulatory practices, which permit recovery of current taxes payable. This amount was determined using the enacted Federal income tax rate of 35% and State income tax rate of 9%.
Energy Holdings’ effective tax rate differs from the statutory Federal income tax rate of 35% primarily due to the imposition of state taxes and the fact that Global accounts for many of its investments using the equity method of accounting. In addition, as allowed under APB Opinion No. 23, “Accounting for Income Taxes-Special Areas” and SFAS 109, Management generally has maintained a permanent reinvestment strategy as it relates to Global’s international investments. If Management were to change that strategy, a deferred tax expense and deferred tax liability would need to be recorded to reflect the expected taxes that would need to be paid on Global’s offshore earnings. As of December 31, 2006 and 2005, undistributed foreign earnings were approximately $80 million and $220 million, respectively. During 2006, the reinvestment strategy for three of Global’s investments was modified, resulting in a deferred tax expense of $7 million. The determination of the amount of unrecognized U.S. Federal deferred income tax liability for undistributed earnings is not practicable.
The 2005 Jobs Act provided a one-year window to repatriate earnings from foreign investments and claim a special 85% dividends received tax deduction on such distributions. PSEG approved a total of three Domestic Reinvestment Plans, which provided for the repatriation of approximately $242 million through December 2005, of which approximately $177 million was eligible for the reduced tax rate pursuant to the Jobs Act. The tax expense associated with such repatriation totaled approximately $11 million and was recorded in 2005. Other than amounts discussed above, Global has made no change in its current intention to indefinitely reinvest accumulated earnings of its foreign subsidiaries.
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The following is an analysis of deferred income taxes:
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Note 16. Pension, OPEB and Savings Plans
PSEG
PSEG sponsors several qualified and nonqualified pension plans and other postretirement benefit plans covering PSEG’s, and its participating affiliates, current and former employees who meet certain eligibility criteria. Eligible employees of PSE&G, Power, Energy Holdings and Services participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below.
In September 2006, the FASB issued SFAS 158 (see Note 2. Recent Accounting Standards), which became effective prospectively for periods ending after December 15, 2006. In accordance with SFAS 158, PSEG, Power, PSE&G and Energy Holdings were required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions were measured as of December 31, 2006 in compliance with SFAS 158 and in accordance with customary practice of each PSEG company prior to the issuance of SFAS 158. For under funded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation (PBO). For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, the statement requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income, a separate component of Stockholder’s Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs were recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses, prior service costs and transition obligations arising from the adoption of the preceding pension and OPEB accounting standards, which have not been expensed.
Prior accounting guidance required that unrecognized costs be presented in a footnote to the financial statements as part of a reconciliation of a plan’s funded status to amounts recorded in the financial statements. The unrecognized costs are amortized as a component of net periodic pension or OPEB expense. Under the new standard, for Power and Energy Holdings, the charge to Other Comprehensive Income will be amortized and recorded as net periodic pension cost in the Statement of Operations. For PSE&G, the Regulatory Asset will be amortized and recorded as net periodic pension cost in the Statement of Operations.
The following presents the impact of applying the provisions of SFAS 158 on the Balance Sheet of PSEG as of December 31, 2006:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2006 and 2005. It also provides the funded status of the plans and the amounts recognized and amounts not recognized in the Statement of Financial Position at the end of both years. Because December 31, 2006 balances reflect the recognition and disclosure requirements of SFAS 158, and December 31, 2005 balances reflect the requirements of prior accounting standards, the Reconciliation of Funded Status found below applies only to 2005 and the Additional Amounts Recognized in Accumulated Other Comprehensive Income, Regulated Assets and Deferred Assets applies only to 2006.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and other postretirement benefit plans on an aggregate basis. The nonqualified pension plans are partially funded with Rabbi Trusts. In accordance with SFAS 87, the plan assets in the table above do not include the assets held in the Rabbi Trusts. The fair values of these assets are included on the Consolidated Balance Sheets. For additional information see Rabbi Trusts below.
Accumulated Benefit Obligation
The accumulated benefit obligation (ABO) for all PSEG’s defined benefit pension plans was $3.2 billion for both December 31, 2006 and 2005.
The following table provides the PBO, ABO, and fair value of plan assets for pension plans with an ABO in excess of plan assets.
The following table provides the components of net periodic benefit cost for the years ended December 31, 2006, 2005 and 2004.
Amounts that are expected to be amortized from Accumulated Other Comprehensive Income into Net Periodic Benefit Cost in 2007 are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following assumptions were used to determine the benefit obligations and net periodic benefit costs.
Plan Assets
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31.
PSEG utilizes an independent pension consultant to forecast returns, risk, and correlation of all asset classes in order to develop an optimal portfolio, which is designed to produce the maximum return opportunity per unit of risk. In 2002, PSEG completed its latest asset/liability study. The results from the study indicated that, in order to achieve the optimal risk/return portfolio, target allocations of 62% equity securities, 30% fixed income securities, 5% real estate investments, and 3% for other investments should be maintained. Derivative financial instruments are used by the plans’ investment managers primarily to rebalance the fixed income/equity allocation of the portfolio and hedge the currency risk component of the foreign investments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The expected long-term rate of return on plan assets was 8.75% as of December 31, 2006. For 2007, the expected long-term rate of return on plan assets will remain at 8.75%. This expected return was determined based on the study discussed above and considered the plans’ historical annualized rate of return since inception of the plans, which was an annualized return of 10.3%.
Plan Contributions
PSEG may contribute up to $70 million into its qualified pension plans and postretirement healthcare plan for calendar year 2007.
Cash Flows
Estimated Future Benefit Payments
The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Postretirement benefit payments are shown both gross and net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. The Act provides a nontaxable federal subsidy to employers that provide retiree prescription drug benefits that are equivalent to the benefits of Medicare Part D.
Rabbi Trusts
PSEG maintains certain unfunded, nonqualified benefit plans for which certain assets have been set aside in grantor trusts commonly known as “Rabbi Trusts” to provide supplemental retirement and deferred compensation benefits to certain of its and its subsidiaries’ key employees and directors.
Effective January 1, 2003, PSEG began accounting for the assets in the Rabbi Trusts under SFAS 115. PSEG classifies investments in the Rabbi Trusts as available-for-sale under SFAS 115. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trusts.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 2006, other-than-temporary impairments of $4 million were recognized on $73 million of debt securities, which was included in the Estimated Fair Value of Investments in Rabbi Trusts as of December 31, 2006.
Net realized losses of $1 million were recognized in Other Deductions on PSEG’s Consolidated Statement of Operations for the year ended December 31, 2006. The available-for-sale debt securities held as of December 31, 2006, had the following maturities: $2 million less than one year, $33 million one to five years, $23 million five to 10 years, $9 million 10 to 15 years, $4 million 15 to 20 years, and $44 million over 20 years. The cost of these securities was determined on the basis of specific identification.
The estimated fair value of the Rabbi Trusts related to PSEG, PSE&G, Power and Energy Holdings are detailed as follows:
401(k) Plans
PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) defined contribution plans. Eligible represented employees of PSE&G, Power and Services participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSE&G, Power, Energy Holdings and Services participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans. Employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants are matched with Employer contributions of cash equal to 50% of such employee contributions. The amount paid for Employer matching contributions to the plans for PSEG, PSE&G, Power and Energy Holdings are detailed as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG, PSE&G, Power and Energy Holdings
The following represents the impact of applying the provisions of SFAS 158 on the respective Balance Sheets of Power, PSE&G and Energy Holdings as of December 31, 2006
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension costs and OPEB costs for PSEG, PSE&G, Power and Energy Holdings are detailed as follows:
Note 17. Stock Based Compensation
PSEG
As approved at the Annual Meeting of Stockholders in 2004, PSEG’s 2004 Long-Term Incentive Plan (2004 LTIP) replaced prior Long-Term Incentive Plans (the 1989 LTIP and 2001 LTIP). The 2004 LTIP is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance shares, restricted stock, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIPs are non-qualified options to purchase shares of PSEG’s common stock, restricted stock awards and performance unit awards. However, since 2004 through December 31, 2006, only restricted stock has been granted.
The 2004 LTIP currently provides for the issuance of equity awards with respect to approximately 13 million shares of common stock. As of December 31, 2006, there were approximately 11.9 million shares available for future awards under the 2004 LTIP.
Stock Options
Under the 2004 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees of PSEG and its subsidiaries selected by the Organization and Compensation Committee of PSEG’s Board of Directors, the plan’s administrative committee (Committee). Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest based on three to five years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change- in-control, retirement, death or disability. Options are exercisable over a period of time designated by the Committee (but not prior to one year or longer than 10 years from the date of grant) and are subject to such other terms and conditions as the Committee determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering previously acquired shares of PSEG common stock.
On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Prior to September 1, 2006, PSEG had purchased shares on the open market to meet the exercise of stock options. For the years ended December 31, 2006, 2005 and 2004, PSEG paid out approximately $46 million, $72 million and $13 million, respectively, to settle the exercise of stock options.
Restricted Stock
Under the 2004 LTIP, PSEG has granted restricted stock awards to officers and other key employees. These shares are subject to risk of forfeiture until vested by continued employment. Restricted stock generally vests annually over three years, but is considered outstanding at the time of grant, as the recipients are entitled to dividends and voting rights. Vesting may be accelerated upon certain events, such as change in control (unless substituted with an equity award of equal value), retirement, death or disability.
In addition, from 1998 to 2001, PSEG granted 210,000 shares of restricted stock to a key executive, which are subject to risk of forfeiture until vested by continued employment. The shares vest on a staggered schedule through March 2007.
PSEG issues restricted stock from treasury stock.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Performance Units
Under the 2004 LTIP, performance units were granted to certain key executives, which provide for payment in shares of PSEG common stock based on achievement of certain financial goals over the three-year period from 2004 through 2006. The payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance compared to the performance of other companies in the Dow Jones Utilities Index. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG common stock up until January 1, 2007. Vesting may be accelerated upon certain events such as change in control, retirement, death or disability.
Stock-Based Compensation
Effective January 1, 2006, PSEG adopted SFAS 123R. See Note 2. Recent Accounting Standards for a description of the adoption of SFAS 123R. As a result, all outstanding unvested stock options as of January 1, 2006 are being expensed based on their grant date fair values, which were determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.
Prior to the adoption of SFAS 123R, PSEG recognized compensation expense for restricted stock over the vesting period based on the grant date fair market value of the shares. PSEG will continue to recognize compensation expense over the vesting term.
Also prior to the adoption of SFAS 123R, PSEG recognized compensation expense for performance units. The fair value of each performance unit was based on the grant date fair value of PSEG common stock. The accrual of compensation cost was based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. The current accrual is estimated at 100% of the original grant. The accrual is adjusted for subsequent changes in the estimated or actual outcome.
Compensation cost from options, restricted stock and performance units is included in Operation and Maintenance Expense on PSEG’s Consolidated Statements of Operations and amounted to approximately $17 million, $6 million and $3 million for the years ended December 31, 2006, 2005 and 2004, respectively. The total income tax benefit recognized on PSEG’s Consolidated Statements of Operations was approximately $7 million, $3 and $1 million for the years ended December 31, 2006, 2005 and 2004, respectively. Compensation cost capitalized as part of Property, Plant and Equipment was less than $1 million for each of the years ended December 31, 2006, 2005 and 2004. Of the total compensation cost for the years ended December 31, 2006, approximately $1 million, after-tax, related to the adoption of SFAS 123R, which was primarily due to expensing stock options for the first time. There was no impact on basic and diluted earnings per share from the implementation of SFAS 123R because there were a relatively small number of outstanding unvested stock options as of the implementation date.
Prior to the adoption of SFAS 123R, PSEG presented all tax benefits for deductions resulting from the exercise of share-based compensation as operating cash flows on the Consolidated Statement of Cash Flows. SFAS 123R requires the benefits of tax deductions in excess of the taxes expensed on recognized compensation cost to be reported as financing cash flows. There was approximately $15 million, $30 million and $5 million of excess tax benefits included as a financing cash inflow on the Consolidated Statement of Cash Flow for the years ended December 31, 2006, 2005 and 2004, respectively. Total cash flow will remain unchanged from what would have been reported under prior accounting rules.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table illustrates the effect on Net Income and earnings per share if PSEG had applied the fair value recognition provisions of SFAS 123R for the years ended December 31, 2005 and 2004.
Prior to the adoption of SFAS 123R, PSEG recognized the compensation cost of stock based awards issued to retirement eligible employees that fully or partially vest upon an employee’s retirement over the nominal vesting period of performance, and recognized any remaining compensation cost at the date of retirement. In accordance with SFAS 123R, PSEG recognizes compensation cost of awards issued after January 1, 2006 over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.
There were no options granted during 2005 or 2006. Changes in stock options for the years ended December 31, 2006 are summarized as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no options granted during 2006. The following weighted average assumptions were used for grants in 2004: expected volatility of 26.74%, risk-free interest rate of 3.09%, expected life of 4.0 years. There was a weighted average dividend yield of 5.00% in 2004.
The intrinsic value of options is the difference between the current market price and the exercise price. The total intrinsic value of options exercised during the years ended December 31, 2006, 2005 and 2004 was approximately $56 million, $72 million and $13 million, respectively. During the years ended December 31, 2006, 2005 and 2004, cash received from stock options exercised was approximately $86 million, $141 million and $59 million, respectively. The tax benefit realized from stock options exercised during the years ended December 31, 2006, 2005 and 2004 was approximately $13 million, $29 million and $5 million, respectively.
Approximately 1 million options vested during each of the years ended December 31, 2006, 2005 and 2004, respectively. The weighted average fair value per share for options vested during the years ended December 31, 2006, 2005 and 2004 was $41.15, $38.26 and $36.54 respectively.
As of December 31, 2006, there was less than $1 million of unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted average period of eight months.
Restricted Stock Information
Changes in restricted stock for the years ended December 31, 2006 are summarized as follows:
The weighted average grant date fair value per share was $65.88, $57.46 and $42.75 for restricted stock awards granted during the years ended December 31, 2006, 2005 and 2004, respectively.
The total intrinsic value of restricted stock vested during the years ended December 31, 2006 and 2005 was approximately $2 million and $1 million, respectively.
As of December 31, 2006, there was approximately $14 million of unrecognized compensation cost related to restricted stock, which is expected to be recognized over a weighted average period of 1.7 years.
Performance Units Information
In May 2004, 94,400 performance units were granted to certain key executives, which provide for payment in shares of PSEG Common Stock based on achievement of certain financial goals over the 2004 through 2006 three-year period. The number of units outstanding and unvested as of January 1, 2006 and December 31, 2006 was 83,600 and 82,700, respectively. 11,700 units were forfeited in 2005 and 900 in 2006. Approximately 9,500 dividend equivalents had accrued on these performance units. The grant date fair value of the performance units is $42.75 per unit.
Assuming performance units are paid out at the 100% performance level, the total intrinsic value of performance units outstanding as of December 31, 2006 was approximately $6 million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Outside Directors
During 2006, each director who was not an officer of PSEG or its subsidiaries and affiliates was paid an annual retainer of $50,000. Pursuant to the Compensation Plan for Outside Directors, 50% of the annual retainer was paid in PSEG common stock.
PSEG also maintains a Stock Plan for Outside Directors (Stock Plan) pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive a restricted stock award, currently 1,000 shares per year, for each year of service as a director. The restrictions on the stock granted under the Stock Plan provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 72nd birthday. This restriction would be deemed to have been satisfied if the director’s service were terminated after a “change in control” as defined in the Stock Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director who has the right to vote the shares. The fair value of these shares is recorded as compensation expense on the Consolidated Statements of Operations. Compensation expense for the Stock Plan for each of the years ended December 31, 2006 and 2005 was approximately $1 million and less than $1 million for the year ended December 31, 2004.
Employee Stock Purchase Plan
PSEG maintains an employee stock purchase plan for all eligible employees of PSEG and its subsidiaries. Under the plan, shares of PSEG common stock may be purchased at 95% of the fair market value through payroll deductions. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. During the years ended December 31, 2006, 2005 and 2004, employees purchased 60,351, 76,729, and 99,712 shares at an average price of $61.63, $54.00 and $40.59 per share, respectively. As of December 31, 2006, 1.8 million shares were available for future issuance under this plan.
Note 18. Financial Information by Business Segment
Basis of Organization
PSEG, PSE&G, Power and Energy Holdings
The reportable segments were determined by management in accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS 131). These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how it allocates resources to each business.
PSE&G
PSE&G earns revenue from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.
Power
Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding energy, capacity and ancillary services into the markets for these products. Power also enters into trading contracts for energy, capacity, firm transmission rights, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Energy Holdings
Global
Global earns revenues from its investment in and operation of projects in the generation and distribution of energy, both domestically and internationally. Global has ownership interests in three distribution companies and in electric generation facilities which sell energy, capacity and ancillary services to numerous customers. The generation plants sell power under long-term agreements as well as on a merchant basis while the distribution companies are rate-regulated enterprises. Revenues include revenues of consolidated investments. Gains and losses on sales of investments are typically recognized in revenues.
Resources
Resources earns revenues from its passive investments in leveraged leases, limited partnerships, leveraged buyout funds and marketable securities. Approximately 95% of Resources’ investments are in leveraged leases. DSM investments earn revenues primarily from monthly payments from utilities, representing shared electricity savings from the installation of energy efficient equipment. Resources operates both domestically and internationally; however, revenues from all international investments are denominated in U.S. dollars. Gains and losses on sales of investments are typically recognized in revenues.
Other
Energy Holdings’ other activities include amounts applicable to Energy Holdings (parent company). The net losses primarily relate to financing and certain administrative and general costs at the Energy Holdings parent corporation.
Other
PSEG’s other activities include amounts applicable to PSEG (parent corporation), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 21. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at the PSEG parent corporation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information related to the segments of PSEG and its subsidiaries is detailed below:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Geographic information for PSEG is disclosed below. The foreign assets and operations noted below relate solely to Energy Holdings.
As of December 31, 2006, Global and Resources had approximately $2.1 billion and $1.6 billion, respectively, of international assets. As of December 31, 2006, foreign assets represented 13% and 60% of PSEG’s and Energy Holdings’ consolidated assets, respectively, and the revenues related to those foreign assets contributed 5% and 40% to PSEG’s and Energy Holdings’ consolidated revenues, respectively, for the year ended December 31, 2006.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 19. Property, Plant and Equipment and Jointly-Owned Facilities
Information related to Property, Plant and Equipment as of December 31, 2006 and 2005 is detailed below:
PSE&G and Power
PSE&G and Power have ownership interests in and are responsible for providing their share of the necessary financing for the following jointly-owned facilities. All amounts reflect the share of PSE&G’s and Power’s jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power
Power holds undivided ownership interests in the jointly-owned facilities above, excluding related nuclear fuel and inventories. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category.
Power’s subsidiary, Nuclear, co-owns Salem and Peach Bottom with Exelon Generation. Nuclear is the owner-operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners reviews/approves major planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by the owner-operator.
Reliant Energy, Inc. is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by all co-owners makes all planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by Reliant Energy, Inc.
Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. First Energy Corporation is also a co-owner and the operator of this facility. First Energy submits separate capital and Operations and Maintenance budgets, subject to the approval of Power.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Reservoir is the owner-operator of this facility. The operator submits separate capital and Operations and Maintenance budgets, subject to the approval of the non-operating owners.
All owners receive revenues, Operations and Maintenance and capital allocations based on their ownership percentages. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.
Note 20. Selected Quarterly Data (Unaudited)
PSEG, PSE&G, Power and Energy Holdings
The information shown below, in the opinion of PSEG, PSE&G, Power and Energy Holdings, includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G
As disclosed in Note 1. Organization and Summary of Significant Accounting Policies, certain amounts have been reclassified to conform to the current presentation. Such reclassifications primarily relate to recording revenues and expenses related to a certain contract at PSE&G on a net basis versus gross. The amounts in the tables above for PSEG and PSE&G reflect the reduction of $46 million, $44 million and $57 million in both Operating Revenues and Energy Costs for the quarters ended September 30, 2006, June 30, 2006 and March 31, 2006, respectively; and $80 million, $50 million, $44 million and $40 million for the quarters ended December 31, 2005, September 30, 2005, June 30, 2005 and March 31, 2005, respectively, with no impact on Operating Income.
Note 21. Related-Party Transactions
The majority of the following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.
BGSS and BGS Contracts
PSE&G and Power
PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 31, 2012 and year-to-year thereafter.
Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.
The amounts which Power charged to PSE&G for BGS and BGSS are presented below:
As of December 31, 2006 and 2005, Power had receivables from PSE&G of approximately $370 million and $454 million, respectively, primarily related to the BGS and BGSS contracts. These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Consolidated Financial Statements.
In addition, as of December 31, 2006 PSE&G had a payable to Power of approximately $174 million as of December 31, 2005. PSE&G had a receivable from Power of approximately $152 million related to gas supply hedges Power entered into for BGSS. For additional information, see Note 12. Commitments and Contingent Liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Services
PSE&G, Power and Energy Holdings
Services provides and bills administrative services to PSE&G, Power and Energy Holdings. In addition, PSE&G, Power and Energy Holdings have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. The billings for administrative services and payables are presented below:
These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Consolidated Financial Statements. PSEG, PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximate market value for such services.
Tax Sharing Agreement
PSEG, PSE&G, Power and Energy Holdings
PSEG files a consolidated Federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.
PSE&G, Power and Energy Holdings had (payables to) receivables from PSEG related to taxes as follows:
Affiliate Loans and Advances
PSEG and Power
As of December 31, 2006 and December 31, 2005, Power had a demand note payable to PSEG of approximately $54 million and $202 million, respectively, for short-term funding needs. Interest Income and Interest Expense relating to these short term funding activities was immaterial.
PSEG and Energy Holdings
As of December 31, 2006 and 2005, Energy Holdings had a demand note receivable due from PSEG of $28 million and $409 million, respectively. These notes reflect the investment of Energy Holdings’ excess cash with PSEG. Interest Income related to these borrowings for the years ended December 31, 2006 and 2005 was $18 million and $4 million, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G and Services
As of each of December 31, 2006 and 2005, PSE&G had advanced working capital to Services of approximately $33 million. The amount is included in Other Noncurrent Assets on PSE&G’s Consolidated Balance Sheets.
Power and Services
As of each of December 31, 2006 and 2005, Power had advanced working capital to Services of approximately $17 million. The amount is included in Other Noncurrent Assets on Power’s Consolidated Balance Sheets.
Changes in Capitalization
PSE&G
PSE&G paid common stock dividends of approximately $200 million and $100 million to PSEG in 2006 and 2004, respectively.
Power
PSEG contributed capital of approximately $300 million to Power during 2004.
Energy Holdings
During 2006, 2005, and 2004 Energy Holdings made cash distributions to PSEG totaling $520 million, $412 million and $491 million, respectively, in the form of returns of capital preference unit redemptions, preference unit distributions and ordinary unit distributions.
Credit Agreements with The Bank of New York (BONY)
Thomas A. Renyi, a director of PSEG, is Chairman of the Board and Chief Executive Officer of BONY, a participant in three credit facilities of PSEG and its subsidiaries. Each of these facilities, and BONY’s participation, was made in the ordinary course of business, on substantially the same terms, including interest rates and collateral, as those prevailing at the time for comparable loans with persons not related to BONY, and did not involve more than the normal risk of collectibility or present other unfavorable features.
Other
PSEG and PSE&G
As of December 31, 2006 and 2005, PSE&G had net receivables from PSEG of approximately $3 million and $6 million, respectively, related to amounts that PSEG had collected on PSE&G’s behalf.
PSEG and Power
As of December 31, 2006 and 2005, Power had net receivables from PSEG of less than $1 million and approximately $2 million, respectively, related to amounts that PSEG had collected on Power’s behalf.
Energy Holdings and PSE&G
As of December 31, 2006 and December 31, 2005, Energy Holdings had a receivable of approximately $1 million and $3 million, respectively, related to efficiency incentive initiatives performed for PSE&G’s customers. Energy Holdings recorded revenues for such services of approximately $10 million, $22 million and $26 million for the years ended December 31, 2006, 2005 and 2004, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 22. Guarantees of Debt
Each series of Power’s Senior Notes and Pollution Control Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed financial information for the guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 23. Subsequent Events
Energy Holdings:
Global
From about 1995 through 2001, Global and its partners expended approximately $12 million towards the construction of a power plant in the Konya-Ilgin region of Turkey. In 2001, Turkey passed legislation and otherwise deprived Global of rights and fair and equitable treatment and expropriated Global’s Concession contract for the power plant project without compensation, despite the Turkish Government’s obligation to compensate Global for its costs under the existing contract and Turkish law. In 2002, Global initiated arbitration before the International Centre for Settlement of International Disputes seeking return of sunk costs, lost profits, interest and attorney fees and costs. A decision in this matter was made in January 2007 under which the Turkish Government will be required to pay approximately $20 million for sunk costs, interest and arbitration fees. After legal contingency fees, Global expects to receive approximately $7 million, after tax, for its share of the project. Global expects to receive payment in the second quarter of 2007.
Resources
In 2001, Resources made an investment of $14 million in a collateralized bond obligation fund (CBO fund) which was managed by Credit Suisse First Boston LLC and Credit Suisse First Boston (Europe) Limited (collectively, CSFB). Resources was an equal 33% partner in the CBO fund with the CIT Group and Dana. In 2002, the CBO fund was liquidated and Resources recovered a portion of its original investment. Resources and its partners filed claims against CSFB for lost interest and principal of its investment. The case was settled in January 2007 and Resources received $11 million, recording an after-tax gain of approximately $4 million.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
PSEG, PSE&G, Power and Energy Holdings
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to each company, including their respective consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer of each company by others within those entities. PSEG, PSE&G, Power and Energy Holdings have established a disclosure committee which is made up of several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures as of December 31, 2006 and, based on this evaluation, have concluded that the disclosure controls and procedures were effective in providing reasonable assurance during the period covered in these annual reports.
Internal Controls
PSEG, PSE&G, Power and Energy Holdings
PSEG has conducted an assessment of its internal control over financial reporting as of December 31, 2006 as required by Section 404 of the Sarbanes-Oxley Act. Management’s report on PSEG’s internal control over financial reporting is included on page 194. The Independent Registered Public Accounting Firm’s report with respect to management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of PSEG’s internal control over financial reporting is included on page 195. Management has concluded that internal control over financial reporting is effective as of December 31, 2006.
PSEG, PSE&G, Power and Energy Holdings continually review their respective disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting. However, there have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2006 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
PSEG, PSE&G, Power and Energy Holdings
None.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Public Service Enterprise Group (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSEG’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSEG’s annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG’s internal control over financial reporting using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSEG’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG’s financial reporting and the preparation of its financial statements as of December 31, 2006 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2006.
PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2006 included in this annual report on Form 10-K and, as part of that audit, have issued a report on management’s assessment of internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.
/s/ E. JAMES FERLAND
Chief Executive Officer
/s/ THOMAS M. O’FLYNN
Chief Financial Officer
February 27, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors of
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED:
We have audited management’s assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting, that Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on the criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2006 of the Company, and our report dated February 27, 2007 expressed an unqualified opinion on those consolidated financial statements and consolidated financial statement schedule, and included explanatory paragraphs regarding the adoption of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” and Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.”
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 27, 2007
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Executive Officers
PSEG, PSE&G, Power and Energy Holdings
The Executive Officers of each of PSEG, PSE&G, Power and Energy Holdings, respectively, are set forth below, as indicated for each individual.
On February 22, 2007, PSEG announced the election of Ralph Izzo as Chairman of the Board and Chief Executive Officer of PSEG. Mr. Izzo has also been elected as Chairman of the Board and Chief Executive Officer of PSEG’s subsidiaries, PSE&G Power and Energy Holdings. These actions are effective as of April 1, 2007. See Executive Officers table, above, for additional information regarding Mr. Izzo’s background with PSEG and its subsidiaries and Item 11.
ITEM 11. EXECUTIVE COMPENSATION
PSEG
The information required by Item 11 of Form 10-K is set forth under the heading “Executive Compensation” in PSEG’s definitive Proxy Statement for the 2007 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 5, 2007 and such information set forth under such heading is incorporated herein by this reference thereto.
PSE&G
COMPENSATION COMMITTEE REPORT
The Organization and Compensation Committee of the Board of Directors of PSEG has reviewed and discussed the Compensation Discussion and Analysis included in this Annual Report on Form 10- K with management and with Frederic W. Cook, Co., Inc., the Committee’s independent compensation consultant. Based on such review and discussions the Organization and Compensation Committee has recommended to the Board of Directors of PSE&G that the Compensation Discussion and Analysis be included in PSE&G’s Annual Report on Form 10-K.
Shirley Ann Jackson, Chair
Ernest H. Drew
Conrad K. Harper
William V. Hickey
Thomas A. Renyi
February 22, 2007
COMPENSATION DISCUSSION AND ANALYSIS
The Company is a wholly-owned subsidiary of PSEG and as such has no standing committees of its Board of Directors. Executive compensation is administered under the direction of the Organization and Compensation Committee (Committee) of PSEG, which oversees compensation programs and policies for PSEG and its subsidiaries. In light of responsibilities of the Committee, the Board of Directors of PSE&G does not believe it is necessary for it to have a separate committee of its own with respect to compensation
matters. The Committee is made up of directors who are independent under NYSE rules and the Company’s requirements for independent directors.
The executive officers named in the Summary Compensation Table (NEOs) for PSE&G are as follows: Mr. Ferland, the Chairman and Chief Executive Officer (CEO), who is also the Chairman and CEO of PSEG; Mr. Izzo, who was President and Chief Operating Officer (COO) until September 30, 2006, after which he became President and COO of PSEG; Mr. LaRossa, the President and COO since October 1, 2006; Mr. Selover, the Executive Vice President and General Counsel, who is also the Executive Vice President and General Counsel of PSEG; Mr. Busch, the Senior Vice President and Chief Financial Officer, who retired effective January 18, 2007; and Ms. Rado, the Vice President and Controller, who retired effective January 2, 2007. Under the compensation program administered by the Committee, each NEO is compensated on the basis of all positions he or she holds with PSEG and its subsidiaries, including PSE&G. Mr. Ferland will retire from all positions within the PSEG family of companies effective March 31, 2007. At that time, Mr. Izzo will become the Chairman and CEO of PSEG and PSE&G.
Compensation Philosophy and Program
Our Executive Compensation Program (Program) is designed to attract, motivate and retain high performing executives who are critical to our long-term success. The Program is structured to link executive compensation to how successfully we execute our business plans and meet a number of corporate, financial and operational goals. This design is intended to provide executives increased compensation when we do well and to provide less compensation when we do not.
As discussed below under Committee Activity, the Committee has been engaged since the fourth quarter of 2006 in a comprehensive review of executive compensation, including an analysis of its compensation philosophy and its use of consultants.
The Committee’s general philosophy is to set compensation of executive officers at the median of compensation of a peer group of companies. The Committee’s specific policies and benchmarking are discussed below.
The Committee reviews the philosophy, goals and objectives of the Program at least annually. In assessing their continued appropriateness, the Committee examines our success and the contributions of the individual executives in achieving our business plans. The Committee considers the motivational impact of the Program as an incentive in attaining desired business results and in the continued ability to attract and retain high-quality executives. Key factors in judging whether the Program has met its goals are the Program’s relationship to our financial results, our future outlook and our ability to attract and retain key executive talent.
The Committee has the responsibility to review, approve and modify, as necessary, our Program and each of its constituent elements.
Compensation Consultant
In October 2006, the Committee engaged Frederic W. Cook & Co., Inc. (Cook) as its executive compensation consultant to perform a comprehensive review of PSEG’s approach to and delivery of executive compensation. The scope of the assignment also included review of the CEO’s and other executive officers’ specific compensation levels, including analysis of competitive market data and the mix of base salary, equity, incentive and other payments. The results of the review were used in setting executive officer compensation for 2007.
Cook does not and will not perform any other services for PSEG. Its only roles will be advising the Committee on executive compensation, and also the PSEG Corporate Governance Committee on matters pertaining to compensation of directors who are not executive officers. Responsibility for assignment to and evaluation of work by Cook is solely that of the Committee and, beginning in April 2007 with respect to non-officer directors, the Corporate Governance Committee. In furtherance of Cook’s independence, management receives copies of certain materials provided by Cook to the Committee only after the materials have been provided to the Committee.
In setting executive base pay levels for 2006 and awards made in January 2006 for 2005 performance under the annual management incentive compensation program (MICP), the Committee utilized Hewitt Associates, Inc. (Hewitt) as its executive compensation consultant. Hewitt provided data as to executive
compensation trends and to assist in establishing the CEO’s compensation and in reviewing the CEO’s recommendations for the compensation of other executive officers.
PSEG pays the fees of the compensation consultants retained by the Committee. In addition, it has agreed to indemnify Cook for certain matters related to Cook’s engagement by the Committee, other than matters involving negligence or intentional misconduct by Cook.
Committee Activity
In setting 2006 and 2007 compensation, the Committee examined the following elements of compensation: base salary, award targets and performance criteria under the annual management incentive compensation plan (MICP) and equity and any other long-term incentive compensation awards under the long-term incentive compensation plan (LTIP).
Following Cook’s review of executive compensation, the Committee, in January 2007, considered the recommendations of Cook with regard to compensation design and effectiveness, compensation for the CEO and the NEOs, certain other officers and directors. As a result, the Committee determined to:
•
Change the peer group of companies (the peer groups appear below under Benchmarking) with respect to which executive compensation comparisons would be made to more closely align PSEG with its market contemporaries;
•
Change the form of long-term equity awards from one-third each for options, restricted stock and performance units (restricted stock only during the pendency of the proposed Exelon merger), to one-half each options and performance units for executive officers and one-half each performance units and restricted stock for other key employees;
•
Change the procedure for conveyance of the consultant’s compensation information so that the Committee would receive the data prior to management receiving it; and
•
Replace the PSEG Directors’ Stock Plan with a new equity compensation plan for outside directors.
The Committee also considered compensation recommendations for the NEOs made by the consultant and the CEO. Based on this review and the recommendations, the Committee, in conjunction with all the independent directors, established 2007 base compensation levels for the CEO and the COO of PSEG. The Committee also established the 2007 base compensation levels for the other NEOs and certain other officers based on recommendations by the CEO. Also in January 2007, the Committee certified the achievement of performance goals and determined the amounts earned and payable under the MICP with respect to 2006 performance.
In reviewing and establishing compensation levels for 2007, the Committee used the revised comparison peer group. The Committee’s decisions in determining compensation for 2006 and 2007, were made independent of prior equity awards, outstanding performance units, pensions or future compensation opportunities.
Compensation Policies
PSEG and the Committee have established compensation policies to implement the compensation philosophy stated above. To meet our compensation objectives and to focus executive efforts on improving corporate performance, the Committee has developed and currently administers pay delivery systems that fall into three broad categories:
•
Base salary;
•
Annual cash incentive compensation, including annual performance-based incentives; and
•
Long-term incentive compensation, including equity and performance awards, such as restricted stock, stock options and performance units.
Each of these elements of compensation, including our related policies regarding determination and evaluation, is discussed further below. Our policy is to provide a mix of these elements in the proportion best designed, as determined by the Committee, to achieve our compensation objectives. The Committee annually reviews the relationships among these elements, including cash, equity, performance-based pay, incentives, amount at risk and vesting schedules. The Committee does not have specific proportional factors it takes into account when establishing these elements.
In addition to the above elements of compensation, our practice has been to provide the following benefits (described more fully below) to non-represented employees generally, including the NEOs:
•
Post-employment and post-termination benefits, including defined benefit (pension) plans and severance and change-in-control benefits;
•
Health care programs;
•
Employee Stock Purchase Plan (for the purchase of PSEG Common Stock (Common Stock) at a 5% discount); and
•
A defined contribution (401(k)) plan (the Thrift Plan).
Executive and other key employees are provided with certain additional benefits, such as deferred compensation opportunities, enhanced post-employment benefits and a limited number of perquisites, in amounts deemed appropriate by the Committee and management based on the individual’s position and ability to contribute to achievement of our business goals.
Except for certain employment agreements with senior managers, described below, or with respect to certain benefits resulting from a termination of employment following a change in control for certain executive officers covered under PSEG’s Key Executive Severance Plan, also described below, we generally do not provide a tax gross-up of benefit amounts deemed to be taxable income under federal or state income tax laws and regulations.
Role of Executive Officers
The CEO attends Committee meetings, other than executive sessions, generally acting as Secretary for the Committee. Other executive officers and internal compensation professionals may attend portions of Committee meetings. The CEO recommends the compensation of his direct reports within an overall base salary budget and the Committee considers these recommendations in the context of the peer group. This includes base salary, incentive compensation targets for the MICP and the LTIP, goals and objectives and performance evaluation. Management’s data provided to the Committee generally includes a recommendation with respect to CEO compensation which, historically, has reflected the average base compensation adjustment and average MICP multiplier of other officers.
The design and effectiveness of compensation policies and programs are reviewed by the CEO periodically in light of general industry and peer trends, and recommendations for changes are made to the Committee as deemed advisable by the CEO. The CEO reviews such compensation matters with our internal compensation professionals and other consultants. The Committee believes that the role played by the CEO in this process is reasonable and appropriate because the CEO is best suited to evaluate the performance of his direct reports.
Benchmarking
As an important element, the Committee sets executive cash compensation so as to be competitive with other large energy services corporations.
The Committee looks at each element of cash compensation within the peer group as well as total compensation within the peer group. General industry data is also taken into consideration for certain positions where the talent pool falls outside of the energy sector. Such positions may include the finance, human resources, accounting and information technology fields. For 2006, the following peer group was used:
AES Corporation
Ameren Corporation
American Electric Power Company, Inc.
CenterPoint Energy, Inc.
CMS Energy Corporation
Consolidated Edison, Inc.
Constellation Energy Group, Inc.
Dominion Resources, Inc.
DTE Energy Company
Duke Energy Corporation
Edison International
Entergy Corporation
Exelon Corporation
FirstEnergy Corp.
FPL Group, Inc.
JEA
ONEOK, Inc.
PG&E Corporation
Pepco Holdings, Inc.
PPL Corporation
Progress Energy, Inc.
Reliant Resources, Inc.
Sempra Energy
Tennessee Valley Authority
The Southern Company
The Williams Companies, Inc.
TXU Corp.
WPS Resources Corporation
Xcel Energy Inc.
In determining executive compensation for 2007, the following group of energy services firms with reported net income averaging about $1 billion/year and market capitalization averaging about $16 billion was used. PSEG’s net income and market capitalization are approximately at the median of this group and we believe that this group is more closely aligned with PSEG.
AES Corporation
American Electric Power Company, Inc.
Consolidated Edison, Inc.
Dominion Resources, Inc.
Duke Energy Corporation
Edison International
Entergy Corporation
Exelon Corporation
FirstEnergy Corp.
FPL Group, Inc.
PG&E Corporation
Progress Energy, Inc.
Sempra Energy
The Southern Company
The Williams Companies, Inc.
TXU Corp.
Xcel Energy Inc.
As an initial positioning, the Committee targets the 50th percentile of relative positions within this group for total cash compensation, which is considered the total of salary and annual cash incentive compensation. The “mix” of total cash compensation for each of the executive positions is surveyed from this peer group. The reported pay structure from the competitive analysis is used as a general guideline in determining the appropriate mix of compensation among base salary, annual incentive opportunity and long-term compensation opportunity. There is no predetermined formula regarding the allocation of salary and incentives. The mix of incentives is selected so as to be reflective of the competitive practice found in this group for each of the pay components listed above.
Compensation Components
Base Salary
The NEOs’ base salary levels are reviewed annually by the Committee using a budget it establishes for merit increases and salary survey data provided by external compensation consultants. Market competitive base salary levels are determined and established for all covered executive positions as well as for other officers. Annually, the individual performance of the executives with respect to corporate performance criteria is determined and taken into account when setting salaries against the competitive market data. Such corporate performance criteria include attainment of business unit plans and financial targets, as well as individual measures for each NEO related to such person’s area of responsibility. In addition, factors such as leadership ability, managerial skills and other personal aptitudes and attributes are considered. Base salaries for satisfactory performance are targeted at the median (50th percentile) of the competitive market. Generally, for 2006, base salaries as a group were increased 3.6% from 2005 levels to reflect general market adjustments for comparable positions.
The Committee attempts to assure that annual salary determinations, on average, fall within the range of median base salaries provided to executives in the peer panel that have duties and responsibilities similar to those of our executive officers. Differences are primarily driven by the executive’s individual performance and experience.
Base salaries and base salary adjustments for individual NEOs other than the CEO are determined relative to the recommendations of the CEO, considering the individual’s level of responsibilities, sustained performance over time and results during the immediately preceding year and the executive’s pay in relation to the market median. Performance metrics included achievement of business plans, safety and operational results, customer satisfaction, regulatory outcomes and other factors.
For fiscal year 2006, the base salary of E. James Ferland, Chairman of the Board and CEO, based on overall performance and consideration of market data, was set at a rate of $1,120,000 or a 3.7% increase over the rate for 2005, which was approximately the median of base salary provided to CEO’s of other large energy services organizations. In determining base salary for the CEO, individual performance in relation to corporate performance factors such as achievement of business plans, financial results, safety, human resources management, nuclear operations and civic leadership was considered. For 2007, until Mr. Ferland’s retirement on March 31st, he will be paid a salary at the annual rate of $1,160,000. On his election as President and COO of PSEG in October 2006, Ralph Izzo’s annual base salary rate was set at $700,000. For 2007, Mr. Izzo’s annual rate of base salary as COO of PSEG was increased to $725,000. The annual rate of
base salary for 2007 for Mr. Selover is $505,000 and for Mr. LaRossa is $380,000. Mr. Busch and Ms. Rado both retired in January 2007.
Annual Cash Incentive Compensation
The MICP, which was approved by stockholders in 2004, is an annual cash incentive compensation program for executive and other officers. To support the performance based objectives of our compensation program, corporate and business unit goals and measures are established each year based on factors deemed necessary to achieve strategic financial and non-financial business objectives. The goals and measures are established by the CEO for the NEO’s reporting to him, and for all other officers by the individual to whom he or she reports. The goals and measures applicable to each NEO for 2006 are further discussed below.
The MICP was designed to comply with Section 162(m) of the Internal Revenue Code, which, as explained below, limits the Federal income tax deduction for compensation in excess of certain limits. The MICP sets a maximum award fund in any year of 2.5% of PSEG’s net income. The CEO’s maximum award cannot exceed 10% of the award fund and the maximum award for each other participant cannot exceed 90% of the award fund divided by the number of participants, other than the CEO, for that year. For 2006 performance under the MICP, these limits were $18,475,000 for the total award pool (of which $7,919,300 was awarded), $1,847,500 for the CEO’s maximum award and $437,600 for each other participant’s maximum award.
Subject to the overall maximums stated above, NEOs are eligible for annual incentive compensation based on a combination of the achievement of individual performance goals by each officer which determines his/her Individual Performance Factor, as adjusted by overall corporate performance, as measured by the Corporate Factor. The Corporate Factor is a financial measure, PSEG’s Return on Equity (ROE), which is a relative performance assessment comparing PSEG’s ROE against the median ROE performance of energy companies that comprise the Dow Jones Utility Index (DJUI). This Corporate Factor is the significant determinant of MICP awards. A maximum award is based on a comparative performance factor of 1.5 and is achieved if PSEG’s annual ROE, as measured on September 30, exceeds the median ROE performance of the group of energy companies that make up the DJUI by five hundred basis points. The minimum award threshhold, based on a comparative performance factor of 0.5, is reached if PSEG’s ROE is not more than five hundred basis points below the DJUI median. Actual incentive awards for participants in the MICP are computed as follows: (A) the participant’s Target Award Amount (% of base salary) is multiplied by (B) the participant’s Individual Performance Factor (0.0 to 1.5), which, in turn, is multiplied by (C) the Corporate Factor to arrive at the Final Award. In no case, however, may a Final Award exceed the lesser of (i) 1.5 times the participant’s Target Award Amount or (ii) the maximum amount allowed for that participant under the total award pool for that year.
Individual Performance Goals for NEOs include the following measures: OSHA safety performance, operational performance, customer satisfaction, operations and environmental performance and compliance. Each NEO position has a targeted incentive award established by the Committee at the beginning of each year ranging from 35% (increased to 40% for 2007) to 100% of base salary. Annual incentive awards are intended to provide a competitive level of compensation if the corporation meets its financial goals and the NEO achieves his or her business unit specific and individual goals. Since MICP targets are set as a percentage of base salary, increases in salary affect target bonuses. The goals and measures applicable to each NEO for 2006 are further discussed on page 213.
For the 2006 performance year, based on PSEG’s ROE of 15.3%, as compared with the median ROE of the companies comprising the DJUI of 13.4%, the Corporate Factor applied to MICP participants was 1.19. Also for 2006, Mr. Ferland’s final award was limited to an overall performance factor of 1.5, the maximum allowed, which was also the average overall performance factor of his direct reports. The MICP awards of the NEOs for 2006 are shown below in the Summary Compensation Table. The Committee made its determinations regarding MICP awards for the 2006 performance year in January of 2007. Payment was made as soon as practicable thereafter.
Long-Term Incentive Compensation
The LTIP was approved by PSEG’s stockholders at the 2004 Annual Meeting. To permit flexibility, the LTIP provides for different forms of equity awards including:
•
stock options (the right to purchase shares of Common Stock at a stated price);
•
restricted stock (shares of Common Stock subject to forfeiture if certain service requirements or other restrictions are not met); during the restriction period, recipients of shares of restricted
stock may exercise full voting rights with respect to those shares and are entitled to receive all dividends on the shares; and
•
performance units (the right to receive a stated number of shares of Common Stock or cash based upon the value of such stated number of shares upon the attainment of certain performance goals).
NEOs, other officers and other key employees, as selected by the Committee, are eligible to participate in the LTIP.
This plan is designed to attract and retain qualified personnel for positions of substantial responsibility, to motivate participants toward goal achievement by means of appropriate incentives, to achieve long-range corporate goals, to provide incentive compensation opportunities that are competitive with those of other similar companies and to align participants’ interests with those of our stockholders.
The exercise price of any stock option granted under the LTIP may not be below the closing price of Common Stock on the date of grant, no repricing may be done without stockholder approval and no discounted options may be granted. Performance goals are used for any performance based awards.
Neither options nor performance units were granted to NEOs in 2005 and 2006. All grants made were restricted stock awards because the Committee determined that this type of award was most compatible with the proposed merger with Exelon. In January 2005, LTIP awards were made with respect to 2005 compensation and in December 2005, LTIP awards were made with respect to 2006 compensation.
For 2007 grants, the Committee determined that senior officers, including the NEOs, would be granted a long-term award consisting of 50% performance shares and 50% non-qualified stock options. For other participants, 2007 awards would consist of 50% performance shares and 50% restricted stock. The Committee structured the grants in this manner to increase the performance related nature of the grants to senior officers.
Grant levels are determined by the Committee based upon several factors including the value of long-term incentive awards made by firms in the peer group to executives in similar positions and whose cash compensation is similar to each NEO as well as the individual’s ability to contribute to PSEG’s overall success. The level of grants is reviewed annually by the Committee. In general, when making LTIP grants, the Committee’s determinations are made independently from any consideration of the individual’s prior LTIP awards.
The CEO determines his recommendations for the size of LTIP grants for NEOs and each other participant by averaging the median of long-term incentive grants for a comparable position in the peer group and the median of long-term incentive grants for comparable levels of base salary for positions within the peer group. In making his recommendation for the size of a particular LTIP grant for each NEO, the CEO adjusts this average to reflect the individual’s performance and ability to contribute to PSEG’s long-term value.
PSEG has not granted stock options to NEOs since early 2004, shortly after PSEG’s stockholders approved the LTIP at the 2004 Annual Meeting. Generally, the Committee considers changes regarding executive officer salary adjustments, short-term cash incentive goals and equity compensation grants at its December meeting each year. However, because of the ongoing review of executive compensation by Cook at year-end 2006, LTIP awards for 2007 were not made until January 2007. For future years, the Committee intends to resume its practice of making compensation decisions and LTIP grants within the same period, generally around December of each year. The Committee expects this practice to be followed without consideration of the timing of release of earnings or other non-public information.
The following table discloses LTIP awards made by the Committee to the NEOs in February 2007:
The Stock Options granted have a term of ten years and an exercise price of $65.85 (the closing price on the date of grant). The right to exercise one-quarter of the stock options vests on each of December 31, 2007, 2008, 2009 and 2010.
The performance units are subject to the achievement of certain performance goals related to PSEG’s performance with respect to Total Shareholder Return and ROE relative to the companies in the DJUI over a performance period ending on December 31, 2009.
Other Executive Compensation Programs
Retirement
We provide certain retirement benefits to maintain practices that are competitive with companies with which we compete for executive talent. In addition to the qualified pension plan, we maintain supplemental plans to provide competitive retirement benefits. These benefits are described below under Pension Benefits.
Severance and Change in Control Benefits
We provide for severance benefits in the event of certain employment terminations. These benefits are available to officers, including the NEOs, in order to be competitive with the companies with which we compete for executive talent. We also provide severance benefits upon a change in control to officers, including the NEOs, and to certain key executive level employees. A change in control is by its nature disruptive to an organization and to many executives. Such executives are frequently key players in the success of organizational change. To assure the continuing performance of such executives in the face of a possible termination of employment in the event of a change in control, PSE&G deems it prudent to provide a competitive severance package. In addition, some executives, not a key party to such transaction, may have their employment terminated following its completion. A severance plan with benefits applicable upon a change in control is an important element for attracting and retaining key executives. These benefits are described below under Potential Payments upon Termination of Employment or Change in Control.
Perquisites
We also provide certain perquisites that PSEG believes are reasonable to maintain compensation practices that are competitive with companies with which we compete for executive talent. These include automobile use, financial planning services, annual physical examinations, spousal travel to accompany executive officers on business trips, PSEG-purchased tickets to entertainment and sporting events, home security, home computer services and chartered air travel. These perquisites are described in the Summary Compensation Table.
Stock Ownership Guidelines
To encourage equity ownership of Common Stock by our officers, PSEG has established guidelines for stock ownership over a reasonable period of time as follows:
In fulfilling the stock ownership guidelines, the executive may count all stock owned directly and beneficially. All restricted stock whether or not vested may be included. Also included are shares held in the Thrift Plan. Stock options and performance units are not counted.
PSEG’s Insider Trading Policy prohibits the pledging or hedging of such shares.
The Stock Ownership Guidelines will be reviewed annually by the Committee.
In making 2007 grants under the LTIP, the stock ownership policy was not a factor considered by the Committee.
The following table shows, for each NEO, the dollar amount of stock ownership required by the Stock Ownership Guidelines and the dollar amount of these actual stock holdings as of February 16, 2007 (see Security Ownership of Directors, Management and Certain Beneficial Owners):
Accounting and Tax Implications
The Committee has considered the effect of the adoption of FAS 123R (see Notes 2 and 17 of the Notes to Consolidated Financial Statements included in this Form 10-K) regarding the expensing of stock options in determining the nature of the grants under the LTIP.
The Committee considers the tax-deductibility of our compensation payments. Section 162(m) of the Internal Revenue Code (IRC) generally denies a deduction for United States federal income tax purposes for compensation in excess of $1 million for persons named in the proxy statement, except for compensation pursuant to shareholder-approved performance-based plans. Stockholder approval of the LTIP and MICP was received at PSEG’s 2004 Annual Meeting of Stockholders. As a result, performance-based compensation under these plans is not now subject to the limitation on deductions contained in Section 162(m) of the IRC.
In 2006, Messrs. Ferland and Izzo had compensation (consisting of base salary and the taxable value of restricted stock that vested during the year) in excess of the amount deductible under Section 162(m) of the IRC. The Committee will continue to evaluate executive compensation in light of Section 162(m) of the IRC. For 2007, the Committee has determined to make all awards to NEO’s under the LTIP performance-based.
In light of Section 162(m), as well as certain New York Stock Exchange rules, the Committee’s general policy is to present all incentive compensation plans in which executive officers participate to stockholders for approval prior to implementation.
SUMMARY COMPENSATION TABLE
The amount shown reflects the expense included on PSE&G Financial Statements for 2006 related to restricted stock awards and performance units granted in current or prior years under the LTIP and still outstanding as determined under Financial Accounting Standard (FAS)123R. The fair value at the grant date of the number of shares of equity awards granted in 2006 is shown below in the Grants of Plan-Based Awards Table. Generally, restricted stock awards vest one-third annually and, during the restricted period, earn dividends as declared on the Common Stock.
Under their terms, all shares of restricted stock vest upon retirement. For Mr. Busch and Ms. Rado, in accordance with FAS 123R, a portion of the market value of unvested shares of restricted stock was recognized in 2006 and reflected in the amount shown. The amount expensed by PSE&G was accelerated to reflect earlier vesting following their announcements of anticipated retirement dates.
Performance units are denominated in shares of Common Stock and are subject to achievement of certain performance goals over a three-year period and are payable as determined by PSEG in shares of stock or cash. For a discussion of the assumptions made in valuation see Note 17 of the Notes to the Consolidated Financial Statements included in PSEG’s 2006 Annual Report on Form 10-K.
The respective amounts attributable to restricted stock and performance units are as follows:
Expense of options granted in current or prior years under the LTIP and still outstanding as determined under FAS 123R. The fair value at the grant date of the number of shares of equity awards granted in 2006 is shown below in the Grants of Plan-Based Awards Table.
Amounts awarded were earned under the MICP and determined and paid in the following year.
Includes change in actuarial present value of accumulated benefit under defined benefit pension plans between 12/31/05 and 12/31/06 determined by calculating the benefit under the applicable plan benefit
formula for each of the plans, based on credited service and earnings in effect at the respective measurement dates. These changes are:
Includes interest earned under the Deferred Compensation Plan at Prime plus 1/2%, to the extent that it exceeds 120% of the applicable long-term rate. These amounts are:
Includes perquisites and personal benefits which include (a) automobile, gas, parking and maintenance, (b) financial planning services, (c) physical examinations and related transportation, (d) home computer and related services, (e) home security systems, (f) airline clubs, (g) travel on chartered aircraft, (h) spousal travel and (i) personal/family entertainment. We compute the aggregate incremental cost to PSEG by estimating the amount by which the value of the benefit provided exceeds whatever reimbursement for such expenses the NEO would ordinarily been entitled to claim under established business expense policies. For automobiles, the lease value of the vehicle was used; for parking, the amount charged back to the NEO’s business unit for the space was used; for the driver, actual compensation and benefit expense was used; for gasoline and maintenance, estimates were used based on the vehicle’s annual mileage. For each NEO, the amount that exceeded the greater of $25,000 or 10% of his total perquisite and personal benefit amount is shown in the following chart:
a
Mr. Ferland receives the services of a driver for business, commuting and occasional personal use.
In addition, the Company chartered aircraft to transport Mr. Ferland on some occasions when business needs precluded Mr. Ferland from taking commercial flights, which Mr. Ferland had scheduled for personal reasons. The cost to PSEG of such charters was $87,797. Mr. Selover traveled with Mr. Ferland on two such trips.
Includes the following employer contributions to Thrift and Tax-Deferred Savings Plan:
GRANTS OF PLAN-BASED AWARDS TABLE
Material Factors Concerning Awards Shown in Summary Compensation Table, Grants of Plan-Based Awards Table and Employment Agreements
MICP
The Plan-based awards for annual incentive compensation included in the Summary Compensation Table were paid in 2007 with respect to 2006 performance under the terms of the MICP. The range of possible awards for each NEO in relation to his Target Award is set forth in the Grants Based Awards Table above. The results of individual performance goals are multiplied by the overall corporate performance factor and applied against the individual’s performance target (see Compensation Discussion and Analysis for an explanation of how the MICP works).
Mr. Ferland’s 2006 MICP award was $1,680,000. The Organization and Compensation Committee evaluates Mr. Ferland’s performance based on overall corporate performance plus the relative performance of his direct reports taken as a group.
Mr. Izzo’s 2006 MICP award was $437,600 and was limited by the maximum award allowed for participants in the MICP other than the CEO (see Compensation Discussion and Analysis for an explanation). Mr. Izzo had eight performance goals for 2006, with the preponderance related to business integration planning for the proposed merger with Exelon and contingency planning in the event of a merger termination. His other goals included responsibility for developing a corporate-wide financial plan for 2007-2011, providing programs to improve employee health and safety and increasing diversity in employee recruitment and retention.
Mr. Selover’s 2006 MICP award was $356,250. Mr. Selover had five performance goals for 2006, with the preponderance related to legal support of the merger preparation and integration planning processes. His other goals related to support for maintaining the business of PSEG on a stand alone basis in event of a merger termination; restart of operations on merger termination and improving quality of the legal and environmental services to the operating companies.
Mr. Busch’s 2006 MICP award was $303,750. Mr. Busch had two performance goals for 2006, both related to the performance of Services. The first related to maintaining the day-to-day operations, including staffing levels, of Services during the merger integration process to enable it to support the operating companies effectively. The second was to demonstrate, through client surveys, improvements in accuracy, responsiveness, innovation and value of the services provided to the operating companies.
Ms. Rado’s 2006 MICP award was $149,600. Ms. Rado had two performance goals for 2006. The first related to maintaining the design and integrity of PSEG’s financial systems and processes during the
merger integration process. The second related to alignment of PSEG’s purchase accounting and accounting policy systems in anticipation of the merger close.
Mr. LaRossa’s 2006 MICP award was $176,400. Mr. LaRossa had four performance goals for 2006, each related to the operations of PSE&G. One related to customer satisfaction as measured by customer survey responses; another related to workforce safety as measured by OSHA incident results; a third related to reliability of electric service measured by scores on availability indices and the last related to managing capital and O&M expenditures with target levels of $362.7 million for capital expenditures and $295.2 million for O&M expenditures.
LTIP
As discussed in the Compensation Discussion and Analysis, no LTIP awards were made to NEOs in 2006, except for an award of 3,125 shares of restricted stock to Mr. Izzo upon his election as President and COO of PSEG in October 2006. The award was determined based on the proportionate difference between the restricted stock award he received in December 2005 as President and COO of PSE&G and the award he would have received had he been President and COO of PSEG at that time.
While no Performance Unit Awards were made during 2006, the performance measurement period with respect to Performance Unit Awards granted by the Committee in 2004 was completed on December 31, 2006. Under the terms of the award grants, award recipients were eligible to receive 100% of their grant amount if, for the three-year performance period ending on December 31, 2006, (a) PSEG’s Total Shareholder Return (TSR) placed it within the third quintile of the companies within the DJUI and (b) PSEG’s ROE was within one percent (1%) of the ROE of the DJUI. For performance above or below these levels, the final award could be increased to as much as 200% of the grant amount (TSR in the first quintile and ROE more than 3% above the DJUI) decreased to as little as zero.
See the Option Exercises and Stock Vested During 2006 Table, below, for a list of the NEOs’ target awards. As of the date of this Proxy Statement, the comparative data necessary to calculate comparative performance and final award amounts was not yet available.
Employment Agreements
PSEG entered into an employment agreement dated as of June 16, 1998 and amended as of November 20, 2001 with Mr. Ferland (together, the Ferland Employment Agreement) covering his employment as Chief Executive Officer through March 31, 2007. The Ferland Employment Agreement provides that Mr. Ferland will be renominated for election as a director during his employment thereunder. The Ferland Employment Agreement also provides that Mr. Ferland’s base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices for CEOs of similar companies and that his annual salary will not be reduced during its term. The Ferland Employment Agreement also provided for an award to him of 150,000 shares of restricted Common Stock as of June 16, 1998 and 60,000 shares of restricted Common Stock as of November 20, 2001, with 60,000 shares vesting in 2002; 20,000 shares vesting in 2003; 30,000 shares vesting in 2004; 40,000 shares vesting in 2005; 30,000 shares vesting in 2006; and 30,000 shares vesting in 2007. The Ferland Employment Agreement provides for the granting of 22 years of pension credit for Mr. Ferland’s prior experience, which was awarded at the time of his initial employment.
When Mr. Ferland retires at the end of his term of employment on March 31, 2007, he will be fully vested in any outstanding shares of restricted stock and any other equity awards he received as a long-term incentive award, and he will be paid any previously deferred compensation. He will not receive any special severance payments on retirement.
PSEG entered into an employment agreement with Mr. Izzo dated October 18, 2003, covering his employment as President and COO of PSE&G and in other executive positions to which he may be elected through October 18, 2008. The agreement provides that his base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices of similar companies and that annual salary will not be reduced during its term, and awarded him options with respect to 250,000 shares of Common Stock, 50,000 of which vest on each October 18 from 2004 through 2008, and expire on October 18, 2013, provided he has remained continuously employed through each such vesting date.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END (12/31/06) TABLE
OPTION EXERCISES AND STOCK VESTED DURING 2006 TABLE
Represents: (i) the aggregate number of shares acquired from the vesting of restricted stock awards under the LTIP and (ii) the aggregate number of performance units granted under the LTIP which vested on 12/31/06 at the completion of the three-year performance cycle applicable to such awards as follows:
The value attributable to the vested restricted stock is based on the closing price of the Common Stock on the respective date(s) that the shares vested and the value attributable to the vested performance units is based upon the closing price of the Common Stock on December 29, 2006. These amounts are:
a
Amounts shown represent the number and value of target awards, since the final comparative performance data necessary to calculate the final award amounts is not expected to be available until late March 2007.
PENSION BENEFITS TABLE
All NEOs participate in either a traditional defined benefit pension plan (pension plan) or a cash balance pension plan (cash balance plan) (depending on date of hire), each of which is a qualified plan under the IRC. Such plans are available to all other employees under the same terms and conditions. Messrs. Ferland, Izzo, Selover and Ms. Rado participate in the pension plan. Mr. Busch participates in the cash balance plan.
Certain employees receive additional years of credited service for the purpose of retirement benefit calculations in recognition of prior work experience before joining employment, including 22 years for Mr. Ferland and 15 years for Mr. Busch.
Amounts shown represent actuarial present value of accumulated benefit computed as of the same pension plan measurement date used for PSEG’s financial statements for the year ended December 31, 2006, with two exceptions: (i) NEOs were assumed to retire at the earliest point at which the benefits were payable on an unreduced basis in the plan providing the largest target benefit and (ii) no pre- retirement termination, disability or death was assumed to occur. For a discussion of the valuation method and material assumptions applied in quantifying the present value, see Note 16 to Notes to Financial Statements in this Form 10-K.
The actuarial present value of accumulated benefits based on actual years of service is $2,112,000 and the actuarial present value of accumulated benefits based on additional years of service is $1,264,000.
Qualified Pension Plans
All employees are eligible to participate in either a traditional defined benefit pension plan (pension plan) or a cash balance pension plan (cash balance plan). The pension plan covers employees hired prior to January 1, 1996 and provides participants with a life annuity benefit at normal retirement (age 65) pursuant to a formula based upon (a) the participant’s number of years of service and (b) the average of the participant’s five highest years of compensation after 12/31/94 up to the limit imposed by the IRC.
The benefit formula is A + B + C:
A
=
1.3% of the lesser of 5-year final average earnings not in excess of $24,600 times years of credited service not exceeding 35 years,
B
=
1.5% of the amount by which 5-year final average earnings exceeds $24,600 times years of credited service not exceeding 35 years,
C
=
1.5% of 5-year final average earnings times years of credited service in excess of 35 years.
An additional benefit equal to $4.00 per month for each year of credited service is payable until the retiree reaches age 65.
Participants become fully vested in their pension plan benefit upon completion of five years of service. Benefits are payable on an unreduced basis (i) at age 65, (ii) at age 60, if the participant’s age, plus years of service, equals or exceeds 80 or (iii) at age 55, if the participant has 25 or more years of service. Participants whose age, plus years of service, equals or exceeds 80, but who are not yet age 55, may commence their pension plan benefits on a reduced basis. Messrs. Ferland, and Selover are currently eligible for early retirement under the pension plan. Mr. Ferland will retire on March 31, 2007. Mr. Busch and Ms. Rado retired in January 2007.
The cash balance plan covers employees hired or rehired on or after January 1, 1996 and provides each participant with a life annuity benefit at normal retirement (age 65) equal to the actuarial equivalent of a notational amount maintained for him/her. Participants are eligible for retirement under the cash balance plan upon the attainment of age 55 with five or more years of service. Participants’ accounts are credited each year with a percentage of compensation, which is determined based on the participant’s age plus years of service measured at year-end.
Each participant’s notional amount grows each year with interest credits based on a 6.0% annual rate of interest. Participants become fully vested in their cash balance plan benefit upon completion of five years of service.
Reinstatement Plan
All employees are eligible to participate in a non-qualified supplemental retirement plan, the Retirement Income Reinstatement Plan for Non-Represented Employees (Reinstatement Plan), designed to replace earned pension benefits as determined by the qualified pension formula, but which are not eligible for payment from the qualified pension plans as a result of IRC mandated limits for qualified plans. The benefits payable under this plan mirror those of the qualified plans described above except that the compensation considered in computing the benefit (i) will not be limited by qualified plan limits, (ii) will include any amounts that the participant may have deferred under deferred compensation plans, (iii) will include amounts earned under MICP (which are not considered under the qualified pension plans), (iv) will be limited to 150% of average base salary for the applicable five years and (v) will be offset by any benefits received by the participant under the qualified plan.
Mid-Career Plan
Certain employees receive additional years of service for the purpose of retirement benefit calculations in recognition of prior work experience. Such benefits are paid from a non-qualified plan, the Mid-Career Hire Supplemental Retirement Income Plan (Mid-Career Plan). Under the Mid-Career Plan, certain participants, including the NEOs, receive an additional five years of credited service for the purpose of pension benefit calculations if they retire between ages 60 and 65. The credited years of service reduce by one year for each six-month period such participant works beyond age 65. This feature of the plan is designed to encourage retirement on or before age 65. Benefits payable under the Mid-Career Plan mirror those payable under the Reinstatement Plan, except that the additional years of service are considered in calculating the amount of benefit. Any benefit payable under this plan is offset by benefits payable under the qualified plan and the Reinstatement Plan.
Limited Plan
Certain employees, including the NEOs, participate in a limited non-qualified supplemental retirement plan, the Limited Supplemental Benefits Plan for Certain Employees (Limited Plan). This plan seeks to provide a total target replacement income percentage equal to credited service for qualified pension calculation purposes, Mid-Career Plan calculation purposes plus 30 to a maximum of 75%. Compensation covered for the Limited Plan is the same as for the Mid-Career Plan. The target replacement amount under the Limited Plan is reduced by any pension benefits accrued and vested from a previous employer at the time of hire, by the participant’s Social Security benefit at normal retirement age and by the pension benefits provided by each other PSEG retirement benefit plan (qualified plans and non-qualified plans). The Limited Plan also provides a death benefit equal to 150% of base compensation if death occurs while the participant is actively employed. Participants become entitled to a Limited Plan benefit only upon (a) retirement under the terms of the qualified plan in which they participate (pension plan or cash balance plan) or (b) death, at which point the benefit is payable as an annuity on an unreduced basis.
NON-QUALIFIED DEFERRED COMPENSATION TABLE
Deferred Compensation Plan
Under the PSEG’s Deferred Compensation Plan for Certain Employees (Deferred Compensation Plan), participants, including the NEOs, may elect to defer any portion of their compensation by making appropriate elections in the calendar year prior to the year in which the services giving rise to the compensation being deferred is rendered. For performance-based compensation, elections may be made up to the date that is six months before the end of the related performance period, as long as a) the performance period is at least 12 months in length, b) the participant performed services continuously from the date the performance criteria were established through the date the deferral election is made and c) at the time the deferral election is made, the performance-based compensation is not both i) substantially certain to be paid and ii) readily ascertainable. A participant may change an election to defer compensation not later than the date that is the last date that an election to defer may be made.
At the same time he/she elects to defer compensation, the participant must make an election as to the timing and the form of distribution from his/her Deferred Compensation Plan account. Distributions may commence (a) on the thirtieth day after the date he/she terminates employment or, in the alternative, (b) on January 15th of any calendar year following termination of employment elected by him/her, but in any event no later than the later of (i) the January of the year following the year of his/her 70th birthday or (ii) the January following termination of employment. Notwithstanding the forgoing, however, for NEOs, distribution of his/her account may not occur earlier than six months following the date of his/her
termination of service. Participants may elect to receive the distribution of their Deferred Compensation account in the form of (x) one lump-sum payment, (y) annual distributions over a five-year period or (z) annual distributions over a 10-year period.
Participants may make changes of distribution elections on a prospective basis. Participants may also make changes of distribution elections with respect to prior deferred compensation as long as (a) any such new distribution election is made at least one year prior to the date that the commencement of the distribution would otherwise have occurred and (b) the revised commencement date is at least five years later than the date that the commencement of the distribution would otherwise have occurred.
Amounts deferred under the Deferred Compensation Plan are credited with earnings based on (a) the performance of one or more of the life style investment funds or the S&P 500 Fund available to employees under PSEG’s 401K Plans or (b) at the rate of Prime plus 1/2%, in such percentages as selected by the participant. A participant who fails to provide a designation of investment funds will accrue earnings on his/her account at the rate of Prime plus 1/2%.
POTENTIAL PAYMENTS UPON TERMINATION OF EMPLOYMENT
OR CHANGE-IN-CONTROL
The employment agreements of Messrs. Ferland and Izzo discussed above each provide for certain severance benefits. Each of these agreements provides that if the individual is terminated without “cause” (a willful failure to perform his duties) or resigns for “good reason” (a reduction in pay, position or authority) during the term of such agreement, the respective entire restricted stock award and/or entire option award becomes vested, the individual will be paid a benefit of two times base salary and target bonus, and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a “change in control” (as defined below), the payment to the individual becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years unless sooner reemployed, payment of the net present value of providing three years additional service under our retirement plans and a gross-up for excise taxes due under the IRC on any termination payments. Each of the agreements provides that the individual is prohibited for one year (two years for Mr. Ferland) from competing with and for two years from recruiting employees from us or its subsidiaries or affiliates, after termination of employment. Violations of these provisions require a forfeiture of the respective restricted stock and option grants and certain benefits.
PSEG’s Key Executive Severance Plan provides severance benefits to Messrs. Selover and LaRossa and, prior to their retirements, Mr. Busch and Ms. Rado and to certain of our key executive-level employees whose employment is terminated without cause after a Change in Control.
Under the Key Executive Severance Plan, if Mr. Selover and Mr. LaRossa are terminated without cause or resign their employment for good reason within two years after a change in control, they will receive (1) a pro rata bonus based on their respective target annual incentive compensation, (2) three times the sum of their salary and target incentive bonus, (3) accelerated vesting of equity-based awards, (4) a lump sum payment equal to the actuarial equivalent of their benefits under all of our retirement plans in which they participate calculated as though the participant remained employed for three years beyond the date their employment terminates less the actuarial equivalent of such benefits on the date their employment terminates, (5) three years continued welfare benefits (the first 18 months of which will be provided through PSEG-paid COBRA continuation coverage), (6) one year of PSEG-paid outplacement services and (7) vesting of any compensation previously deferred. Similar provisions applied to Mr. Busch and Ms. Rado prior to their respective retirements.
Messrs. Selover and LaRossa also participate in PSEG’s Separation Allowance Benefit Plan for Non-Represented Employees (Separation Allowance Plan) which provides certain severance benefits to non-represented employees who suffer a termination of employment as a result of a reduction in force or reorganization. Under the Separation Allowance Plan, key managers, including Messrs. Selover and LaRossa, are entitled to two weeks of base salary for each year of service, with a minimum of 26 weeks and a maximum of 52 weeks of base salary, as well as a prorated payment of their target incentive award and certain outplacement services, educational assistance, health care and life insurance coverage. Similar provisions applied to Mr. Busch and Ms. Rado until their respective retirements.
If a termination without cause, with good reason or for a reduction in force or reorganization had occurred on December 31, 2006, each of the NEOs would have received the following benefits:
If a termination without cause or with good reason had occurred on December 31, 2006 following a change in control, each of the NEOs would have received the following benefits:
When Mr. Busch and Ms. Rado retired in January 2007, neither received a severance benefit under these plans.
Change in Control under the Employment Agreements of Messrs. Ferland and Izzo and under the Key Executive Severance Plan generally means the occurrence of any of the following events:
(a) any person is or becomes the beneficial owner of our securities representing 25% or more of the combined voting power of PSEG’s then outstanding securities; or
(b) a majority of PSEG’s Board of Directors is replaced without approval of the current Board; or
(c) there is consummated a merger or consolidation of PSEG, other than a merger or consolidation which would result in PSEG’s voting securities outstanding immediately prior to such merger continuing to represent at least 75% of the combined voting power of the securities of PSEG or such surviving entity immediately after such merger or consolidation; or
(d) PSEG’s shareholders approve a plan of complete liquidation or dissolution of us or there is consummated an agreement for the sale or disposition by us of all or substantially all of PSEG’s assets.
DIRECTOR COMPENSATION TABLE1
PSE&G is a wholly-owned subsidiary of PSEG. PSE&G’s directors consist of five persons who are also directors of PSEG: Ms. Dorsa, and Messrs. Ferland, Gamper, Harper and Izzo. Messrs. Ferland and Izzo are employees and are not paid any fees as directors. Ms. Dorsa and Messrs. Gamper and Harper are paid a retainer and meeting fees as PSEG directors and do not receive an additional retainer as directors of PSE&G. The amounts shown below include the fees paid to each as PSEG directors.
Includes all meeting fees, chair/committee retainer fees and cash portion ($25,000) of the annual retainer. During 2006, each director who was not an officer of us or our subsidiaries and affiliates was paid an annual retainer of $50,000 and a fee of $1,500 for attendance at any Board or committee meeting, inspection trip, conference or other similar activity relating to us or PSE&G. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, as determined by the Board, fifty percent during 2006, of the annual retainer is paid in shares of Common Stock. Each Committee Chair received an additional annual retainer of $5,000, except for the Chair of the Audit Committee, who received $10,000. In addition, each member of the Audit Committee received an additional annual retainer of $5,000.
Includes a payment of the number of shares of Common Stock equal to $25,000, the fair value computed in accordance with FAS 123R, the stock portion of the annual retainer. Also includes the grant date fair value computed in accordance with FAS 123R of 1,000 shares granted under the Stock Plan for Outside Directors, pursuant to which directors who are not employees of us or our subsidiaries receive shares of restricted stock for each year of service as a director. For 2006, this amount was 1,000 shares.
The restrictions on the shares of Common Stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 72nd birthday. This restriction would be deemed to
have been satisfied if the director’s service were terminated after a change in control as defined in the Plan or if the director were to die in office. The Plan’s administrative committee (comprised of the directors who do not participate in the plan) has the ability to waive these restrictions for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares of Common Stock held subject to restrictions are paid directly to the director and the director has the right to vote the shares of Common Stock. In November 2006, the Committee recommended changes to the Directors Restricted Stock Plan, to provide that grants would be made on May 1 of each year, rather than on the first business day following the Annual Meeting, and to reflect the change from age 70 to age 72 in the mandatory retirement age for Directors previously made by the Board. The Board subsequently approved these changes. Subsequently, the Board, based on the recommendation of the Organization and Compensation Committee, determined to replace the Directors’ Stock Plan with a new equity compensation plan for outside directors.
Includes interest earned under the Directors’ Deferred Compensation Plan at Prime plus 1/2% to the extent that it exceeds 120% of the applicable Federal long-term rate. The directors do not participate in a PSEG-sponsored pension plan.
Directors’ Deferred Compensation Plan
Under PSEG’s Deferred Compensation Plan for Directors (Directors’ Deferred Compensation Plan), directors who are not employees may elect to defer any portion of their retainer and meeting attendance fees by making appropriate elections in the calendar year prior to the year in which the services giving rise to the compensation being deferred is rendered. A participant may change an election to defer compensation not later than the date that is the last date that an election to defer may be made.
At the same time he/she elects to defer compensation, the participant must make an election as to the timing and the form of distribution from his/her Directors’ Deferred Compensation Plan account. Distributions may commence (i) on the thirtieth day after the date he/she terminates service as a director or, in the alternative, (ii) on January 15th of any calendar year following termination of service elected by the him/her, but in any event no later than the later of (A) the January of the year following the year of the his/her 71st birthday or (B) the January following termination of service. Participants may elect to receive the distribution of their Directors’ Deferred Compensation account in the form of (i) one lump-sum payment, (ii) annual distributions over a period selected by the participant, up to 10 years.
Participants may make changes of distribution elections on a prospective basis. Participants may also make changes of distribution elections with respect to prior deferred compensation as long (A) any such new distribution election is made at least one year prior to the date that the commencement of the distribution would otherwise have occurred and (B) the revised commencement date is at least five years later than the date that the commencement of the distribution would otherwise have occurred.
Amounts deferred under the Directors’ Deferred Compensation Plan are credited with earnings based on (i) the performance of one or more of the lifestyle investment funds or the S&P 500 fund available to employees under PSEG’s 401K Plans, (ii) at the rate of Prime plus 1/2% or (iii) by reference to the performance of the Common Stock, in such percentages designated by the participant. A participant who fails to provide a designation will accrue earnings on his/her account at the rate of Prime plus 1/2%.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
PSE&G does not have a compensation committee. Decisions regarding compensation of PSE&G’s executive officers are made by the Organization and Compensation Committee of PSEG. During 2006, each of the following individuals served as a member of the Organization and Compensation Committee: Shirley Ann Jackson, Chair, Ernest H. Drew, Conrad K. Harper, William V. Hickey and Thomas A. Renyi. During 2006, no member of the Organization and Compensation Committee was an officer or employee or a former officer or employee of any PSEG company. No PSEG officer served as a director of or on the compensation committee of any of the companies for which any of these individuals served as an officer.
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
PSEG
The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the 2007 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 5, 2007, and such information set forth under such heading is incorporated herein by this reference thereto.
For information relating to securities authorized for issuance under equity compensation plans, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
PSE&G
The following table sets forth, as of February 19, 2007, beneficial ownership of PSEG Common Stock, including options, by the directors and executive officers named in PSE&G’s Summary Compensation table. None of these amounts exceeds 1% of the Common Stock outstanding.
Certain Beneficial Owners
The following table sets forth, as of February 19, 2007, beneficial ownership by any person or group known to us to be the beneficial owner of more than five percent of Common Stock. According to the Schedules 13G filed by these owners with the SEC, these securities were acquired and are held in the ordinary course of business and not for the purpose of changing or influencing the control of PSEG.
Section 16 Beneficial Ownership Reporting Compliance
During 2006, none of our directors or executive officers was late in filing a Form 3, 4 or 5 in accordance with the requirements of Section 16(a) of the Securities Exchange Act of 1934, as amended, with regard to transactions involving Preferred Stock.
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PSEG
The information required by Item 13 of Form 10-K is set forth under the heading “Transactions with Related Persons” in PSEG’s definitive Proxy Statement for the 2007 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the (SEC) on or about March 5, 2007. Such information set forth under such heading is incorporated herein by this reference thereto.
PSE&G
Transactions with Related Persons
Except as stated below, there were no transactions during 2006, and there are no transactions currently proposed, in which PSE&G was or is to be a participant and the amount involved exceeded $120,000 and in which any related person (director, nominee, executive officer, or their immediate family members) had or will have a direct or indirect material interest.
Thomas A. Renyi, a director of PSEG and a member of the Organization and Compensation Committee, is Chairman of the Board and CEO of The Bank of New York (BONY), a participant in three credit facilities of PSEG and its subsidiaries, including PSE&G. Each of these facilities, and BONY’s participation, was made in the ordinary course of business, on substantially the same terms, including interest rates and collateral, as those prevailing at the time for comparable loans with persons not related to BONY, and did not involve more than the normal risk of collectibility or present other unfavorable features.
PSE&G’s policies and procedures with regard to transactions with related parties, including the review, approval or ratification of any such transactions, the standards applied and the responsibilities for application are set forth in the Corporate Governance Principles and the Standards of Integrity, discussed above.
Director Independence
As determined by the Board, all current PSE&G directors, with the exception of E. James Ferland, Chairman of the Board and CEO, and Ralph Izzo, President and COO of PSEG, are independent under the requirements of the SEC and the NYSE. This determination was based on a review of the questionnaires submitted by each director, PSE&G’s relevant business records, publicly available information and applicable SEC and NYSE requirements.
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed to PSEG by Deloitte & Touche LLP for 2006 and 2005” in PSEG’s definitive Proxy Statement for the 2007 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 5, 2007. Such information set forth under such heading is incorporated herein by this reference thereto.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
LIST OF EXHIBITS:
a.
PSEG:
3a
Certificate of Incorporation Public Service Enterprise Group Incorporated1
3b
By-Laws of Public Service Enterprise Group Incorporated as in effect May 16, 20052
3c
Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 19873
3d
Amended and Restated Trust Agreement for Enterprise Capital Trust I4
3e
Amended and Restated Trust Agreement for Enterprise Capital Trust II5
3f
Amended and Restated Trust Agreement for Enterprise Capital Trust III6
3g
Amended and Restated Trust Agreement for PSEG Funding Trust I7
3h
Amendment No. 1 to Amended and Restated Trust Agreement for PSEG Funding Trust I8
3i
Amended and Restated Trust Agreement for PSEG Funding Trust II9
4a(1)
Indenture between Public Service Enterprise Group Incorporated and First Union National Bank (US Bank National Association, successor), as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)10
4a(2)
First Supplemental Indenture to Indenture dated as of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (US Bank National Association, successor), as Trustee, dated June 1, 1998 providing for the issuance of Floating Rate Deferrable Interest Subordinated Debentures, Series B (relating to Trust Preferred Securities)11
4a(3)
Second Supplemental Indenture to Indenture dated as of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (US Bank National Association, successor), as Trustee, dated July 1, 1998 providing for the issuance of Deferrable Interest Subordinated Debentures, Series C (relating to Trust Preferred Securities)12
4b
Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (US Bank National Association, successor) providing for the issuance of Senior Debt Securities13
4c
First Supplemental Indenture to Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association (US Bank National Association, successor), as Trustee, dated September 10, 2002 providing for the issuance of Senior Deferrable Notes (Senior Debt Securities)14
4d
Second Supplemental Indenture to Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association (US Bank National Association, successor), as Trustee, dated July 27, 200515
4e
Indenture dated as of December 17, 2002 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association (US Bank National Association, successor), providing for the issuance of Debentures in Series including 8.75% Deferrable Interest Junior Subordinated Debentures, Series D16
Inapplicable
10a(1)
Deferred Compensation Plan for Directors85
10a(2)
Deferred Compensation Plan for Certain Employees86
10a(3)
Amended and Restated Limited Supplemental Benefits Plan for Certain Employees87
10a(4)
Mid Career Hire Supplemental Retirement Income Plan88
10a(5)
Retirement Income Reinstatement Plan for Non-Represented Employees89
10a(6)
1989 Long-Term Incentive Plan, as amended17
10a(7)
2001 Long-Term Incentive Plan18
10a(8)
Restated and Amended Management Incentive Compensation Plan19
10a(9)
Employment Agreement with E. James Ferland dated June 16, 199820
10a(10)
Amendment to Employment Agreement with E. James Ferland dated November 20, 200121
10a(11)
Second Amendment to Employment Agreement with E. James Ferland dated December 20, 200422
10a(12)
Employment Agreement with Thomas M. O’Flynn dated April 18, 200123
10a(13)
Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 200124
10a(14)
Key Executive Severance Plan94
10a(15)
Employment Agreement with Ralph Izzo dated October 18, 200326
10a(16)
Stock Plan for Outside Directors, as amended27
10a(17)
Employment Agreement with Robert E. Busch dated April 24, 200128
10a(18)
Employee Stock Purchase Plan29
10a(19)
Compensation Plan for Outside Directors30
10a(20)
2004 Long-Term Incentive Plan31
10a(21)
Retention Program for Key Employees32
10b(1)
Agreement and Plan of Merger33
10b(2)
Operating Services Contract34
Inapplicable
Computation of Ratios of Earnings to Fixed Charges
Inapplicable
Code of Ethics84
Inapplicable
Inapplicable
Subsidiaries of the Registrant
Inapplicable
Consent of Independent Registered Public Accounting Firm
Inapplicable
31a
Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act
31b
Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act
32a
Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32b
Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
b.
PSE&G:
3a(1)
Restated Certificate of Incorporation of PSE&G35
3a(2)
Certificate of Amendment of Certificate of Restated Certificate of Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act36
3a(3)
Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock37
3a(4)
Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock38
3a(5)
Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed January 27, 1995 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock-$25 Par as series of Preferred Stock39
3b(1)
By-Laws of PSE&G40
4a(1)
Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924, securing First and Refunding Mortgage Bond41 Indentures between PSE&G and First Fidelity Bank, National Association (US Bank National Association, successor), as Trustee, supplemental to Exhibit 4a(1), dated as follows:
4a(2)
April 1, 192742
4a(3)
June 1, 193743
4a(4)
July 1, 193744
4a(5)
December 19, 193945
4a(6)
March 1, 194246
4a(7)
June 1, 1991 (No. 1)47
4a(8)
July 1, 199348
4a(9)
September 1, 199349
4a(10)
February 1, 199450
4a(11)
March 1, 1994 (No. 2)51
4a(12)
May 1, 199452
4a(13)
October 1, 1994 (No. 2)53
4a(14)
January 1, 1996 (No. 1)54
4a(15)
January 1, 1996 (No. 2)55
4a(16)
May 1, 199856
4a(17)
September 1, 200257
4a(18)
August 1, 200358
4a(19)
December 1, 2003 (No. 1)59
4a(20)
December 1, 2003 (No. 2)60
4a(21)
December 1, 2003 (No. 3)61
4a(22)
December 1, 2003 (No. 4)62
4a(23)
June 1, 200463
4a(24)
August 1, 2004 (No. 1)64
4a(25)
August 1, 2004 (No. 2)65
4a(26)
August 1, 2004 (No. 3)66
4a(27)
August 1, 2004 (No. 4)67
4b
Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (The Bank of New York, successor), as Trustee, providing for Secured Medium-Term Notes dated July 1,
4c
Indenture dated as of December 1, 2000 between Public Service Electric and Gas Company and First Union National Bank (US Bank National Association, successor), as Trustee, providing for Senior Debt Securities69
10a(1)
Deferred Compensation Plan for Directors85
10a(2)
Deferred Compensation Plan for Certain Employees86
10a(3)
Amended and Restated Limited Supplemental Benefits Plan for Certain Employees87
10a(4)
Mid Career Hire Supplemental Retirement Income Plan88
10a(5)
Retirement Income Reinstatement Plan for Non-Represented Employees89
10a(6)
1989 Long-Term Incentive Plan, as amended17
10a(7)
2001 Long-Term Incentive Plan18
10a(8)
Restated and Amended Management Incentive Compensation Plan19
10a(9)
Employment Agreement with E. James Ferland, dated June 16, 199820
10a(10)
Amendment to Employment Agreement with E. James Ferland dated November 20, 200121
10a(11)
Second Amendment to Employment Agreement with E. James Ferland dated December 20, 200422
10a(12)
Key Executive Severance Plan95
10a(13)
Employment Agreement with Ralph Izzo dated October 18, 200326
10a(14)
Employment Agreement with Robert E. Busch dated April 24, 200126
10a(15)
Employee Stock Purchase Plan29
10a(16)
Stock Plan for Outside Directors, as amended27
10a(17)
Compensation Plan for Outside Directors30
10a(18)
2004 Long-Term Incentive Plan31
10a(19)
Retention Program for Key Employees32
Inapplicable
12a
Computation of Ratios of Earnings to Fixed Charges
12b
Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements
Inapplicable
Code of Ethics84
Inapplicable
Inapplicable
Inapplicable
21a
Inapplicable
23a
Consent of Independent Registered Public Accounting Firm
Inapplicable
31c
Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act
31d
Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act
32c
Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32d
Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
c.
Power:
3a
Certificate of Formation of PSEG Power LLC70
3b
PSEG Power LLC Limited Liability Company Agreement71
3c
Trust Agreement for PSEG Power Capital Trust I72
3d
Trust Agreement for PSEG Power Capital Trust II73
3e
Trust Agreement for PSEG Power Capital Trust III74
3f
Trust Agreement for PSEG Power Capital Trust IV75
3g
Trust Agreement for PSEG Power Capital Trust V76
4a
Indenture dated April 16, 2001 between and among PSEG Power, PSEG Fossil, PSEG Nuclear, PSEG Energy Resources & Trade and The Bank of New York and form of Subsidiary Guaranty included therein77
4b
First Supplemental Indenture, supplemental to Exhibit 4a, dated as of March 13, 200278
10a(1)
Deferred Compensation Plan for Certain Employees90
10a(2)
Amended and Restated Limited Supplemental Benefits Plan for Certain Employees91
10a(3)
Mid Career Hire Supplemental Retirement Income Plan92
10a(4)
Retirement Income Reinstatement Plan for Non-Represented Employees93
10a(5)
1989 Long-Term Incentive Plan, as amended17
10a(6)
2001 Long-Term Incentive Plan18
10a(7)
Restated and Amended Management Incentive Compensation Plan19
10a(8)
Employment Agreement with E. James Ferland, dated June 16, 199820
10a(9)
Amendment to Employment Agreement with E. James Ferland dated November 20, 200121
10a(10)
Second Amendment to Employment Agreement with E. James Ferland dated December 20, 200422
10a(11)
Employment Agreement with Thomas M. O’Flynn dated April 18, 200123
10a(12)
Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 200124
10a(13)
Key Executive Severance Plan96
10a(14)
Employee Stock Purchase Plan29
10a(15)
2004 Long-Term Incentive Plan31
10a(16)
Retention Program for Key Employees32
10b(1)
Operating Services Contract34
Inapplicable
12c
Computation of Ratio of Earnings to Fixed Charges
Inapplicable
Code of Ethics84
Inapplicable
Inapplicable
Inapplicable
Consent of Independent Registered Public Accounting Firm
Inapplicable
31e
Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act
31f
Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act
32e
Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32f
Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
d.
Energy Holdings:
3a
Certificate of Formation of PSEG Energy Holdings L.L.C.79
3b
Certificate of Amendment to Certificate of Formation of PSEG Energy Holdings L.L.C.80
3c
Limited Liability Company Agreement of PSEG Energy Holdings L.L.C.80
4a
Indenture dated October 8, 1999 between Energy Holdings and First Union National Bank (US Bank National Association, successor)82
4b
First Supplemental Indenture to Exhibit 4a between Energy Holdings and Wachovia Bank, National Association (US Bank National Association, successor) dated September 30, 200283
10a(1)
Deferred Compensation Plan for Certain Employees90
10a(2)
Amended and Restated Limited Supplemental Benefits Plan for Certain Employees91
10a(3)
Mid Career Hire Supplemental Retirement Income Plan92
10a(4)
Retirement Income Reinstatement Plan for Non-Represented Employees93
10a(5)
1989 Long-Term Incentive Plan, as amended17
10a(6)
2001 Long-Term Incentive Plan18
10a(7)
Restated and Amended Management Incentive Compensation Plan19
10a(8)
Employment Agreement with E. James Ferland, dated June 16, 199820
10a(9)
Amendment to Employment Agreement with E. James Ferland dated November 20, 200121
10a(10)
Second Amendment to Employment Agreement with E. James Ferland dated December 20, 200422
10a(11)
Employment Agreement with Thomas M. O’Flynn dated April 18, 200123
10a(12)
Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 200124
10a(13)
Employee Stock Purchase Plan29
10a(14)
2004 Long-Term Incentive Plan31
10a(15)
Key Executive Severance Plan97
10a(16)
Retention Program for Key Employees32
Inapplicable
12d
Computation of Ratios of Earnings to Fixed Charges
Inapplicable
Code of Ethics84
Inapplicable
Inapplicable
Inapplicable
31g
Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act
31h
Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act
32g
Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
32h
Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
SCHEDULE II
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Schedule II-Valuation and Qualifying Accounts
Years Ended December 31, 2006-December 31, 2004
(A)
Accounts Receivable/Investments written off.
(B)
Reduced reserve to appropriate level and to remove obsolete inventory.
(C)
Includes various liquidity, credit and bad debt reserves.
(D)
Valuation allowances reversed in connection with PSEG Energy Technologies Asset Management Company LLC (PETAMC) Accounts Receivable settlement.
(E)
Recorded $10 million in connection with the sales of certain properties held by Enterprise Group Development Corporation (EGDC), in 2004.
(F)
Recorded in 2004 to reduce the carrying value of the Collins Lease by $17 million.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Schedule II-Valuation and Qualifying Accounts
Years Ended December 31, 2006-December 31, 2004
PSEG POWER LLC
Schedule II-Valuation and Qualifying Accounts
Years Ended December 31, 2006-December 31, 2004
(A)
Reduced reserve to appropriate level and removed obsolete inventory.
(B)
Includes various liquidity, credit and bad debt reserves.
PSEG ENERGY HOLDINGS L.L.C.
Schedule II-Valuation and Qualifying Accounts
Years Ended December 31, 2006-December 31, 2004
(A)
Valuation allowances reversed in connection with PETAMC Accounts Receivable settlement.
(B)
Recorded in 2004 to reduce the carrying value of the Collins Lease by $17 million.
(C)
Recorded $10 million in connection with the sales of certain properties held by EGDC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
By:
/s/ RALPH IZZO
Ralph Izzo
President and
Chief Operating Officer
Date: February 27, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
By:
/s/ RALPH LAROSSA
Ralph LaRossa
President and
Chief Operating Officer
Date: February 27, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PSEG POWER LLC
By:
/s/ FRANK CASSIDY
Frank Cassidy
President and
Chief Operating Officer
Date: February 27, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PSEG ENERGY HOLDINGS L.L.C.
By:
/s/ THOMAS M. O’FLYNN
Thomas M. O’Flynn
President and
Chief Operating Officer
Date: February 27, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
EXHIBIT INDEX
The following documents are filed as a part of this report: