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Public Service Enterprise Group 10-K 2006 Documents found in this filing:
UNITED STATES FORM 10-K (Mark One) S ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005, OR £ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE FOR THE TRANSITION PERIOD FROM TO .
Securities registered pursuant to Section 12(b) of the Act:
5.381% Preferred Trust Securities, $50 liquidation amount per Preferred Trust Security, issued by PSEG Funding Trust I (Registrant) and listed on the New York Stock Exchange. Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG's Debentures), $25 par value at 8.75%, issued by PSEG Funding Trust II (Registrant) and listed on the New York Stock Exchange.
(Cover continued on next page)
(Cover continued from previous page) Securities registered pursuant to Section 12(g) of the Act: Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes £ No S Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes S No £ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. S Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No S The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2005 was $14,247,381,923 based upon the New York Stock Exchange Composite Transaction closing price. The number of shares outstanding of Public Service Enterprise Group Incorporated's sole class of Common Stock, as of the latest practicable date, was as follows: As of January 31, 2006, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated. PSEG Power LLC and PSEG Energy Holdings L.L.C. are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are filing their respective Annual Reports on Form 10-K with the reduced disclosure format authorized by General Instruction I. DOCUMENTS INCORPORATED BY REFERENCE—NONE
TABLE OF CONTENTS i
Page Item 9. Item 9A. Item 9B. Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. ii
Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. 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) undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The following review should not be construed as a complete list of factors that could effect forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: iii
PSEG, PSE&G and Energy Holdings PSEG, Power and Energy Holdings PSEG and Power PSEG and Energy Holdings Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, PSEG, PSE&G, Power and Energy Holdings or their respective business prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and Energy Holdings expressly disclaims any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur
or arise after the date hereof. In making any investment decision regarding PSEG's, PSE&G's, Power's and Energy Holdings' securities, PSEG, PSE&G, Power and Energy Holdings are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. iv
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) file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (SEC). You may read and copy any document that PSEG, PSE&G, Power and Energy Holdings file at the Public Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. You may also obtain PSEG's, PSE&G's, Power's and Energy Holdings' filings on the Internet at the SEC's website at www.sec.gov or at PSEG's website, www.pseg.com. PSEG's Common Stock
is listed on the New York Stock Exchange under the ticker symbol “PEG.” You can obtain information about PSEG at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005. This combined Annual Report on Form 10-K is separately filed by PSEG, PSE&G, Power and 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 makes representations only as to itself and its subsidiaries and makes no other representations whatsoever as to any other company. 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 was an exempt public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA) prior to its repeal. The Energy Policy Act of 2005 (Energy Policy Act), among other things, repealed PUHCA as of February 8, 2006 and enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005). PSEG is in the process of evaluating the compliance requirements under PUHCA 2005. 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): The regulatory structure that has historically governed the electric and gas utility industries in the United States (U.S.) has changed dramatically in recent years. Actions by state regulators and the Federal Energy Regulatory Commission (FERC) and the implementation of the National Energy Policy Act of 1992 have afforded power marketers, merchant generators, Exempt Wholesale Generators (EWGs) and utilities the opportunity to compete actively in wholesale energy markets and have allowed consumers the right to choose 1
their energy suppliers. The deregulation and restructuring of the nation's energy markets, the unbundling of energy and related services, the diverse strategies within the industry related to holding, building, buying or selling generation capacity and consolidation within the industry have had, and are likely to continue to have, a significant effect on PSEG and its subsidiaries, providing them with new opportunities and exposing them to new risks. As energy markets have changed dramatically in recent years, PSEG and its subsidiaries have transitioned from a vertically-integrated utility to an energy company with a diversified business mix. PSEG realigned its organizational structure to address the competitive environment brought about by the deregulation of the electric generation industry and evolved from primarily being a state-regulated New Jersey utility to operating as a competitive energy company with operations primarily in the Northeastern 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. PSEG seeks to reduce future volatility of earnings and cash flows principally by entering into longer-term contracts for material portions of its anticipated energy output. PSEG may also reduce exposure to its international businesses by seeking to opportunistically monetize investments of Energy Holdings that may no longer have a strategic fit. PSEG also expects a gradual decline in earnings from Resources' leveraged leasing business due to the maturation of its investment portfolio. For additional information, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A)—Overview of 2005 and Future Outlook. PENDING MERGER PSEG, PSE&G, Power and Energy Holdings 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, whereby PSEG will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG Common Stock will be converted into 1.225 shares of Exelon Common Stock. The Merger Agreement has been unanimously approved by both companies' Boards of Directors. On July 19, 2005, shareholders of PSEG voted to approve the Merger and on July 22, 2005, shareholders of Exelon voted to approve the issuance of common shares to PSEG shareholders to effect the Merger. Completion of the Merger is subject to approval by a number of governmental authorities, some of which have already been obtained. The authorities may impose conditions on completion of the Merger, require changes to the terms of the Merger or fail to approve the Merger. For additional information related to the Merger, see Item 3. Legal Proceedings, Item 7. MD&A—Pending Merger and Note 23. Pending Merger of the Notes to the Consolidated Financial Statements (Notes). PSE&G is a New Jersey corporation, incorporated in 1924, and has 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. PSE&G, pursuant to an order of the New Jersey Board of Public Utilities (BPU) issued under the provisions of the New Jersey Electric Discount and Energy Competition Act (EDECA), transferred all of its electric generation facilities, plant, equipment and wholesale power trading contracts to Power and its subsidiaries in August 2000 for approximately $2.8 billion. Also, pursuant to a BPU order, PSE&G transferred its gas supply business, including its inventories and supply contracts, to Power in May 2002 for approximately
$183 million. PSE&G continues to own and operate its electric and gas transmission and distribution business. 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 rights to receive certain non-bypassable amounts 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 2
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 franchise rights (including consents) necessary for its electric and gas distribution operations in the territory it serves. Such franchise rights are not exclusive. 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 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. 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. 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. New Jersey's Electric Distribution Companies (EDCs), including PSE&G, provide two types of Basic Generation Service (BGS). BGS is the default electric supply service for customers who do not choose a third party to source their electric supply requirements. BGS-Fixed Price (FP) provides supply for smaller commercial and residential customers at seasonally-adjusted fixed prices. BGS-FP rates change annually on June 1, and are based on the average BGS price obtained at auctions in the current year and two prior years. BGS-Commercial and Industrial Energy Price (CIEP) provides supply for larger customers at hourly PJM Interconnection, L.L.C. (PJM) real-time market prices for a term of 12 months. BGS-FP and BGS-CIEP represent approximately 84% and 16%, respectively, of PSE&G's BGS-eligible load. Customers
may obtain their electric supply through either the BGS default electric supply service or through competitive third-party electric suppliers. 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. PSE&G's total BGS-FP load is approximately 8,600 megawatts (MW). Approximately one-third of this total load is expected to be auctioned each year for a three-year term. The current pricing is as follows: Load (MW) $ per kWh 3
The February 2006 BGS-FP auction sought approximately one-third of PSE&G's BGS-FP eligible load (2,882 MW), since contracts for the other two-thirds were procured through the 2004 and 2005 auctions. The 2006 clearing price for PSE&G's BGS-FP load was 10.251 cents per kWh, an increase of approximately 57% over the 2005 auction price. The term of the supply period is from June 2006 through May 2009. Due to the stabilizing effect of the portfolio approach (blending this year's price with the prices set in the auctions in 2005 and 2004), residential customers' bills are expected to increase by approximately 14% beginning June 1, 2006. The 2006 BGS-CIEP auction was not fully subscribed. Of the 1,830 MW offered, only 1,153 MW, approximately 63%, was filled by BGS-CIEP suppliers for the period June 2006 through May 2007. Since nearly 85% of BGS-CIEP load has migrated to third party suppliers on a spot market basis, PSE&G expects its required supply obligation to be approximately 110 MW of BGS-CIEP load, although it could vary if migration amounts change in response to changing market prices. PSE&G expects to be able to meet this requirement. PSE&G has filed a contingency plan, which was approved by the BPU, which covered instances where the auction volume for either BGS-FP or BGS-CIEP was reduced. The process calls for those reduced volumes to be served by the EDC from PJM administered markets with full cost recovery from customers. However,
it is PSE&G's responsibility to carry out that obligation in a prudent manner to insure full cost recovery. PSE&G has a full requirements contract through 2007 with Power to meet the supply requirements of PSE&G's gas customers. Power charges PSE&G for gas commodity costs which PSE&G recovers from its customers. Any difference between rates charged by Power under the Basic Gas Supply Service (BGSS) contract and rates charged to PSE&G's customers are deferred and collected or refunded through adjustments in future rates. There has been a significant increase in commodity prices, including fuel, emission allowances and electricity over the past year. For example, both natural gas and electric prices in PJM have more than doubled. Price increases of this magnitude are much greater than have been experienced in recent history and could continue to have considerable impacts. For PSE&G, 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. 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. As of December 31, 2005, 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. Commercial Residential Industrial Total 4
As of December 31, 2005, PSE&G had 6,335 employees. PSE&G has six-year collective bargaining agreements, which were ratified in 2005, with four unions representing 5,043 employees. PSE&G believes that it maintains satisfactory relationships with its employees. 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, 2005, Power's generation portfolio consisted of approximately 13,846 MW of installed capacity which is diversified by fuel source and market segment. 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. Through its operating subsidiaries, Power competes as an independent wholesale electric generating company, primarily in the Northeast U.S. Most of Power's generating assets are strategically located within PJM, one of the nation's largest and most developed energy markets. In addition to the electric generation business described above, Power's revenues include gas supply sales under the BGSS contract with PSE&G. 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 Company LLC (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. For additional information, see Item 2. Properties—Power. For a discussion of recent operational issues, see Regulatory Issues—Nuclear Regulatory Commission (NRC). Nuclear unit capacity and availability factors for 2005 were as follows: Salem Unit 1 Salem Unit 2 Hope Creek Peach Bottom Unit 2 Peach Bottom Unit 3 Total Power Ownership Nuclear has several long-term purchase contracts with uranium suppliers, converters, enrichers and fabricators to meet the currently projected fuel requirements for the Salem and Hope Creek nuclear power plants. Nuclear has been advised by Exelon Generation that it has similar purchase contracts to satisfy the annual fuel requirements for Peach Bottom. For additional information, see Item 7. MD&A—Overview of 2005 and Future Outlook—Power and Note 12. Commitments and Contingent Liabilities of the Notes. Concurrent with the Merger Agreement, Nuclear entered into an Operating Services Contract (OSC) with Exelon Generation, which commenced on January 17, 2005, relating to the operation of the Salem and Hope Creek nuclear generating stations. The OSC requires Exelon Generation to provide a chief nuclear 5
officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon operating model, which defines practices that Exelon has used to manage its own nuclear performance program. 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. The OSC has a term of two years, subject to earlier termination in certain circumstances. In the event of termination, Exelon Generation will continue to provide services under the OSC for a transition period of at least 180 days and up to two years at the election of Nuclear. This period may be further extended by Nuclear for up to an additional twelve
months if Nuclear determines that additional time is necessary to complete required activities during the transition period. In May 2005, a scheduled refueling outage at Salem Unit 2 was completed ahead of schedule while meeting self-imposed nuclear safety targets. In November 2005, Salem Unit 1 returned to service, completing a scheduled refueling outage with a reactor head replacement in world record time. During 2005, Salem Unit 1 and Salem Unit 2 experienced their longest continuous on-line running days at nearly 100% capacity. Fossil has an ownership interest in 12 generating stations in New Jersey, one in New York, two in Connecticut, two in Pennsylvania and one in Indiana. For additional information, see Item 2. Properties—Power. Since 1999, Fossil has added units to its fleet, including the Bergen 2 station in New Jersey, the Bridgeport Harbor and New Haven Harbor facilities in Connecticut, the Lawrenceburg station in Indiana and the Bethlehem Energy Center in New York, which was completed and placed in service on July 18, 2005, replacing the Albany Station. In addition, Fossil is currently in final stages of construction for its Linden, New Jersey plant, which is scheduled to be operational in the second quarter of 2006. During 2005, Fossil sold its Waterford, Ohio plant, which commenced commercial operation in August 2003. For additional information see Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes. 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. The majority of Power's fossil generating stations obtain their fuel supply from within the U.S. 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. Power believes it has sufficient fuel supply, including transportation,
for its facilities over the next several years. For additional information, see Item 7. MD&A—Overview of 2005 and Future Outlook—Power and Note 12. Commitments and Contingent Liabilities of the Notes. 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. In anticipation of the proposed Merger with Exelon and a resulting reduction in personnel, ER&T has recently de-emphasized the proprietary trading component of its business to narrow its focus on its asset-based opportunities, including BGS and other load-related contracts,
BGSS, capacity, emissions and congestion related products such as firm transmission rights (FTRs) and auction revenue rights. Power's generation capacity is sourced from a diverse mix of fuels comprised of approximately 45% gas, 25% nuclear, 17% coal, 12% 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 the MWh output of Power's generating stations by fuel type in 2005, based on actual output of approximately 50,000 MWhs, 6
and its estimated MWh output by fuel type for 2006, based on anticipated output of approximately 52,000 MWhs. Nuclear: New Jersey facilities Pennsylvania facilities Fossil: Coal: New Jersey facilities Pennsylvania facilities Connecticut facilities Oil and Natural Gas: New Jersey facilities New York facilities Connecticut facilities Pumped Storage: Total 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 2005 and Future Outlook—Power. As described above, Power sells gas to PSE&G under the BGSS contract. Additionally, based upon availability, Power sells gas to others. About 42% 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 1.16 billion cubic-feet-per-day of firm transportation capacity under contract to meet the primary needs of the gas consumers of PSE&G and the needs of its generation fleet. In addition, Power supplements that supply with a total storage capacity of 80 billion cubic feet that provides a maximum of 0.91 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. There has been a significant increase in commodity prices, including fuel, emission allowances and electricity over the past year. For example, both natural gas and electric prices in PJM have more than doubled. Price increases of this magnitude are much greater than have been experienced in recent history and could continue to have considerable impacts. System operators in the 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 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. 7
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 increases in the price of natural gas will often translate into significant increases 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. Recently, the price of many of these products has increased dramatically. For example, the spot price of electricity at the quoted PJM West market has increased from $25 per MWh for 2002 to $60 per MWh in 2005. Similarly, the price of
natural gas at the Henry Hub terminal has increased from an average of about $5 per one million British Thermal Units (MMBtu) for 2002 to 2004 to about $9 per MMBtu in 2005. 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 2005 are reflected in the graphs below:
Historical and Forward PJM Western Hub RTC Prices
$75
$65
$55
$45
$35
$25
2002
2003
2004
2005
2006
2007
WH Historical Prices
(Source: PJM)
WH Forward Prices as of December 31, 2005
(Source: NYMEX)
Year
$11
$10
$9
$8
$7
$6
$5
$4
$3
2002
2003
2004
2005
2006
2007
Historical Gas Prices
(Source: Energy Information Administration)
Forward Gas Prices as of December 31, 2005
(Source: NYMEX)
Historical and Forward Henry Hub Gas Prices
Year While these prices 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, 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. 8
Another of the products from which Power derives revenue is capacity. In PJM, New York and the New England Power Pool (NEPOOL), the market provides a payment for the capability to provide electricity, known as a capacity payment. This payment is 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. A substantial increase in the construction of new capacity in each of these markets in recent years has created a surplus of capacity, depressing capacity prices. For example, capacity prices in PJM have recently averaged well below $10 per kW-year as compared to an average price of more than $25 per kW-yr during the period from 1999
to 2001. While there is generally an abundance of 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, recently announced the retirement of certain older generating facilities in these constrained areas due to insufficient energy and capacity revenues to support their continued operation. In separate instances, both PJM and NEPOOL have responded with fixed payments to the owners of these facilities to enable their continued availability. These Reliability-Must-Run (RMR) contracts for certain units 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 has received RMR payments in each of PJM and NEPOOL. In addition, discussions are currently taking place that may result in changes in the nature of capacity payments on a prospective basis in each of PJM and NEPOOL. In PJM, a new capacity-pricing regime known as the Reliability Pricing Model (RPM), if approved, would provide generators with differentiated capacity payments based upon the location and operating characteristics of their respective facilities. Similarly, the Locational Installed Capacity (LICAP) proposal currently being discussed in NEPOOL provides for locational capacity payments. Both proposals are based in part on the premise that a more structured, forward-looking, transparent pricing scheme would 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. There is widespread debate in each of these areas, with many market participants having different views and divergent interests on the appropriate mechanisms to prospectively conduct market activities. Power supports capacity markets in general, and the recognition of locational capacity value, as the market value for capacity should reflect the fact that reliability, or supply adequacy, often manifests itself on a locational basis. Power believes that much of its nearly 14,000 MW of generating capacity may experience changes in value from aspects of market design currently being discussed. While Power believes there is potential additional revenue from these changes, it cannot predict the outcome of potential changes in either market. For additional information on Power's collection of RMR payments in PJM and NEPOOL and the RPM and LICAP proposals, see Regulatory Issues—Federal Regulation. 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. In the PJM market, the pricing of energy is based upon the locational marginal price (LMP) set through power providers' bids. Due to transmission constraints, the LMP may be higher in congested areas 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, relative to the more liquid PJM West market location. Power also tends to contract a considerable amount of its production into this area, including its participation in the BGS auctions conducted in New Jersey. At various times, depending upon its production and its obligations, this price differential can serve to increase or decrease profitability. 9
The New England market has excess capacity and is also undergoing changes. The existence of reliability-based payments, coupled with the anticipated start of locational capacity markets in 2006, could enhance the value of Power's generation assets in Connecticut. The Midwest has excess capacity due to recent additions, which will continue to negatively impact the expected returns of Power's Lawrenceburg facility. The drivers to reduce the excess capacity will be load growth, the retirement of certain inefficient plants, particularly older plants of competitors, and increased costs associated with higher levels of environmental compliance. In addition, there has been a significant increase in commodity prices, including fuel and emission allowances, resulting in increased costs to produce electricity, which could potentially alter the dispatch order of units based upon fuel choice and efficiency. For additional information regarding increased commodity prices and proposed changes to capacity markets, see Market Price Environment. Power's businesses are also under competitive pressure due to technological advances in the power industry and increased efficiency in certain energy markets. 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. 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. 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. 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, Connecticut and the Midwest. 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 February 2006, the BPU approved the results of the most recent BGS auction for New Jersey customers, in which each bidder was limited to a third of each EDC's total load. Power was a successful bidder in the FP auction, which serves the state's residential and small industrial and commercial customers for a three-year
period. 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 has also extended into the New England Power Market by securing a three-year contract with a Connecticut utility expiring 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. Power has also entered into a full requirements contract with PSE&G under which Power provides the gas supply services needed to meet PSE&G's BGSS and other contractual requirements through March 2007. For the year ended December 31, 2005, approximately 34% of Power's revenue was comprised of billings to PSE&G for BGS and BGSS. See Note 21. Related-Party Transactions for additional information. As of December 31, 2005, Power had 2,590 employees, of which 1,414 employees (694 employees for Fossil and 720 employees for Nuclear) are union members. Power has six-year collective bargaining agreements with three union groups, which were ratified in February, July and August 2005, respectively. Power believes that it maintains satisfactory relationships with its employees. 10
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 focusing on the operating segments of the electric industries and Resources primarily making financial investments in these industries. Global and Resources have more than 70 financial and operating investments. Energy Holdings' portfolio is diversified by number, type and geographic location of investments. As of December 31, 2005, its assets were comprised of the following types: Leveraged Leases (mainly energy-related) International Electric Distribution Facilities International Electric Generation Plants Domestic Electric Generation Plants Other(1) Total The characteristics of each of these investment types are described in more detail below. Global Global owns investments in power producers and distributors that own and operate electric generation and distribution facilities in selected domestic and international markets. Global's assets include consolidated projects and those accounted for under the equity method. As of December 31, 2005, Global's share of project MW and number of customers by region are as follows: Generation: North America South America(1) Other(2) Distribution: South America Other: Other(3) Total 11
Global's near-term emphasis is on maintaining adequate liquidity and improving profitability of currently held investments. Beginning in 2003, Global has been reviewing its portfolio for the purpose of opportunistically monetizing investments that no longer have a strategic fit. As part of this strategy, in May 2004, Global completed the sale of its majority interest in Carthage Power Company (CPC) in Rades, Tunisia. In December 2004, Global completed the sale of its 50% equity interest in Meiya Power Company Limited (MPC). Consistent with this strategy, Global entered into an agreement with CEZ a.s. on January 31, 2006 to sell its interests in Elcho and Skawina. For additional information relating to these dispositions, see Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes. While Global still expects certain of its investments in South America to contribute significantly to its earnings in the future, adverse political and economic risks associated with this region could have a material adverse impact on such investments. To the extent practical, Global attempts to limit its financial exposure associated with each operating subsidiary to mitigate development risk, foreign currency exposure, interest rate risk and operating risk, including exposure to fuel costs, through financial and commodity contracts. For additional information related to these risks, see Item 7A. Qualitative and Quantitative Disclosures About Market Risk. In addition, project loan agreements are generally structured on a non-recourse basis. Further, Global generally structures non-recourse financings so that a default
under one will have no effect on the loan agreements of other operating subsidiaries or on Energy Holdings' debt. 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. Resources invests 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 50 separate investments. Based on current market conditions and Energy Holdings' intent to limit capital expenditures, it is unlikely that Resources will make significant additional investments in the near term. Resources also owns and manages a 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, 2005 were: Leveraged Leases Energy-Related Foreign Domestic Real Estate—Domestic Commuter Railcars—Foreign Total Leveraged Leases Limited Partnerships Other Investments(A) Owned Property Current and Other Assets Total Resources' Assets As of December 31, 2005, no single investment represented more than 9% of Resources' total assets. 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 12
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 obtaining 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.
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 accounting principles generally accepted 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. 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 recorded amount 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 and Acquisitions of the Notes. 13
Resources' ten largest lease investments as of December 31, 2005 were as follows: Reliant Energy MidAtlantic Power Holdings, LLC Dynegy Holdings Inc Midwest Generation (Guaranteed by Edison Mission Energy) ENECO ESG Merrill Creek Grand Gulf EZH Nuon EDON 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 and 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, 2005, Resources has a remaining net investment in four leased aircraft of approximately $32 million. On September 14, 2005, Delta Airlines (Delta) and Northwest Airlines (Northwest), the lessees for Resources' four remaining aircraft, 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, 2005. In 2004 and 2005, Resources successfully restructured the leases and converted the Delta and Northwest leases from leveraged leases to operating leases. Energy Holdings expects to recover its investment through cash flows from the operating leases. 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, 2005 and 2004 were $71 million and $72 million, respectively, and include developed land in New Jersey, Maryland and Virginia and an 80% partnership interest in buildings and land in New Jersey. Energy Holdings and its subsidiaries continue to experience substantial competition, both in the U.S. and in international markets. In the U.S., an overbuild in generation facilities has led to a large capacity surplus in several regions. This has resulted in reduced operating margins for both independent power producers and 14
utility generators where the marketplace has been evolving from a rate-regulated structure to a competitive environment. These matters in Texas showed improvement in 2005, evidenced by improved margins and increased utilization of Global's facilities. With respect to Global's distribution businesses in Chile, Peru, Brazil and Oman these investments are rate-regulated and are exposed to minimal market risks from competitors. See Regulatory Issues—International Regulation for additional information. Global has ownership interests in four distribution companies in South America which serve approximately three million customers and has developed or acquired 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. As of December 31, 2005, Energy Holdings had 61 employees. 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 services to PSEG and its subsidiaries. These include accounting, legal, communications, federal affairs, human resources, information technology, treasury and financial, investor relations, stockholder services, real estate, insurance, risk management, tax, library, research and information services, security, corporate secretarial and certain planning, budgeting and forecasting 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, 2005, Services had 1,039 employees, including 107 unionized employees.
A new six-year collective bargaining agreement with the union group representing these employees was ratified in February 2005. Services believes that it maintains satisfactory relationships with its employees. Federal Regulation PSEG, PSE&G, Power and Energy Holdings PSEG has claimed an exemption from regulation by the SEC as a registered holding company under PUHCA, except for Section 9(a)(2) thereof, which relates to the acquisition of 5% or more of the voting securities of an electric or gas utility company. Fossil, Nuclear, certain subsidiaries of Fossil and certain subsidiaries of Energy Holdings with domestic operations are EWGs. In addition, several of Energy Holdings' investments include foreign utility companies (FUCOs) under PUHCA and Qualifying Facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA). The Energy Policy Act, which became law on August 8, 2005, repealed PUHCA as of February 8, 2006 and established PUHCA 2005. 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. For additional information on the impact of PUHCA repeal, see State Regulation. 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 U.S. Environmental Protection Agency (EPA), the U.S. Department of Energy (DOE) and other regulators. For information on environmental regulation, see Environmental Matters. 15
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 prices 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. Several PSEG subsidiaries including PSE&G, Fossil, Nuclear, ER&T and certain subsidiaries of Fossil and certain subsidiaries of Energy Holdings with domestic operations are public utilities subject to regulation by FERC. FERC's regulation of public utilities is comprehensive and governs such matters as rates, services, mergers, financings, affiliate transactions, market behaviors and reporting. FERC is also responsible under PURPA for administering PURPA's requirements for
QFs. Mandatory Reliability Standards On September 27, 2005, PSEG joined ReliabilityFirst, a reliability organization that, as of January 1, 2006, consolidated three independent regional reliability councils that had promoted the reliability of the bulk power electric system throughout the Mid-Atlantic and portions of the Midwestern U.S. The Energy Policy Act requires 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. When FERC designates a single ERO, which is expected in the near future, PSEG may be subject to additional regulation by this entity or by FERC, which may now enforce reliability standards on its own initiative or by complaint. PSEG, PSE&G, Power and Energy Holdings do not expect any significant impacts resulting from additional regulation by the ERO or FERC on these issues since they are currently subject to, and comply with, certain reliability standards already in effect, however, no assurances can be given. 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, Fossil, Nuclear, ER&T and certain subsidiaries of Fossil and Energy Holdings, have applied for and received MBR authority from FERC. Power is scheduled for its next triennial market power review in 2006. In April 2004, FERC issued a final order revising its generation market power screen, which it uses to determine whether power sellers may have the ability to exercise market power. Upon application by a power seller, if FERC determines that a seller is not able to exercise market power under the screen, and the seller passes other tests, FERC's rules permit the seller to sell power at MBR. Failing FERC's revised screen will not conclusively determine whether an entity has market power and applicants failing the test will have the ability to demonstrate that they do not possess market power despite the screen failure. The screen includes two separate analyses: (1) an uncommitted pivotal supplier analysis and (2) a market share analysis that is to be prepared on a seasonal basis. FERC eliminated an exemption that
previously existed for generators in Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs), such as PJM and New York ISO (NYISO), and will require all entities that wish to sell at MBR to comply with the revised market power screen. PSEG Lawrenceburg Energy Company LLC (Lawrenceburg), an indirect wholly owned subsidiary of Power, is authorized by FERC order to sell wholesale power at MBR. The order requires Lawrenceburg to file a revised market power analysis within 30 days of the closing of the pending merger with Exelon and to treat Exelon as an affiliate for purposes of Exelon's MBR codes of conduct, which are on file with FERC, to guard against cross-subsidization between business units. Expanded Merger Review Authority The Energy Policy Act expands FERC's authority to review mergers and acquisitions under the FPA. It extends the scope of FERC's authority to require prior FERC approval regarding transactions involving certain transfers of generation facilities, certain holding companies' transactions, and utility mergers and consolidations of any value. The Energy Policy Act requires that FERC, when reviewing proposed transactions, examine cross-subsidization and pledges or encumbrances of utility assets. This new authority does not apply to the pending Merger between PSEG and Exelon. PSEG, PSE&G, Power and Energy 16
Holdings are unable to predict the effect of this authority on any potential future transactions in which they may be involved. Regional through and out rates (RTOR) RTOR are separate transmission rates for transactions where electricity originated in one transmission control area 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. PSEG and its subsidiaries, along with other stakeholders, jointly (1) filed for rehearing of the November 18, 2004 order as it relates to the imposition of a SECA charge, (2) protested the SECA compliance filings and (3) protested and moved to reject the filing of American Electric Power, Commonwealth Edison Company and Dayton Power & Light Company (New PJM Companies) to collect certain lost revenues resulting from the elimination of RTORs between PJM transmission owners. This request for rehearing is currently pending. On November 30, 2004, FERC issued an order that allowed the New PJM Companies to make a filing with FERC to collect their lost revenues. The BPU has also authorized the pass-through of SECA charges to certain New Jersey ratepayers, so that PSE&G will be able to collect funds
from these ratepayers and return them to certain BGS suppliers. As a BGS supplier, Power expects to receive funds from PSE&G to reimburse certain of its SECA expenses. On December 1, 2004, PSE&G began charging its BGS-FP customers for the increase in transmission charges. Consistent with the terms of the BGS-FP contracts, Power (and other BGS-FP suppliers) will not receive any revenue associated with a BGS-FP pass-through of the SECA charge until FERC's November 18, 2004 order is final and non-appealable. Pursuant to a reciprocity provision in its tariff, PJM and MISO began billing for the SECA in the May 2005 billing cycle. 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 is now scheduled to commence on May 2, 2006, with an initial decision by August 11, 2006. Depending on the outcome of this proceeding, which cannot be predicted at this time, PSEG, PSE&G and/or Power's results of operations could be adversely affected. 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. PJM requested that FERC issue an order on the proposal by January 1, 2006 in order to permit implementation of the RPM by June 1, 2006. Comments, interventions and protests of the filing made by other parties in October 2005. Numerous parties filed comments and protests. On November 8, 2005, PJM filed an extensive answer to comments and protests and asked for a determination by October 2006 so that implementation could commence in June 2007. While FERC has not responded to PJM's recommendations, it held a technical
conference on February 3, 2006 to present opposing views regarding the RPM. Power supported the RPM at the conference. No conclusive determinations were made by FERC, and PSEG, PSE&G and Power are unable to predict the outcome of this proceeding. 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 Regional Transmission Expansion Plan (RTEP) process. Among other matters, FERC's order responded to a proposal to continue PJM's current zonal rate design. 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. Under the schedule for this proceeding, this hearing will commence in April 2006. The May 31, 2005 order also accepts the tariff sheets filed by certain PJM transmission owners to establish the general procedures for filing to recover the costs incurred under the RTEP process, subject to further compliance filings. In accordance with the schedule
for this proceeding, 17
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 opposed both of these proposed rate designs. Rebuttal testimony was due on February 15, 2006. If FERC adopts one or a combination of these alternatives, PSEG's, PSE&G's or Power's results of operations could be negatively affected. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding. FERC Order No. 888 On September 16, 2005, FERC issued a Notice of Inquiry seeking comments on whether reforms are needed to the protections that FERC established in its Order No. 888 in order to prevent undue discrimination and preference in the provision of transmission service. FERC's Notice of Inquiry generally posed questions as to whether it should revise the pro forma Open Access Transmission Tariff. Order No. 888 established this tariff to govern the terms and conditions under which transmission owners must provide transmission service to all eligible customers. If FERC ultimately adopts structural remedies, such as further separating the ownership of generation and transmission, PSEG, PSE&G and Power's results of operations could be negatively affected. PJM Stated Rate Filing On July 1, 2005, PJM filed with FERC a proposal to change the rate design for its administrative cost recovery from a formula rate, which allocates PJM's administrative costs to its members on a yearly basis, to a stated rate of 39 cents per MW-hour. On August 31, 2005, FERC accepted these changes subject to the provision of further cost-of-service data by PJM within 60 days to demonstrate that its stated rate is a just and reasonable prediction of its costs for future years. PJM provided this cost-of-service data on November 30, 2005. Several parties, including PSE&G, Power, the BPU and the New Jersey RatePayer Advocate, submitted comments and protests regarding PJM's filing, which protested the filing and requested that FERC order an evidentiary hearing regarding the filing. Settlement discussions
are currently ongoing. If FERC ultimately accepts PJM's stated rate proposal, PSEG, PSE&G and Power's results of operations could be affected. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding. PSEG and Power LICAP Market 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 would begin to receive 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 would 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. If the settlement receives final approval from a majority of the settling parties, it is expected to be filed with FERC in early March. If the terms and conditions of the settlement in principle are ultimately approved by FERC, or if the settlement is not finalized and FERC adopts a different market design, the outcome could materially impact the pricing of installed capacity in the New England market. PSEG and Power are unable to predict the outcome of this proceeding. Power RMR Status 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 18
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. On February 24, 2005, Power requested that FERC approve such cost-of-service rate treatment for the Sewaren 1, 2, 3 and 4 and Hudson 1 units. On April 25, 2005, FERC issued an order accepting the February 24, 2005 filing, effective February 24, 2005, but establishing settlement procedures and a hearing on certain issues. Effective February 24, 2005, subject to refund and hearing, Power began to collect a monthly fixed payment of $3.3 million, net of operating margins at the units. On August 9, 2005, the parties reached a settlement in principle of the issues that FERC set for hearing. A detailed settlement was filed with FERC on September 23, 2005. The settlement permits Power to recover annual fixed costs of approximately $19 million and $14.5 million 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. 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. Beginning on January 14, 2005, when FERC issued an order accepting this filing, subject to refund and hearing. Power Connecticut began collecting monthly fixed payments
of approximately $1.6 million and $3.9 million for reliability services provided by the Bridgeport Harbor Station, Unit 2 and the New Haven Harbor Station, respectively, net of operating margins at the units. On June 17, 2005, Power Connecticut filed revised studies supporting monthly recovery of $1.3 million and $3.3 million for the Bridgeport Harbor and New Haven Harbor units, respectively. On June 20, 2005, FERC issued an order on rehearing of its January 14, 2005 order and reversed its prior conclusion that Power Connecticut's November 17, 2004 filing would become effective only after a 60-day notice period. Instead, the rehearing order allowed the filing to become effective as of November 18, 2004, which permits Power Connecticut two additional months of RMR compensation. On November 28, 2005, FERC denied rehearing of its June 20, 2005 order. While Power Connecticut was unable to settle the issues that FERC set for hearing, Power Connecticut believes that it has meritorious positions with respect to these issues; however, a final outcome of this process cannot be determined at this time. The hearing is currently scheduled to commence April 19, 2006. In addition, certain parties opposing the filing sought judicial review of FERC's orders in this proceeding on January 27, 2006. While Power Connecticut does not believe that such challenges are likely to be successful, it cannot predict a final outcome at this time. PSE&G Neptune Complaint Proceeding On December 21, 2004, Neptune Regional Transmission System, LLC (Neptune) filed a complaint with FERC against PJM. Neptune is directly interconnected to the transmission system of FirstEnergy Corporation (FirstEnergy), but upgrades to the PSE&G transmission system will also be required to move power across the grid. In its complaint, Neptune alleges that PJM impermissibly conducted an interconnection re-study triggered by generator retirements in PJM, which had the effect of increasing Neptune's cost exposure for network upgrades. On February 10, 2005, FERC granted Neptune's complaint against PJM. On June 24, 2005, in response to requests for rehearing and clarification, FERC issued an order denying rehearing and granting clarification of its February 10, 2005 order. FERC's June 24, 2005 order effectively approves Neptune's Interconnection Service Agreement with PJM, in which Neptune's cost responsibility is 19
set at the level of approximately $6 million. Costs arising as a result of generation retirements announced after Neptune received a System Impact Study from PJM, which costs total at least $20 million, may be allocated to PSE&G and FirstEnergy and/or to customers in these zones. On August 15, 2005, PSE&G sought judicial review of FERC's orders in the U.S. Circuit Court of Appeals. Two additional petitioners also sought judicial review of these orders. PSE&G cannot at this time predict the outcome of these challenges. 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 demonstrations to the NRC that plant operations meet requirements are also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. The current operating licenses of Power's nuclear facilities expire in the years shown below: Salem 1 Salem 2 Hope Creek Peach Bottom 2 Peach Bottom 3 Security The NRC has issued orders to all nuclear power plants to implement compensatory security measures. Some of the requirements formalize a series of security measures that licensees had taken in response to advisories issued by the NRC in the aftermath of the September 11, 2001 terrorist attacks. Nuclear has evaluated these orders for the Salem, Peach Bottom and Hope Creek facilities. Security measures required to be in place by October 2004 have been completed at Salem, Hope Creek and Peach Bottom. Additional security upgrades were identified and have been implemented following an NRC Force-On-Force security exercise in January 2005. Power's share of the Security Project was approximately $7 million in 2004 and $30 million in 2005. A second Force-On-Force exercise was completed in July 2005. A follow-up letter from
the NRC credited Salem/Hope Creek for demonstrating a sound protective strategy and indicated the NRC's interest in returning in 2006 to observe the site's annual Force-On-Force exercises. Reactor Vessel Heads In 2002, the NRC issued a bulletin requiring that all operators of pressurized water reactor (PWR) nuclear units submit certain information related to potential degradation of reactor vessel heads. In 2003, the NRC issued an order to all operators of PWR units concerning reactor vessel head inspections. The order confirms the previous bulletin's requirements and adds more intrusive and frequent future inspections, which apply to Salem 1 and 2. In September 2002, Nuclear provided the requested information for Salem to the NRC, and performed inspections in accordance with the NRC order for Salem 1 and 2 during 2004 and 2003, respectively. The reactor heads were determined to be satisfactory for continued safe operation. Nuclear replaced Salem 1 and 2 reactor heads in 2005 as a preventive measure, during scheduled refueling
outages. Pursuant to an NRC directed order, the frequency of inspection on the new reactor heads is extended to three years. Nuclear's Hope Creek unit and Peach Bottom 2 and 3 are unaffected by these bulletins as they are boiling water reactor nuclear units. Power cannot predict what other actions the NRC may take on this issue. 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 20
issues. Power responded to the letter in February 2004 and had independent assessments of the work environment at both facilities performed. The results of these assessments were provided to the NRC in May 2004. The assessments concluded that Salem and Hope Creek were safe for continued operations, but also identified issues that needed to be addressed. At an NRC public meeting on June 16, 2004, Power outlined its action plan to address these issues, which focused on a safety-conscious work environment, the corrective action program and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. On July 30, 2004, the NRC provided a letter to Power indicating that it had completed its review. The letter indicated that the NRC had not identified any safety violations and that it appeared that the PSEG action plan would address the key findings of both the NRC and Power assessments. On August 30, 2005, the NRC provided Power with its mid-cycle performance reviews of Salem and Hope Creek, which detailed the NRC's plan for enhanced oversight related to the work environment. The letter indicated the NRC plans to continue with
this heightened oversight until Power has concluded that substantial, sustainable progress has been made, and the NRC has completed a review that confirms Power's conclusions. Under the NRC oversight program, among other things, Power provided the NRC with a report of its progress at public meetings in June and November 2005. The next public meeting is scheduled for the first half of 2006. 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 will be replaced at the next Hope Creek outage, scheduled for April 2006. PSE&G Investment Tax Credits (ITC) For a discussion of an Internal Revenue Service (IRS) proposal that could have a material impact on PSE&G's treatment of ITCs, see Note 12. Commitments and Contingent Liabilities of the Notes. 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 the electric and natural gas industries in Pennsylvania. PSE&G and Power are also subject to rules and regulations of the New Jersey Department of Environmental Protection (NJDEP) and the New Jersey Department of Transportation (NJDOT). PSEG is not subject to direct regulation by the BPU, except, potentially, with respect to certain transfers of control and reporting requirements. Certain subsidiaries of PSEG and Power with operations in New Jersey may be subject to some regulation by the BPU, with respect to energy supply (BGS and BGSS), certain asset sales, transfers of control, reporting requirements and affiliate standards. 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. 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 Energy Policy Act. In its order, the BPU requested 21
information from each New Jersey public utility regarding its financial and organizational structure and the BPU indicated that it was in the process of preparing a formal rulemaking recommendation to address these issues. On October 7, 2005, the BPU initiated an informal stakeholder process in this proceeding and requested comments from New Jersey's public utilities regarding the BPU's access to utility records, limits on utility diversification, restrictions on the transfer of capital by utilities to their corporate parents or affiliates, affiliate transactions and the prevention of cross-subsidization. PSE&G has provided the requested information and filed comments generally arguing that no additional regulatory protections are necessary. On December 19, 2005, the BPU proposed a new regulation that would prevent a holding company that owns a New Jersey gas or electric utility from investing more than 25% of its combined assets in businesses unrelated to the utility industry. The proposed rule also would prevent holding companies primarily involved in non-utility businesses from purchasing New Jersey utilities unless they divest sufficient holdings to comply with the proposed rule. The BPU held a public hearing regarding the proposed rule on February 8, 2006. Comments on the proposed rule were due by February 17, 2006. PSEG, PSE&G, Power and Energy Holdings are not able to predict the outcome of these proceedings at this time. 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 $68 million. The BPU issued an order on February 7, 2006 that and found that insufficient information had been provided to support the rate increase at this time. The order permits PSE&G to file, no later than June 15, 2006, actual data through March 31, 2006. The BPU will determine, based on the additional information, if the rate increase is warranted. The impact of not receiving this increase reduces PSE&G's earnings and cash flows by more than $5 million (pre-tax) per month. On May 27, 2005, PSE&G filed its 2005/2006 BGSS commodity charge filing, requesting an increase in its BGSS commodity charge to its residential gas customers of approximately $162.7 million, excluding Sales and Use Taxes (SUT), in annual revenues effective October 1, 2005, or approximately 10.2% for the class average residential heating customer. PSE&G subsequently filed with the BPU requesting that the new rate become effective on September 1, 2005 rather than October 1, 2005. A provisional settlement was approved by the BPU on August 18, 2005. Under this settlement, PSE&G's filed BGSS rates became effective on September 1, 2005 on a provisional basis, subject to refund with interest. PSE&G's filing was transferred to the Office of Administrative Law (OAL) for a full review and
an Initial Decision. On November 10, 2005, PSE&G filed a Motion for Emergent Relief due to the extreme increase in the price of natural gas since the original filing. The request was for an increase of $203.5 million (excluding SUT) or approximately 15.6% for the class average residential heating customer with an effective date of December 14, 2005. A provisional settlement was approved by the BPU on December 15, 2005 and the new rate went into effect immediately. A prehearing conference with the ALJ assigned to the case was held and a full review including additional discovery and a hearing, if necessary, must take place before both BGSS increases can be approved on a final basis. Remediation Adjustment Clause (RAC) Filing PSE&G has implemented a program to address potential environmental concerns regarding its former Manufactured Gas Plant (MGP) properties in cooperation with and under the supervision of NJDEP. On April 22, 2004, PSE&G filed its RAC-11 filing with the BPU to recover approximately $36 million of remediation program expenditures for the period from August 1, 2002 through July 31, 2003. Public hearings 22
were held in July 2004. On September 10, 2004, the ALJ issued an Initial Decision recommending approval of the settlement reached between all parties, allowing PSE&G to recover all requested costs. This resulted in PSE&G recovering an additional $0.4 million annually in remediation program expenditures. On October 5, 2004, the BPU issued a Final Decision and Order approving, in its entirety, the ALJ's Initial Decision recommending acceptance of the settlement. On April 25, 2005, PSE&G filed its RAC-12 filing with the BPU to recover approximately $18 million of remediation program expenditures for the period from August 1, 2003 through July 31, 2004. On October 6, 2005, PSE&G signed a settlement agreement with the RPA and the BPU. The settlement agreement, which provides for PSE&G to recover substantially all of the $18 million requested, was approved October 13, 2005 by the ALJ. On December 5, 2005, the BPU issued a Decision and Order approving in its entirety the ALJ's Initial Decision recommending acceptance of the settlement. 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 is for an increase in book depreciation rates. The balance of the request will cover the return on increased plant investment, higher operating expenses and provide an 11% return on equity. PSE&G's current gas base rates have been in effect since January 2002. PSE&G presented a detailed overview of the filing to the BPU and the RPA in October 2005 and subsequent to the presentation signed an agreement with the BPU Staff providing for transfer of the matter to OAL and agreeing to have the matter settled or ready for a BPU decision before September 28, 2006. The amount and timing of any rate relief cannot be predicted. EDECA required that the BPU provide electric and natural gas customers with the opportunity to choose a supplier for some or all electric or natural gas customer account services (CAS). In July 2004, PSE&G filed a petition with the BPU to implement the CAS Cost Recovery Mechanism for both its electric and gas operations to recover $4 million of CAS costs and accumulated interest resulting from implementing PSE&G's dual billing for its delivery costs and for the third-party suppliers' commodity charges as a result of customer migration from PSE&G. In September 2004, the case was transferred to the OAL as a contested case. A pre-hearing conference was held on December 20, 2005 at which time a schedule was established. Settlement discussions are being held between the parties. 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 December 31, 2003 was released by the consultant to the BPU in February 2005. The draft report addressed the Societal Benefits Clause (SBC), Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances. 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 $118 million. PSE&G and the BPU Staff are continuing discussions to resolve these issues and, if a resolution cannot be achieved, a BPU proceeding may be instituted to consider the issues raised. The BPU required PSE&G to produce discovery in the Deferral Audit related to the MTC issue for the RPA's review. It appears that there may be a full hearing on the MTC issue. 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. Further, PSE&G believes the deferral audit and deferral proceeding that were approved by the BPU in its order of April 22, 2004 are non-appealable. PSE&G cannot predict the impact of the outcome of any such proceeding. 23
Levelized Gas Adjustment Clause (LGAC)/BGSS Audit The BPU's Division of Audit reviews gas costs of utilities in New Jersey on a regular basis. As part of its regular review in November 2004, the BPU commenced an audit of the gas supply costs incurred during the period October 1, 1999 through September 30, 2004. The field work for the audit has been completed. Company personnel met with the Audit Staff and provided some additional support. The outcome of the audit cannot be determined at this time. New Jersey Clean Energy Program 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 sum of PSE&G's electric and gas funding requirement for 2005 was $82 million and grows to $137 million in 2008 for a four-year total of $406 million. This liability has been recorded at a discounted present value with an offsetting regulatory asset. The BPU is seeking new program managers for the Energy Efficiency program currently being administered by the utilities. The transition from the utilities to the program managers is expected to take place in mid-2006. Power Connecticut Electric Authority (CEA) Legislation proposed by the Attorney General of Connecticut has been recently introduced in the State Assembly to create a new public power authority to be known as the CEA. The CEA would have broad authority, including the power to procure, through open public auction, all of the electric power required by the state's electric utilities, to build or buy and operate generating, transmission and related facilities, to finance their construction or acquisition and to sell or resell electric power to the State's electric utilities for delivery to their “standard service” customers at cost. The enactment of a “windfall” profits tax of between 20% and 50% on a power generator's earnings in excess of 20% is also proposed for enactment. Revenues raised by such tax would be dedicated to financing
the CEA and for rate relief. In addition, a separate bill has been introduced that would require the Connecticut Department of Public Utility Control to develop a plan by September 1, 2006 to commence a “contested case” proceeding to develop a plan for the withdrawal of all Connecticut electric distribution companies from participation in NEPOOL or the system of any electric system operator. 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. International Regulation Energy Holdings Global Global's electric distribution facilities in South America and Oman 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. Brazil Rio Grande Energia S.A. (RGE) is regulated by Agencia Nacional de Energia Eletrica (ANEEL), the national regulatory authority. ANEEL's functions include granting and supervising electric utility concessions, approving electricity tariffs, issuing regulations and monitoring distribution systems' performance. The rate-setting process for Brazilian distribution companies has two components: an annual adjustment for which RGE applies every April which is embedded in the concession contract and a rate case revision, which is repeated every fifth year and was last conducted in 2003. 24
RGE has contingent liabilities relating to past due taxes with the governing tax authority in Brazil and a tax assessment relating to a loan entered into by a former wholly owned subsidiary of RGE. For further information regarding these matters, see Note 12. Commitments and Contingent Liabilities of the Notes. Chile Distribution companies in Chile, including Chilquinta Energia S.A. (Chilquinta), 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. Peru Distribution companies in Peru, including Luz del Sur (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. Oman Global, through Dhofar Power, has a 20-year concession agreement to own and operate a vertically operated utility that includes both the power plant and the local electric transmission and distribution systems. Gas for the power plant is supplied by the Government of Oman as a pass-through cost. Based on the original capital investment, the Government of Oman and Dhofar Power have an agreed tariff structure comprised of three components: generation allowances comprised of fixed capital cost allowances, fixed operating cost allowance, and variable operating allowances and fuel cost allowance; transmission and distribution system allowances comprised of transmission and distribution system allowances of the existing system and enhancements and extensions to the existing system, and the transmission and distribution system
operating allowance; and the general allowances covering general and administrative cost allowance. Any transmission and distribution expansion projects must be approved by the Government of Oman. Upon approval, Dhofar Power would receive an additional capital investment and operation and maintenance allowance. 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. 25
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 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 is seeking to order companies allegedly 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 the 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. For additional discussion of PSD/NSR, see Note 12. Commitments and Contingent Liabilities of the Notes. 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 26
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. A new facility that Power developed in Indiana became subject to rules that Indiana promulgated to comply with the NOx SIP Call. Because the rules in Indiana both set aside allowances for allocation to new sources, Power did not experience any material adverse effects from complying with this program in Indiana. 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 is proposing 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. States need to submit plans to the EPA for complying with the rule by November 2006. 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 Countries participating in the Kyoto Protocol will be required to achieve material reductions of CO2 and certain other greenhouse gases between 2008 and 2012. Although the U.S. has not ratified the treaty, Global's assets in Italy will be affected by implementation of the Kyoto Protocol, as adopted through regulations by the European Union (EU). Global will more than meet the expected CO2 requirements and they are not anticipated to have a material effect on operations at Global's European assets in Italy. In 2002, Power announced a voluntary agreement that called for a December 31, 2005 goal of reducing the annual average CO2 emission rate of its New Jersey fossil fuel-fired electric generating units by 15% below the 1990 average annual CO2 emission rate. Power is expected to exceed the target and will pay approximately $700,000 per the agreement pending emissions data verification. Fossil also made a $1.5 million payment to the NJDEP to assist in the development of landfill gas projects and had agreed to make a payment equal to $1 per ton of CO2 emitted greater than the 15% goal, up to
$1.5 million, if that reduction was not achieved. PSEG joined the EPA Climate Leaders Program in February 2002. On January 13, 2004, PSEG established a goal of reducing its CO2 emissions intensity by 18% per MWh generated (nuclear excluded) from 2000 levels by December 31, 2008. The goal would in part be met by re-powering the Bergen, Linden and Albany plants. PSEG has developed an emission inventory and inventory management plan, which was accepted by the EPA Climate Leaders Program. As of December 31, 2005, PSEG has met the 18% reduction commitment. Several states, primarily in the Northeastern U.S., are developing state-specific or regional legislative initiatives to stimulate CO2 emission reductions in the electric power industry. For example, 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 model rule is expected in March 2006 and states are expected to enact legislation and/or regulation representing, at least, the minimum requirements stipulated in the MOU. The NJDEP in 2005 finalized
amendments to its regulations governing air pollution control that would designate CO2 as an air contaminant subject to regulation. The RGGI program is 27
scheduled to start in 2009. The outcome of this initiative cannot be determined at this time; however, adoption of stringent CO2 emission reduction requirements in the Northeast could materially impact Power's operation of its fossil fuel-fired electric generating units. 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. 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 provide the following 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: (1) reduce flow commensurate with a closed-cycle system or reduce intake
velocity; (2) meet 28
applicable performance standards for reduction of entrainment and impingement mortality through the use of the existing design, construction, operational or restoration measures; (3) meet applicable performance standards through a combination of existing and proposed design, construction, operational or restoration measures; (4) installation of a design and construction technology specified by the regulation or pre-approved by the agency; and (5) a site-specific determination that the cost to the facility to meet the performance standards is “significantly greater” than either (a) the costs that the EPA estimated for that type of facility or (b) the environmental benefits of complying with the performance standards. 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 to Power and the rule's ability to withstand legal challenges cannot be determined at this time for all of Power's facilities. If application of the Phase II rules by the states requires the retrofitting of cooling water intake structures at Power's existing facilities, additional material capital expenditures could be required to modify the existing plants to enable their continued operations. Several environmental groups, the Attorney Generals of six Northeastern states, the Utility Water Act Group and several of its members, including Power, are parties to litigation challenging the Phase II rule. The case will be heard in the U.S. Court of Appeals for the Second Circuit. The states and environmental groups have challenged the use of restoration and other measures to satisfy performance standards as well as a state's ability to make site-specific determinations based on cost tests. A decision issued in February 2004 by the Second Circuit in litigation challenging the Phase I rule (new facilities) struck down that rule's provision allowing for the use of restoration measures to satisfy the specified performance standards. An unfavorable decision in the Phase II litigation could have a material impact
on Power's ability to renew its NJPDES permits at its larger once-through cooled plants without significant upgrades to their existing intake structures and cooling systems. Power For information on permit renewals for Salem, see Note 12, Commitments and Contingent Liabilities of the Notes. 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. 29
Uranium Enrichment Decontamination and Decommissioning Fund In accordance with the Energy Policy 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 $75 million (adjusted for inflation). As of December 31, 2005, PSE&G had paid $70 million, resulting in a balance due of $6 million. As of December 31, 2005, Power also had a balance due of approximately $1 million, which related to interests in certain nuclear units it purchased. These amounts
are payable to the DOE in annual installments through October 2006. The New Jersey Administrative Code 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. For a discussion of nuclear fuel disposal, see Note 12. Commitments and Contingent Liabilities of the Notes. 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. PSE&G For information regarding PSE&G's MGP Remediation Program, see Note 12. Commitments and Contingent Liabilities of the Notes. 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 30
could cause generating station operations to fall below expected levels include, but are not limited to, the following: 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, considerable uncertainties exist in certain countries due to economic, political and social concerns that could have an adverse impact. 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. 31
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: 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 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 32
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. 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 33
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 payment obligations. Any failure to collect these payments from 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. These restrictions could further restrict Energy Holdings' ability to service its outstanding indebtedness. 34
Adverse international developments could negatively impact results Energy Holdings A component of PSEG's and Energy Holdings business strategy has been the development, acquisition and operation of projects outside the U.S. 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 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 acquires an asset by obtaining 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 2005, the IRS proposed
to disallow certain deductions associated with some of the leveraged leases which have been designated by the IRS as listed transactions. Any material disallowance of deductions could impact Energy Holdings' earnings and ability to service its outstanding indebtedness. Failure to consummate the proposed Merger with Exelon PSEG, PSE&G, Power and Energy Holdings The proposed Merger with Exelon is subject to regulatory reviews not yet concluded, including the BPU and the U.S. Department of Justice (DOJ). The required regulatory approvals might not be received by June 20, 2006, the date set after which either PSEG or Exelon could terminate the Merger Agreement. Any regulatory approvals could contain one or more conditions which either PSEG or Exelon could determine constitute a “burdensome order” under the Merger Agreement giving each the right to terminate. If the Merger is not closed, PSEG, PSE&G, Power and Energy Holdings could experience one or more of the following consequences: 35
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: 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. 36
ITEM 1B. UNRESOLVED STAFF COMMENTS PSEG None. PSE&G, Power and Energy Holdings Not Applicable. 37
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, 2005, PSE&G's transmission and distribution system included approximately 21,818 circuit miles, of which approximately 7,826 circuit miles were underground, and approximately 799,471 poles, of which approximately 537,632 poles were jointly-owned. Approximately 99% of this property is located in New Jersey. In addition, as of December 31, 2005, PSE&G owned five electric distribution headquarters and four subheadquarters in four operating divisions, all located in New Jersey. As of December 31, 2005, 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: Burlington LNG Camden LPG Central LPG Harrison LPG Total As of December 31, 2005, PSE&G owned and operated approximately 17,241 miles of gas mains, owned 12 gas distribution headquarters and three subheadquarters, all in two operating regions located in New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, PSE&G operated 61 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. 38
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, 2005, PSE&G owned 41 switching stations in New Jersey with an aggregate installed capacity of 21,728 megavolt-amperes and 244 substations with an aggregate installed capacity of 7,772 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. 39
As of December 31, 2005, Power's share of installed generating capacity was 13,846 MW, as shown in the following table: OPERATING POWER PLANTS Steam: Hudson Mercer Sewaren Linden(F) Keystone(A)(B) Conemaugh(A)(B) Bridgeport Harbor New Haven Harbor Total Steam Nuclear: Hope Creek Salem 1 & 2(A) Peach Bottom 2 & 3(A)(C) Total Nuclear Combined Cycle: Bergen Lawrenceburg Bethlehem Total Combined Cycle Combustion Turbine: Essex Edison Kearny Burlington Linden Mercer Sewaren Bayonne Bergen National Park Kearny Salem(A) Bridgeport Harbor Total Combustion Turbine Internal Combustion: Conemaugh(A)(B) Keystone(A)(B) Total Internal Combustion Pumped Storage: Yards Creek(A)(D)(E) Total Operating Generation Plants 40
As of December 31, 2005, Power had generating capacity in construction or advanced development, as shown in the following table: POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT Combined Cycle: Linden Total Construction Nuclear Uprates Total Advanced Development Total Owned Operating Generation Plants Under Construction Advanced Development Less: Planned Retirements Projected Capacity 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. 41
Global has invested in the following generation facilities that were in operation as of December 31, 2005: OPERATING POWER PLANTS United States Texas Independent Energy, L.P. (TIE) Guadalupe Power Partners, L.P. (Guadalupe) Odessa-Ector Power Partners, L.P. (Odessa) Total TIE Kalaeloa Partners L.P. (Kalaeloa) GWF Power Systems, L.P. (GWF) Hanford L.P. (Hanford) Thermal Energy Development Partnership L.P. (Tracy) GWF Energy LLC (GWF Energy) Hanford—Peaker Plant Henrietta—Peaker Plant Tracy—Peaker Plant Total GWF Energy Bridgewater Conemaugh Total United States International (A) PPN Power Generating Company Limited (PPN) Prisma Crotone Bando D'Argenta I Strongoli Total Prisma Electroandes Turboven Maracay Cagua Total Turboven Turbogeneradores de Maracay (TGM) Dhofar Power Company S.A.O.C. (Dhofar Power) SAESA Group Total International Total Operating Power Plants As of December 31, 2005, Global had invested in the following generation facility that was in advanced development: POWER PLANTS IN ADVANCED DEVELOPMENT Electroandes Total Projected Capacity 42
Domestic Generation In Operation TIE 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 50% of the total peak capacity of both Guadalupe and Odessa plants for 2006 have 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 sold capacity of Odessa above is a 350 MW five-year daily capacity call option that provides stable revenues and cash flows. 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 209 MW. Global and 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 two local oil refineries with price and minimum volumes negotiated 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 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 its petroleum coke through a contract with the new owner of a refinery that was previously scheduled to close but which was sold to the new owner in 2005. Hanford, Henrietta and Tracy Peaker Plants GWF Energy, which is 60% owned by Global and 40% owned by Harbinger GWF LLC (Harbinger), an affiliate of 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 (approximate book value), pursuant to an arbitration panel's finding. 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 in Operation 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% 43
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%. TNEB has not made full payment to PPN for the purchase of energy under the contract. For a discussion of the TNEB's failure to meet its obligations under this PPA, see Item 3. Legal Proceedings. Electroandes Global owns a 100% interest in Electroandes located in Peru. Electroandes' main assets include four hydroelectric facilities with a combined installed capacity of 183 MW and 437 miles of transmission lines located in the central Andean region east of Lima. In addition, Electroandes is in the process of developing a 35 MW expansion to an existing station. In 2005, 98% of Electroandes' revenues were obtained through various PPAs, denominated in U.S. Dollars, expiring through 2008. 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 2006 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. 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. Dhofar Power In March 2001, Global, through Dhofar Power, signed a 20-year concession with the Government of Oman to privatize the electric system of the city of Salalah. Global owns 46% of Dhofar Power following the sale by Global in April 2005 of a 35% interest through a public offering on the Oman stock exchange as required under the concession agreement. The remainder of Dhofar Power's shares are owned by several major Omani investment groups (19%) and the public (35%) following the public offering. See Note 12. Commitments and Contingent Liabilities of the Notes for discussions regarding contractual disputes between Dhofar Power and the Government of Oman. Electric Distribution Facilities Global has invested in the following major distribution systems: RGE Chilquinta SAESA Group LDS Total As part of Dhofar Power's concession, Global also operates a distribution system serving approximately 47,000 customers in the southeast Dhofar region of Oman. 44
RGE Global owns a 32% equity interest in RGE. Global is the named operator for the system. A shareholders' agreement establishes corporate governance, voting rights and key financial provisions. Global has veto rights over certain actions, including approval of the annual budget and financing plan, appointment of executive officers, significant investments or acquisitions, sale or encumbrance of assets, establishment of guarantees, amendment of the by-laws of the company and dividend policies. Day-to-day operations are the responsibility of RGE's management, subject to shareholder oversight. The remaining ownership interest is held by Companhia Paulista de Forcae Luz (CPFL), an electric distribution company in which Global's original partners, VBC Energia S.A. (a Brazilian power company) and Previ (the pension
fund of the Bank of Brazil), collectively, own a majority interest. RGE operates under a territorial concession agreement ending in 2027. Under a new regulation passed in 2004, the concession is exclusive and only large consumers have the right to choose another provider of energy or to self-generate. Global does not believe this represents a material threat to the profitability of the distribution system in Brazil since the tariff structure provides the distribution system the opportunity to recover all costs associated with distribution service plus a return. In 2002, RGE secured its energy supply through a 12-year contract signed with Tractebel, a European generation company, which covers all of RGE's actual capacity not covered by other existing contracts. Of RGE's existing contracts, only one is denominated in U.S. Dollars. This contract represents 19% of RGE's current
needs. For additional information related to RGE, see Item 1. Business—Regulatory Issues and Item 3. Legal Proceedings. Chilquinta and LDS Global together with its partner, Sempra Energy (Sempra), own 99.99% of the shares of Chilquinta, an energy distribution company with numerous energy holdings, based in Valparaiso, Chile. Global's interest is 50% of this aggregate. 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. 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 together with subsidiaries of SAESA 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 two MW wind). The transmission company, Sistema de Transmision del Sur S.A. (STS), provides transmission 45
services to electric generation facilities that have PPAs with distributors in Regions VIII, IX and X and has installed transformation capacity of 939 megavolt-amperes. The SAESA Group also owns a 50% interest in an Argentine distribution company, Empresa de Energia Rio Negro S.A. (EDERSA), which provides generation, transmission and distribution services to approximately 147,000 customers in the Province of Rio Negro, Argentina. The Chilean members of the SAESA Group are organized and administered according to a centralized administrative structure designed to maximize operational synergies. In Argentina, EDERSA has its own independent administrative structure. The SAESA Group is currently in the process of selling EDERSA and has entered into an agreement with the buyer. The sale process is pending Argentine governmental regulatory approval. For additional information related to the SAESA Group, see Item 1. Business—Regulatory Issues. PSE&G In November 2001, Consolidated Edison Company of New York, Inc. (Con Edison) filed a complaint against PSE&G with FERC asserting that PSE&G had breached agreements 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 are not being met. In a December 30, 2005 filing with FERC, Con Edison claims to have incurred $57 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. The matter is currently pending before FERC, and PSEG and PSE&G are unable to predict the outcome of this proceeding. Energy Holdings In July 2003, Texas Commercial Energy LLC (TCE) filed suit against the three major electric utilities in Texas, certain wholesale power generators, their related affiliated retail electric providers and certain qualified scheduling entities, as well as the Electric Reliability Council of Texas (ERCOT), in its function as the ISO for the Texas energy market. The action filed in the U.S. District Court for the Southern District of Texas (District Court), Civil Action No. C-03-249, alleged price-fixing, predatory pricing and certain common law claims. Automated Power Exchange, Inc. (APX), a named defendant, acting as the qualified scheduling entity, submitted bids on behalf of Guadalupe Power Partners, LP (Guadalupe) and Odessa-Ector Power Partners, L.P. (Odessa), as well as several other generators in the ERCOT energy
market. In this connection, APX has submitted a demand for indemnification from Guadalupe and Odessa. In February 2004, TCE amended its complaint and named TIE, Guadalupe, Odessa and others as additional defendants. In May 2004, the District Court granted the defendants' motion to dismiss the state and federal antitrust claims. On June 17, 2005, a two-judge panel of the Fifth Circuit Court of Appeals (Fifth Circuit) issued its decision affirming the District Court's dismissal of TCE's state and federal antitrust claims. TCE subsequently filed a Petition seeking a rehearing before the entire panel of the Fifth Circuit, which was denied. On October 14, 2005, TCE filed a Petition for Certification of this matter to the U.S. Supreme Court. The parties have since agreed to settle the case for an immaterial amount and the matter was subsequently dismissed with prejudice by
the Supreme Court. TCE has since filed for bankruptcy, which could impact the final settlement. 46
On February 18, 2005, Utility Choice L.P. and Cirro Group Inc. filed suit against many of the same defendants in the TCE suit, including TIE, Guadalupe and Odessa, based on facts similar to those alleged in the TCE litigation. The new action, filed in the District Court also alleges price-fixing, predatory pricing and various other claims. The District Court issued a stay of action pending the outcome of the TCE appeal and the stay continued until the TCE request to the Fifth Circuit was determined. The District Court originally lifted the stay for the sole purpose of permitting motions to dismiss to be filed but later allowed the case to proceed to discovery. The case has been resolved by the parties for an immaterial amount and the matter has been voluntarily dismissed with prejudice. 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. The project was not dispatched during the fourth quarter of 2005, primarily due to the high cost of naphtha fuel and resulting low ranking on the merit order dispatch list. The past due receivable as of December 31, 2005 was approximately $1 million, net of a $79 million reserve. Provided that TNEB continues to pay consistent with recent practices, PPN is not expected to have liquidity problems. 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. As of December 31, 2005, Global's total investment in PPN was approximately $33 million, a reduction of $5 million from the December 31, 2004 balance of $38 million due to dividends received from this investment. From about 1995 through 2001, Global and its partners expended approximately $12 million towards the construction of a lignite-fired thermal 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 Government's obligation to compensate Global for its costs under the existing contract and Turkish law. In 2002, Global initiated an arbitration under the U.S.-Turkey Bilateral Investment Treaty (BIT) before the International Centre for Settlement of International Disputes for Turkey's violation of its international rights under the BIT seeking return of sunk costs, lost profits, interest and attorney fees and
costs for a total of $300 million. Written testimony has been submitted by both parties and hearings are scheduled for the first two weeks of April 2006 in Washington, D.C. A decision is expected later in 2006. While Global believes it has valid and sustainable claims against the Government of Turkey, which it will continue to vigorously assert, it is unable to predict the outcome of this matter. The recovery of costs in this matter could have a material positive impact on Energy Holdings' earnings and cash flows. 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: 47
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17) (18) (19) (20) (21) (22) 48
(23) (24) (25) (26) 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. The remedy itself and responsibility for the costs of its implementation
are the subject of litigation currently in the U.S. District Court for the Eastern District of Pennsylvania entitled United States of America, et. al., v. Union Corporation, et. al., Civil Action No. 80-1589. (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. 49
PSEG—None. PSE&G—None. Power—None. Energy Holdings—None. 50
PSEG PSEG's Common Stock is listed on the New York Stock Exchange, Inc. As of December 31, 2005, there were 100,679 holders of record. The following table indicates the high and low sale prices for PSEG's Common Stock and dividends paid for the periods indicated: 2005: First Quarter Second Quarter Third Quarter Fourth Quarter 2004: First Quarter Second Quarter Third Quarter Fourth Quarter In January 2006, PSEG's Board of Directors approved a one-cent increase in its quarterly common stock dividend, from $0.56 to $0.57 per share, for the first quarter of 2006. This increase reflects an indicated annual dividend rate of $2.28 per share. The Merger Agreement between PSEG and Exelon provides that, subject to applicable law and the fiduciary duties of its Board of Directors, Exelon will increase its quarterly dividend so that the first dividend paid after completion of the Merger is an amount equal to the dividend PSEG shareholders received in the quarter immediately prior to completion of the Merger based on the 1.225 exchange ratio used, up to a maximum of $0.47 per share of Exelon Common Stock. It is anticipated that the combined company will maintain Exelon's current dividend payout policy of 50% to 60% of earnings. 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 2005 and Future
Outlook and Liquidity and Capital Resources and Note 9. Schedule of Consolidated Capital Stock and Other Securities 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 2005 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 2005 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 2005 and Future Outlook. 51
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). Operating Revenues Income from Continuing Operations Net Income Earnings per Share: Income from Continuing Operations: Basic Diluted Net Income: Basic Diluted Dividends Declared per Share As of December 31: Total Assets Long-Term Obligations(B) PSE&G The information presented below should be read in conjunction with the MD&A, the Consolidated Financial Statements and the Notes. Operating Revenues Income Before Extraordinary Item Net Income As of December 31: Total Assets Long-Term Obligations(A) 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. 52
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. PSEG, PSE&G, Power and Energy Holdings 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, whereby PSEG and its subsidiaries will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG Common Stock will be converted into 1.225 shares of Exelon Common Stock. The Merger Agreement has been unanimously approved by both companies' Boards of Directors. On July 19, 2005, shareholders of PSEG voted to approve the Merger, and on July 22, 2005, shareholders of Exelon voted to approve the issuance of common shares to PSEG shareholders to effect the Merger. Completion of the Merger is subject to approval by a number of governmental authorities. As described below, PSEG and Exelon have obtained all regulatory approvals from the principal agencies involved except the Nuclear Regulatory Commission (NRC), U.S. Department of Justice (DOJ) and the New Jersey Board of Public Utilities (BPU). On June 30, 2005, the Federal Energy Regulatory Commission (FERC) voted to approve the Merger. FERC determined that Exelon's and PSEG's proposed divestitures and other commitments in their original and supplemental filings with FERC, together with their answers to intervenors' questions, met the public interest standard of the Federal Power Act. Exelon and PSEG have committed to divest 4,000 megawatts (MW) of intermediate and peaking generation facilities located primarily in eastern PJM Interconnection, L.L.C. (PJM), and to “virtually divest” 2,600 MW of nuclear capacity by effectively transferring control of the output through sales to third parties. A number of parties filed requests for rehearing, which FERC denied on December 15, 2005. Several parties, including the BPU and the New Jersey RatePayer
Advocate have filed notices to appeal FERC's Order. During 2005, regulatory approvals or clearances related to the Merger were also obtained from the Connecticut Siting Council (CSC) regarding the transfer of PSEG Power Connecticut LLC's Certificate of Environmental Compatibility and Public Need to Exelon Generation Connecticut LLC, the New Jersey Department of Environmental Protection (NJDEP) under the Industrial Site Recovery Act, the New York Public Service Commission (NYPSC), FERC with respect to the transfer of the hydro license for Yards Creek Generating Station, the Indiana Utility Regulatory Commission, the Public Utility Commission of Texas and Brazil's Agencia Nacional de Energia Elétrica. On January 27, 2006, the Pennsylvania Public Utility Commission (PAPUC) approved the Merger, principally adopting a settlement by PECO Energy Company (PECO), an Exelon public utility subsidiary serving areas in Southeastern Pennsylvania, and PSE&G with a number of the parties to the proceeding representing consumer, business, environmental and low income interests. Pursuant to the settlement, if the Merger is consummated, PECO will provide $120 million over four years in rate discounts for customers and cap its rates through the end of 2010. The settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer and service reliability and pledges for charitable
donations and maintenance of its current headquarters at current staff levels in Philadelphia until the end of 2010. On February 8, 2006, PUHCA was repealed, obviating approval by the SEC under that statute. The NRC proceeding is essentially complete, and an order is pending. PSEG and Exelon presently expect to complete their responses to the current information requests of the DOJ under the HSR Act in the first quarter of 2006. Once the DOJ has evaluated the information submitted by PSEG, Exelon and others, PSEG and Exelon expect to discuss any suggestions or remedies proposed by the DOJ. 53
In New Jersey, the BPU issued an order requiring Exelon and PSEG to prove that positive benefits flow to PSE&G's customers and the State as a result of the Merger, and that, at a minimum, there be no adverse impact to competition, employees or reliability due to the Merger. The procedural schedule for the BPU's regulatory approval process in New Jersey includes opportunities for settlement discussions with the consumer advocacy groups and other interested parties during the course of the proceedings. In late November 2005, the BPU concluded five public hearings at which representatives from business, environmental coalitions, non-profit organizations and consumer groups offered opinions about the Merger. Representatives of the four unions representing workers at PSEG testified in support the Merger upon reaching an agreement with PSEG and Exelon that there will be no layoffs of union workers in New Jersey through the remaining five years of the unions' six-year contracts. The hearings related to the BPU review of the Merger, commenced on January 4, 2006 and are currently ongoing at the New Jersey Office of Administrative Law. The schedule most recently approved by the Administrative Law Judge (ALJ) provides for the hearings to be completed around the end of March 2006, to enable the PJM Market Monitor the opportunity to complete his analysis of the adequacy of the proposal by PSEG and Exelon to mitigate market power of the new company through the sale of 4,000 MW of fossil generation and the virtual divestiture of 2,600 MW of nuclear. No assurances can be given that such analysis will be completed or, if completed, will be acceptable to either PSEG or Exelon. During the hearings, other parties have proposed additional divestiture and have opposed the use of virtual divestiture to address
market power issues. During the hearings, PSEG and Exelon have also committed to provide rate credits to PSE&G's customers of $120 million over 3 or 4 years, to maintain PSE&G's capital expenditure program and to implement certain governance procedures. Settlement discussions began in December 2005 and are expected to resume after the hearings conclude. No assurances can be given as to whether any such discussions will result in settlements. No firm dates have been set for the ALJ's initial decision and final order from the BPU. Commonwealth Edison Co. (ComEd), a wholly owned subsidiary of Exelon providing retail electric service in Illinois, is involved in regulatory proceedings in Illinois pertaining to the restructuring of the Illinois electric markets, which began in 1997. Since that time, the rates of ComEd have been reduced and capped, and ComEd transferred or sold its generation assets to third parties or to its affiliate, Exelon Generation LLC (Exelon Generation). Currently, the rate freeze for ComEd and contractual power supply obligations of Exelon Generation to ComEd expire December 31, 2006. In January 2006, the Illinois Commerce Commission (ICC) approved, with certain modifications, a proposal by ComEd to procure power commencing January 1, 2007 through an auction designed to reflect market rates. Various parties to the proceeding,
including the Illinois Attorney General and the Citizens Utility Board have requested the ICC to reconsider its decision, and have indicated they will file appeals to the courts if the ICC ruling is not modified so as to disapprove the ComEd proposal. In addition, legislation has been introduced in the Illinois General Assembly to continue ComEd's rate freeze for an additional three years. ComEd has indicated that it believes that enactment of such legislation would violate Federal law and the U.S. Constitution. Nevertheless, ComEd has indicated that it cannot predict the outcome of these regulatory proceedings and legislative actions and that a rate freeze extension or other significant constraint on its ability to recover its power supply costs would have materially adverse financial and operating effects and would likely cause ComEd to resort to protection of the bankruptcy courts
to continue as a going concern. The regulatory and political developments in Illinois could also have an effect on the timing or closing conditions of the Merger. Exelon and PSEG presently expect to complete all of the regulatory reviews and close the Merger in the third quarter of 2006. Closing may occur earlier if a settlement is reached and accepted by the BPU. The Merger Agreement provides that if the Merger is not consummated by June 20, 2006, either party may terminate the Merger Agreement. Although Exelon and PSEG believe that the expectations as to timing for the closing of the Merger described above are reasonable, no assurances can be given as to the timing of the receipt of any remaining regulatory approvals, that all required approvals will be received, or that conditions in future regulatory orders will be acceptable to the parties or not have materially adverse conditions. PSEG is committed to maintaining a viable stand-alone business strategy in the event the Merger does not close. Management believes PSEG will continue to operate successfully; however, inability to close the Merger could have an impact on PSEG's and Power's credit ratings and could impact the financial condition, results of operations and cash flows of PSEG, PSE&G, Power and Energy Holdings. 54
OVERVIEW OF 2005 AND FUTURE OUTLOOK PSEG 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 is a discussion of the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG's businesses within these markets and significant events that have occurred during 2005 and expectations for 2006 and beyond. PSEG develops a long-range growth target by building business plans and financial forecasts for each major business (PSE&G, Power, Global and Resources). These plans and forecasts incorporate detailed estimates of revenues, operating and maintenance expenses, capital expenditures, financing costs and other material factors for each business. Key factors that may influence the performance of each business, such as fuel costs and forward power prices, are also incorporated. Sensitivity analyses are performed on the key variables that drive the businesses' financial results in order to understand the impact of these assumptions on PSEG's projections. Once plans are in place, PSEG management monitors actual results and key variables and updates financial projections to reflect changes in the energy markets, the
economy and regional and global conditions. PSEG management believes this monitoring and forecasting process enables it to alter operating and investment plans as conditions change. For 2006, PSEG expects Income from Continuing Operations to range from $3.45 to $3.75 per share, excluding Merger-related costs. The increase as compared to 2005 earnings is primarily due to anticipated higher earnings at Power, offset by modest reductions at PSE&G and Energy Holdings. The projected increase at Power is due to anticipated higher margins through the expiration of existing contracts and the realization of current and anticipated higher market prices, partially offset by increases in depreciation and interest expense associated with the new Linden plant expected to be placed into service in mid-2006 and a full-year of operations for the Bethlehem Energy Center which commenced commercial operations in July 2005, increased Operation and Maintenance costs and lower earnings from the Nuclear Decommissioning
Trust (NDT) Funds. The decrease at PSE&G is primarily due to the planning assumption of normal weather during 2006. The reduction at Energy Holdings is primarily due to the absence of the gain from the sale of Seminole Generation Station Unit 2 (Seminole). Also assumed in the earnings projections for 2006 are continued improved nuclear and fossil operations, a positive and timely outcome to the financial review by the BPU for PSE&G (discussed below) and continued strong contributions from Global's operations in Texas and South America. The earnings range for 2006 excludes the expected gain on the sale of Global's two generating facilities in Poland, Elektrocieplownia Chorzow Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina), which will be reflected in Discontinued Operations, as well as any potential finance costs associated with use of the proceeds. The guidance range
also does not contemplate the potential earnings fluctuations that could occur due to mark-to-market (MTM) accounting being applied to certain of Power's and Energy Holdings' operations pursuant to Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended and interpreted (SFAS 133). See Note 11. Risk Management of the Notes for additional information. In addition, PSEG anticipates earnings per share growth to be in excess of 10% per year for 2007 and 2008, which assumes continued improved operations at Power and reasonable outcomes in PSE&G's regulatory proceedings. PSEG expects operating cash flows beyond 2005 to be sufficient to meet capital needs and dividend requirements and may employ any excess cash to reduce debt, invest in its businesses, increase dividends or, in the longer term, repurchase shares. On January 17, 2006, PSEG announced an increase in its quarterly dividend from $0.56 to $0.57 per share for the first quarter of 2006. This increase reflects an indicated annual dividend rate of $2.28 per share. Several key factors that will drive PSEG's future success are energy, capacity and fuel prices, performance of Power's generating facilities, PSE&G's ability to maintain a reasonable rate of return under its regulated rate structure and the stability of international economies for Energy Holdings. PSE&G PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the BPU for its distribution operations and by FERC for its electric transmission and wholesale sales operations. 55
Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. In February 2006, 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. On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78% increase in its gas base rates to appropriately recover the cost of gas delivery and to be effective June 30, 2006. Approximately $55 million of the $133 million request is for an increase in book depreciation rates. The balance of the request will cover increased plant investment, higher operating expenses and provide an 11% return on equity. PSE&G's current gas base rates have been in effect since January 2002. The current schedule provides for a decision on the gas base rate case from the BPU in September 2006, with new rates effective October 1, 2006. PSE&G cannot predict the timing and amount of any rate relief. On August 19, 2005, the BPU approved PSE&G's request for an increase in its Basic Gas Supply Service (BGSS) commodity charge to its residential gas customers of approximately $163 million (excluding sales and use taxes (SUT)) in annual revenues effective September 1, 2005 or approximately 10.2% for the class average residential heating customer. On December 15, 2005, the BPU approved PSE&G's request for an additional increase of approximately $204 million (excluding SUT) or approximately 15.6% for the class average residential heating customer which became effective immediately. The December 15, 2005 BGSS increase was intended to eliminate any large underrecovery and is expected to produce a zero deferred balance at September 30, 2006 based on the conditions at the time of the filing and is also intended
to be in lieu of the 5% increases on December 1, 2005 and February 1, 2006. In 2006, PSE&G expects Income from Continuing Operations to range from $315 million to $335 million, which is slightly lower than results for 2005, primarily due to the planning assumption of normal weather conditions for 2006. Also included in PSE&G's projections is a positive and timely outcome, which cannot be assured, to the financial review at the BPU for approximately $64 million. As part of the settlement of PSE&G's electric base rate case in 2004, a $64 million annual depreciation credit was established. This credit expired on December 31, 2005. As part of the settlement, PSE&G was required to make a financial filing with the BPU in November 2005 to support a corresponding increase in rates to offset the loss of the depreciation credit. The BPU issued an order on February 7, 2006 and found that insufficient information had been provided to support the rate increase at the time. The order permits PSE&G to file, no later than June 15, 2006, actual data through March 31, 2006. The BPU will determine, based on the additional
information, if the rate increase is warranted. The impact of not receiving this increase reduces PSE&G's earnings and cash flows by more than $5 million (pre-tax) per month. The timing and amount of an increase cannot be predicted with certainty. The risks from this 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. In 2006 and beyond, PSE&G's success will depend, in part, on its ability to maintain a reasonable rate of return, including a reasonable outcome to its current Gas Base Rate Case and the ability to realize the approximate $64 million electric distribution rate increase per year beginning in 2006, continue cost containment initiatives, maintain system reliability and safety levels and continue to recover with an adequate return 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 extending from Maine to the Carolinas and the Atlantic Coast to Indiana. 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 generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear 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 56
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 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, 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. Recently, the price of many of these products has increased dramatically. These price increases have been accompanied by increases in volatility as well. 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 but the volatility in the market will also increase the risk to Power's results as the market changes are likely to impact the value of the uncontracted portion of Power's portfolio. 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 driven by dramatic increases in gas prices is anticipated to yield higher near-term margins for Power. In the near term, Power anticipates recognizing these higher 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 a more attractive environment for Power to contract the sale of its anticipated
output, allowing for potentially sustained higher profitability. Power believes that recent events in PJM, New York and the New England Power Pool (NEPOOL) have created the potential for incremental value to be received from the capacity markets for its units. These include existing and anticipated Reliability-Must-Run (RMR) contracts to provide generation unit owners with fixed reliability payments to enable their continued availability and potential changes in the nature of capacity markets which would provide generators with differentiated capacity payments based upon the location and operating characteristics of their respective facilities. During 2005, the rising commodity price environment resulted in increased liquidity requirements for Power's energy sales contracts entered into in the normal course of business. In response to such changes in the business environment, PSEG and Power obtained additional sources of liquidity. In addition, Accumulated Other Comprehensive Loss (OCL) increased as contracts that qualify for hedge accounting were marked to market. 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 nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of approximately two to four years. In 2005, these units produced over 85% of Power's generation, and given their historic low operating cost, an even higher percentage of the company's margin. As of February 15, 2006, Power has contracted for over 95% of its anticipated 2006 nuclear and coal-fired generation, with 85% to 95% contracted for 2007 and 65% to 80% contracted for 2008, with a relatively small amount contracted beyond 2008. 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 15, 2006, Power had contracted for 100% of its anticipated nuclear fuel needs through 2008, and approximately 75% of its average anticipated coal needs, including transportation, through 2008. 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 low-cost units. The natural gas-fired units generally provide a lower contribution to the margin of Power than either the nuclear or coal units. 57
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, a significant portion of Power's existing contractual obligations, entered into during lower-priced periods, resulted 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. Concurrent with the signing of the Merger Agreement, Power entered into an Operating Services Contract (OSC) with Exelon Generation. Under the terms of the OSC, since January 17, 2005, Exelon Generation has provided management personnel and its proprietary management systems under a fee arrangement to Power to operate the Salem and Hope Creek nuclear generating facilities. The OSC has a term of two years, subject to earlier termination in certain events upon prior notice, including any termination of the Merger Agreement. In the event of termination, Exelon Generation is required to continue to provide services under the OSC for a transition period of at least 180 days and up to two years at the election of Nuclear. This period may be further extended by Nuclear for up to an additional 12 months if Nuclear determines that
additional time is necessary to complete required activities during the transition period. On July 18, 2005, Power's new Bethlehem Energy Center (BEC), a 750 MW, natural gas -fired combined cycle power generation plant near Albany, New York, began commercial operations, replacing a 376 MW oil-fired facility at the same site. On September 28, 2005, Power completed the sale of its electric generation facility located in Waterford, Ohio (Waterford) to a subsidiary of American Electric Power Company, Inc. The sale price for the facility and inventory was $220 million. The proceeds, together with anticipated reduction in tax liability, were approximately $320 million, which will be used to retire debt at Power. See Note 4. Discontinued Operations, Dispositions and Acquisitions of the Notes for further discussion. In 2006, Power expects Income from Continuing Operations to range from $475 million to $525 million, reflecting continued improvements in the operating performance of its nuclear and fossil stations, strong energy markets and increased contracting opportunities. These increases will be partially offset by increases in depreciation and interest expense associated with the new Linden plant expected to be placed into service in mid-2006 and a full year for the Bethlehem Energy Center, increased Operation and Maintenance costs and lower earnings from the NDT Funds. The guidance range does not contemplate the potential earnings fluctuations that could occur due to MTM accounting being applied to Power's operations pursuant to SFAS 133. See Note 11. Risk Management of the Notes for additional information. 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 benefit from any future increases in market prices will depend, to a large extent, on efficient power plant operations, especially for its low-cost nuclear and coal-fired facilities. 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. For additional information on liquidity requirements, see Liquidity and Capital Resources. In addition,
forward prices are constantly changing and therefore there is no assurance that Power will be able to contract its output at attractive prices. 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 merchant generation companies, and Resources, which primarily invests in energy-related leveraged leases. Energy Holdings' earnings significantly exceeded its earnings guidance range in 2005 and previous years' results. The increase was driven by strong results in Global's generation projects in Texas and its South American distribution businesses and a gain on the sale of Resources' leveraged lease investment in Seminole. Also, Energy Holdings contributed over $400 million in cash distributions to PSEG while calling all $309 million of its 7.75% 2007 Senior Notes. In 2004, Energy Holdings contributed $475 million
to PSEG and redeemed over $300 million of debt. Energy Holdings' strong cash flow in 2005 was largely due to dividends from its investments, the repatriation of approximately $240 million of cash from its foreign investments under the 58
American Jobs Creation Act of 2004 (Jobs Act), the collection of the note receivable from the 2004 sale of MPC and the sale of Resources' investment in Seminole. For 2006, Energy Holdings expects Income from Continuing Operations to range from $155 million to $175 million. The expected 2006 range is less than the 2005 Income from Continuing Operations primarily due to a $43 million after-tax gain recognized in 2005 from the sale of Seminole. The earnings range for 2006 excludes the expected gain on the sale of Global's two generating facilities in Poland, Elcho and Skawina, which will be reflected in Discontinued Operations, as well as any potential finance costs associated with use of the proceeds. The guidance range also does not contemplate the potential earnings fluctuations that could occur due to MTM accounting being applied to Global's operations in Texas as the energy and gas contracts, which are backed by the physical capacity of the plant and sold in the normal
course of business, must be marked to market pursuant to SFAS 133. See Note 11. Risk Management of the Notes for additional information related to this contract. Global Although Global continues to produce significant earnings and operating cash flow, the returns on several of the investments in its international portfolio have not been commensurate with the level of risk associated with international investments in developing energy markets. As a result, since 2003, Energy Holdings has refocused its strategy from one of growth to one that places emphasis on increasing the efficiency and returns of its existing assets. Accordingly, Global continues to limit its capital spending, while focusing on operations and improved performance of existing businesses and is seeking to opportunistically monetize investments that may no longer have a strategic fit. On January 31, 2006, Energy Holdings entered into an agreement with CEZ a.s., the former Czech national utility company and the largest electric power company in central and eastern Europe, to sell Global's interest in two coal-fired plants in Poland, Elcho and Skawina. The sale is expected to close in the second quarter of 2006. Net proceeds from the sale are subject to various purchase price adjustments, foreign currency fluctuations and contingencies and are currently expected to be approximately $300 million after taxes and transaction costs, which is in excess of the book value of
the facilities as of December 31, 2005. In April 2005, Global sold a 35% interest in Dhofar Power Company S.A.O.C. (Dhofar Power), reducing its ownership interest from 81% to 46%, through a public offering on the Omani stock exchange for net proceeds of approximately $25 million. The capital requirements of Global's consolidated subsidiaries are primarily financed from internally generated cash flow within the projects and from local sources on a basis that is non-recourse to Global or limited discretionary investments by Energy Holdings. Under the provisions of the Jobs Act and the currently released IRS regulations, Global had a one-year window to repatriate earnings from its foreign investments and claim a special one-time 85% dividends received tax deduction on such distributions. In 2005, PSEG executed a total of three Domestic Reinvestment Plans under which approximately $242 million was repatriated, of which $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. Other than amounts remitted under the Jobs Act, Global has made no change in its current intention to indefinitely reinvest accumulated earnings of its foreign subsidiaries. Global's success will depend, in part, upon its ability to mitigate risks of its international strategy. The economic and political conditions in certain countries where Global has investments present risks that may be different or more significant than those found in the U.S. including: renegotiation or nullification of existing contracts, changes in law or tax policy, interruption of business, nationalization, expropriation, war and other factors. Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In some countries in which Global has interests, economic and monetary conditions and other factors could affect its ability to convert its cash distributions to U.S. Dollars or other freely convertible currencies. Furthermore,
the central bank of any such country may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to limit distributions to foreign investors. 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. Resources' ability to realize tax benefits associated with its leveraged lease investments is dependent upon taxable income 59
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, specifically certain lessees that collectively comprise a substantial portion of Resources' investment portfolio as discussed further below. Resources also faces risks related to potential changes in the current accounting and tax treatment of certain investments in leveraged leases. The manifestation of either of these risks could cause a materially adverse effect on Resources' strategy and its forecasted results of operations, financial position and net cash flows. In January 2005, Resources and Global sold their interests in three Solar Electric Generating Systems (SEGS) projects for proceeds of approximately $7 million. Also in January 2005, Resources also received proceeds of approximately $17 million from the KKR Fund's sale of its investment in KinderCare Learning Centers, Inc. In June 2005, Resources wrote off its entire investment of approximately $15 million, net of tax, in an aircraft lease to United Airlines (UAL) upon termination of the lease and repossession of the aircraft by the lenders in a bankruptcy proceeding with UAL. In December 2005, Resources sold its interest in Seminole in Palatka, Florida, to Seminole Electric Cooperative Inc. for $286 million. Seminole is a 659 MW coal-fired facility. It is one of two units at the Seminole plant. The sale resulted in a $43 million after-tax gain. Net proceeds of $235 million together with other funds were used to redeem Energy Holdings' $309 million outstanding 7.75% Senior Notes due in 2007. As of December 31, 2005, Resources has a remaining net investment in four leased aircraft of approximately $32 million. On September 14, 2005, Delta Airlines (Delta) and Northwest Airlines (Northwest), the lessees for Resources' four remaining aircraft, 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, 2005. In 2004 and 2005, Resources successfully restructured the leases and converted the Delta and Northwest leases from leveraged leases to operating leases. Energy Holdings expects to recover its investment through cash flows from the operating leases. During 2005, the IRS proposed to disallow certain deductions associated with some of the leveraged leases which have been designated by the IRS as listed transactions. In addition, a proposal by the Financial Accounting Standards Board (FASB) concerning leveraged leases would require a lessor to perform a recalculation of a leveraged lease when there is a change in the timing of the realization of tax benefits generated by the lease. If implemented in its present form, the impact of this proposal could be material. For additional information, see Note 12. Commitments and Contingent Liabilities of the Notes. 60
PSEG, PSE&G, Power and Energy Holdings 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 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 and Dispositions of the Notes. Net Income for the year ended December 31, 2004 was $726 million or $3.05 per share of common stock, diluted, based on approximately 238 million average shares outstanding. Net Income for the year ended December 31, 2003 was approximately $1.2 billion or $5.07 per share of common stock, diluted, based on approximately 229 million average shares outstanding. Included in 2003's Net Income was a $370 million after-tax Cumulative Effect of a Change in
Accounting Principle related to the adoption in 2003 of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). See Note 3. Asset Retirement Obligations of the Notes. PSE&G Power Energy Holdings: Global Resources Other(A) Total Energy Holdings Other(B) PSEG Income from Continuing Operations Loss from Discontinued Operations, including Gain (Loss) on Disposal(C) Extraordinary Item(D) Cumulative Effect of a Change in Accounting Principle(E) PSEG Net Income PSE&G Power Energy Holdings: Global Resources Other(A) Total Energy Holdings Other(B) PSEG Income from Continuing Operations Loss from Discontinued Operations, including Gain (Loss) on Disposal(C) Extraordinary Item(D) Cumulative Effect of a Change in Accounting Principle(E) PSEG Net Income 61
The $88 million, or $0.28 per share, increase in Income from Continuing Operations for the year ended December 31, 2005, as compared to the same period in 2004, was primarily due to higher earnings at Power. Power's 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 August 2005 and Lawrenceburg, Indiana, which commenced operation in June 2004.
Energy Holdings also contributed to the increase with higher earnings due to improved operations at Texas Independent Energy, L.P. (TIE) and in South America and an after-tax gain of $43 million from the sale of Resources' leveraged lease investment in Seminole in December 2005. At PSE&G, higher margins, due to favorable weather conditions, and reduced interest expense were substantially offset by higher Operation and Maintenance costs. These increases were partially offset by after-tax Merger-related costs of approximately $32 million at PSEG, PSE&G and Power in 2005 and approximately $4 million at PSEG in 2004. The $85 million, or $0.51 per share, decrease in Income from Continuing Operations for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to lower earnings at Power due to decreased load being served under the fixed-price BGS contracts, higher Operation and Maintenance costs primarily incurred for work performed during a longer-than-planned refueling outage at the Hope Creek nuclear unit, the loss of Market Transition Charge (MTC) revenues, which ceased effective August 1, 2003 at the end of the transition period and higher replacement power and congestion costs in 2004. Also contributing to the decrease were currency fluctuations at Global and lower earnings at Resources, primarily resulting from the termination of the Collins lease. These decreases were partially offset by improved
earnings at PSE&G, primarily relating to increased electric base rates. Changes in Net Income were also attributable to Loss from Discontinued Operations due to Power's sale of Waterford in 2005 and Energy Holdings' sale of its majority interests in Elcho and Skawina on January 31, 2006 and its sales of CPC in 2004 and Energy Technologies in 2003. Power reported Losses from Discontinued Operations of $198 million (including a loss of $178 million on disposal of Waterford), $34 million and $9 million in 2005, 2004 and 2003, respectively. Energy Holdings reported Income from Discontinued Operations of $18 million in 2005 and Losses from Discontinued Operations of $10 million in 2004 and $38 million in 2003. 62
PSEG Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Income from Equity Method Investments Other Income Other Deductions Interest Expense Income Tax Expense Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax Extraordinary Item, net of tax Cumulative Effect of a Change in Accounting Principle, net of tax 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 Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income Other Deductions Interest Expense Income Tax Expense 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. Operating Revenues increased $756 million for the year ended December 31, 2005, as compared to the same period in 2004, due to increases of $667 million in commodity revenues, $82 million in delivery revenues and $7 million in other operating revenues. Operating Revenues increased $232 million for the year ended December 31, 2004, as compared to the same period in 2003, due to increases of $13 million in commodity revenues, $198 million in delivery revenues and $21 million in other operating revenues. 63
PSE&G makes no margin on commodity sales as the costs are passed through to customers. The difference between costs and the amount paid by customers in revenues is deferred and collected from or returned to customers in future periods. Total commodity volumes and revenues are subject to market forces. 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. Commodity revenues increased $667 million for the year ended December 31, 2005, as compared to the same period in 2004, due to increases of $305 million in electric commodity revenues, $235 million primarily due to higher BGS and Non-Utility Generation (NUG) prices and $70 million in higher volumes due to weather. Also contributing to the increase was $362 million in increased gas commodity revenues, $392 million primarily due to higher BGSS prices, offset by a $42 million decrease due to the expiration of the Third Party Shopping Incentive on July 1, 2005. There is a corresponding $42 million increase in delivery revenues, described below. Also contributing to the increase is $12 million in higher volumes, primarily due to increased cogeneration operations. Commodity revenues increased $13 million for the year ended December 31, 2004, as compared to the same period in 2003. This was due to increases of $16 million in electric commodity revenues, $249 million from higher BGS prices offset by $233 million in lower volumes due to the migration of large customers to third-party suppliers. This was offset by $3 million in decreased gas commodity revenues, $249 million primarily due to higher BGSS prices, offset by $252 million in lower volumes, primarily due to decreased cogeneration operations. The $82 million increase in delivery revenues for the year ended December 31, 2005, as compared to the same period in 2004, was due to increases of $75 million in electric revenues and $7 million in gas revenues. The $75 million in electric revenues was primarily due to higher volumes of $68 million due to weather and $7 million due to increased distribution prices. The $7 million in increased gas revenues was due to the expiration of the Third Party Shopping Incentive Fund on July 1, 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 Societal Benefits Clause (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. The $198 million increase in delivery revenues for the year ended December 31, 2004, as compared to the same period in 2003, was due to increases of $222 million in electric revenues offset by decreases of $24 million in gas revenues. The $222 million in electric revenues was primarily due to $180 million in increased prices due to the effect of full-year base rate increases in August 2003 and other rate adjustments in January 2004 and increased volumes of $42 million. The $24 million in decreased gas revenues was primarily due to $18 million in lower volumes due to weather and $5 million due to lower prices. Operating Expenses The $686 million increase for the year ended December 31, 2005, as compared to the same period in 2004, was comprised of increases of $319 million in electric costs and $367 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 $315 million or 17% increase in gas prices and an $89 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. The $137 million decrease for the year ended December 31, 2004, as compared to the same period in 2003, was comprised of decreases of $96 million in electric costs and $41 million in gas costs. The electric decrease was caused by $262 million in lower BGS volumes due to customer migration to third-party suppliers offset by $166 million or 6% in higher prices for BGS and NUG purchases. The gas decrease was 64
caused by a $388 million or 20% decrease in sales volumes due primarily to lower sales to cogenerators offset by a $347 million or 26% increase in gas prices. The $68 million increase for 2005, as compared to the same period in 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 Net Operating Losses. SBC costs are deferred when incurred and amortized to expense when recovered in revenues. The $33 million increase for 2004, as compared to the same period in 2003, was due primarily to increased Demand Side Management (DSM) amortization of $20 million, increased consumer education expenses of $24 million, an $18 million reduction in real estate tax expense in 2003 and $10 million related to a regulatory asset reserve reversal in 2003. DSM costs are deferred when incurred and amortized to expense when recovered in revenues. Offsetting the increases were decreased labor and fringe benefits of $7 million, due to lower pension costs as a result of improved fund performance, a $22 million reduction in SBC expenses and $10 million in lower shared services costs due to reduced technology spending. The $30 million increase the year ended December 31, 2005, as compared to the same period in 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 Remediation Adjustment Clause (RAC). These were offset by an $8 million decrease in software amortization and a $3 million increase in excess depreciation reserve amortization. The $151 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to a $132 million reduction in amortization of an excess electric distribution depreciation reserve regulatory liability, a $30 million increase in the amortization of various regulatory assets and a $10 million increase due to increased plant in service. These increases were offset by a $16 million decrease from the use of a lower book depreciation rate for electric distribution property, which took effect in August 2003 following the conclusion of the electric base rate case, and a $6 million decrease due to plant assets transferred to an affiliate in 2003. The $3 million increase for the year ended December 31, 2005, as compared to the same period in 2004, was due primarily to increases of $3 million due to the sale of land and $1 million of interest income offset by $1 million in lower realized gains on investments. The $6 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to $11 million of equity return adjustments to regulatory assets in 2003, $4 million of interest income related to an affiliate loan and other Investment Income of $3 million offset by decreased gains on excess property sales of $12 million. The $20 million decrease for the year ended December 31, 2005, as compared to the same period in 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. The $28 million decrease for the year ended December 31, 2004, as compared to the same period in 2003, was due primarily to lower interest on long-term debt of $37 million as a result of lower interest rates and lower levels of long-term debt outstanding, partially offset by $11 million in increased interest on affiliated loans. 65
The $11 million decrease for the year ended December 31, 2005, as compared to the same period in 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. The $117 million increase for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to higher pre-tax income combined with lower tax benefits primarily attributable to the excess depreciation reserve adjustment in 2003. Power Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income Other Deductions Interest Expense Income Tax Expense Loss from Discontinued Operations, including Loss on Disposal, net of tax Cumulative Effect of a Change in Accounting Principle, net of tax Operating Revenues increased $891 million for the year ended December 31, 2005, as compared to the same period in 2004, due to increases of $573 million in generation revenues and $368 million in gas supply revenues partly offset by a decrease of $50 million in trading revenues. Operating Revenues decreased by $440 million for the year ended December 31, 2004, as compared to the same period in 2003, due to decreases of $485 million in generation revenues and $6 million in trading revenues offset by an increase of $51 million in gas supply revenues. Generation revenues increased $573 million for the year ended December 31, 2005, as compared to the same period in 2004, primarily due to higher revenues of approximately $256 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 approximately $103 million from new wholesale contracts, approximately $74 million from operations in New York, largely due to the commencement of BEC's operations in July 2005, partially offset by operations of the Albany Steam Station which was operational in 2004 and retired in February 2005, approximately $65 million from Reliability Must-Run (RMR) revenues which Power began receiving in 2005
for certain of its generating facilities and approximately $75 million from increased ancillary services and operating reserves. Generation revenues decreased $485 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to $1.1 billion in lower revenues due to decreased load being served under the fixed-priced BGS contracts, which was partially offset by $869 million of higher revenues from new contracts and higher sales into the various power pools. Additionally, the loss of MTC and NDT revenues, which amounted to $111 million and $17 million, respectively, comprised part of the decrease. Also contributing to the decrease in 2004 from 2003 was the adoption of Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities,” and Not “Held 66
for Trading Purposes” as defined in EITF 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” (EITF 03-11), which requires gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 to be shown net when recognized in the Consolidated Statement of Operations, whether or not settled physically, if the derivative instruments are “held for trading purposes” as defined in EITF 02-3, which became effective on a prospective basis for transactions occurring after September 30, 2003. Since prior periods were not restated in 2004, the effect of adopting EITF 03-11 reduced Power's Operating Revenues by approximately $174 million, with an equal reduction in Energy Costs, as compared
to the same period in 2003. Gas supply revenues increased $368 million for the year ended December 31, 2005, as compared to the same period in 2004, 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. Gas supply revenues increased by $51 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to higher gas prices under the BGSS contract partially offset by decreased sales volumes mainly due to lower demand by PSE&G. The $50 million decrease in trading revenues for the year ended December 31, 2005, as compared to the same period in 2004, resulted principally from reductions in realized gains related to emission credits. The $6 million decrease in trading revenues for the year ended December 31, 2004, as compared to the same period in 2003, was primarily due to market conditions. Operating Expenses 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. Energy Costs increased approximately $732 million for the year ended December 31, 2005, as compared to the same period in 2004, primarily due to increased generation costs, reflecting higher fossil fuel prices and higher prices on increased volume of purchased power for new contracts and higher prices for gas purchased to satisfy Power's BGSS obligations. Energy Costs decreased approximately $196 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to a $213 million decrease in purchased power due to decreased load being served under the BGS contracts, which was offset by increased replacement power costs due to outages and higher purchased power for new contracts and a $12 million increase in gas supply costs due to higher gas prices. Also contributing to the decrease for the year was a reduction of approximately $174 million related to the adoption of EITF 03-11, as discussed above. Partially offsetting these decreases were higher fuel costs for generation of approximately $159 million, primarily related to higher gas prices and higher usage, including an increase of approximately $20 million related to the settlement for
nuclear waste storage costs for Peach Bottom. For additional information regarding the settlement, see Note 12. Commitments and Contingent Liabilities—Nuclear Fuel Disposal of the Notes. Operation and Maintenance expense decreased $5 million for the year ended December 31, 2005, as compared to the same period in 2004, primarily due to a decrease of $36 million in equipment repair costs related to outages at the nuclear facilities as well as $9 million of lower real estate taxes, $5 million of lower transmission fees in the power pools 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, a $14 million restructuring charge recorded in 2005 related to 67
Nuclear's workforce realignment plan and a $12 million U.S. Department of Energy (DOE) settlement in 2004. Operation and Maintenance expense increased $43 million for the year ended December 31, 2004, as compared to the same period in 2003, due to increased costs of $85 million related to the outages at Hope Creek, Salem and Mercer. This was offset by $12 million related to the settlement for nuclear waste storage costs for Peach Bottom and $10 million in lower real estate taxes and other items. Additional offsets include the absence of reorganization costs of $9 million and the lower write-down costs related to obsolete materials and supplies of $8 million. For additional information regarding the settlement, see Note 12. Commitments and Contingent Liabilities—Nuclear Fuel Disposal of the Notes. Depreciation and Amortization expense increased $23 million for the year ended December 31, 2005, as compared to the same period in 2004, primarily due to the BEC facility being placed into service in July 2005 and a higher depreciable asset base in 2005 at Nuclear. The increase is also due to the Lawrenceburg facility being placed into service in June 2004. Depreciation and Amortization expense increased $11 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to the Lawrenceburg facility. Other Income increased $19 million for the year ended December 31, 2005, as compared to the same period in 2004, primarily due to increased realized gains and income related to the NDT Funds and a $5 million gain from the sale in September 2005 of four gas turbine generators located in Burlington, New Jersey. Other Income increased $17 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to increased realized gains and income related to the NDT Funds. Other Deductions decreased $12 million for the year ended December 31, 2005, as compared to the same period in 2004, primarily due to decreased realized losses of $8 million related to the NDT Funds and a write-off of $5 million of unamortized issuance costs in the first quarter of 2004 related to the extinguishment of non-recourse financing of the Lawrenceburg facility. Other Deductions decreased $23 million for the year ended December 31, 2004, as compared to the same period in 2003, primarily due to $28 million in lower realized losses and expenses related to the NDT Funds, partially offset by a $5 million write-off of unamortized issuance costs related to the extinguishment non-recourse financing of the Lawrenceburg facility. Interest Expense increased $18 million for the year ended December 31, 2005, as compared to the same period in 2004, due primarily to $23 million of lower capitalized interest costs in 2005 related to commencement of operations of the Lawrenceburg and BEC facilities in June 2004 and July 2005, respectively, partially offset by an overall decrease of $8 million due to the extinguishment of project debt and issuance of new long-term debt at more favorable pricing in March 2004. Interest Expense increased $6 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to $4 million related to an affiliate loan and additional interest on increased levels of long-term debt outstanding. Income taxes increased $90 million for the year ended December 31, 2005, as compared to the same period in 2004, 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. 68
Income taxes decreased $123 million for the year ended December 31, 2004, as compared to the same period in 2003, due primarily to lower pre-tax income and the aforementioned $16 million reversal of contingency reserves and other prior period adjustments. Loss from Discontinued Operations, including Loss on Disposal, net of tax 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. The proceeds, together with anticipated reduction in tax liability, were approximately $320 million, which will be used to retire debt at Power. Power's Losses from Discontinued Operations of Waterford, not including the Loss of Disposal, were $20 million, $34 million and $9 million for the years ended December 31, 2005, 2004 and 2003, respectively. See Note 4. Discontinued Operations, Dispositions and Acquisitions 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. For the year ended December 31, 2003, Power recorded an after-tax benefit in the amount of $370 million due to the required remeasurement of Power's nuclear and fossil decommissioning obligations under SFAS 143, which was adopted on January 1, 2003. See Note 3. Asset Retirement Obligations of the Notes for additional information. Energy Holdings Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Income from Equity Method Investments Other Income Other Deductions Interest Expense Income Tax Expense | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
