UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
100 F. ST N.E.
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
S ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006,
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO .
|
Commission File Number |
Registrants, State of Incorporation, Address, and Telephone Number |
I.R.S. Employer Identification No. |
||
| 001-09120 |
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza, P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com |
22-2625848 | ||
| 001-00973 |
PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza, P.O. Box 570 Newark, New Jersey 07101-0570 973 430-7000 http://www.pseg.com |
22-1212800 | ||
| 000-49614 |
PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza—T25 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com |
22-3663480 | ||
| 000-32503 |
PSEG ENERGY HOLDINGS L.L.C. (A New Jersey Limited Liability Company) 80 Park Plaza—T20 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com |
42-1544079 | ||
Securities registered pursuant to Section 12(b) of the Act:
| Registrant | Title of Each Class |
Name of Each Exchange On Which Registered |
||
|
Public Service Enterprise Group Incorporated |
Common Stock without par value |
New York Stock Exchange | ||
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.
|
Registrant |
Title of Each Class | Title of Each Class |
Name of Each Exchange On Which Registered |
||||||||||||
|
Public Service Electric and Gas Company |
Cumulative Preferred Stock $100 par value Series: |
First and Refunding Mortgage Bonds: |
|||||||||||||
| Series | Due | ||||||||||||||
| 4.08% | 91/4 | % | CC | 2021 | |||||||||||
|
|
4.18% | 63/4 | % | VV | 2016 | New York Stock Exchange | |||||||||
| 4.30% | 61/4 | % | WW | 2007 | |||||||||||
|
|
5.05% | 63/8 | % | YY | 2023 | ||||||||||
| 5.28% | 8 | % | 2037 | ||||||||||||
|
|
5 | % | 2037 | ||||||||||||
(Cover continued on next page)
(Cover continued from previous page) Public Service Enterprise
Group Incorporated Public Service Electric and
Gas Company PSEG Power LLC PSEG Energy Holdings
L.L.C. Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Public Service Enterprise Group Incorporated Public Service Electric and Gas Company PSEG Power LLC PSEG Energy Holdings L.L.C. 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. Public Service Enterprise Group Incorporated Public Service Electric and Gas Company PSEG Power L.L.C. PSEG Energy Holdings L.L.C. 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, 2006 was $16,424,868,840 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, 2007, 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
Securities registered pursuant to Section 12(g) of the Act:
Registrant
Title of Class
Floating Rate Capital Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Debentures), $1,000 par value issued by Enterprise Capital Trust II (Registrant), LIBOR plus 1.22%
Floating Rate Notes, Series A
6.92% Cumulative Preferred Stock $100 par value
Medium-Term Notes, Series A
Medium-Term Notes, Series B
Medium-Term Notes, Series C
Medium-Term Notes, Series D
Limited Liability Company Membership Interest
Limited Liability Company Membership Interest
Yes S
No £
Yes £
No S
Yes £
No S
Yes £
No S
(Check one):
Large accelerated filer S
Accelerated filer £
Non-accelerated filer £
Large accelerated filer £
Accelerated filer £
Non-accelerated filer S
Large accelerated filer £
Accelerated filer £
Non-accelerated filer S
Large accelerated filer £
Accelerated filer £
Non-accelerated filer S
Class
Outstanding at January 31, 2007
Common Stock, without par value
252,771,080
Part of Form 10-K of
Public Service
Enterprise
Group Incorporated
Documents Incorporated by Reference
III
Portions of the definitive Proxy Statement for the 2007 Annual Meeting of Stockholders of Public Service
Enterprise Group Incorporated, which definitive Proxy Statement is expected to be filed with the
Securities and Exchange Commission on or about March 5, 2007, as specified herein.
TABLE OF CONTENTS i
ii
Page
Note 21. Related-Party Transactions
188
Note 22. Guarantees of Debt
191
Note 23. Subsequent Events
192
Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
193
Item 9A.
Controls and Procedures
193
Item 9B.
Other Information
193
PART III
Item 10.
Directors and Executive Officers of the Registrants
196
Item 11.
Executive Compensation
200
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
223
Item 13.
Certain Relationships and Related Transactions
224
Item 14.
Principal Accounting Fees and Services
225
PART IV
Item 15.
Exhibits and Financial Statement Schedules
226
Schedule II—Valuation and Qualifying Accounts
237
Signatures
240
Exhibit Index
244
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 affect 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: • ability to attain satisfactory regulatory results; • operating performance or cash flow from investments falling below projected levels; • credit, commodity, interest rate, counterparty and other financial market risks; • liquidity and the ability to access capital and maintain adequate credit ratings; • adverse or unanticipated weather conditions that significantly impact costs and/or operations, including generation; • ability to attract and retain management and other key employees; • changes in the electric industry, including changes to power pools; • changes in energy policies and regulation; • changes in demand; • changes in the number of market participants and the risk profiles of such participants; • availability of power transmission facilities that impact the ability to deliver output to customers; • growth in costs and expenses; • environmental regulations that significantly impact operations; • changes in rates of return on overall debt and equity markets that could adversely impact the value of pension and other postretirement benefits assets and liabilities and the Nuclear
Decommissioning Trust Funds; • changes in political conditions; • changes in technology that make generation, transmission and/or distribution assets less competitive; • continued availability of insurance coverage at commercially reasonable rates; • involvement in lawsuits, including liability claims and commercial disputes; • acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG’s, PSE&G’s, Power’s and Energy Holdings’ strategy or structure; • business combinations among competitors and major customers; • general economic conditions, including inflation or deflation; • changes in tax laws and regulations; • changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements; • ability to recover investments or service debt as a result of any of the risks or uncertainties mentioned herein; • acts of war or terrorism; iii
•
regulatory issues that significantly impact operations;
PSEG, PSE&G and Energy Holdings PSEG, Power and Energy Holdings • inability to meet generation operating performance expectations; • energy transmission constraints or lack thereof; • adverse changes in the market for energy, capacity, natural gas, emissions credits, congestion credits and other commodity prices, especially during significant price movements for natural gas and
power; • adverse market developments or changes in market rules, including delays or impediments to implementation of reasonable capacity markets; • surplus of energy capacity and excess supply; • substantial competition in the domestic and worldwide energy markets; • margin posting requirements, especially during significant price movements for natural gas and power; • availability of fuel and timely transportation at reasonable prices; • effects on competitive position of actions involving competitors or major customers; • changes in product or sourcing mix; • delays, cost escalations or unsuccessful construction and development; PSEG and Power • ability to maintain nuclear operating performance at projected levels; PSEG and Energy Holdings • deterioration in the credit of lessees and their ability to adequately service lease rentals; • ability to realize tax benefits; • changes in political regimes in foreign countries; and • international developments negatively impacting business. 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
•
adverse changes in rate regulation and/or ability to obtain adequate and timely rate relief;
•
inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations;
•
changes in regulation and safety and security measures at nuclear facilities;
•
changes in foreign currency exchange rates;
WHERE TO FIND MORE INFORMATION 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 has four principal direct
wholly owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services). The following organization chart shows PSEG and its principal subsidiaries, as well as the principal
operating subsidiaries of Power: PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T); and of Energy Holdings: PSEG Global L.L.C. (Global) and
PSEG Resources L.L.C. (Resources): PSEG is an energy company with a diversified business mix. PSEG’s operations are primarily in the Northeastern and Mid Atlantic United States (U.S.) and in other select markets. As the competitive
portion of PSEG’s business has grown, the resulting financial risks and rewards have become greater, causing financial requirements to change and increasing the volatility of earnings and cash flows. For additional information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)—Overview of 2006 and Future Outlook. 1
Termination of Merger Agreement On December 20, 2004, PSEG entered into an Agreement and Plan of Merger (Merger Agreement) with Exelon Corporation (Exelon) providing for a merger of PSEG with and into Exelon (Merger).
On September 14, 2006, PSEG received from Exelon a formal notice terminating the Merger under the provisions of the Merger Agreement. PSE&G is a New Jersey corporation, incorporated in 1924, and has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSE&G is an operating public utility company engaged
principally in the transmission and distribution of electric energy and gas in New Jersey. In addition, PSE&G owns PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC
(Transition Funding II), which are bankruptcy-remote entities that purchased the irrevocable right to receive certain non-bypassable charges per Kilowatt-hour (kWh) of energy delivered to PSE&G
customers and issued transition bonds secured by such property. PSE&G provides electric and gas service in areas of New Jersey in which approximately 5.5 million people, about 70% of the state’s population, reside. PSE&G’s electric and gas service area is a corridor
of approximately 2,600 square miles running diagonally across New Jersey from Bergen County in the northeast to an area below the city of Camden in the southwest. The greater portion of this area is
served with both electricity and gas, but some parts are served with electricity only and other parts with gas only. This heavily populated, commercialized and industrialized territory encompasses most of
New Jersey’s largest municipalities, including its six largest cities—Newark, Jersey City, Paterson, Elizabeth, Trenton and Camden—in addition to approximately 300 suburban and rural communities. This
service territory contains a diversified mix of commerce and industry, including major facilities of many nationally prominent corporations. PSE&G’s load requirements are split among residential, commercial
and industrial customers, described below under customers. PSE&G believes that it has all the non-exclusive franchise rights (including consents) necessary for its electric and gas distribution operations in the
territory it serves. Energy Supply PSE&G distributes electric energy and gas to end-use customers within its designated service territory. All electric and gas customers in New Jersey have the ability to choose an electric energy and/or
gas supplier. Pursuant to the New Jersey Board of Public Utilities (BPU) requirements, PSE&G serves as the supplier of last resort for electric and gas customers within its service territory. PSE&G earns no
margin on the commodity portion of its electric and gas sales. As shown in the table below, PSE&G continues to provide the electric energy and gas supply for the majority of the customers in its service territory for the year ended December 31, 2006. PSE&G Third Party Suppliers Total Delivered New Jersey’s Electric Distribution Companies (EDCs), including PSE&G, provide two types of Basic Generation Service (BGS). BGS-Fixed Price (FP) provides supply for smaller commercial and
residential customers at seasonally-adjusted fixed prices and BGS-Commercial and Industrial Energy Price (CIEP) provides supply for larger customers at hourly PJM Interconnection, L.L.C. (PJM) real-
time market prices. BGS prices are determined through annual auctions conducted before the BPU. PSE&G has a full requirements contract with Power to meet the Basic Gas Supply Service (BGSS) requirements of PSE&G’s gas customers. The contract term extends to March 31, 2012, and year-to-year
thereafter. Power charges PSE&G for gas commodity costs which PSE&G recovers from its customers. Any difference between the BGS and BGSS costs and revenues received from PSE&G’s residential customers are deferred and collected or refunded through adjustments in future rates. 2
GWH
%
Million Therms
%
34,340
79
1,975
62
9,323
21
1,194
38
43,663
100
3,169
100
Distribution Rates PSE&G earns margins through the transmission and distribution of electricity and gas. PSE&G’s revenues for these services are based upon tariffs approved by the BPU and FERC. Approximately 98% of
PSE&G’s 2006 revenues were covered by BPU tariffs. The demand for electric energy and gas by PSE&G’s customers is affected by customer conservation, economic conditions, weather and other factors not
within PSE&G’s control. On November 9, 2006 the BPU approved separate settlements providing for increases in PSE&G’s electric and gas base rates. The settlements include a restriction against any further base rate changes
becoming effective before November 15, 2009. In addition, PSE&G must file a joint electric and gas petition for any future base rate increases. For additional information on these settlements, see Regulatory
Issues—State Regulation. Market Price Environment Over the past few years, there has been a significant volatility in commodity prices, including fuel, emission allowances and electricity. Such volatility can have a considerable impact on PSE&G since a
rising commodity price environment results in higher delivered electric and gas rates for end-use customers, and may result in decreased demand by end users of both electricity and gas, increased regulatory
pressures and greater working capital requirements as the collection of higher commodity costs may be deferred under PSEG’s regulated rate structure. For additional information see Item 7. MD&A. Competitive Environment The electric and gas transmission and distribution business has minimal risks from competitors. PSE&G’s transmission and distribution business is minimally impacted when customers choose alternate
electric or gas suppliers since PSE&G earns its return by providing transmission and distribution service, not by supplying the commodity. Customers As of December 31, 2006, PSE&G provided service to approximately 2.1 million electric customers and approximately 1.7 million gas customers, detailed below. In addition to its transmission and
distribution business, PSE&G also offers appliance services and repairs to customers throughout its service territory. Customer Type Commercial Residential Industrial Total Employee Relations As of December 31, 2006, PSE&G had 6,154 employees. PSE&G has six-year collective bargaining agreements, which were ratified in 2005, with four unions representing 4,955 employees. PSE&G believes
that it maintains satisfactory relationships with its employees. Power Power is a Delaware limited liability company, formed in 1999, and has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Power is a multi-regional, wholesale energy supply
company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management functions through three principal direct wholly owned
subsidiaries: Nuclear, Fossil and ER&T. As of December 31, 2006, Power’s generation portfolio consisted of approximately 14,639 MW of installed capacity, which is primarily located in the Northeast and Mid Atlantic regions of the U.S.
where 3
% of Sales
Electric
Gas
56
%
36
%
31
%
60
%
13
%
4
%
100
%
100
%
some of the nation’s largest and most developed energy markets are located. For additional information, see Item 2. Properties. As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a
series of energy-related products used to optimize the operation of the energy grid, known as ancillary services. Power’s revenues also include gas supply sales under the BGSS contract with PSE&G. Nuclear Nuclear has an ownership interest in five nuclear generating units: the Salem Nuclear Generating Station, Units 1 and 2 (Salem 1 and 2), each owned 57.41% by Nuclear and 42.59% by Exelon
Generation; the Hope Creek Nuclear Generating Station (Hope Creek), which is owned 100% by Nuclear; and, the Peach Bottom Atomic Power Station Units 2 and 3 (Peach Bottom 2 and 3), each of
which is operated by Exelon Generation and owned 50% by Nuclear and 50% by Exelon Generation. For additional information, see Item 2. Properties—Power. Nuclear Operations In January 2005, Nuclear entered into an Operating Service Contract (OSC) with Exelon Generation relating to the operation of the Hope Creek and Salem nuclear generating stations. The OSC
requires Exelon Generation to provide key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement a management model that Exelon has
used to manage its own nuclear facilities. Nuclear continues as the license holder with exclusive legal authority to operate and maintain the Salem and Hope Creek plants, retains responsibility for
management oversight and has full authority with respect to the marketing of its share of the output from the facilities. In October 2006, Nuclear informed Exelon Generation that it was electing to continue
the OSC for up to two years beyond the initial January 2007 period. In December 2006, Power announced its plans to resume direct management of the Salem and Hope Creek nuclear generating stations before the expiration of the OSC. As part of this plan, on January
1, 2007, the senior management team at Salem and Hope Creek, which consisted of three senior executives from Exelon Generation, became employees of Power. During 2006, over half of Power’s generating output was from its nuclear generating stations. Nuclear unit capacity factors for 2006 were as follows: Unit Salem Unit 1 Salem Unit 2 Hope Creek Peach Bottom Unit 2 Peach Bottom Unit 3 Total Power Ownership For additional information on recent operational issues, see Regulatory Issues—Nuclear Regulatory Commission (NRC). Nuclear Fuel Nuclear has several long-term purchase contracts for the supply of nuclear fuel for the Salem and Hope Creek Nuclear Generating Stations which include: • conversion of uranium concentrates to uranium hexafluoride; • enrichment of uranium hexafluoride; and • fabrication of nuclear fuel assemblies. 4
Capacity
Factor*
100.7
%
93.6
%
92.6
%
93.3
%
101.8
%
95.9
%
*
Maximum Dependable Capacity (MDC) net.
•
purchase of uranium (concentrates and uranium hexafluoride);
The nuclear fuel markets are competitive and although prices for uranium, conversion and enrichment are increasing, Nuclear does not anticipate any significant problems in meeting its future
requirements. Nuclear has been advised by Exelon Generation that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom. For additional information, see Item 7. MD&A—Overview of 2006
and Future Outlook—Power and Note 12. Commitments and Contingent Liabilities of the Notes. Fossil Fossil has an ownership interest in 17 generating stations, primarily in the Northeast and Mid Atlantic U.S., including the Bethlehem Energy Center in New York and the Linden station in New Jersey,
which were completed and placed in service in 2005 and 2006, respectively. Power’s facility in Indiana, the Lawrenceburg Energy Center, is currently under an agreement to be sold. For additional
information, see Item 2. Properties—Power. Fossil uses coal, natural gas and oil for electric generation. These fuels are purchased through various contracts and in the spot market and represent a significant portion of Power’s working capital
requirements. In order to minimize emissions levels, the Bridgeport generating facility uses a specific type of coal, which is obtained from Indonesia through a fixed-price supply contract that runs through
2008. If the supply of coal from Indonesia or equivalent coal from other sources was not available for the Connecticut facilities, additional material capital expenditures could be required to modify the
existing plants to enable their continued operation. In addition, the Hudson facility, under a consent decree with the New Jersey Department of Environmental Protection (NJDEP) and the U.S.
Environmental Protection Agency (EPA), will also utilize this type of coal. Power believes it has access to sufficient fuel supply, including transportation, for its facilities over the next several years. For
additional information, see Item 7. MD&A—Overview of 2006 and Future Outlook—Power and Note 12. Commitments and Contingent Liabilities of the Notes. ER&T ER&T purchases the capacity and energy produced by each of the generation subsidiaries of Power. In conjunction with these purchases, ER&T uses commodity and financial instruments designed to cover
estimated commitments for BGS and other bilateral contract agreements. ER&T also markets electricity, capacity, ancillary services and natural gas products on a wholesale basis. ER&T is a fully integrated
wholesale energy marketing and trading organization that is active in the long-term and spot wholesale energy and energy-related markets. Electric Supply Power’s generation capacity is comprised of a diverse mix of fuels of approximately 47% gas, 26% nuclear, 18% coal, 8% oil and 1% pumped storage. Power’s fuel diversity serves to mitigate risks
associated with fuel price volatility and market demand cycles. The following table indicates proportionate MWh output of Power’s generating stations by fuel type, based on actual 2006 output of approximately 54,000 MWhs, and its estimated 53,000 MWh output
by fuel type for 2007. Generation by Fuel Type 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 5
Actual
2006
Estimated
2007(A)
37
%
37
%
18
%
18
%
11
%
11
%
11
%
11
%
5
%
4
%
12
%
14
%
4
%
3
%
1
%
1
%
1
%
1
%
100
%
100
%
(A)
No assurances can be given that actual 2007 output by source will match estimates.
For a discussion of Power’s management and hedging strategy relating to its energy sales supply and fuel needs, see Market Price Environment and Item 7A. MD&A—Overview of 2006 and Future
Outlook—Power. Gas Supply As described above, Power sells gas to PSE&G under the BGSS contract. Additionally, based upon availability, Power sells gas to others. About 41% of PSE&G’s peak daily gas requirements are provided
through firm transportation, which is available every day of the year. The remainder comes from field storage, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery and
landfill gas. Power purchases gas for its gas operations directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipeline suppliers. Power has approximately 1 billion cubic-feet-per-day of firm transportation capacity under contract to meet the primary needs of PSE&G’s gas consumers and the needs of its own generation fleet. In
addition, Power supplements that supply with a total storage capacity of 78 billion cubic feet that provides a maximum of approximately 1 billion cubic feet-per-day of gas during the winter season. Power expects to be able to meet the energy-related demands of its firm natural gas customers. However, the ability to maintain an adequate supply could be affected by several factors not within
Power’s control, including curtailments of natural gas by its suppliers, severe weather and the availability of feedstocks for the production of supplements to its natural gas supply. In addition, supply of all
types of gas is affected by the nationwide availability of all sources of fuel for energy production. Market Price Environment System operators in the electric markets in which Power participates will generally dispatch the lowest cost units in the system first, with higher cost units dispatched as demand increases. As such,
nuclear units, with their low variable cost of operation, will generally be dispatched whenever they are available. Coal units generally follow next in the merit order of dispatch and gas and oil units generally
follow to meet the total amount of demand. The price that all dispatched units receive is set by the last, or marginal unit that is dispatched. This method of determining supply and pricing creates an environment where natural gas prices often have a major impact on the price that generators will receive for their output, especially in periods
of relatively strong demand. As such, significant changes in the price of natural gas will often translate into significant changes in the price of electricity. As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a
series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, commodity prices, such as electricity, gas, coal and
emissions, as well as the availability of Power’s diverse fleet of generation units to produce these products, when necessary, have a considerable effect on Power’s profitability. There is significant volatility in
commodity markets, including electricity, fuel and emission allowances. For example, the spot price of electricity at the quoted PJM West market has increased from an average of about $25 per MWh for
2002 to an average of about $60 per MWh in 2005 and then decreased to an average of about $50 per MWh in 2006. Similarly, the price of natural gas at the Henry Hub terminal has increased from an average of about $3 per one million British Thermal Units (MMBtu)
in 2002 to about $9 per MMBtu in 2005 and then decreased to an average of about $7 per MMBtu in 2006. The prices at which transactions are entered into for future delivery of these products, as evidenced through the market for forward contracts at points such as PJM
West, have escalated as well. The historical spot prices and forward prices as of year-end 2006 are reflected in the graphs below. 6
In the electricity markets where Power participates, the pricing of electricity can vary by location. For example, prices may be higher in congested areas due to transmission constraints during peak
demand periods reflecting the bid prices of the higher cost units that are dispatched to supply demand. This typically occurs in the eastern portion of PJM, where many of Power’s plants are located. At
various times, depending upon its production and its obligations, these price differentials can serve to increase or decrease Power’s profitability. While the prices reflected in the tables above do not necessarily represent prices at which Power has contracted, they are representative of market prices at relatively liquid hubs, with nearer term
forward pricing generally resulting from more liquid markets than pricing for later years. While they provide some perspective on past and future prices and recent prices are considerably higher than in
prior years, the forward prices are highly volatile, and there is no assurance that such prices will remain in effect nor that Power will be able to contract its output at these forward prices. Power is also provided with payments from the various markets for the capability to provide electricity, known as a capacity payments, which are reflective of the value to the grid for having the
assurance of sufficient generating capacity to meet system reliability and energy requirements, and to encourage the future investment in adequate sources of new generation to meet system demand. While
there is generally sufficient capacity in the markets in which Power operates, there are certain areas in these markets where there are constraints in the transmission system, causing concerns for reliability
and a more acute need for capacity. Some generators, including Power, announced the retirement of certain older generating facilities in these constrained areas due to insufficient revenues to support their
continued operation. In separate instances, both PJM and the New England Power Pool (NEPOOL) responded with Reliability-Must-Run (RMR) contracts for these units to enable their continued
availability that provide their owners with fixed payments which, while not necessarily reflective of the full value of those units’ contribution to reliability (e.g. they are 7
cost-based), are nonetheless significant. Such payment structure by its nature acknowledges that these units provide a reliability service that is not compensated in the existing markets. It also suggests that
fixed periodic payments, as would be provided in a capacity market, are an appropriate form of compensation for such units for this service. Power receives RMR payments in both PJM and NEPOOL. In addition, FERC issued certain orders in 2006 related to market design that have changed the nature of capacity payments in the New England Power Pool (NEPOOL) and is scheduled to change the
nature of payments in PJM. In PJM, a new capacity-pricing regime known as the Reliability Pricing Model (RPM) will provide generators with differentiated capacity payments based upon the location of
their respective facilities. Similarly, the Forward Capacity Market (FCM) settlement in NEPOOL provides for locational capacity payments. Both market designs are based in part on the premise that a
more structured, forward-looking, transparent pricing scheme will give prospective investors in new generating facilities more clarity on the future value of capacity, sending a pricing signal to encourage
expansion of capacity for future market demands. FERC has approved the market changes in each of these markets, with the anticipated start date for RPM set for June 1, 2007 and FCM transition period
having begun on December 1, 2006. Power believes that the majority of its generating capacity may experience changes in value from aspects of these market designs. While Power believes it may derive
considerable additional revenue from these changes, it is difficult to predict the ultimate outcome of these changes. For additional information on Power’s collection of RMR payments in PJM and NEPOOL and the RPM and FCM proposals, see Regulatory Issues—Federal Regulation. Competitive Environment Power’s competitors include merchant generators with or without trading capabilities, including banks, funds and other financial entities, utilities that have generating capability or have formed
generation and/or trading affiliates, aggregators, wholesale power marketers and developers of transmission and Demand Side Management (DSM) projects and combinations thereof. These participants
compete with Power and one another buying and selling in wholesale power pools, entering into bilateral contracts and/or selling to aggregated retail customers. Power’s businesses are also under competitive pressure due to technological advances in the power industry and increased efficiency in certain energy markets. For example, it is possible that advances
in technology, such as distributed generation, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. There is also a risk to Power if states should decide to turn away from competition and allow regulated utilities to continue to own or reacquire and operate generating stations in a regulated and
potentially uneconomical manner, or to encourage rate-based generation for the construction of new base-load units. This has already occurred in certain states. The lack of consistent rules in energy
markets can negatively impact the competitiveness of Power’s plants. Also, regional inconsistencies in environmental regulations, particularly those related to emissions, have put some of Power’s plants
which are located in the Northeast, where rules are more stringent, at an economic disadvantage compared to its competitors in certain Midwest states. Also, environmental issues such as air pollution controls may have a competitive impact on Power to the extent its plants are more expensive to maintain in compliance, thus affecting its ability to be a
lower cost provider compared to competitors without such restrictions. In addition, as discussed in the Regulatory Issues section herein–specifically, in the discussion concerning (i) Transmission Rates and Cost Allocation and (ii) Transmission Infrastructure–current rules
being developed at FERC, at DOE and at PJM with respect to the construction of transmission and the allocation of costs for such construction may have the effect of altering the level playing field
between transmission options and generation options, which could have a competitive impact upon PSEG and Power. Customers As EWGs, Power’s subsidiaries do not directly serve retail customers. Power uses its generation facilities primarily for the production of electricity for sale at the wholesale level. Power’s customers
consist mainly of wholesale buyers, primarily within PJM, but also in New York and Connecticut. Power is at times a direct or indirect supplier of New Jersey’s EDCs, including PSE&G, depending on the
positions it takes in the New Jersey BGS auction. In prior years, Power had also been a bidder in the CIEP auction, which serves large 8
industrial and commercial customers at hourly PJM real-time market prices for a term of 12 months. Power’s three-year contract with a Connecticut utility ended on December 31, 2006. These contracts are
full requirements contracts, where Power is responsible to serve a percentage of the full supply needs of the customer class being served, including energy, capacity, congestion and ancillary services. In
addition, Power has four-year contracts with two Pennsylvania utilities expiring in 2008 and is considering pursuing similar opportunities in other states. PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract term was originally through March 31, 2007, and year-to-year thereafter.
In the settlement of the 2005/06 BGSS proceeding the Parties agreed to an amendment to the contract that changed the contract term to March 31, 2012, and year-to-year thereafter. Power charges PSE&G
for gas commodity costs which PSE&G recovers from its customers. Any difference between the residential gas cost charged by Power under the BGSS contract and revenues received from PSE&G’s
residential customers are deferred and collected or refunded through adjustments in future rates. For the year ended December 31, 2006, approximately 46% of Power’s revenue was comprised of billings to PSE&G for BGS and BGSS. See Note 21. Related-Party Transactions of the Notes for
additional information. Employee Relations As of December 31, 2006, Power had 2,538 employees, of which 1,414 employees (705 employees for Fossil and 708 employees for Nuclear) are represented by three union groups under six-year
collective bargaining agreements, which were ratified in February, July and August 2005, respectively. Power believes that it maintains satisfactory relationships with its employees. Energy Holdings is a New Jersey limited liability company and is the successor to PSEG Energy Holdings Inc., which was incorporated in 1989. Energy Holdings’ principal executive offices are located
at 80 Park Plaza, Newark, New Jersey 07102. Energy Holdings has two principal direct wholly owned subsidiaries, which are also its segments: Global and Resources. Energy Holdings pursued investment opportunities in the domestic and international energy markets, with Global focused on the operating segments of the electric industries and Resources primarily
made financial investments in these industries. Global owns investments in power producers and distributors that own and operate electric generation and distribution facilities in selected domestic and international markets. See Item 2.
Properties—Energy Holdings for discussion of individual investments, including significant power purchase agreements (PPAs), fuel supply agreements, financing structures and other matters. Global’s assets include consolidated projects and those accounted for under the equity method. As of December 31, 2006, Global’s share of project MW and number of customers by region are as
follows: Chile and Peru Distribution and Generation U.S. Generation Other Total 9
As of December 31, 2006
Total Capital
Invested (1)
Assets
MW
Number of
Customers
(Millions)
$
1,245
$
1,864
303
1,974,000
508
911
2,396
N/A
153
343
172
N/A
$
1,906
$
3,118
2,871
1,974,000
(1)
Total Capital Invested represents Global’s equity invested in the projects, excluding currency translation adjustments.
Energy Holdings has reduced its international risk by opportunistically monetizing investments at Global that no longer had a strategic fit. During the past three years,
Global has received proceeds of over $1 billion from sales of investments in China, Brazil, Poland, India, Africa and the Middle East. The decrease in Global’s portfolio size due to the above sales was
partially offset by strong earnings from its Texas generation facilities and its electric distribution companies in Chile and Peru. As a result, Global’s current portfolio is primarily comprised of investments in
Chile, Peru and the United States. Global also has modest sized investments in Italy, India and Venezuela totaling about 8% of Global’s total investment balance. As a result of these sales, approximately 50% of Global’s future earnings is expected to be derived from its domestic generation business, of which, over half are from its 2,000 MW gas-fired combined cycle
merchant generation business in Texas, with the balance from its 12 fully-contracted generating facilities in which Global’s ownership interests equate to nearly 400 MW. The other 50% of Global’s earnings
is expected to be essentially from three electric distribution businesses in Chile and Peru and a 183 MW hydro generation facility in Peru. The regulatory environments in both Chile and Peru have been generally constructive
since Global acquired these investments. Rate cases are held every four years (with the next rate case beginning in 2008) and the rate calculation methodologies are designed to achieve a reasonable return
on the net replacement value of each system. See Regulation for additional information on the regulatory process in Chile and Peru. Chile also maintains an investment grade rating
and Peru’s rating, although non-investment grade, has improved. Energy Holdings continues to review Global’s portfolio, with a focus on its international investments. As part of this review, Energy Holdings considers the returns of its remaining investments against
alternative investments across the PSEG companies, while considering the strategic fit and relative risks of these businesses. Market Price Environment Global’s projects in California, Hawaii and New Hampshire are fully contracted under long-term PPAs with the public utilities or power procurers in those areas. Therefore, Global does not have price
risk with respect to the output of such assets, and generally, with respect to such assets, has limited risk with respect to fuel prices. Global’s risks related to these projects are primarily operational in nature
and have historically been minimal. Global’s generation business in Texas (Texas Independent Energy. L. P. (TIE)) is a merchant generation business with higher risks. TIE seeks to enter into a mix of contracts to sell its output—approximately 20% of its output is sold under a five-year contract, which expires in 2010, and another 10% to 20% is sold forward under one-year on-peak calendar or seasonal contracts
and the balance is sold during the year. As a result, TIE’s business is subject to substantial volatility in earnings and cash flows as power prices fluctuate. Although Global’s business in Texas has performed
very well as high natural gas prices and the resulting high energy prices led to strong margins in 2005 and 2006, there can be no assurances that such pricing in the market will continue at these levels. Competitive Environment Although TIE’s generating stations operate very efficiently relative to other gas-fired generating plants, new technology could make TIE’s plants less economical in the future. Also, several competitors
have announced plans to build a substantial amount of capacity in the Electric Reliability Council of Texas (ERCOT) market. Although it is not clear if this capacity will be built or, if so, what the economic
impact would be, such additions could impact market prices and TIE’s competitiveness. Also, as ERCOT transitions to nodal pricing from zonal pricing the competitiveness of TIE’s generating plants could
be impacted. As TIE represents a substantial portion of Energy Holdings’ and Global’s business, volatility in that portion of the business will impact Global’s and Energy Holdings’ overall portfolio results. Of the remaining portion of Global’s business, the majority of its earnings are generated by two major rate-regulated distribution businesses in Chile and one in Peru. Although these entities are not
granted exclusive franchises, there is minimal competition for distribution companies. See Regulatory Issues—International Regulation for a discussion of the ratemaking process in Chile and Peru. Global
also owns a 10
hydro generation facility in Peru. Although new generation capacity is being built in Peru, there are not many opportunities for hydro expansion, mitigating competition with Global’s hydro generation
investment. Customers Global has ownership interests in three distribution companies in South America which serve approximately two million customers. Global also has ownership interests in electric generation facilities
which sell energy, capacity and ancillary services to numerous customers through PPAs, as well as into the wholesale market. For additional information, see Item 2. Properties—Energy Holdings. Resources Resources has investments in energy-related financial transactions and manages a diversified portfolio of assets, including leveraged leases, operating leases, leveraged buyout funds, limited partnerships
and marketable securities. Established in 1985, Resources has a portfolio of approximately 45 separate investments. Resources does not anticipate making significant additional investments in the near term. Resources also owns and manages a Demand Side Management (DSM) business. DSM revenues are earned principally from monthly payments received from utilities, which represent shared electricity
savings from the installation of the energy efficient equipment. The major components of Resources’ investment portfolio as a percent of its total assets as of December 31, 2006 were: Leveraged Leases Energy-Related Foreign Domestic Real Estate—Domestic Commuter Railcars—Foreign Total Leveraged Leases Owned Property (real estate and aircraft) Limited Partnerships, Other Investments & Current and Other Assets Total Resources’ Assets As of December 31, 2006, no single investment represented more than 10% of Resources’ total assets. Leveraged Lease Investments Resources maintains a portfolio that is designed to provide a fixed rate of return. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding
investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as Operating
Revenues as these events occur in the ordinary course of business of managing the investment portfolio. In a leveraged lease, the lessor acquires an asset by investing equity representing approximately 15% to 20% of the cost of the asset and incurring non-recourse lease debt for the balance. The lessor
acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the
asset under applicable federal and state tax guidelines. In addition, the lessor receives income from lease payments made by the lessee during the term of the lease and from tax benefits associated with
interest and depreciation deductions with respect to the leased property. The ability of Resources to realize these tax benefits is dependent on operating gains generated by its affiliates and allocated
pursuant to PSEG’s consolidated tax sharing agreement. The Internal Revenue Service (IRS) has recently disallowed certain tax deductions claimed by Resources for certain of these leases. See Note 12.
Commitments and Contingent Liabilities of the Notes for further discussion. Lease rental payments are unconditional obligations of the lessee and are set at levels at 11
As of December 31, 2006
Amount
% of
Resources’
Total Assets
(Millions)
$
1,499
51
%
1,041
35
%
182
6
%
88
3
%
2,810
95
%
124
4
%
35
1
%
$
2,969
100
%
least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to
the lessor determines the return on the investment. Under generally accepted accounting principles in the U.S. (GAAP), the lease investment is recorded on a net basis and income is recognized as a
constant return on the net unrecovered investment. Resources has evaluated the lease investments it has made against specific risk factors. The assumed residual-value risk, if any, is analyzed and verified by third parties at the time an investment is
made. Credit risk is assessed and, in some cases, mitigated or eliminated through various structuring techniques, such as defeasance mechanisms and letters of credit. As of December 31, 2006, the weighted
average credit rating of the lessees in the portfolio was A–/A3. Resources has not taken currency risk in its cross-border lease investments. Transactions have been structured with rental payments
denominated and payable in U.S. dollars. Resources, as a passive lessor or investor, has not taken operating risk with respect to the assets it owns, so leveraged leases have been structured with the lessee
having an absolute obligation to make rental payments whether or not the related assets operate. The assets subject to lease are an integral element in Resources’ overall security and collateral position. If
the value of such assets were to be impaired, the rate of return on a particular transaction could be affected. The operating characteristics and the business environment in which the assets operate are,
therefore, important and must be understood and periodically evaluated. For this reason, Resources will retain, as necessary, experts to conduct appraisals on the assets it owns and leases. On December 28, 2005, Resources sold its interest in the Seminole Generation Station Unit 2 in Palatka, Florida. For additional information relating to this disposition, see Note 4. Discontinued
Operations, Dispositions, Acquisitions and Impairments of the Notes. Resources’ ten largest lease investments as of December 31, 2006 were as follows: Investment Reliant Energy MidAtlantic Power Dynegy Holdings Inc Midwest Generation (Guaranteed ENECO ESG EZH Merrill Creek Grand Gulf 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, Item 7A. Qualitative and Quantitative
Disclosures About Market Risk—Credit Risk—Energy Holdings and Note 12. Commitments and Contingent Liabilities of the Notes. 12
Description
Recorded
Investment Balances
as of
December 31, 2006
% of
Resources’
Total Assets
(Millions)
Holdings, LLC
Three generating stations
(Keystone, Conemaugh and
Shawville)
$
284
10
%
Two electric generating stations
(Danskammer and Roseton)
239
8
%
by Edison Mission Energy)
Two electric generating stations
(Powerton and Joliet)
206
7
%
Gas distribution network
(Netherlands)
168
6
%
Electric distribution system
(Austria)
145
5
%
Electric generating station
(Netherlands)
133
4
%
Merrill Creek Reservoir Project
130
4
%
Nuclear generating station (U.S.)
121
4
%
Gas distribution network
(Netherlands)
111
4
%
Gas distribution network
(Netherlands)
105
3
%
$
1,642
55
%
As of December 31, 2006, Resources has a remaining gross investment in three leased aircraft of approximately $41 million. On September 14, 2005, Delta Airlines (Delta) and Northwest Airlines
(Northwest), the lessees for Resources’ four remaining aircraft at that time, filed for Chapter 11 bankruptcy protection. This had no material effect on Energy Holdings as it continues to believe that it will
be able to recover the recorded amount of its investments in these aircraft as of December 31, 2006, although no assurances can be given. In 2004 and 2005, Resources successfully restructured the leases and
converted the Delta and Northwest leases from leveraged leases to operating leases. The Delta aircraft was sold in January 2006 generating a small gain for Resources. Other Subsidiaries Enterprise Group Development Corporation (EGDC), a commercial real estate property management business, is conducting a controlled exit from its real estate business. Total assets of EGDC as of
December 31, 2006 and 2005 were $70 million and $71 million, respectively, less non-recourse debt of $19 million and $21 million, respectively less minority interest of $6 million for each year, for a net
investment of approximately $45 million and $44 million, respectively. These investments are composed of three properties in New Jersey, Maryland and Virginia and an 80% partnership interest in
buildings and land in New Jersey. Employee Relations As of December 31, 2006, Energy Holdings had 53 direct employees. In addition, Energy Holdings’ subsidiaries had a total of 1,091 employees, of which 692 were represented by unions under collective
bargaining agreements expiring between June 2007 and January 2010. Energy Holdings believes that it maintains satisfactory relationships with its employees. Services Services is a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Services provides management and administrative and general services to PSEG
and its subsidiaries. These include accounting, treasury, financial risk management, law, tax, communications, planning, development, human resources, corporate secretarial, information technology,
investor relations, stockholder services, real estate, insurance, library, records and information services, security and certain other services. Services charges PSEG and its subsidiaries for the cost of work
performed and services provided pursuant to the terms and conditions of intercompany service agreements. As of December 31, 2006, Services had 932 employees, including 100 employees represented by a
union group under a six-year collective bargaining agreement that was ratified in February 2005. Services believes that it maintains satisfactory relationships with its employees. Federal Regulation Public Utility Holding Company Act (PUHCA) PSEG, PSE&G, Power and Energy Holdings The Energy Policy Act (EP Act), which became law on August 8, 2005, repealed PUHCA as of February 8, 2006 and established PUHCA 2005, which grants to FERC “books and records” oversight of
public utility holding companies. PSEG had historically claimed an exemption from regulation by the SEC as a registered holding company under PUHCA. As part of that exemption, Fossil, Nuclear,
certain subsidiaries of Fossil and certain subsidiaries of Energy Holdings with domestic operations obtained EWG or Qualifying Facility (QF) status (the latter designation obtained under the Public Utility
Regulatory Policies Act of 1978 (PURPA)), while most of Energy Holdings’ foreign investments obtained Foreign Utility Company (FUCO) status. Notwithstanding the repeal of PUHCA, these companies
have retained their designations as EWGs, FUCOs or QFs, since such designation affords certain protections under FERC’s PUHCA 2005. Specifically, companies subject to the provisions of PUHCA 2005
must provide state regulators access to their books and records. PSEG, PSE&G, Power and Energy Holdings do not expect PUHCA 2005 to materially affect their respective businesses, prospects or
properties, and in October 2006, PSEG obtained from FERC a waiver of 13
PUHCA 2005’s accounting, record retention and reporting requirements. For additional information on the impact of PUHCA repeal, see State Regulation. Environmental PSEG, PSE&G, Power and Energy Holdings PSEG and its subsidiaries are subject to the rules and regulations relating to environmental issues promulgated by the EPA, the U.S. Department of Energy (DOE) and other regulators. For
information on environmental regulation, see Environmental Matters. FERC PSEG, PSE&G, Power and Energy Holdings FERC is an independent federal agency that regulates the transmission of electric energy and sale of electric energy at wholesale in interstate commerce pursuant to the Federal Power Act (FPA).
FERC also regulates the interstate transportation of, as well as certain wholesale sales of, natural gas pursuant to the Natural Gas Act. FERC’s oversight includes: merger review, compliance, including
Standards of Conduct issues, transmission rates and terms and conditions of service, and market power, market design and capacity design and rates. Several PSEG subsidiaries, including PSE&G, Fossil,
Nuclear, and ER&T, as well as certain subsidiaries of Fossil and certain domestic subsidiaries of Energy Holdings are “public utilities” as defined by the FPA and subject to extensive regulation by FERC.
FERC’s regulation of public utilities is comprehensive and governs such matters as rates, services, mergers, financings, affiliate transactions, market conduct and reporting. FERC is also responsible under
PURPA for administering PURPA’s requirements for QFs. PSEG, through its subsidiaries, owns several QF plants. QFs are subject to many, but not all, of the same FERC requirements as public utilities. Expanded Merger Review Authority PSEG, PSE&G, Power and Energy Holdings The EP Act expanded FERC’s authority to review mergers and acquisitions under the FPA. It extended the scope of FERC’s authority to require prior FERC approval regarding transactions involving
certain transfers of generation facilities, certain holding company transactions, and utility mergers and consolidations having a value in excess of $10 million. The EP Act requires that FERC, when
reviewing proposed transactions, examine cross-subsidization and pledges or encumbrances of utility assets. PSEG, PSE&G, Power and Energy Holdings are unable to predict the effect of this authority on
any potential future transactions in which they may be involved. Compliance Reliability Standards PSEG, PSE&G, Power and Energy Holdings The EP Act required FERC to empower a single, national Electric Reliability Organization (ERO) to develop and enforce national and regional reliability standards for the U.S. bulk power system.
FERC has designated the North American Electric Reliability Corporation (NERC) as this ERO. NERC has filed with FERC delegation agreements that would in turn delegate, to a significant degree, the
enforcement of such reliability standards to eight regional reliability councils approved by NERC, such as ReliabilityFirst. Thus, the relationship between NERC and the regional reliability councils
(responsible for reliability standards compliance within a particular geographic region) is a contractual one. PSE&G’s transmission assets, and most of Power’s generation assets, are located within the
geographic scope of Reliability First, and PSEG’s remaining domestic assets, including the New York, Connecticut and Texas generating assets, are within the scope of other regional reliability councils such
as NPCC and ERCOT. After being designated as an ERO, NERC asked FERC to approve a set of proposed mandatory Reliability Standards, many of which mirrored existing, voluntary standards. On October 20, 2006,
FERC issued a Notice of Proposed Rulemaking (NOPR), which proposed to approve 83 of the 107 filed standards and asked for additional information regarding the remaining 24 standards. Compliance
with these 83 14
standards, enforcement of which will largely be delegated to the regional reliability councils such as Reliability First, is mandatory and sanctions may attach for non-compliance. Pursuant to the EP Act,
FERC has the ability to impose penalties of up to $1 million a day for violations of these standards. Under the NOPR, which is not yet a Final Rule, compliance with these Standards will be required by the
commencement of the 2007 summer peak season. These Standards are applicable to transmission owners and generation owners, and thus PSEG, PSE&G, Power and Energy Holdings (or their subsidiaries)
will be obligated to comply with the Standards. PSEG, PSE&G, Power and Energy Holdings are currently evaluating all of the requirements imposed by the Standards and are preparing to ensure that they
will be in compliance by FERC-required date. It should be noted in this regard that PSE&G’s local control center (LCC) was the first control center voluntarily audited by NERC in January 2006 with respect
to LCC “readiness.” NERC concluded in this audit that PSE&G has adequate facilities, processes, plans, procedures, tools, and trained personnel to effectively operate as an LLC within PJM and found no
significant operational problems. FERC Standards of Conduct PSEG, PSE&G, Power and Energy Holdings On January 18, 2007, FERC issued a NOPR which proposes to make certain changes to its Standards of Conduct applicable to both electric and natural gas transmission providers. The NOPR was
issued in response to a decision by the United States Court of Appeals of the District of Columbia, which vacated FERC’s existing Standards of Conduct as they applied to natural gas pipelines. The NOPR,
however, proposes changes to the Standards of Conduct for both natural gas and electric providers Some of the proposed changes include modifying the definition of Energy Affiliate and thereby changing
the scope of applicability of the Standards of Conduct, changing the regulations with respect to the permissible tasks of “shared” employees (employees that may be shared by both the Transmission
Provider and the Energy Affiliates) and modifying the information disclosure regulations. PSE&G is currently subject to FERC’s Standards of Conduct as a Transmission Provider and subsidiaries of Power
and Energy Holdings are subject to the Standards of Conduct as Energy Affiliates. Thus, FERC’s proposed changes may have an impact on PSEG, PSE&G, Power and Energy Holdings and the interactions
between these entities, although its impact is not clear at this time. PSEG is currently evaluating the NOPR and will file comments to the same prior to FERC issuing a Final Rule. The outcome of this
proceeding cannot be predicted at this time. Transmission Rates and Cost Allocation PSEG, PSE&G and Power PJM Schedule 12 Cost Allocation for Regional Transmission Expansion Planning( RTEP) Projects On January 5, 2006, PJM proposed cost allocation recommendations for new transmission projects pursuant to Schedule 6 of its FERC-approved Operating Agreement and Schedule 12 of its Open
Access Transmission Tariff (Tariff). PJM identified the “Responsible Customers” that would be required to pay for certain transmission upgrades approved through PJM’s Regional Transmission Expansion
Planning (RTEP) process and the percentage of the project cost that would be allocated to such Responsible Customers. This was the first filing by PJM pursuant to these new cost allocation mechanisms
and it included (i) large cost allocations to eastern load as a result of proposed construction in the western and southern portions of PJM and (ii) allocations to merchant transmission projects such as
Neptune Regional Transmission System, LLC. On May 26, 2006, FERC issued an order that accepted and suspended PJM’s cost allocation filing, made the filing effective subject to refund as of May 30,
2006 and established a hearing and settlement judicial procedure. In addition, on May 4, 2006, PJM made a second RTEP cost allocation filing at FERC, addressing cost allocations to Responsible Customers associated with additional RTEP projects. PSEG protested
the filing, objecting to, among other things, PJM’s netting of cost impacts within a PJM zone to allocate RTEP costs and PJM’s failure to consider the impact of certain adjustments in determining zonal cost
allocation. On July 19, 2006, FERC consolidated PJM’s January 5, 2006 and May 4, 2006 filings that propose to allocate the costs of new transmission projects that PJM has directed to be built through its RTEP
process. On July 21, 2006, PJM submitted to FERC a further proposal to allocate the costs of an additional group of new transmission projects that PJM has directed be built through its RTEP. The July 21,
2006 filing includes 15
allocations for the $850 million, 200-mile 500 kV Loudon transmission line which runs from Allegheny Power’s service territory, through West Virginia to Northern Virginia, as well as many other
transmission projects in the PJM region. This proceeding was consolidated with the other two PJM cost allocation filings and was then the subject of settlement proceedings before a ALJ. Settlement
discussions terminated in November 2006 and, on November 7, 2006, the proceedings were set for hearing, with a hearing to commence no later than June 19, 2007. PJM has used the same allocation
methodology to identify which load should pay for these new transmission projects through regulated transmission rates. PSEG is actively participating in this proceeding, as the cost allocation methodology
used by PJM may result in a disproportionate allocation of costs to loads in the eastern portion of PJM. However, assuming continued pass-through of transmission charges to retail customers, neither Power
nor PSE&G are expected to be impacted by the allocation of Schedule 12 charges. PSEG, PSE&G and Power are unable to predict the outcome of this hearing at this time. Regional through and out rates (RTOR) RTOR are separate transmission rates for transactions where electricity originated in one transmission control area is transmitted to a point outside that control area. Both the Midwest Independent
Transmission System Operator, Inc. (MISO) and PJM charged RTORs through December 1, 2004. FERC approved a new regional rate design, which became effective December 1, 2004 for the entire
PJM/MISO region and approved the continuation of license plate rates and a transitional Seams Elimination Charge/Cost Adjustment/Assignment (SECA) methodology effective from December 1, 2004
through March 2006. On February 10, 2005, FERC issued an order that accepted various SECA filings, established December 2004 as the effective date for the SECA rates, made them subject to refund and surcharge, and
established hearing procedures to resolve the outstanding factual issues raised in the filings and the responsive pleadings. A trial-type hearing was held in May 2006, encompassing a review of the actual amount of lost revenues to be recovered via the SECA mechanism. On August 10, 2006, the ALJ issued an initial
decision finding that the rate design for the recovery of SECA charges is flawed, and that the SECA rate charges are therefore unjust, unreasonable and unduly discriminatory. FERC has not yet issued an
order on review of the ALJ initial decision. In addition, in March 2006, PSE&G and Power entered into a settlement with a limited group of parties in PJM, which settlement was certified to FERC, under
which the parties have agreed to pay and collect reductions of SECA revenues. On October 12, 2006, the limited settlement agreement was expanded to include additional parties and on January 18, 2007,
an additional settlement agreement was entered into with certain MISO parties. FERC has not yet acted to approve the March, October or January SECA settlements. Due to the uncertainty of this
proceeding, PSE&G has continued to defer the collection of any SECA revenues on its books. At the present time, PSEG, PSE&G and Power do not anticipate any adverse impact as a result of the SECA
decision. PJM Long-Term Transmission Rate Design On May 31, 2005, FERC issued an order addressing the recovery of costs for transmission upgrades designated through PJM’s RTEP process. Among other matters, FERC’s order responded to a
proposal to continue PJM’s current rate design, under which transmission customers pay rates within the particular transmission zone in which they take service. FERC concluded that the existing rate
design may not be just and reasonable and it established a hearing to examine the justness and reasonableness of continuing PJM’s modified zonal rate design. Certain entities filed proposals with FERC on
September 30, 2005 for alternative rate designs for the PJM region. PSE&G, as part of a coalition of potentially affected PJM transmission owners, filed answering testimony on November 22, 2005 that
supported continuation of the zonal rate design in PJM. A hearing was held in April 2006 and on July 13, 2006, a FERC ALJ issued a decision concluding that the existing PJM modified zonal rate design for existing facilities has been shown to be unjust and
unreasonable, and should be replaced with a postage stamp rate design (single “postage stamp” rate paid by all transmission customers in PJM) for such facilities to be effective April 1, 2006. To mitigate
rate impacts, the ALJ determined that the rate design should be phased in, so that no customer receives greater than a 10% annual rate increase. The ALJ also determined that the existing process for
allocating costs of new transmission projects pursuant to Schedule 6 of PJM’s Operating Agreement and Schedule 12 of the PJM Tariff was just and reasonable. Briefs on exceptions to the ALJ’s initial
decision and reply briefs were filed in this proceeding challenging the decision to find the existing rate design unjust and unreasonable, the appropriateness of imposing a postage stamp rate design, the
decision as to the appropriateness of applying 16
the current Schedule 6 and Schedule 12 process for allocating costs of new transmission projects and the phase-in of the new rate design. FERC has not yet issued a decision on review of the ALJ’s initial
decision. Should FERC ultimately approve this postage stamp rate design on review of the ALJ’s initial decision, or adopt one or a combination of the alternative rate designs proposed, assuming continued
pass-through of transmission charges to retail customers, PSEG’s and PSE&G’s results of operations could be adversely impacted with no adverse impact currently anticipated for Power. Market Power, Market Design and Capacity Issues PSEG, PSE&G and Power Market Power Under FERC regulations, public utilities may sell power at cost-based rates or apply to FERC for authority to sell at market-based rates (MBR). PSE&G, ER&T and certain other subsidiaries of Fossil and
Energy Holdings have applied for and received MBR authority from FERC, which permits them to sell power into the wholesale market at market-based rates. FERC requires that holders of MBR tariffs
file an update, on a triennial basis, demonstrating that they continue to lack market power. On November 30, 2006, PSE&G and ER&T filed their respective triennial updated market power reports with FERC.
FERC has not yet acted on these updated market power reports. On May 19, 2006, FERC issued a NOPR concerning the standards to be used by FERC in granting market-based rate authority. The proposed regulations would adopt, in most respects, FERC’s
current standards. In its NOPR, FERC suggests certain changes, such as in the areas of cost-based market power mitigation, modifications to the horizontal (generation) market power screens, and
clarifications to existing vertical market power screens. On September 20, 2006, PSE&G and Power submitted comments in this NOPR proceeding. FERC has not yet issued a Final Rule in this rulemaking
proceeding. The outcome of this proceeding and its impact on PSEG, PSE&G, Power and Energy Holdings cannot be predicted at this time, but Power does not expect the new rules to disqualify its MBR
authority. However, no assurances can be given. FERC’s MBR policies and the wholesale electricity markets which they help support are evolving and subject to change. Specifically, on December 19, 2006, the United States Court of Appeals for the
Ninth Circuit overturned certain FERC orders in a series of cases, to which PSEG was not a party, which involved long term wholesale contracts entered into during the California Energy Crisis and, by so
doing, seriously undermined the “contract sanctity” doctrine that had previously been applied to preserve these contracts. Moreover, the court held that FERC’s MBR policies are insufficient to establish
that agreements reached under MBR tariffs are just and reasonable at the outset. Thus, the fact that a contract is entered into under a MBR tariff may not render it immune from “just and reasonable”
review by FERC. This case will likely be appealed to the U.S. Supreme Court but represents a significant development and is one that will be monitored for its impact on the wholesale electric market in the
future. RMR Status PJM Although applicable tariff provisions differ from region to region, RMR tariff provisions provide compensation to a generation owner when a unit proposed for retirement must continue operating for
reliability purposes. In September 2004, Power filed notice with PJM that it was considering the retirement of seven generating units in New Jersey, effective December 7, 2004, due to concerns about the
economic viability of the units under the then current market structure. The units that were being considered for retirement were Sewaren 1, 2, 3 and 4, Kearny 7 and 8 and Hudson 1. Kearny 7 and 8 were
retired in 2005. In response to Power’s filed notice, PJM identified certain system reliability concerns associated with the proposed retirements. Effective February 24, 2005, subject to refund and hearing, Power began to collect a monthly fixed payment of $3.3 million, pre-tax, net of operating margins for the Sewaren 1, 2, 3 and 4 and Hudson 1
units. A detailed settlement was filed with FERC on September 23, 2005 that permits Power to recover annual fixed costs of approximately $19 million and $14.5 million, pre-tax, for the Sewaren and
Hudson units, respectively, plus reimbursements of Power’s expenditures in connection with certain construction at the units that are necessary to maintain reliability, offset by certain revenues earned in
PJM’s energy market. 17
FERC accepted this settlement retroactive to February 24, 2005. On March 28, 2006, Power filed a refund report with FERC pursuant to which Power refunded $11 million to PJM, although most of this
refund related to the timing of payments under the settlement agreement and thus will be repaid to Power, with carrying charges, at a later date. FERC did not issue a public notice requesting comments on
the report and no party has made any objections or other comments with respect to the report. Power is in the process of extending its RMR contract for Hudson Unit 1 through September 2010. For
additional information, see Note 12. Commitments and Contingent Liabilities of the Notes. New England In the New England electricity market, many owners of generation facilities have filed with FERC for RMR treatment under the NEPOOL Open Access Transmission Tariff. If FERC grants RMR
status for a generation facility located in the New England market, the owner is entitled to receive cost-of-service treatment for its facility for the duration of an RMR contract that it enters into with ISO
New England Inc. On November 17, 2004, PSEG Power Connecticut LLC (Power Connecticut), a wholly owned indirect subsidiary of Power, filed a request for RMR treatment for the New Haven Harbor
generation station and Unit 2 at the Bridgeport Harbor generation station. FERC issued an order on January 14, 2005, subject to refund and hearing which allowed Power Connecticut to begin collecting
monthly fixed payments of approximately $1.6 million and $3.9 million, pre-tax, for reliability services provided by the Bridgeport Harbor Station, Unit 2 and the New Haven Harbor Station, respectively,
net of operating margins. On June 17, 2005, Power Connecticut filed revised studies supporting monthly recovery of $1.3 million and $3.3 million, pre-tax, for the Bridgeport Harbor and New Haven Harbor
units, respectively. On April 21, 2006, Power Connecticut, the Connecticut Department of Public Utility Control, the Connecticut Office of Consumer Counsel and ISO New England Inc. filed with FERC a Joint
Stipulation and Settlement Agreement and Motion for Expedited Consideration. The Joint Stipulation and Settlement settled all matters associated with the RMR agreements filed by Power Connecticut
for its Bridgeport Harbor 2 and New Haven Harbor stations. Among other things, the settlement provides for monthly fixed payments of approximately $1 million for Bridgeport Harbor and $3 million for
New Haven Harbor. The only disputed issues concern the standard of review applicable to certain types of potential tariff changes that could be filed in the future. No party has challenged the settlement
rates proposed to become effective. The ALJ certified the settlement to FERC on June 21, 2006 as a contested offer of settlement. It is anticipated that the settlement will be approved as certified or, if
modified, will not be modified in a manner that adversely affects the settlement rates. However, Power Connecticut cannot predict a final outcome at this time, as FERC has not yet acted to approve the
settlement. PJM Reliability Pricing Model (RPM) On August 31, 2005, PJM filed its RPM with FERC. The RPM constitutes a locational installed capacity market design for the PJM region, including a forward auction for installed capacity priced
according to a downward-sloping demand curve and a transitional implementation of the market design. FERC issued an order on April 20, 2006 that accepted most of the core concepts of the RPM filing
with an implementation date of June 1, 2007. The April 20, 2006 order set certain details of the filing for paper hearing and technical conference procedures including the slope of the demand curve and the
mechanism for identification of the locational capacity zones. Such hearing and technical conference procedures have now been completed. Also, commencing in June 2006, settlement discussions mediated
by a FERC ALJ commenced at the request of certain intervenors. A final settlement was filed with FERC on September 29, 2006 with a requested approval date of no later than December 22, 2006. PSE&G
and Power filed comments to the settlement supporting the basic structural elements of the RPM proposal but nonetheless requesting certain modifications which, in their view, would better promote the
adequacy of generation reserves on a cost-effective basis. On December 22, 2006, FERC issued an order approving the September 29 settlement, with certain conditions. FERC’s approval of this settlement
is expected to have a favorable impact on generation facilities located in constrained locational zones. The final revenue impact on Power of the settlement approved in the December 22, 2006 FERC order
could result in incremental margin of $100 million to $150 million in 2007, with higher increases in future years as the full year impact is realized and existing capacity contracts expire. The April 20, 2006
order remains subject to rehearing requests filed by several parties. Moreover, on January 22, 2007, PSEG as well as other parties to the proceeding filed for rehearing of the December 22, 2006 order. 18
Given the pending rehearing requests and the likelihood of eventual judicial appeals, PSEG, PSE&G and Power are unable to predict the outcome of this proceeding. Forward Capacity Market (FCM) Settlement in New England On January 31, 2006, certain interested market participants in New England agreed to a settlement in principle of litigation regarding the design of the region’s market for installed capacity, which
would institute a transition period leading to the implementation of a new market design for capacity as early as 2010. Commencing in December 2006, all generators in New England began receiving fixed
capacity payments that escalate gradually over the transition period. RMR contracts, such as Power’s, would continue to be effective until the implementation of the new market design. The new market
design is expected to consist of a forward auction for installed capacity that is intended to recognize the locational value of generators on the system, and is expected to contain incentive mechanisms to
encourage generator availability during generation shortages. During the transition period, these payments are expected to benefit Power’s Bridgeport Harbor 2 plant. The final version of the settlement was
filed with FERC on March 6, 2006 and was approved by order dated June 16, 2006 finding that, as a package, the settlement represents a just and reasonable outcome. The settlement was contested by
certain parties and a rehearing was sought of the June 16, 2006 order. On October 31, 2006, FERC denied rehearing and accepted the FCM settlement in a final order; the order, however, remains subject to
judicial challenge. Transmission Infrastructure PSEG, PSE&G, and Power RTEP On September 8, 2006, PJM filed with FERC a proposal that would significantly modify its regional transmission planning process for economic transmission planning. Currently, the PJM RTEP
identifies transmission that is needed to address reliability, operational performance and economic needs of the PJM region based on historic congestion. The PJM proposal sought to expand the economic portion of the RTEP by
forecasting economic congestion over its transmission planning horizon, which, in 2006, PJM modified from five to 15 years. PSE&G and Power filed a protest to the PJM proposal requesting that FERC
reject PJM’s proposal or set it for hearing. On November 21, 2006, FERC issued an order conditionally accepting PJM’s proposed changes to the RTEP for economic transmission planning. FERC directed PJM to make certain modifications to its proposal, including requiring PJM to make a compliance filing within 120 days identifying how it will weigh and/or combine the metrics it proposes for
determining the net benefits of a particular project and to make a compliance filing within 90 days elaborating on the criteria it will use to determine if an alternative project is more “economic” than an
RTEP project. Nonetheless, PJM’s changes to its economic transmission planning process may result in the establishment of a preference for rate-based transmission solutions to address congestion, as
opposed to reliance on private investment and competitive non-transmission market solutions. PSE&G and Power filed for rehearing of the November 21, 2006 FERC order on December 21, 2006. FERC has
not yet issued an order on rehearing. PSEG, PSE&G and Power are unable to predict the final outcome of this proceeding. DOE Congestion Study On August 8, 2006, the DOE issued a National Electric Transmission Congestion Study (Congestion Study), as directed by Congress in the EP Act. This Congestion Study identified two areas in the
U.S. as “critical congestion areas;” one of the areas is the region between New York and Washington, D.C. Under the EP Act, the DOE has the ability to designate transmission corridors in these “critical
congestion areas,” to which FERC back-stop transmission siting authority will attach. Thus, corridor designation may facilitate the construction of rate-based transmission projects to address congestion in
these corridors. The DOE has not yet designated any transmission corridors as a result of this Congestion Study but will likely do so in the first quarter of 2007. PSE&G and Power filed comments to the
Congestion Study, in which they contended that the Congestion Study contained several analytical flaws. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding at this time. 19
LDV Complaint Proceeding On December 30, 2004, Jersey Central Power & Light Company (JCP&L) filed a complaint at FERC against the other four signatories, including PSE&G, to the Lower Delaware Valley (LDV)
Transmission System Agreement, which expires in 2027 and governs the construction of, and investment in, certain 500 kV transmission facilities in New Jersey. In the complaint proceeding, JCP&L seeks to
terminate its payment obligations to the other contract signatories. A hearing was conducted in this proceeding in November 2006 and an initial decision is expected by the ALJ in March 2007. In this
litigation, JCP&L is not only seeking to terminate its payment obligations to PSE&G of approximately $3 million per year through 2027, but also to receive credit from PSE&G and the other LDV Agreement
parties for transmission facilities previously constructed by JCP&L in New Jersey; if the ALJ were to accept all of JCP&L’s crediting arguments, an outcome that is unlikely, PSE&G would owe approximately $5
million to JCP&L under the LDV Agreement. PSE&G cannot predict the outcome of this proceeding at this time. PJM Strategic Initiative In the fourth quarter of 2006, PJM launched a “strategic initiative” to more specifically define its role in the evolving wholesale energy markets. As part of this initiative, PJM sought comments from its
members, including PSEG, on a number of items, including whether PJM should consider splitting its wholesale market operations from its transmission grid operations and whether PJM should consider
changes to its current corporate governance structure. PJM has since pulled back from its idea of splitting market and grid operations but continues to consider whether there is a need to modify aspects of
its current market and governance structure. PSEG will continue to actively participate in these discussions. NRC PSEG and Power Nuclear’s operation of nuclear generating facilities is subject to continuous regulation by the NRC, a federal agency established to regulate nuclear activities to ensure protection of public health and
safety, as well as the security and protection of the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental
requirements. Continuous demonstration to the NRC that plant operations meet requirements is also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may
operate. Power has recently commenced the process to extend the operating licenses for the Salem and Hope Creek facilities. The current operating licenses of Power’s nuclear facilities expire in the years
shown below: Facility Salem 1 Salem 2 Hope Creek Peach Bottom 2 Peach Bottom 3 Nuclear Safety Issues In January 2004, the NRC issued a letter requesting Power to conduct a review of its Salem and Hope Creek nuclear generation facilities to assess the workplace environment for raising and addressing
safety issues. Power responded to the letter in February 2004 and had independent assessments of the work environment at both facilities performed which concluded that Salem and Hope Creek were safe
for continued operations, but also identified issues that needed to be addressed. These facilities were under enhanced oversight by the NRC related to the work environment until August 31, 2006, at which
time the NRC provided a letter informing Power that its mid-cycle performance review had concluded that the substantive cross-cutting issue in the safety-conscious work environment area at Salem and
Hope Creek was closed. The NRC has restored Salem and Hope Creek to normal oversight levels. Recirculation Pump In a letter to the NRC dated January 9, 2005, Power committed to install vibration-monitoring equipment on Hope Creek’s “B” Reactor Recirculation Pump prior to the unit’s return to service to
address pump vibration concerns and replace the pump’s shaft during the next refueling outage or any sooner outage of sufficient duration. This commitment was the subject of a January 11, 2005
Confirmatory Action Letter 20
Year
2016
2020
2026
2033
2034
from the NRC. The shaft was replaced during the Hope Creek outage in April 2006. On April 20, 2006, the NRC issued a Closure of Confirmatory Action Letter indicating that all of the commitments were
completed. Other PSE&G Investment Tax Credits (ITC) As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings (PLRs) that concluded that the refunding of excess deferred tax and ITC balances to utility customers was
permitted only over the related assets’ regulatory lives, which were terminated upon New Jersey’s electric industry deregulation. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC
liability relating to PSE&G’s generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry in New
Jersey. PSE&G was directed by the BPU to seek a PLR from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the
tax normalization rules of the Internal Revenue Code. PSE&G filed a PLR request with the IRS in 2002. On December 21, 2005, the U.S. Department of the Treasury (Treasury) proposed new regulations for comment addressing the normalization of ITC, replacing regulations originally proposed in 2003.
The new proposed regulations, if finalized, would not permit retroactive application. Accordingly, the IRS’s conclusions in the above referenced PLRs would continue to remain in effect for all industry
deregulations prior to December 21, 2005. On April 26, 2006, the BPU issued an order to PSE&G revoking its previous instruction and directing PSE&G to withdraw its request for a PLR by April 27, 2006. The BPU asserted that the Treasury’s
proposed regulation project was the more appropriate authority to rely upon in deciding the ITC issue. On May 1, 2006, PSE&G filed a motion for reconsideration with the BPU requesting that it modify its April 26, 2006 order to PSE&G to withdraw the PLR request. On May 5, 2006, the BPU denied
PSE&G’s motion for reconsideration and reiterated its order to withdraw the PLR request. On May 8, 2006, PSE&G filed a petition with the Appellate Court of New Jersey challenging the BPU’s order to
withdraw the PLR. On May 11, 2006, the IRS issued a PLR to PSE&G. The PLR concluded that none of the generation ITC could be passed to utility customers without violating the normalization rules.
While the holding in the PLR is a favorable development for PSE&G, the outstanding Treasury regulation project could overturn the holding in the PLR if the Treasury were to alter the position set out in
the December 21, 2005 proposed regulations. The issue cannot be fully resolved until the final Treasury regulations are issued. On May 16, 2006, the BPU voted in favor of a special investigation and hearing before the BPU concerning PSE&G’s actions leading up to receiving the PLR, specifically its failure to abide by the BPU
order to withdraw the request. An order detailing such special investigation has not yet been issued and no investigation has begun. On October 13, 2006, the Appellate Division of the Superior Court of New Jersey granted PSE&G’s motion to dismiss PSE&G’s appeal of the BPU’s order to withdraw the PLR since PSE&G has already
received the PLR. The court also determined that if the BPU seeks to take future action against PSE&G based on the alleged violation of its order, PSE&G can restart the appeal. State Regulation PSEG, PSE&G, Power and Energy Holdings The BPU is the regulatory authority that oversees electric and natural gas distribution companies in New Jersey. PSE&G is subject to comprehensive regulation by the BPU including, among other
matters, regulation of retail electric and gas distribution rates and service and the issuance and sale of securities. Power’s partial ownership of generating facilities in Pennsylvania, as well as PSE&G’s
ownership of certain transmission facilities in Pennsylvania, are subject to regulation by the Pennsylvania Public Utility Commission (PAPUC), which oversees retail electric and natural gas service in
Pennsylvania. PSE&G and Power are also subject to rules and regulations of the NJDEP and the New Jersey Department of Transportation (NJDOT). 21
As discussed below, various Power subsidiaries and Energy Holdings’ subsidiaries are subject to some state regulation in other individual states where they operate facilities, including New York,
Connecticut, Indiana, Texas, California, Hawaii and New Hampshire. PUHCA Repeal On August 1, 2005, the BPU initiated a proceeding to consider whether additional ratepayer protections were necessary in light of the repeal of PUHCA by the EP Act. The proceeding considered the
BPU’s current authority to protect utility ratepayers from risks associated with a utility being part of a holding company structure. The BPU determined that additional protections were necessary and
commenced a two phase rulemaking to address its view of potential risks associated with a utility being part of a holding company structure. Phase I of the rulemaking effort resulted in the adoption of new
regulations effective October 2, 2006, addressing the diversification activities of New Jersey utilities and their holding companies. These new rules impose a requirement that each New Jersey public utility
and its holding company ensure that the aggregate assets of all nonutility activities in the holding company system do not exceed a defined percentage (25%) of the aggregate assets of the utility and utility-
related assets in the holding company system without BPU consent. The rules broadly define utility-related activities to include such things as the production, generation, transmitting, delivering, storing,
selling, marketing of natural gas, propane, electricity and other fuels to wholesale or retail customers, energy management services and sale of energy appliances. Both PSE&G and PSEG currently satisfy
these requirements and expect to continue to satisfy them based on the companies’ current business plans. However, constant monitoring will be required to ensure that the regulation is satisfied and to
meet the annual certification process. The BPU is currently developing Phase II of the rulemaking in a stakeholder process. In Phase II the BPU is proposing new regulations that would increase the BPU’s
access to books and records, impose restrictions on service agreements between utilities and their affiliated service companies and impose additional requirements on utility board of director composition,
utility participation in money pools and additional reporting obligations. New Jersey Energy Master Plan The Governor of New Jersey has recently directed the BPU, in partnership with other New Jersey agencies, to develop an energy master plan. State law in New Jersey requires that an energy master
plan be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. In the
Governor’s directive regarding the energy master plan, the Governor established three specific goals: (1) reduce the State’s projected energy use by 20% by the year 2020; (2) supply 20% of the State’s
electricity needs with certain renewable energy sources by 2020; and (3) emphasize energy efficiency, conservation and renewable energy resources to meet future increases in New Jersey electric demand
without increasing New Jersey’s reliance on non-renewable resources. In November, PSEG submitted a number of strategies designed to improve efficiencies in customer use and increase the level of
renewable generation. During January and February 2007, PSEG has been actively involved in the broad-based constituent working groups created to develop specific strategies to achieve the goals and
objectives. Public meetings on the energy master plan are expected take place during the first and second quarters of 2007, and a final plan is expected to be completed by October 2007. The outcome of this proceeding and
its impact on PSEG, PSE&G and Power cannot be predicted at this time. PSE&G and Power BGS Auctions All of New Jersey’s EDCs jointly procure the supply to meet their BGS obligations through two concurrent auctions authorized by the BPU for New Jersey’s total BGS requirement. Results of these
auctions determine which energy suppliers are authorized to supply BGS to New Jersey’s EDCs. Certain conditions are required to participate in these auctions. Energy suppliers must agree to execute the
BGS Master Service Agreement, provide required security within three days of BPU certification of auction results and satisfy certain creditworthiness requirements. In 2006, the BPU initiated a proceeding to review the annual BGS procurement process as well as the policy issues thereto for all of the New Jersey EDCs. In June 2006, the BPU ruled on certain
issues regarding the acquisition of BGS for the period beginning in June 2007. The BPU agreed that a descending clock auction format should be used for the procurement of BGS-FP supply for 2007. 22
On July 10, 2006, PSE&G filed the Joint EDC proposal for the procurement of BGS for the period beginning June 1, 2007. This proposal includes a descending clock auction format to be held in
February 2007 for the procurement of all BGS supply. On October 28, 2006, the BPU approved a descending clock auction format for BGS-FP and BGS-CIEP supply for the period beginning June 1, 2007.
On December 22, 2006, the BPU approved the remainder of the items in the EDCs filing, without material changes. The BPU also directed the EDCs to remit all remaining retail margin monies previously
collected from larger customers to the State Treasurer in January 2007, and to remit any future collections of the retail margin to the State Treasurer on a quarterly basis. In 2003, the BPU directed the
EDCs to collect a 0.5 per kWh retail adder from all BGS customers greater than 750 kW. These monies were held in a regulatory liability account. For additional information see Note 5 Regulatory Matters
and Note 12. Commitments and Contingent Liabilities of the Notes. PSE&G Electric Distribution Financial Review Based on the Electric Base Rate Case approved in July 2003, PSE&G recorded a regulatory liability in the second quarter of 2003 by reducing its depreciation reserve for its electric distribution assets by
$155 million and amortized this liability from August 1, 2003 through December 31, 2005. The $64 million annual amortization of this liability resulted in a reduction of Depreciation and Amortization
expense. PSE&G filed for a $64 million (based on 2003 test year sales volumes) annual increase in electric distribution rates effective January 1, 2006, subject to BPU approval, including a review of PSE&G’s
earnings and other relevant financial information. Based on current sales volumes, the amount approximates $69 million. On November 9, 2006, the BPU approved a settlement agreement reached by the parties to the proceeding authorizing a $22 million reduction to electric distribution rates, resulting in additional
revenue to PSE&G of approximately $47 million annually based on current sales volumes. The settlement includes a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file a joint electric and gas petition for any future base
rate increases. BGSS Filings The parties to the 2005/2006 BGSS proceeding entered into a Stipulation in which the parties agreed that the BGSS Commodity Charge increases of September 1, 2005 and December 15, 2005 that
were previously approved by the BPU on a provisional basis should become final. The BPU approved the Stipulation. In addition, all the remaining gas contract issues were also resolved and an amended
Gas Requirements Contract was attached to the Stipulation and also approved by the BPU. The primary changes were the term was extended by five years and the default provision was changed from three
days to one day. PSE&G made its 2006/2007 BGSS filing on May 26, 2006. In this filing, PSE&G requested a reduction in annual BGSS gas revenues of approximately $19.7 million (excluding losses and New Jersey Sales
and Use Tax) or approximately a 1.0% decrease to be implemented for service rendered on and after October 1, 2006 or earlier. Additionally, PSE&G requested an increase in its Balancing Charge. The
combined impact of both changes for the class average residential heating customer is an increase in the winter monthly bills of approximately 0.1%; however, on an annual basis the impact is a decrease of
approximately 0.2%. The parties entered into a Stipulation to make the filed BGSS rate effective October 1, 2006 on a provisional basis. However, since the time of the filing, prices of gas futures have dropped significantly
and as a result, additional BGSS data has been requested by and provided to the BPU. Settlement discussions with the BPU Staff were completed and a new Stipulation, dated October 27, 2006, was
executed by the parties. This new Stipulation was approved by the BPU and results in a decrease in annual BGSS revenues of approximately $120 million, which is approximately a 6% reduction in a typical
residential gas customer’s bill. The new BGSS rate became effective on November 9, 2006. The Stipulation did not include any change in the Balancing Charge. The parties entered into a second Stipulation, which addresses the Balancing Charge only. The BPU Staff recommended a lower Balancing Charge than proposed by the Company and received
agreement from Rate Counsel. The parties executed the Stipulation for the lower rate and BPU approval was received on January 17, 2007. 23
Remediation Adjustment Clause (RAC) Filing PSE&G is engaged in a program to address potential environmental concerns regarding its former Manufactured Gas Plant (MGP) properties in cooperation with and under the supervision of NJDEP.
The costs of the program are recovered through the Remediation Adjustment Clause (RAC). The RAC addresses costs in annual periods ending July 31st of each year. The expenditures in each RAC
period are recovered over seven years. The costs of the program, including interest, are deferred and amortized as collected in revenues. On December 5, 2005 the BPU approved for recovery $18 million for the RAC-12 remediation expenditures incurred from August 1, 2003 through July 31, 2004. No change in the RAC recovery factor
was required. In February 2007, PSE&G submitted its RAC-13 and RAC-14 filings with the BPU. In these filings, PSE&G seeks an order finding that the $71 million of RAC program costs incurred during the two-year
period, August 1, 2004 through July 31, 2006, are reasonable and are available for recovery. PSE&G proposes that the current gas and electric RAC rates be reduced by approximately $18 million annually,
effective July 1, 2007. Gas Base Rate Case On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78% increase in its gas base rates to cover the cost of gas delivery to be effective June 30, 2006. Approximately $55
million of the $133 million request was for an increase in book depreciation rates. On November 9, 2006, the BPU approved a settlement agreement reached by the parties to the proceeding. The agreement provides for an annual increase in gas revenues of $40 million or
approximately 1.1%. In addition, the settlement provides for an adjustment to lower book depreciation and amortization expense for PSE&G by approximately $26 million annually and the amortization of
accumulated cost of removal that will further reduce depreciation and amortization expense by $13 million annually for five years. The settlement includes a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file a joint electric and gas petition for any future base
rate increases. Societal Benefits Clause (SBC) Filing On August 12, 2005, PSE&G filed a motion with the BPU seeking approval of changes in its electric and gas SBC rates and its electric non-utility generation transition charge (NTC) rates. For electric
customers, the rates proposed were designed to recover approximately $106 million in SBC revenues offset by lower NTC rates of $93 million beginning January 1, 2006. For gas, the rates proposed were
designed to recover approximately $10 million in SBC revenues. In 2006, PSE&G filed updates to its filing, modifying its requested changes to electric SBC/NTC rates and gas SBC rates. Public hearings were
held and settlement discussions began on outstanding issues. On January 19, 2007, settlement documents were filed with the ALJ, which upon approval, would result in an annual increase of approximately
$16 million in electric SBC/NTC revenues and $12 million in gas SBC revenues. Deferral Audit The BPU Energy and Audit Division conducts audits of deferred balances. A draft Deferral Audit—Phase II report relating to the 12-month period ended July 31, 2003 was released by the consultant to
the BPU in April 2005. The draft report addressed the SBC, Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances. The consultant to the BPU found that the Phase II
deferral balances complied in all material respects with the BPU orders regarding such deferrals, the consultant noted that the BPU Staff had raised certain questions with respect to the reconciliation
method PSE&G employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. For additional information regarding PSE&G’s Deferral
Audit, see Note 12. Commitments and Contingent Liabilities of the Notes. 24
Gas Purchasing Strategies Audit In January 2007, the BPU has issued an RFP to solicit bid proposals to engage a contractor to perform an analysis of the gas purchasing practices and hedging strategies of the four New Jersey gas
distribution companies (GDC’s), including PSE&G. The primary focus will be to examine and compare the financial and physical hedging policies and practices of each GDC and to provide recommendations
for improvements to these policies and practices. PSE&G cannot predict the outcome of this process. New Jersey Clean Energy Program In December 2004, the BPU has approved a funding requirement for each New Jersey utility applicable to Renewable Energy and Energy Efficiency programs for the years 2005 through 2008. The
State of New Jersey has awarded contracts to two market managers, TRC Energy Services and Honeywell Utility Solutions to take over program management functions from the utilities. This transition is
now expected to take place in the first half of 2007. For additional information regarding PSE&G’s Clean Energy Program, see Note 12. Commitments and Contingent Liabilities of the Notes. Power Connecticut Legislation has been introduced in the Connecticut General Assembly that would impose a tax on electric generators of 50% on earnings above a 20% return on equity. Proceeds from this proposed
“windfall profits tax” would be used to provide consumer rate relief. Legislation also has been introduced that would allow the state’s electric utility companies to build and place into rate base up to 300
megawatts of peaking electric generation. Neither PSEG nor Power is able to predict whether any of such proposals will be enacted into law or their impact, if any, or whether similar initiatives may be considered in other jurisdictions. Connecticut Department of Public Utility Control (DPUC) To reduce the impact of federally-mandated congestion charges on Connecticut ratepayers, Connecticut has launched a procurement process to facilitate the development of incremental generation
capacity, as authorized by legislation which permits the DPUC to establish a competitive procurement process intended to encourage new supply-side and demand-side resources. Specifically, the DPUC is
required to develop and issue a request for proposals (RFP) to solicit the development of long-term projects, with local distribution companies serving as the counterparties to these contracts. The impact of
this RFP process on Power Connecticut’s assets is unclear at the present time. Energy Holdings Texas Global’s generation business in Texas (TIE) is a merchant generation business that participates, through its subsidiaries, Odessa-Ector Power Partners, L.P. (Odessa) and Guadalupe Power Partners, LP
(Guadalupe), in the Texas wholesale energy market administered by ERCOT. Under the regulation of the Public Utility Commission of Texas, ERCOT performs three main roles in managing the electric
power grid and marketplace: ensuring that the grid can accommodate scheduled energy transfers, ensuring grid reliability, and overseeing retail transactions. While neither TIE, Odessa nor Guadalupe are
public utilities subject to the jurisdiction of FERC, they are subject to FERC jurisdiction for purposes of complying with NERC’s Reliability Standards (see discussion in Federal
Regulation—Compliance—Reliability Standards). Like other energy markets, energy prices in ERCOT have risen over the past few years due, in large measure, to higher fuel costs. In an attempt to lower electricity prices, the legislature in Texas is
currently examining proposals for draft legislation that could affect the Texas market. PSEG does not know at this time if any legislation will ultimately pass, or if it does, what its effect will be on Global’s
generation business in Texas. 25
International Regulation Energy Holdings Global Global’s electric distribution facilities in South America are rate-regulated enterprises. Rates charged to customers are established by government authorities and are viewed by Global as currently
sufficient to cover operating costs and provide a return on its investments. Global can give no assurances that future rates will be established at levels sufficient to cover such costs, provide a return on its
investments or generate adequate cash flow to pay principal and interest on its debt or to enable it to comply with the terms of its debt agreements. Chile Distribution companies in Chile, including Chilquinta Energia S.A. (Chilquinta) and associated companies, Sociedad Austral de Electricidad S.A. (SAESA) and other members of the SAESA Group,
are subject to rate regulation by the Comision Nacional de Energia (CNE), a national governmental regulatory authority. The Chilean regulatory framework has been in existence since 1982, with rates set
every four years based on a model company for each typical concession area. The tariff which distribution companies charge to regulated customers consists of two components: the actual cost of energy
purchased and an additional amount to compensate for the value added in distribution (DVA tariff). The DVA tariff considers allowed losses incurred in the distribution of electricity, administrative costs
of providing service to customers, costs of maintaining and operating the distribution systems and an annual return on investment between 6% to 14% over inflation applied to the replacement cost of
distribution assets. Changes in electricity distribution companies’ cost of energy are passed through to customers, with no impact on the distributors’ margins (equal to the DVA tariff). Therefore,
distributors, including members of the SAESA Group and Chilquinta, should not be affected by changes in the generation sector which affect prices. The most recent tariff adjustments for members of the
SAESA Group and Chilquinta occurred in 2004 and have been reviewed and approved by the CNE. In addition, the first auction for long-term supply contracts for Chilean distribution companies was simultaneously conducted during 2006. SAESA and Chilquinta were successful in contracting for
approximately 2,900 Gwh/yr and 800 Gwh/yr, respectively from various generation companies to supply their regulated customers needs starting in 2010 and continuing through 2020 and 2025 for SAESA and Chilquinta, respectively. A
second auction process for additional needs for Chilquinta (approximately 1,800 Gwh/year) will be held during 2007. Peru Distribution companies in Peru, including Luz del Sur S.A.A. (LDS), are subject to tariff regulation by the Organismo Supervisor de la Inversion en Energia, a national governmental regulatory
authority. The Peruvian regulatory framework has been in existence since 1992, with tariffs set every four years based on a model company. The tariff which distribution companies charge to regulated
customers consists of two components: the actual cost of energy purchased plus an additional amount to compensate for the DVA tariff. The DVA tariff considers allowed losses incurred in the distribution
of electricity, administrative costs of providing service to customers, costs of maintaining and operating the distribution systems and an annual return on investment of 8% to 16% over inflation, based on
the replacement cost of distribution assets. Changes in electricity distribution companies’ cost of energy are passed through to customers, with no impact on the distributors’ margins (equal to the DVA
tariff). Therefore, distributors, including LDS, should not be affected by changes in the generation sector, which affect prices. The most recent tariff adjustments for LDS occurred in connection with the
2005 tariff-setting process. New tariffs were effective as of November 1, 2005. In addition, in accordance with local regulations, an auction was conducted at the end of December 2006 for prospective energy supply requirements for LDS. The total amount bid by Peruvian power
producers was 650 MW of capacity. This supply combined with the contracts still in force are expected to be sufficient to meet LDS’s energy supply needs for 2007. In order to secure the growing supply
needs for 2008 and beyond, management plans to conduct additional energy supply auctions, as necessary, during 2007. Management is concurrently exploring the feasibility of other forms of bilateral supply
contracts, as well as advocating the extension of a law beyond December 2007, which currently allows LDS and other distribution companies without supply contracts, to draw energy from the grid, as
required, at regulated prices to satisfy the regulated market’s demand. 26
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. PSEG, PSE&G, Power and Energy Holdings Federal, regional, state and local authorities regulate the environmental impacts of PSEG’s operations within the U.S. Laws and regulations particular to the region, country or locality where PSEG’s
operations are located govern the environmental impacts associated with its foreign operations. For both domestic and foreign operations, areas of regulation may include air quality, water quality, site
remediation, land use, waste disposal, aesthetics, impact on global climate and other matters. To the extent that environmental requirements are more stringent and compliance more costly in certain states where PSEG operates compared to other states that are part of the same market, such
rules may impact its ability to compete within that market. Due to evolving environmental regulations, it is difficult to project expected costs of compliance and its impact on competition. For additional
information related to environmental matters, see Item 3. Legal Proceedings. PSEG, Power and Energy Holdings Air Pollution Control The Federal Clean Air Act (CAA) and its implementing regulations require controls of emissions from sources of air pollution and also impose record keeping, reporting and permit requirements.
Facilities in the U.S. that Power and Energy Holdings operate or in which they have an ownership interest are subject to these Federal requirements, as well as requirements established under state and
local air pollution laws applicable where those facilities are located. Capital costs of complying with air pollution control requirements through 2010 are included in Power’s estimate of construction
expenditures in Item 7. MD&A—Capital Requirements. Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in
some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The Federal government may order companies not in compliance with the PSD/NSR regulations to
install the best available control technology at the affected plants and to pay monetary penalties of up to approximately $27,500 for each day of continued violation. The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-burning units were
implemented in accordance with applicable PSD/NSR regulations. Power completed its response to requests for information and, in January 2002, reached an agreement with the NJDEP and the EPA to
resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur
Dioxide (SO2), Nitrogen Oxide (NOx), particulate matter and mercury from the coal-burning units at the Mercer and Hudson generating stations to ensure compliance with PSD/NSR. Power also agreed to
spend at least $6 million on supplemental environmental projects and pay a $1 million civil penalty. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also
resolved a dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operations to commence. Power notified the EPA and the NJDEP that it was evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution
control equipment and other necessary modifications to the unit. On November 30, 2006, Power, reached an agreement with the EPA and NJDEP on an amendment to its 2002 agreement intended to
achieve the emissions reductions targets of this agreement while providing more time to assess the feasibility of installing additional advanced emissions controls at Hudson. 27
The amended agreement with the EPA and the NJDEP will allow Power to continue operating Hudson and extend for four years the deadline for installing environmental controls beyond the previous
December 31, 2006 deadline. Power will be required to undertake a number of technology projects (SCRs, scrubbers, baghouses, and carbon injection), plant modifications, and operating procedure changes
at Hudson and Mercer designed to meet targeted reductions in emissions of NOx, SO2, particulate matter, and mercury. In addition, Power has agreed to notify the EPA and NJDEP by the end of 2007
whether it will install the additional emissions controls at Hudson by the end of 2010, or plan for the orderly shut down of the unit. Under the program to date, Power has installed Selective Catalytic Reduction Systems (SCRs) at Mercer at a cost of approximately $113 million. The cost of implementing the balance of the amended
agreement at Mercer and Hudson is estimated at $400 million to $500 million for Mercer and at $600 million to $750 million for Hudson and will be incurred in the 2007-2010 timeframe. As part of the
agreement, Fossil has agreed to purchase and retire emissions allowances, contribute approximately $3 million for programs to reduce particulate emissions from diesel engines in New Jersey, and pay a $6
million civil penalty. SO2 / NOx To reduce emissions of SO2 for acid rain prevention, the CAA sets a cap on total SO2 emissions from affected units and allocates SO2 allowances (each allowance authorizes the emission of one ton of
SO2) to those units. Generation units with emissions greater than their allocations can obtain allowances from sources that have excess allowances. At this time, Power does not expect to incur material
expenditures to continue complying with the acid rain SO2 emissions program. The EPA has issued regulations (commonly known as the NOx State Implementation Plan (SIP) Call) requiring 19 states in the eastern half of the U.S. and the District of Colombia to reduce and cap
NOx emissions from power plant and industrial sources. The NOx reduction requirements are consistent with requirements already in place in New Jersey, New York, Connecticut and Pennsylvania, and
therefore have not had an additional impact on the capacity available from Power’s facilities in those states. Power has been implementing measures to reduce NOx emissions at several of its units
(including the installation of selective catalytic reduction systems at the Mercer Generating Station), which has reduced the impact of any further increases to the costs of allowances. In 1997, the EPA adopted a new air quality standard for fine particulate matter and a revised air quality standard for ozone. In 2004, the EPA identified and designated areas of the U.S. that fail to
meet the revised federal health standard for ozone or the new federal health standard for fine particulates. States are expected to develop regulatory measures necessary to achieve and maintain the health
standards, which may require reductions in NOx and SO2 emissions. Additional NOx and SO2 reductions also may be required to satisfy requirements of an EPA rule protecting visibility in many of the
nation’s Class 1 (pristine) environmental areas. Most of Power’s fossil facilities would be affected by this initiative. In May 2005, the EPA published the final Clean Air Interstate Rule (CAIR) that identifies 28 states and the District of Columbia as contributing significantly to the levels of fine particulates and/or
eight-hour ozone in downwind states. New Jersey, New York, Pennsylvania, Indiana, Texas and Connecticut are among the states the EPA lists in the CAIR. Based on state obligations to address interstate
transport of pollutants under the CAA, the EPA has proposed a two-phased emission reduction program for NOx and SO2, with Phase 1 beginning in 2009 (NOx) and 2010 (SO2) and Phase 2 beginning in
2015. The EPA is recommending that the program be implemented through a cap-and-trade program, although states are not required to proceed in this manner. In December 2005, the EPA proposed new National Ambient Air Quality Standards for particulate matter. Power is unable to determine whether any costs it may incur to comply with the above standards would be material. Carbon Dioxide (CO2) Emissions Several states, primarily in the Northeastern U.S., are developing state-specific or regional legislative initiatives to stimulate CO2 emissions reductions in the electric power industry. New York initiated
the Regional Greenhouse Gas Initiative (RGGI) in April 2003. Currently, in the RGGI, seven Northeastern states have signed a memorandum of understanding (MOU) intended to cap and reduce CO2
emissions from the electric power sector in the RGGI region. A final model rule was issued on August 15, 2006 that includes 28
MOU commitments and makes recommendations for states to move forward. The model rule contemplates the creation of a CO2 allowance allocation and auction whereby CO2 generators in the electric
power industry would be expected to acquire through allocation, or purchase through an auction, CO2 allowances in an amount corresponding to each facility’s emissions. Facilities with an insufficient
number of allowances would be required to purchase additional allowances. New York has publicly announced its intent to subject 100% of the allowances to auction, and other states, including New Jersey,
may do the same. States are expected to enact legislation and/or regulation representing, at least, the minimum requirements stipulated in the MOU. The RGGI program is scheduled to start in 2009. The
NJDEP in 2005 finalized amendments to its regulations governing air pollution control that would designate CO2 as an air contaminant subject to regulation. In February 2007, the Governor of New Jersey
issued an executive order committing the State to reduce emissions of greenhouse gasses 20% by 2020 and 80% by 2050. The outcome of this initiative cannot be determined at this time; however, adoption
of stringent CO2 emissions reduction requirements in the Northeast, including the allocation of allowances to PSEG’s facilities and the prices of allowances available through auction, could materially
impact Power’s operation of its fossil fuel-fired electric generating units. Other Air Pollutants In March 2005, the EPA promulgated two rules: one revising its December 2000 determination that Hazardous Air Pollutants from coal-fired and oil-fired Electric Generating Units (EGUs) should be
regulated under section 112 of the CAA and, on that basis, removing those units from the section 112(c) source category list (known as the delisting rule); the second establishing a New Source Performance
Standard limit for nickel emissions from oil-fired EGUs, and a cap-and-trade program for mercury emissions from coal-fired EGUs, with a first phase cap of 38 tons per year (tpy) in 2010 and a second
phase cap of 15 tpy in 2018 (the ‘cap-and-trade rule’). The EPA determined that it would not regulate other emissions from coal-fired and oil-fired EGUs. A number of environmental and medical groups, the city of Baltimore and a total of 16 states (all six New England states, New Jersey, California, Delaware, Illinois, New Mexico, New York,
Minnesota, Pennsylvania, Michigan and Wisconsin) have sued the EPA challenging that the rules should be more restrictive. The environmental petitioners, but not the states, also sought a stay of the rules
from both the agency and the court, but the request was denied. The outcome of these litigations cannot be determined at this time. New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The Connecticut legislation requires coal-fired power plants in
Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions effective in July 2008. The regulations in New Jersey require
coal-fired electric generating units in New Jersey to meet certain emission limits or reduce emissions by 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements are
permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012. Power has a multi-pollutant reduction agreement with the NJDEP as a result of a
consent decree that resolved issues arising out of the PSD and NSR air pollution control programs at the Hudson, Mercer and Bergen facilities. Substantial uncertainty exists regarding the feasibility of
achieving the reductions in mercury emissions required by the New Jersey regulations and Connecticut statute; however, the estimated costs of technology believed to be capable of meeting these emissions
limits at Power’s coal-fired unit in Connecticut by July 2008 and at its Mercer Station by December 15, 2007 are included in Power’s capital expenditure forecast. Water Pollution Control The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to waters of the U.S. from point sources, except pursuant to a National Pollutant Discharge Elimination
System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to
regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including the NJDEP, to administer the NPDES program through
state acts. The New Jersey Water Pollution Control Act (NJWPCA) authorizes the NJDEP to implement regulations and to administer the NPDES program with EPA oversight, and to issue and enforce
New Jersey Pollutant Discharge Elimination System (NJPDES) permits. Power and Energy Holdings also have ownership interests in domestic facilities in 29
other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters that directly govern Power’s or Energy Holdings’ facilities in these
jurisdictions. The EPA promulgated regulations under FWPCA Section 316(b), which requires that cooling water intake structures reflect the best technology available (BTA) for minimizing ‘adverse environmental
impact.’ Phase I of the rule covering new facilities became effective on January 17, 2002. None of the projects that Power currently has under construction or in development is subject to the Phase I rule.
The Phase II rule covering large existing power plants became effective on September 7, 2004. The Phase II regulations provided five alternative methods by which a facility can demonstrate that it complies
with the requirement for BTA for minimizing adverse environmental impacts associated with cooling water intake structures. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its decision in litigation of the Phase II rule brought by several environmental groups, the Attorneys General of six
Northeastern states, the Utility Water Act Group and several of its members, including Power. The court remanded major portions of the rule and determined that Section 316(b) of the Clean Water Act
does not support the use of restoration and the site specific cost-benefit test. Among the provisions the court remanded back to EPA for further consideration and rulemaking, the court instructed EPA to
reconsider the definition of BTA without comparing the costs of the best performing technology to its benefits. Prior to this decision, Power has used restoration and site-specific cost benefit tests in
applications it has filed to renew the NJPDES permits at its once-though cooled plants, including Salem, Hudson and Mercer. Although the rule applies to all of Power’s electric generating units that use
surface waters for once-through cooling purposes, the impact of the rule and the decision of the court cannot be determined at this time for all of Power’s facilities. Depending on the outcome of any
appeals, or actions by EPA to repromulgate the rule, this decision could have a material impact on Power’s ability to renew its NPDES permits at its larger once-through cooled plants, including Salem,
Hudson, Mercer, New Haven and Bridgeport, without making significant upgrades to their existing intake structures and cooling systems. The costs of those upgrades could be material to one or more of Power’s once-through
cooled plants. Power Permit Renewals For information on permit renewals for Salem, see Note 12, Commitments and Contingent Liabilities of the Notes. PSE&G and Power Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and New Jersey Spill Compensation and Control Act (Spill Act) CERCLA and the Spill Act authorize Federal and state trustees for natural resources to assess damages against persons who have discharged a hazardous substance, causing an injury to natural
resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The
NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation
of contaminated sites. In 2003, the NJDEP issued a policy directive memorializing its efforts to recover natural resource damages and its intent to continue to pursue the recovery of natural resource
damages. The NJDEP also issued guidance to assist parties in calculating their natural resource damage liability for settlement purposes, but has stated that those calculations are applicable only for those
parties that volunteer to settle a claim for natural resource damages before a claim is asserted by the NJDEP. PSE&G and Power cannot assess the magnitude of the potential financial impact of this
regulatory change. See Note 12. Commitments and Contingent Liabilities of the Notes for additional information. Because of the nature of PSE&G’s and Power’s respective businesses, including the production and delivery of electricity, the distribution of gas and, formerly, the manufacture of gas, various by-
products and substances are or were produced or handled that contain constituents classified by Federal and state authorities as hazardous. For discussions of these hazardous substance issues and a
discussion of potential liability for remedial action regarding the Passaic River, see Note 12. Commitments and Contingent 30
Liabilities of the Notes. For a discussion of remediation/clean-up actions involving PSE&G and Power, see Item 3. Legal Proceedings. Uranium Enrichment Decontamination and Decommissioning Fund In accordance with the EP Act, domestic entities that own nuclear generating stations are required to pay into a decontamination and decommissioning fund, based on their past purchases of U.S.
government enrichment services. Since these amounts are being collected from PSE&G’s customers over a period of 15 years, this obligation remained with PSE&G following the generation asset transfer to
Power in 2000. PSE&G’s obligation for the nuclear generating stations in which it had an interest was $76 million (adjusted for inflation). As of December 31, 2006, PSE&G and Power had both paid their
remaining obligations. New Jersey Operating Permits The New Jersey Air Pollution Control Act requires that certain sources of air emissions obtain operating permits issued by NJDEP. All of Power’s generating facilities in New Jersey are required to
have such operating permits. The costs of compliance associated with any new requirements that may be imposed by these permits in the future are not known at this time and are not included in capital
expenditures, but may be material. Power Nuclear Fuel Disposal Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate
disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per kWh of nuclear generation, subject to such
escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear
fuel by no later than 1998. The DOE has announced that it does not expect a facility for such purpose to be available earlier than 2017. Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from-
reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). Adequate spent fuel storage capacity is estimated to be available
through 2011 for Salem 1 and 2015 for Salem 2. Power completed, in August 2006, construction of an on-site storage facility that will satisfy the spent fuel storage needs of Hope Creek through the end of its
current license. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach Bottom’s spent fuel storage requirements until at
least 2014. Exelon Generation had previously advised Power that it had signed an agreement with the DOE, applicable to Peach Bottom, under which Exelon Generation would be reimbursed for costs incurred
resulting from the DOE’s delay in accepting spent nuclear fuel for permanent storage. Future costs incurred resulting from the DOE delays in accepting spent fuel will be reimbursed annually until the
DOE fulfills its obligation to accept spent nuclear fuel. In addition, Exelon Generation and Nuclear are required to reimburse the DOE for the previously received credits from the Nuclear Waste Fund,
plus lost earnings. Under this settlement, Power received approximately $27 million for its share of previously incurred storage costs for Peach Bottom, $22 million of which was used for the required
reimbursement to the Nuclear Waste Fund. Exelon Generation paid Power approximately $5.4 million for its portion of the spent fuel storage costs reimbursed by the DOE in 2005 for costs incurred
between October 1, 2003 and June 30, 2005. In September 2001, Power filed a complaint in the U.S. Court of Federal Claims seeking damages for Salem and Hope Creek caused by the DOE not taking possession of spent nuclear fuel in 1998. On
October 14, 2004, an order to show cause was issued regarding whether the U.S. Court of Federal Claims has jurisdiction over the matter. Power responded to this order in November 2004. On January 31,
2005, the Court dismissed the breach-of-contract claims of Power and three other utilities. Power moved for reconsideration in the U.S. Court of Federal Claims and jointly petitioned for permission to
appeal the January 31, 2005 order to the U.S. Court of Appeals for the Federal Circuit. On September 29, 2006, the U.S. Court of Appeals for the Federal Circuit reversed the adverse U.S. Court of Federal
Claims jurisdictional 31
ruling and reinstated Power’s claims in the U.S. Court of Federal Claims. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility. Spent Fuel Pool The spent fuel pool at each Salem unit has an installed leakage collection system. This system was found to be obstructed at Salem Unit 1. Power developed a solution to maintain the design function of
the leakage collection system at Salem Unit 1 and investigated the existence of any structural degradation that might have been caused by the obstruction. The concrete and reinforcing steel laboratory tests
results were completed in March 2006. Test results that have been collected as part of the ongoing testing indicate that no repairs are anticipated. The NRC issued Information Notice 2004-05 in March 2004
concerning this emerging industry issue and Power cannot predict what further actions the NRC may take on this matter. Elevated concentrations of tritium in the shallow groundwater at Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Power conducted a
comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power is conducting remedial actions to address
the contamination in accordance with a remedial action workplan approved by the NJDEP in November 2004. The remedial actions are expected to be ongoing for several years. The costs necessary to
address this on-site groundwater contamination issue are not expected to be material. Low Level Radioactive Waste (LLRW) As a by-product of their operations, nuclear generation units produce LLRW. Such wastes include paper, plastics, protective clothing, water purification materials and other materials. LLRW materials
are accumulated on-site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear
generators, including Power, continued access to the Barnwell LLRW disposal facility which is owned by South Carolina. Power believes that the Atlantic Compact will provide for adequate LLRW disposal
for Salem and Hope Creek through the end of their current licenses, although no assurances can be given. Both Power and Exelon have on-site LLRW storage facilities for Salem, Hope Creek and Peach
Bottom, which have the capacity for at least five years of temporary storage for each facility. For information regarding Nuclear Spent Fuel Pool, see Note 12. Commitments and Contingent Liabilities of
the Notes. PSE&G MGP Remediation Program For information regarding PSE&G’s MGP Remediation Program, see Note 12. Commitments and Contingent Liabilities of the Notes. PSEG, PSE&G, Power and Energy Holdings The following factors should be considered when reviewing the businesses of PSEG, PSE&G, Power and Energy Holdings. These factors could significantly impact the businesses and cause results to
differ materially from those expressed in any statements made by, or on behalf of PSEG, PSE&G, Power or Energy Holdings herein. Some or all of these factors may apply to each of PSEG, PSE&G, Power,
Energy Holdings and their respective subsidiaries. Generation operating performance may fall below projected levels Power and Energy Holdings Operating generating stations below expected capacity levels, especially at low-cost nuclear and coal facilities, may result in lost revenues and increased expenses, including replacement power costs.
Factors that could cause generating station operations to fall below expected levels include, but are not limited to, the following: • disruptions in the transmission of electricity; 32
•
breakdown or failure of equipment, processes or management effectiveness;
• labor disputes; • fuel supply interruptions or transportation constraints; • limitations which may be imposed by environmental or other regulatory requirements; • permit limitations; and • operator error or catastrophic events such as fires, earthquakes, explosions, floods, acts of terrorism or other similar occurrences. The potential lost revenues and increased expenses could result in a case where sufficient cash may not be available to service debt. In addition, any prolonged operating performance issues could
potentially result in an impairment of the value of the affected facility. Failure to obtain adequate and timely rate relief could negatively impact results PSE&G As a public utility, PSE&G’s rates are regulated. These rates are designed to allow PSE&G the opportunity to recover its operating expenses and earn a fair return on its rate base, which primarily consists
of its property, plant and equipment. These rates include its electric and gas tariff rates that are subject to regulation by the BPU as well as its transmission rates that are subject to regulation by FERC.
PSE&G’s base rates are set by the BPU for electric distribution and gas distribution and are effective until the time a new rate case is brought to the BPU. These base rate cases generally take place when
equity returns fall below reasonable levels. Some categories of costs, such as energy costs, are recovered through adjustment charges that are periodically reset to reflect actual costs. If these costs exceed the
amount included in PSE&G’s adjustment charges, there may be a negative impact on cash flows. If PSE&G does not obtain adequate rate treatment on a timely basis in order to meet its operating expenses, there may be a negative impact on earnings and operating cash flows. PSE&G can give no
assurances that tariff relief will be timely or sufficient for it to recover its costs and provide a sufficient return for its investors. Energy Holdings Global’s distribution facilities are rate-regulated enterprises. Governmental authorities establish rates charged to customers. While these rates are designed to cover all operating costs and provide a
return on investment, Energy Holdings can give no assurances that rates will, in the future, be sufficient to cover Global’s costs and provide a sufficient return on its investments. In addition, future rates
may not be adequate to provide cash flow to pay principal and interest on the debt of Global’s subsidiaries and affiliates or to enable its subsidiaries and affiliates to comply with the terms of debt
agreements. Inability to balance energy obligations, available supply and trading risks could negatively impact results Power and Energy Holdings The revenues generated by the operation of the generating stations are subject to market risks that are beyond each company’s control. Generation output will either be used to satisfy wholesale
contract requirements, other bilateral contracts or be sold into other competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their
capital investments through recovery of mandated rates payable by purchasers of electricity. Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served. Power Power’s energy trading and marketing activities frequently involve the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that
Power has produced or purchased energy in excess of its contracted obligations a reduction in market prices could reduce profitability. 33
Conversely, to the extent that Power has contracted obligations in excess of energy it has produced or purchased, an increase in market prices could reduce profitability. If the strategy Power utilizes to hedge its exposures to these various risks is not effective, it could incur significant losses. Power’s substantial market positions can also be adversely affected by the level
of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas, short-term supply and demand imbalances and pricing differentials at various
geographic locations, which cannot be predicted with any certainty. Increases in market prices also affect Power’s ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices and, resultingly, could require the
maintenance of liquidity resources that would be prohibitively expensive. Environmental regulations could limit operations PSEG, PSE&G, Power and Energy Holdings PSEG, PSE&G, Power and Energy Holdings are required to comply with numerous statutes, regulations and ordinances relating to the safety and health of employees and the public, the protection of
the environment and land use. These statutes, regulations and ordinances are constantly changing. While management believes that PSEG, PSE&G, Power and Energy Holdings have obtained all material
approvals currently required to own and operate their respective facilities and that approvals will be issued in a timely manner, significant additional costs could be incurred in order to comply with these
requirements. In some cases, the cost of compliance could exceed the marginal value of the facility. Failure to comply with environmental statutes, regulations and ordinances could have a material effect on
PSEG, PSE&G, Power and Energy Holdings, including potential civil or criminal liability, the imposition of clean-up liens or fines and expenditures of funds to bring facilities into compliance or possible
impairment of the value of the affected facility. PSEG, PSE&G, Power and Energy Holdings can give no assurance that they will be able to: • obtain any necessary modifications to existing environmental approvals; • maintain compliance with all applicable environmental laws, regulations and approvals; or • recover any resulting costs through future sales. Delay in obtaining or failure to obtain and maintain in full force and effect any environmental approvals, or delay or failure to satisfy any applicable environmental regulatory requirements, could
prevent construction of new facilities, operation of existing facilities or sale of energy from these facilities or could result in significant additional costs. Power Many of Power’s generating facilities are located in the State of New Jersey where environmental programs are generally considered to be more stringent in comparison to similar programs in other
states. As such, there may be instances where the facilities located in New Jersey are subject to more stringent and, therefore, more costly pollution control requirements than competitive facilities in other
states. Regulatory issues significantly impact operations and profitability PSEG, PSE&G, Power and Energy Holdings Federal, state and local authorities impose substantial regulation and permitting requirements on the electric power generation business. Power and Energy Holdings are required to comply with
numerous laws and regulations and to obtain numerous governmental permits in order to operate generation stations. In addition, PSE&G’s and certain of Global’s distribution facilities could be subject to
financial penalties if reliability performance standards are not met. PSEG, PSE&G, Power and Energy Holdings can give no assurance that existing regulations will not be revised or reinterpreted, that new laws and regulations will not be adopted or become applicable or
that future changes in laws and regulations, including the possibility of reregulation in some deregulated markets, will not have a detrimental effect on their respective businesses. 34
•
obtain all required environmental approvals not yet received or that may be required in the future;
Power and Energy Holdings Power and Energy Holdings believe that they have obtained all material energy-related federal, state and local approvals currently required to operate their respective generation stations and sell
energy output, including MBR authority from FERC. Although not currently required, additional regulatory approvals may be required in the future due to changes in laws and regulations or for other
reasons. No assurance can be given that Power and Energy Holdings will be able to obtain any required regulatory approval in the future, or that they will be able to obtain any necessary extensions in
receiving any required regulatory approvals. Power is also subject to pervasive regulation by the NRC with respect to the operation of nuclear generation stations. This regulation involves testing, evaluation and modification of all aspects of plant
operation in light of NRC safety, environmental and personnel management requirements. The NRC also requires continuous demonstrations that plant operations meet applicable requirements. The NRC
has the ultimate authority to determine whether any nuclear generation unit may operate. Any failure to obtain or comply with any required regulatory approvals could materially adversely affect Power’s and Energy Holdings’ ability to operate generation stations or sell electricity to third
parties. In addition, there is also a risk to Power and Energy Holdings if states decide to turn away from competition and allow regulated utilities to continue to own or reacquire and operate generating stations
in a regulated and potentially uneconomical manner, or to encourage rate-based treatment for the construction of new base-load generating units. This has already occurred in certain states. The lack of
consistent rules in markets outside of PJM can negatively impact the competitiveness of Power’s plants. Moreover, current rules being developed at FERC, at DOE and at PJM with respect to the access to and construction of transmission and the allocation of costs for such construction may have the
effect of altering the level playing field between transmission options and generation options, which could have a competitive impact upon PSEG and Power. Availability of adequate power transmission facilities PSEG, PSE&G, Power and Energy Holdings The ability to sell and deliver electric energy products may be adversely impacted and the ability to generate revenues may be limited if: • transmission capacity is inadequate; or • a region’s power transmission infrastructure is inadequate. 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 35
•
transmission is disrupted;
activities, Power must meet credit quality standards required by counterparties. Standard industry contracts generally require trading counterparties to maintain investment grade ratings. These same
contracts provide reciprocal benefits to Power. If Power loses its investment grade credit rating, ER&T would have to provide additional collateral in the form of letters of credit or cash, which would
significantly impact the energy trading business. This would increase Power’s costs of doing business and limit its ability to successfully conduct energy trading operations. Power sells generation output through the execution of bilateral contracts. These contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual obligations.
Any failure to perform on the part of these counterparties could have a material impact on PSEG’s and Power’s results of operations, cash flows and financial position. As market prices rise above
contracted price levels, Power is required to post collateral with purchasers. Collateral posting requirements for BGS contracts in particular are one-sided. If market prices fall below BGS contracted price
levels for a single contract, power purchasers are not required to post collateral with Power. However, such margin positions can be netted against margin due from Power in other BGS contracts with the
same counterparty. Substantial competition from well-capitalized participants in the worldwide energy markets PSEG, PSE&G, Power and Energy Holdings Restructuring of worldwide energy markets is creating opportunities for, and substantial competition from, well-capitalized entities that may adversely affect the ability of PSEG, PSE&G, Power and
Energy Holdings to make investments on favorable terms and achieve growth objectives. Increased competition could contribute to a reduction in prices offered for power and could result in lower returns
which may affect PSEG’s, PSE&G’s, Power’s and Energy Holdings’ ability to service their respective outstanding indebtedness, including short-term debt. Some of the competitors include: • banks, funds and other financial entities; • domestic and multi-national utility generators; • energy marketers; • fuel supply companies; and • affiliates of other industrial companies. As a holding company, the ability to service debt could be limited PSEG and Energy Holdings PSEG and Energy Holdings are holding companies with no material assets other than the stock or membership interests of their subsidiaries and project affiliates. As such, PSEG and Energy Holdings
depend on their respective subsidiaries’ and project affiliates’ cash flow and their respective access to capital in order to service their indebtedness. Each of PSEG’s and Energy Holdings’ respective
subsidiaries and project affiliates are separate and distinct legal entities that have no obligation, contingent or otherwise, to pay any amounts when due on PSEG’s or Energy Holdings’ debt or to make any
funds available to pay such amounts. As a result, PSEG’s and Energy Holdings’ debt will effectively be subordinated to all existing and future debt, trade creditors, and other liabilities of their respective
subsidiaries and project affiliates and PSEG’s and Energy Holdings’ rights and hence the rights of their respective creditors to participate in any distribution of assets of any subsidiary or project affiliate
upon its liquidation or reorganization or otherwise would be subject to the prior claims of that subsidiary’s or project affiliate’s creditors, except to the extent that PSEG’s or Energy Holdings’ claims as a
creditor of such subsidiary or project affiliate may be recognized. In addition, Energy Holdings’ subsidiaries’ project-related debt agreements generally restrict the subsidiaries’ ability to pay dividends, make cash distributions or otherwise transfer funds. These
restrictions may include achieving and maintaining financial performance or debt coverage ratios, absence of events of default, or priority in payment of other current or prospective obligations. Also,
Energy Holdings is structurally designed to be able to meet its obligations without any support from its parent, PSEG. These restrictions could further restrict Energy Holdings’ ability to service its
outstanding indebtedness. 36
•
merchant generators;
Adverse international developments could negatively impact results Energy Holdings A component of PSEG’s and Energy Holdings business is international distribution and generation, primarily in Chile and Peru. The economic and political conditions in certain countries where Global
has interests present risks that may be different than those found in the U.S. which could affect the value of its investments, cash flows from projects and make it more difficult to obtain non-recourse
project refinancing on suitable terms or could impair Global’s ability to enforce its rights under agreements relating to such projects. Such risks include: • renegotiation or abrogation of existing contracts; and • changes in law or tax policy. Operations in foreign countries also present risks associated with currency exchange rates and convertibility, inflation and repatriation of earnings. In some countries, economic and monetary conditions
and other factors could affect Global’s ability to convert its cash distributions to U.S. Dollars or other freely convertible currencies, or to move funds offshore from these countries. Furthermore, the central
bank of any of these countries may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to approve distributions to foreign investors. Inability to realize tax benefits Energy Holdings Through its leveraged lease investments, Resources acquired an asset by investing equity representing approximately 15% to 20% of the cost of the asset and incurring non-recourse lease debt for the
balance. As the owner, Resources is entitled to depreciate the asset under applicable federal and state tax guidelines and receives income from the tax benefits associated with interest and depreciation
deductions with respect to the leased property. The ability of Resources to realize these tax benefits is dependent on operating income generated by its affiliates and allocated pursuant to PSEG’s
consolidated tax sharing agreement. A reduction of operating income could impair Resources’ ability to receive such benefits, which would result in a reduction of earnings and cash flows. In addition,
during 2006, the IRS disallowed certain deductions associated with some of the leveraged leases which have been designated by the IRS as listed transactions. For additional information see Note 12.
Commitments and Contingent Liabilities of the Notes. Any material disallowance of deductions could impact Energy Holdings’ earnings and ability to service its outstanding indebtedness. Decreases in the value of the pension and other postretirement assets could require additional funding PSEG, PSE&G, Power and Energy Holdings Adverse changes in the rates of return or performance of the investments in which the pension and other postretirement trust assets are held could lower the value of the funds and the trust assets. Such
a decline in value could result in additional funding obligations to meet the applicable legal and regulatory requirements. To the extent that these additional funding obligations are significant, this could
impact PSEG’s, PSE&G’s, Power’s and Energy Holdings’ ability to service debt. Changes in technology may make power generation assets less competitive Power and Energy Holdings A key element of the business plan is that generating power at central power plants produces electricity at relatively low cost. There are alternative technologies to produce electricity that continue to
attract capital for research and development, most notably fuel cells, microturbines, windmills and photovoltaic (solar) cells. It is possible that advances in technology will reduce the cost of alternative
methods of producing electricity to a level that is competitive with that of most central station electric production. If this were to happen, Power’s and Energy Holdings’ market share could be eroded and
the value of their respective power plants could be significantly impaired. Changes in technology could also alter the channels through which retail electric customers buy electricity, which could affect
financial results. 37
•
expropriation or nationalization of energy assets;
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: • commercial general public liability insurance; • boiler and machinery coverage; • nuclear liability; and • for nuclear generating units, replacement power and business interruption insurance in amounts and with deductibles that management considers appropriate. PSEG, PSE&G, Power and Energy Holdings can give no assurance that this insurance coverage will be available in the future on commercially reasonable terms or that the insurance proceeds received
for any loss of or any damage to any of their respective facilities will be sufficient to fund future payments on debt. Additionally, some properties may not be insured in the event of an act of terrorism. Recession, acts of war or terrorism PSEG, PSE&G, Power and Energy Holdings The consequences of a prolonged recession and adverse market conditions may include the continued uncertainty of energy prices and the capital and commodity markets. Management cannot predict
the impact of any continued economic slowdown, reduced growth rate in energy usage or fluctuating energy prices; however, such impact could have a material adverse effect on PSEG’s, PSE&G’s, Power’s
and Energy Holdings’ financial condition, results of operations and net cash flows. Major industrial facilities, generation plants, fuel storage facilities and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of PSE&G’s, Power’s or
Energy Holdings’ ability to produce or distribute some portion of their respective energy products. Any such disruption could result in a significant decrease in revenues and/or significant additional costs to
repair, which could have a material adverse impact on the financial condition, results of operation and net cash flows of PSEG, PSE&G, Power and Energy Holdings. ITEM 1B. UNRESOLVED STAFF COMMENTS PSEG None. PSE&G, Power and Energy Holdings Not Applicable. 38
•
all-risk property damage insurance;
PSEG and Services PSEG does not own any property. All property is owned by PSEG’s subsidiaries. Services leases a 25-story office tower for PSEG’s corporate headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining three-story building. In addition, Services owns the
Maplewood Test Services Facility in Maplewood, New Jersey. PSEG believes that it and its subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions, to the extent such property is usually
insured and insurance is available at a reasonable cost. PSE&G PSE&G’s First and Refunding Mortgage (Mortgage), securing the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property. PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under
easements or other rights. These easements and other rights are deemed by PSE&G to be adequate for the purposes for which they are being used. PSE&G believes that it maintains adequate insurance coverage against loss or damage to its principal properties, subject to certain exceptions, to the extent such property is usually insured and insurance
is available at a reasonable cost. Electric Transmission and Distribution Properties As of December 31, 2006, PSE&G’s transmission and distribution system included approximately 21,745 circuit miles, of which approximately 7,710 circuit miles were underground, and approximately
804,936 poles, of which approximately 538,811 poles were jointly-owned. Approximately 99% of this property is located in New Jersey. In addition, as of December 31, 2006, PSE&G owned four electric distribution headquarters and five subheadquarters in four operating divisions, all located in New Jersey. Gas Distribution Properties As of December 31, 2006, the daily gas capacity of PSE&G’s 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum
air gas (LPG) and liquefied natural gas (LNG) and aggregated 2,973,000 therms (approximately 2,886,000 cubic feet on an equivalent basis of 1.030 Btu/cubic foot) as shown in the following table: Plant Burlington LNG Camden LPG Central LPG Harrison LPG Total As of December 31, 2006, PSE&G owned and operated approximately 17,556 miles of gas mains, owned 12 gas distribution headquarters and two subheadquarters, all in three operating regions located in
New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, PSE&G operated 62 natural gas metering or regulating stations, all located in New Jersey, of which 28 were located
on land owned by customers or natural gas pipeline suppliers and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the
metering and regulating facilities. 39
Location
Daily Capacity
(Therms)
Burlington, NJ
773,000
Camden, NJ
280,000
Edison Twp., NJ
960,000
Harrison, NJ
960,000
2,973,000
Office Buildings and Facilities PSE&G rents office space from Services as its headquarters in Newark, New Jersey. PSE&G also leases office space at various locations throughout New Jersey for district offices and offices for various
corporate groups and services. PSE&G also owns various other sites for training, testing, parking, records storage, research, repair and maintenance, warehouse facilities and for other purposes related to its
business. In addition to the facilities discussed above, as of December 31, 2006, PSE&G owned 42 switching stations in New Jersey with an aggregate installed capacity of 22,809 megavolt-amperes and 244
substations with an aggregate installed capacity of 7,790 megavolt-amperes. In addition, four substations in New Jersey having an aggregate installed capacity of 109 megavolt-amperes were operated on
leased property. Power Power rents office space from Services as its headquarters in Newark, New Jersey. Other leased properties include office, warehouse, classroom and storage space, primarily located in New Jersey.
Power also owns the Central Maintenance Shop at Sewaren, New Jersey. Power has a 57.41% ownership interest in approximately 13,000 acres in the Delaware River Estuary region to satisfy the condition of the NJPDES permit issued for Salem. Power also owns several
other facilities, including the on-site Nuclear Administration and Processing Center buildings. Power has a 13.91% ownership interest in the 650-acre Merrill Creek Reservoir in Warren County, New Jersey and approximately 2,158 acres of land surrounding the reservoir. The reservoir was
constructed to store water for release to the Delaware River during periods of low flow. Merrill Creek is jointly-owned by seven companies that have generation facilities along the Delaware River or its
tributaries and use the river water in their operations. Power believes that it maintains adequate insurance coverage against loss or damage to its plants and properties, subject to certain exceptions, to the extent such property is usually insured and
insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Note 12. Commitments and Contingent Liabilities of the Notes. 40
As of December 31, 2006, Power’s share of installed generating capacity was 14,639 MW, as shown in the following table: OPERATING POWER PLANTS Name Steam: Hudson Mercer Sewaren 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 Linden Lawrenceburg(F) Bethlehem Total Combined Cycle Combustion Turbine: Essex Edison Kearny Burlington Linden Mercer Sewaren 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 (B) Operated by Reliant Energy. (C) Operated by Exelon Generation. (D) Operated by JCP&L. (E) Excludes energy for pumping and synchronous condensers. (F) On December 29, 2006, Power entered into an agreement to sell Lawrenceburg. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes. 41
Location
Total
Capacity
(MV)
%
Owned
Owned
Capacity
(MV)
Principal
Fuels
Used
Mission
NJ
991
100
%
991
Coal/Gas
Load Following
NJ
648
100
%
648
Coal/Gas
Load Following
NJ
453
100
%
453
Gas/Oil
Load Following
PA
1,700
23
%
388
Coal
Base Load
PA
1,700
23
%
382
Coal
Base Load
CT
518
100
%
518
Coal/Oil
Base Load
CT
455
100
%
455
Oil/Gas
Load Following
6,465
3,835
NJ
1,061
100
%
1,061
Nuclear
Base Load
NJ
2,304
57
%
1,323
Nuclear
Base Load
PA
2,224
50
%
1,112
Nuclear
Base Load
5,589
3,496
NJ
1,225
100
%
1,225
Gas/Oil
Load Following
NJ
1,186
100
%
1,186
Gas
Load Following
IN
1,080
100
%
1,080
Gas
Load Following
NY
793
100
%
793
Gas
Load Following
4,284
4,284
NJ
617
100
%
617
Gas/Oil
Peaking
NJ
504
100
%
504
Gas/Oil
Peaking
NJ
443
100
%
443
Gas/Oil
Peaking
NJ
557
100
%
557
Gas/Oil
Peaking
NJ
340
100
%
340
Gas/Oil
Peaking
NJ
129
100
%
129
Oil
Peaking
NJ
129
100
%
129
Oil
Peaking
NJ
21
100
%
21
Gas
Peaking
NJ
21
100
%
21
Oil
Peaking
NJ
21
100
%
21
Gas
Peaking
NJ
38
57
%
22
Oil
Peaking
CT
15
100
%
15
Oil
Peaking
2,835
2,819
PA
11
23
%
2
Oil
Peaking
PA
11
23
%
3
Oil
Peaking
22
5
NJ
400
50
%
200
Peaking
19,595
14,639
(A)
Power’s share of jointly-owned facility.
As of December 31, 2006, Power had generating capacity in construction or advanced development, as shown in the following table: POWER PLANTS IN ADVANCED DEVELOPMENT Name Nuclear Uprates Total Advanced Development. Projected Capacity Total Owned Operating Generation Plants Advanced Development Less: Planned Sales 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. 42
Location
Total
Capacity
(MW)
%
Owned
Owned
Capacity
(MW)
Principal
Fuels
Used
Scheduled
In Service
Date
NJ/PA
160
Various
142
Nuclear
2007-2008
160
142
Total
Owned
Capacity
(MW)
14,639
142
(1,080
)
13,701
Global has invested in the following generation facilities that were in operation as of December 31, 2006: OPERATING POWER PLANTS Name United States(A) Texas Independent Energy, L.P. (TIE) Guadalupe Power Partners, LP (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) GWF Energy LLC (GWF Energy) Hanford—Peaker Plant Henrietta—Peaker Plant Tracy—Peaker Plant Total GWF Energy Bridgewater Conemaugh Total United States International 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) SAESA Group Total International Total Operating Power Plants 43
Location
Total
Capacity
(MW)
%
Owned
Owned
Capacity
(MW)
Principal
Fuels
Used
TX
1,000
100
%
1,000
Natural gas
TX
1,000
100
%
1,000
Natural gas
2,000
2,000
HI
208
50
%
104
Oil
CA
105
50
%
53
Petroleum coke
CA
27
50
%
13
Petroleum coke
CA
95
60
%
57
Natural gas
CA
97
60
%
58
Natural gas
CA
171
60
%
103
Natural gas
363
218
NH
16
40
%
6
Biomass
PA
15
4
%
1
Hydro
2,734
2,395
India
330
20
%
66
Naphtha/Natural gas
Italy
20
43
%
9
Biomass
Italy
20
85
%
17
Biomass
Italy
40
43
%
17
Biomass
80
43
Peru
180
100
%
180
Hydro
Venezuela
60
50
%
30
Natural gas
Venezuela
60
50
%
30
Natural gas
120
60
Venezuela
40
9
%
4
Natural gas
Natural gas/
Chile
120
100
%
120
Gas/Oil/Hydro/Wind
870
473
3,604
2,868
(A)
On December 22, 2006, Global entered into an agreement to sell its 34.5% interest in Thermal Energy Development Partnership, L.P. which owns the 21 MW biomass-fueled Tracy project in California
and therefore, has been excluded. The sale closed in January 2007. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes.
Domestic Generation TIE Global owns 100% of TIE which owns and operates two electric generation facilities, one in Guadalupe County in south central Texas (Guadalupe) and one in Odessa in western Texas (Odessa).
Approximately 30% of the total expected output of TIE for 2007 has been sold via bilateral agreements and additional bilateral sales for peak and off-peak services will be signed as the year progresses.
Any remaining uncommitted output is sold in the Texas spot market. Included in the amounts above is a 350 MW daily capacity call option at Odessa that expires on December 31, 2010. Kalaeloa Global’s 50% partner in Kalaeloa is a power fund managed by Harbert Power Corporation (Harbert). All of the electricity generated by the Kalaeloa power plant is sold to the Hawaiian Electric
Company, Inc. (HECO) under a PPA expiring in May 2016. Under a steam purchase and sale agreement expiring in May 2016, the Kalaeloa power plant supplies steam to the adjacent Tesoro refinery. The
primary fuel, low sulfur fuel oil, is provided from the adjacent Tesoro refinery under a long-term all requirements contract. The refinery is interconnected to the power plant by a pipeline and preconditions
the fuel oil prior to delivery. Back-up fuel supply is provided by HECO. The two combustion turbines of Kalaeloa were upgraded in 2004 resulting in both an increase in the net plant output by approximately 20 MW and an improvement in the efficiency of consuming fuel.
As a result of the upgrades, Kalaeloa and HECO entered into two amendments to the PPA. The amendments were effective upon final approval from the Public Utility Commission of the State of Hawaii
in September 2005. The amendments increased Kalaeloa’s firm capacity and associated energy sales to HECO from 180 MW to 208 MW. GWF and Hanford Global and an affiliate of Harbert each own 50% of GWF. PPAs for the five GWF Bay Area plants’ net output are in place with Pacific Gas and Electric Company (PG&E) ending in 2020 and 2021.
GWF acquires the petroleum coke used to fuel its plants through contracts with three local oil refineries with minimum volumes nominated by GWF annually and price negotiated between the parties either
semi-annually or annually. Three of the five GWF plants have been modified to burn a wider variety of petroleum coke products to mitigate fuel supply and pricing risk. Global and an affiliate of Harbert each own 50% of Hanford. A PPA for the plant’s net output is in place with PG&E ending in August 2011. Hanford acquires the petroleum coke fired in its plant
through a contract with a refinery with price negotiated semi-annually. Hanford, Henrietta and Tracy Peaker Plants GWF Energy, which is 60% owned by Global and 40% owned by a power fund managed by Harbert, owns and operates three peaker plants in California. Global owned approximately 75% of GWF
Energy until February 2004 when it sold a 14.9% interest to Harbinger for approximately $14 million. The output of these plants is sold under a PPA with the California Department of Water Resources
(DWR) with maturities in 2011 and 2012. DWR has the right to schedule energy and/or reserve capacity from each unit of the three plants for a maximum of 2,000 hours each year. Energy and capacity not
scheduled by DWR is available for sale by GWF Energy. DWR supplies the natural gas when the units are scheduled for dispatch by DWR. GWF Energy obtains the natural gas used to fuel its plants for
non-DWR sales from the spot market on a non-firm basis. International Generation India PPN Global owns a 20% interest in PPN located in Tamil Nadu, India. Global’s partners include the Apollo Infrastructure Company Ltd., with a 46.9% interest, Marubeni Corporation, with a 26% interest,
Housing 44
Development Finance Corporation (HDFC) and HDFC Life Insurance Corporation, with a 5% and 2.1% interest respectively. PPN has entered into a PPA for the sale of 100% of its output to the State
Electricity Board of Tamil Nadu (TNEB) for 30 years, with an agreement to take-or-pay equal to a plant load factor of at least 68.5%. Italy Prisma Global owns an 85% interest in Prisma which indirectly owns and operates three biomass generation plants in Italy through its ownership of 100% of San Marco Bioenergie S.p.A., which owns a 20
MW plant, and 50% of Biomasse, a partnership with Api Holding S.p.A., which owns two plants totaling 60 MW. Global records Prisma’s investment in Biomasse as an equity method investment due to
Global’s approximate 43% indirect ownership in Biomasse. The output of the plants is sold under power purchase agreements with the Italian national grid (CIP contracts), which include a premium for the
renewable energy output. These contracts expire from 2009 through 2012. For additional information relating to Prisma, see Note 12. Commitments and Contingent Liabilities of the Notes. Peru Electroandes Global owns a 100% interest in Electroandes located in Peru. Electroandes’ main assets include four hydroelectric facilities with a combined installed capacity of 180 MW and 437 miles of transmission
lines located in the central Andean region east of Lima. Electroandes’ revenues were obtained through various PPAs, denominated in U.S. Dollars. Electroandes has contracted for 95% and 91% in 2007
and 2008, respectively, and over 50% for 2009 and 2010. Approximately 75% of the PPAs in 2007 are with unregulated customers with a more balanced split between regulated and unregulated in 2008 and
beyond. Venezuela Turboven The facilities in Maracay and Cagua are owned and operated by Turboven, an entity which is jointly-owned by Global (50%) and Corporacion Industrial de Energia (CIE). PPAs expiring between 2007
and 2011 have been entered into for the sale of approximately 40% of the output of Maracay and Cagua to various industrial customers. The PPAs are structured to provide energy only with minimum take
provisions. Fuel costs are passed through directly to customers and the energy tariffs are calculated in U.S. Dollars and paid in local currency. See Note 4. Discontinued Operations, Dispositions,
Acquisitions and Impairments of the Notes for a discussion of recent events in Venezuela. TGM Global has a 9% indirect interest in TGM through a partnership with CIE. TGM sells all of the energy produced under a PPA with Manufacturas del Papel (MANPA), a paper manufacturing concern
located in Maracay. MANPA and CIE have common controlling shareholders. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes for a discussion of recent
events in Venezuela. Electric Distribution Facilities Global has invested in the following major distribution systems: Name SAESA Group Chilquinta LDS Total 45
Location
Number of
Customers
Global’s
Ownership
Interest
Chile
617,000
100
%
Chile
534,000
50
%
Peru
788,000
38
%
1,939,000
Chile and Peru SAESA Group Global owns a 99.99% equity interest in SAESA, 98.99% of Empresa Electrica de la Frontera S.A. (Frontel) and 100% of PSEG Generacion y Energia Chile Limitada (Generacion), collectively known
as the SAESA Group. The SAESA Group consists of four distribution companies and one transmission company that provide electric service to 390 cities and towns over 900 miles in southern Chile and a
generating company. The SAESA Group has 120 MW of installed generating capacity in operation (46 MW of natural gas-fired peaker capacity, 51 MW oil-fired, 21 MW hydro and 2 MW wind). The
transmission company, Sistema de Transmision del Sur S.A. (STS), provides transmission services to electric generation facilities that have PPAs with distributors in Regions VIII, IX and X and has installed
transformation capacity of 918 megavolt-amperes. The SAESA Group also owned a 50% interest in an Argentine distribution company, Empresa de Energia Rio Negro S.A., which provides generation, transmission and distribution services to
approximately 147,000 customers in the Province of Rio Negro, Argentina, but was sold in the last quarter of 2006. The management of the SAESA Group is organized and administered according to a
centralized administrative structure designed to maximize operational synergies. For additional information related to the SAESA Group, see Item 1. Business—Regulatory Issues. Chilquinta and LDS Global and Sempra Energy (Sempra), each own 50% of the shares of Chilquinta, an energy distribution company with numerous energy holdings, based in Valparaiso, Chile. Following the sale in 2004
of 12% of the shares of LDS to the public, Global and Sempra own 75.9% of LDS, an electric distribution company located in Lima, Peru. As part of the Chilquinta and LDS investments, Global and
Sempra also own Tecnored and Tecsur, located in Chile and Peru, respectively. These companies provide procurement and contracting services to Chilquinta, LDS and others. As equal partners, Global and Sempra share in the management of Chilquinta and LDS. However, Sempra has assumed lead operational responsibilities at Chilquinta, while Global has assumed lead
operational responsibilities at LDS. The shareholders’ agreement provides for important veto rights over major partnership decisions including dividend policy, budget approvals, management appointments
and indebtedness. Chilquinta operates under a non-exclusive perpetual franchise within Chile’s Region V which is located just north and west of Santiago. Global believes that direct competition for distribution
customers would be uneconomical for potential competitors. LDS operates under an exclusive, perpetual franchise in the southern portion of the city of Lima and in an area just south of the city along the
coast serving a population of approximately 3.2 million. Both Chilquinta and LDS purchase energy for distribution from generators in their respective markets on a contract basis. For additional information
related to Chilquinta and LDS, see Item 1. Business—Regulatory Issues. PSE&G In November 2001, Consolidated Edison Company of New York, Inc. (Con Edison) filed a complaint against PSE&G, PJM and NYISO with FERC asserting a failure to comply with agreements between
PSE&G and Con Edison covering 1,000 MW of transmission. PSE&G denied the allegations set forth in the complaint. An Initial Decision issued by an ALJ in April 2002 upheld PSE&G’s claim in part but also
accepted Con Edison’s contentions in part. In December 2002, FERC issued an order modifying the Initial Decision and remanding a number of issues to the ALJ for additional hearings, including issues
related to the development of protocols to implement the findings of the order and regarding Phase II of the complaint. The ALJ issued an Initial Decision on the Phase II issues in June 2003 and in August
2004, FERC issued its decision on Phase II issues. While those decisions were largely favorable to PSE&G, PSE&G sought rehearing as to certain issues, as did Con Edison. Those rehearing applications are
currently pending. The August 2004 order required that PJM, NYISO, Con Edison and PSE&G meet for the purpose of developing operational protocols to implement FERC’s directives. On February 18, 2005, NYISO,
PJM and 46
PSE&G submitted a joint compliance filing pursuant to FERC’s August 2004 decision. FERC approved the joint proposals on May 18, 2005 and they took effect on July 1, 2005. In subsequent filings to FERC
regarding the efficacy of these protocols, Con Edison continues to claim that the obligations under the agreements as interpreted by the FERC’s orders are not being met. In December 30, 2005 and January
19, 2007 filings with FERC, Con Edison claims to have incurred $111 million in damages, and has requested FERC to require refunds of this amount. To the extent that this claim is directed at PSE&G,
PSE&G believes that the claim has no legal basis and that, in any event, PSE&G has meritorious defenses to the claim. PJM, NYISO, Con Edison and PSE&G have agreed to a work plan under which they will
attempt, during the Spring of 2007, to address operational issues associated with the protocols and to address Con Edison’s refund claim. Con Edison has also requested that, if these settlement discussions
are not successful, that FERC convene judge-mediated settlement discussions, to be followed by hearings if necessary. The scope of the discussions envisioned under the work plan are not currently
expected, however, to encompass a comprehensive review of all matters raised in the November 2001 complaint or the pending rehearing requests of the FERC’s orders. As this matter is currently pending
before FERC, PSEG and PSE&G are unable to predict the outcome of this proceeding. Energy Holdings India Global has a 20% ownership interest in PPN, which sells its output under a long-term PPA with the TNEB. TNEB has not made full payment to PPN for the purchase of energy under the PPA.
Resolution of the past due receivables against which PPN has established reserves was expected to be achieved in 2005 by a joint working group including the Central Electric Authority (CEA), PPN and
TNEB. However, in the latter part of 2005, the CEA reportedly stated that it had no jurisdiction in the matter and referred the parties to the Tamil Nadu Electric Regulatory Commission (TNERC).
Neither PPN nor Global believe that TNERC has jurisdiction over Capital Cost Approval, a significant component of the receivables reserve. An adverse outcome concerning the disputed Capital Cost
Approvals could result in impairment of this investment. On March 26, 2004, Global and El Paso Energy Corporation (which sold its ownership interest in PPN in 2005) filed a notice of arbitration on behalf of PPN against TNEB under the arbitration clause
of the PPA, asserting that they have the right as minority shareholders to protect the contractual rights of PPN where PPN has failed to exercise those rights itself. In response, PPN filed a petition for an
anti-suit injunction against the arbitration. Global successfully defended against the petition in two lower courts. PPN has filed its final appeal in the Supreme Court of India (SLP Civil No. 23169). Hearings
that began on January 24, 2005 have resulted in a stay of PSEG’s continued actions in the arbitral court pending a decision by the Indian Supreme Court, which is expected in due course. On December 30, 2006, Global petitioned the Company Law Board (Law Board) in Chennai, India to withdraw, without prejudice, its case against certain other members of PPN’s Board of Directors,
PPN management and certain other PPN shareholders for failure to act in PPN’s best interest and other assertions. The Law Board issued the order as requested and the other parties did not object. The
withdrawal of the Law Board case is expected to result in an eventual dismissal of the injunction against the arbitration described above. As of December 31, 2006, Global’s total investment in PPN was approximately $34 million. Turkey From about 1995 through 2001, Global and its partners expended approximately $12 million towards the construction of a power plant in the Konya-Ilgin region of Turkey. In 2001, Turkey passed
legislation and otherwise deprived Global of rights and fair and equitable treatment and expropriated Global’s Concession contract for the power plant project without compensation, despite the Turkish
Government’s obligation to compensate Global for its costs under the existing contract and Turkish law. In 2002, Global initiated arbitration before the International Centre for Settlement of International
Disputes seeking return of sunk costs, lost profits, interest and attorney fees and costs. A decision in this matter was made in January 2007 under which the Turkish Government will be required to pay
Global and its partners approximately $20 million for sunk costs, interest and arbitration fees. After legal contingency fees, Global expects to receive approximately $7 million, after tax, for its share of the
project. Global expects to receive payment in the second quarter of 2007. 47
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: (2) Page 16. (PSEG, PSE&G and Power) FERC proceeding relating to PJM Long-Term Transmission Rate Design, Docket No. EL05-121-000. (3) Page 18. (Power) PSEG Power Connecticut’s filing with FERC on November 17, 2004, Docket No. ER05-231-000, to request RMR compensation. (4) Page 18. (PSEG, PSE&G and Power) PJM Reliability Pricing Model filed with FERC on August 31, 2005, Docket Nos. ERO5-1410-000 and EL05-148-000. (5) Page 22. (PSEG and PSE&G) BPU proceeding on August 1, 2005 relating to ratepayer protections due to repeal of PUHCA under the Energy Policy Act of 2005. Docket No. AX05070641. (6) Page 23. (PSE&G) BPU proceeding relating to Electric Base Rate Case financial review, Docket No. ER02050303. (7) Page 23. (PSE&G) PSE&G’s BGSS Commodity filing with the BPU on May 28, 2004, Docket No. GR04050390. (8) Page 24. (PSE&G) Remediation Adjustment Clause filing with the BPU on April 25, 2005, Docket No. GR05040383. (9) Page 24. (PSE&G) PSE&G Petition for increase of gas base rates filed with BPU on September 30, 2005, Docket No. GR05100845. (10) Page 24. (PSE&G) Deferral Proceeding filed with the BPU on August 28, 2002, Docket No. EX02060363, and Deferral Audit beginning on October 2, 2002 at the BPU, Docket No. EA02060366. (11) Page 25. (PSE&G) BPU Order dated December 23, 2003, Docket No. EO02120955 relating to the New Jersey Interim Clean Energy Program. (12) Page 29. (Power) Power’s Petition for Review filed in the United States Court of Appeals for the District of Columbia Circuit on July 30, 2004 challenging the final rule of the United States
Environmental Protection Agency entitled “National Pollutant Discharge Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake Structures at Phase II Existing
Facilities,” now transferred to and venued in the United States Court of Appeals for the Second Circuit with Docket No. 04-6696-ag. (13) Page 31. (Power) Filing of Complaint by Nuclear against the DOE on September 26, 2001 in the U.S. Court of Federal Claims, Docket No. 01-0551C seeking damages caused by DOE’s failure to take possession of spent nuclear fuel. The complaint was amended to include PSE&G as a prior owner in interest. (14) Page 152. (PSE&G) Investigation Directive of NJDEP dated September 19, 2003 and additional investigation Notice dated September 15, 2003 by the EPA regarding the Passaic River site. Docket
No. EX93060255. (15) Page 153. (Power) PSE&G’s MGP Remediation Program instituted by NJDEP’s Coal Gasification Facility Sites letter dated March 25, 1988. (16) Page 155. (Energy Holdings) Italian government investigation regarding allegations of violations of Prisma’s air permit for the San Marco facility. 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 48
(1)
Page 16. (PSEG, PSE&G and Power) FERC proceedings with MISO and PJM relating to RTOR and SECA methodology, Docket No. ER05-6-000 et al.
natural resources. The U.S. Government alleges damages of approximately $200 million. To PSE&G’s knowledge there has been no action on this matter since 1988. (2) Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. The EPA had named PSE&G as one of several potentially responsible parties (PRPs) through
a series of administrative orders between December 1984 and March 1985. Following work performed by the PRPs, the EPA declared on May 20, 1987 that all of its administrative orders had been satisfied.
The NJDEP, however, named PSE&G as a PRP and issued its own directive dated October 21, 1987. Remediation is currently ongoing. (3) Various Spill Act directives were issued by NJDEP to PRPs, including PSE&G with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with
operation and maintenance, interim remedial measures and a Remedial Investigation and Feasibility Study (RI/FS) in excess of $25 million. The directives also sought reimbursement of NJDEP’s past and
future oversight costs and the costs of any future remedial action. (4) Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and
formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and other companies are alleged to be liable for contamination at the site and PSE&G has been named as a PRP. A Final Remedial
Design Report was submitted to the EPA in September of 2002. This document presents the design details that will implement the EPA’s selected remediation remedy. The costs of remedy implementation
are estimated to range from $14 million to $24 million. PSE&G’s share of the remedy implementation costs are estimated between $4 million and $8 million. (5) The Klockner Road site is located in Hamilton Township, Mercer County, New Jersey, and occupies approximately two acres on PSE&G’s Trenton Switching Station property. PSE&G entered into a
memorandum of agreement with the NJDEP for the Klockner Road site pursuant to which PSE&G conducted an RI/FS and remedial action at the site to address the presence of soil and groundwater
contamination at the site. (6) The NJDEP assumed control of a former petroleum products blending and mixing operation and waste oil recycling facility in Elizabeth, Union County, New Jersey (Borne Chemical Co. site) and
issued various directives to a number of entities, including PSE&G, requiring performance of various remedial actions. PSE&G’s nexus to the site is based upon the shipment of certain waste oils to the site for
recycling. PSE&G and certain of the other entities named in NJDEP directives are members of a PRP group that have been working together to satisfy NJDEP requirements including: funding of the site
security program; containerized waste removal; and a site remedial investigation program. (7) The EPA sent PSE&G, Power and approximately 157 other entities a notice that the EPA considered each of the entities to be a potentially responsible party (PRP) with respect to contamination in
Berry’s Creek in Bergen County, New Jersey and requesting that the PRPs perform a Remedial Investigation/Feasibility Study (RI/FS) on Berry’s Creek and the connected tributaries and wetlands. Berry’s
Creek flows through approximately 6.5 miles of areas that have been used for a variety of industrial purposes and landfills. The EPA estimates that the study could be completed in approximately five years
at a total cost of approximately $18 million. PSE&G and Power are unable to predict the outcome of this matter; however, the related costs of this study are not expected to be material. (8) The EPA sent PSE&G and three other entities a notice that the EPA considered each of the entities to be a PRP with respect to contamination in the Newark Bay Study Area, which it defined as
Newark Bay and portions of the Hackensack River, the Arthur Kill, and the Kill Van Kull. The notice letter requested that PSE&G participate and fund the EPA-approved study in the Newark Bay Study
Area and encouraged PSE&G to contact Occidental Chemical Corporation (OCC) to discuss participating in the RI/FS that OCC is conducting in the Newark Bay Study Area. EPA considers the Newark
Bay Study Area, along with the Passaic River Study Area, to be part of the Diamond Alkali Superfund Site. The notice states EPA’s belief that hazardous substances were released from sites owned by
PSE&G and located on the Hackensack River. The sites included two operating electric generating stations (Hudson and Kearny Sites), and one former MGP. PSE&G’s costs to clean up former MGPs are
recoverable from utility customers through the SBC. The Hudson and Kearny Sites were transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the
electric generating stations that PSE&G transferred to it, including the Hudson and Kearny Sites. Power has provided notice to insurers concerning this potential claim. PSE&G and Power are unable to
estimate the cost of the investigation at this time. 49
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS PSEG’s Annual Meeting of Stockholders was held on November 21, 2006. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Act of 1934. There was no solicitation
of proxies in opposition to management’s nominees as listed in the proxy statement and all of management’s nominees were elected to the Board of Directors. Details of the voting are provided below: Proposal: Election of Directors Caroline Dorsa E. James Ferland Albert R. Gamper, Jr. Ralph Izzo Proposal: Ratification of Appointment of Deloitte & Proposal: Stockholder Proposal 50
Votes For
Votes
Withheld
209,520,856
10,007,648
207,098,164
12,430,340
209,440,773
10,087,731
208,006,028
11,522,476
Votes For
Votes
Against
Abstentions
Broker
Non-Votes
Touche LLP as Independent Auditor
214,052,603
3,273,939
2,210,538
—
31,230,349
144,720,275
4,552,843
—
PSEG PSEG’s Common Stock is listed on the New York Stock Exchange, Inc. As of December 31, 2006, there were 94,972 holders of record. The graph below shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2001 in PSEG common stock, the S&P Composite Stock Price Index, the Dow Jones
Utilities Index and the S&P Electric Utilities Index. PSEG S&P 500 DJ Utilities S&P Electrics The following table indicates the high and low sale prices for PSEG’s Common Stock and dividends paid for the periods indicated: Common Stock 2006: First Quarter Second Quarter Third Quarter Fourth Quarter 2005: First Quarter Second Quarter Third Quarter Fourth Quarter In January 2007, PSEG’s Board of Directors approved a one and one half-cent increase in its quarterly common stock dividend, from $0.57 to $0.585 per share, for the first quarter of 2007. This increase
reflects an indicated annual dividend rate of $2.34 per share. For additional information concerning dividend payments, dividend history, policy and potential preferred voting rights, restrictions on payment
and common stock repurchase programs, see Item 7. MD&A—Overview of 2006 and Future Outlook and Liquidity and Capital Resources and Note 9. Schedule of Consolidated Capital Stock and Other
Securities of the Notes. 51
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
2001
2002
2003
2004
2005
2006
100.00
80.66
115.97
143.91
187.34
198.28
100.00
77.95
100.27
111.15
116.59
134.96
100.00
76.68
98.97
128.72
160.85
187.61
100.00
84.92
105.17
132.94
156.24
192.43
High
Low
Dividend
Per Share
$
72.45
$
63.97
$
0.57
$
67.63
$
59.00
$
0.57
$
72.61
$
60.47
$
0.57
$
68.10
$
59.12
$
0.57
$
56.23
$
49.32
$
0.56
$
61.66
$
52.00
$
0.56
$
68.47
$
59.09
$
0.56
$
67.58
$
56.05
$
0.56
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2006: Plan Category Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total For additional discussion of specific plans concerning equity-based compensation, see Note 17. Stock Options and Employee Stock Purchase Plan of the Notes. PSE&G All of the common stock of PSE&G is owned by PSEG. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A—Overview of 2006 and Future Outlook. Power All of Power’s outstanding limited liability company membership interests are owned by PSEG. For additional information regarding Power’s ability to pay dividends, see Item 7. MD&A—Overview of
2006 and Future Outlook. Energy Holdings All of Energy Holdings’ outstanding limited liability company membership interests are owned by PSEG. For additional information regarding Energy Holdings’ ability to pay dividends, see Item 7.
MD&A—Overview of 2006 and Future Outlook. 52
Number of Securities
to be Issued Upon
Exercise of
Outstanding
Options, Warrants
and Rights
(#)
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
($)
Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(#)
1,623,169
42.42
11,851,709
192,833
44.37
1,909,235
(A)
1,816,002
42.63
13,760,944
(A)
Shares issuable under the PSEG Employee Stock Purchase Plan, Compensation Plan for Outside Directors and Stock Plan for Outside Directors.
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(A) Income from Continuing Operations(B) Net Income Earnings per Share: Income from Continuing Operations: Basic(B) Diluted(B) Net Income: Basic Diluted Dividends Declared per Share As of December 31: Total Assets Long-Term Obligations(C) (B) Income from Continuing Operations for 2006 include an after-tax charge of $178 million, or $0.70 per share related to the sale of RGE. Income from Continuing Operations for 2002 include after-tax
charges of $368 million, or $1.76 per share, related to losses from Energy Holdings’ Argentine investments. (C) Includes capital lease obligations. PSE&G The information presented below should be read in conjunction with the MD&A, the Consolidated Financial Statements and the Notes. Operating Revenues(A) Income Before Extraordinary Item Net Income As of December 31: Total Assets Long-Term Obligations 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. 53
ITEM 6.
SELECTED FINANCIAL DATA
For the Years Ended December 31,
2006
2005
2004
2003
2002
(Millions, where applicable)
$
12,164
$
12,164
$
10,610
$
10,839
$
8,037
$
752
$
886
$
795
$
855
$
403
$
739
$
661
$
726
$
1,160
$
235
$
2.99
$
3.69
$
3.35
$
3.75
$
1.94
$
2.98
$
3.63
$
3.34
$
3.75
$
1.94
$
2.94
$
2.75
$
3.06
$
5.08
$
1.13
$
2.93
$
2.71
$
3.05
$
5.07
$
1.13
$
2.28
$
2.24
$
2.20
$
2.16
$
2.16
$
28,570
$
29,821
$
29,260
$
28,132
$
26,113
$
10,417
$
11,329
$
12,663
$
12,729
$
10,889
(A)
Includes adjustments to net revenues and expenses for prior years related to one of PSE&G’s contracts that had previously been recorded on a gross basis. For the years ended December 31, 2005, 2004,
2003 and 2002, the adjustments reduced Operating Revenues by $214 million, $162 million, $142 million and $90 million, respectively, with no impact on Operating Income. See Note 1. Organization
and Summary of Significant Accounting Policies for additional information.
For the Years Ended December 31,
2006
2005
2004
2003
2002
(Millions)
$
7,569
$
7,514
$
6,810
$
6,598
$
5,829
$
265
$
348
$
346
$
247
$
205
$
265
$
348
$
346
$
229
$
205
$
14,553
$
14,297
$
13,586
$
13,177
$
12,867
$
4,711
$
4,745
$
4,877
$
5,129
$
5,050
(A)
Includes adjustments to net revenues and expenses for prior years related to one of PSE&G’s contracts that had previously been recorded on a gross basis. For the years ended December 31, 2005, 2004,
2003 and 2002, the adjustments reduced Operating Revenues by $214 million, $162 million, $142 million and $90 million, respectively, with no impact on Operating Income. See Note 1. Organization
and Summary of Significant Accounting Policies for additional information.
This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy
Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make
representations only as to itself and make no other representations whatsoever as to any other company. OVERVIEW OF 2006 AND FUTURE OUTLOOK PSEG, PSE&G, Power and Energy Holdings PSEG’s business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C.
(Resources). The following discussion relates to the markets in which PSEG’s subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets and significant events
that have occurred during 2006 and expectations for 2007 for PSE&G, Power and Energy Holdings, as well as the key factors that will drive the future performance of these businesses. Termination of Merger Agreement On December 20, 2004, PSEG entered into an Agreement and Plan of Merger (Merger Agreement) with Exelon Corporation (Exelon) providing for a merger of PSEG with and into Exelon (Merger).
On September 14, 2006, PSEG received from Exelon a formal notice terminating the Merger under the provisions of the Merger Agreement. PSE&G PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and by the Federal
Energy Regulatory Commission (FERC) for its electric transmission and wholesale sales operations. Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. In February 2007, the BPU approved the results of New Jersey’s annual Basic Generation
Service (BGS)-Fixed Price (FP) and BGS-Commercial and Industrial Energy Price (CIEP) auctions and PSE&G successfully secured contracts to provide the electricity requirements for the majority of its
customers’ needs. Overview of 2006 During 2006 PSE&G: • reached a settlement agreement in the Electric Distribution Financial Review with the BPU Staff, RPA and other intervening parties concerning the excess depreciation rate credit which was
approved by the BPU on November 9, 2006 and authorizes a reduction in the credit to $22 million, resulting in additional revenue to PSE&G of approximately $47 million annually based on current
sales volumes. Future Outlook PSE&G believes that the decisions in November 2006 for both gas and electric base rates positions it to earn reasonable returns on investment in the future. The full year impact of these decisions
combined with an anticipated return to more normal weather conditions is expected to improve PSE&G’s margins for 2007 and beyond. 54
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
•
reached a settlement agreement in the Gas Base Rate Case with the BPU Staff, New Jersey Public Ratepayer Advocate (RPA) and other intervening parties which was approved by the BPU on
November 9, 2006 and provides for an annual increase in gas revenues of $40 million, an adjustment to lower book depreciation expense for PSE&G by approximately $26 million annually and the
amortization of accumulated cost of removal that will further reduce depreciation and amortization expense by $13 million annually for five years.
The risks to PSE&G’s business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically the BPU and FERC. PSE&G’s success will
depend, in part, on its ability to attain a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels and continued recovery, with an adequate return, of the
regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution system. Since PSE&G earns no margin on the commodity portion of its electric and
gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G. Power Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market in the Northeast and Mid Atlantic U.S. Power’s principal operating
subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Through its subsidiaries, Power seeks to balance its
generation production, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear and coal
operations and pursue modest growth based on market conditions. Changes in the operation of Power’s generating facilities, fuel and capacity prices, expected contract prices, capacity factors or other
assumptions could materially affect its ability to meet earnings targets and/or liquidity requirements. In addition to the electric generation business described above, Power’s revenues include gas supply
sales under the Basic Gas Supply Service (BGSS) contract with PSE&G. As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits, and a
series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, the prices of commodities, such as electricity, gas, coal
and emissions, as well as the availability of Power’s diverse fleet of generation units to produce these products, can have a material effect on Power’s profitability. In recent years, the prices at which
transactions are entered into for future delivery of these products, as evidenced through the market for forward contracts at points such as PJM Interconnection, L.L.C. (PJM) West, have escalated
considerably over historical prices. Broad market price increases such as these are expected to have a positive effect on Power’s results. Historically, Power’s nuclear and coal-fired facilities have produced
over 50% and 25% of Power’s production, respectively. With the vast majority of its power sourced from lower-cost units, the rise in electric prices is anticipated to yield higher near-term margins for
Power. Power anticipates recognizing these higher near-term margins, especially on the portion of its output that was more recently contracted or sold on the spot market. Over a longer-term horizon, if
these higher prices are sustained at prices reflective of what the current forward markets indicate, it would yield an attractive environment for Power to contract the sale of its anticipated output, allowing
for potentially sustained higher profitability than recognized in prior years. These escalated prices also increase the cost of replacement power, thereby placing incremental risk on the operations of the
generating units to produce these products. Power seeks to mitigate volatility in its results by contracting in advance for a significant portion of its anticipated electric output and fuel needs. Power believes this contracting strategy increases
stability of earnings and cash flow. By keeping some portion of its output uncontracted, Power is able to retain some exposure to market changes as well as provide some protection in the event of
unexpected generation outages. Power seeks to sell a portion of its anticipated low-cost nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of approximately two to four years. As of February
14, 2007, Power has contracted for approximately 100% of its anticipated 2007 nuclear and coal-fired generation, with 90% to 100% contracted for 2008 and 35% to 50% contracted for 2009, with a modest
amount contracted beyond 2009. Power has also entered into contracts for the future delivery of nuclear fuel and coal to support its contracted sales discussed above. As of February 1, 2007, Power had contracted for 100% of its
anticipated nuclear uranium fuel needs through 2011, and approximately 70% of its average anticipated coal needs, including transportation, through 2009. These estimates are subject to change based upon
the level of operation, and in particular for coal, are subject to market demands and pricing. By contrast, Power takes a more opportunistic approach in hedging its anticipated natural gas-fired generation. The generation from these units is less predictable, as these units are generally dispatched
only 55
when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units generally provide a lower contribution to the margin of Power than either the nuclear or
coal units. Power will generally purchase natural gas as gas-fired generation is required to supply forward sale commitments. In a changing market environment, this hedging strategy may cause Power’s realized prices to be materially different than current market prices. At the present time, some of Power’s existing
contractual obligations, entered into during lower-priced periods, are anticipated to result in lower margins than would have been the case if no or little hedging activity had been conducted. Alternatively,
in a falling price environment, this hedging strategy will tend to create margins in excess of those implied by the then current market. Overview of 2006 During 2006, FERC issued certain orders related to market design that have changed the nature of capacity payments in the New England Power Pool (NEPOOL) and are scheduled to change the
nature of payments in PJM. In PJM, the Reliability Pricing Model (RPM) will provide generators with differentiated capacity payments based upon the location of their respective facilities. Similarly, the
Forward Capacity Market (FCM) settlement in NEPOOL provides for locational capacity payments. FERC has approved the market changes in each of these markets, with the anticipated start date for
RPM set for June 1, 2007 and FCM transition period having begun on December 1, 2006. Power currently receives fixed Reliability-Must-Run (RMR) payments in PJM and NEPOOL for certain of its
facilities which are provided to ensure the continued availability of those facilities. Also during 2006 Power: • reached an agreement with the EPA and NJDEP that will allow the continued operation of the Hudson facility and extends for four years the deadline for installing environmental controls beyond
the previous December 31, 2006 deadline; • announced its plans to resume direct management of the Salem and Hope Creek facilities before the expiration of the Operating Service Contract with Exelon Generation and to have the senior
management team at those facilities to become employees of Power effective January 1, 2007; and • entered into an agreement to sell its Lawrenceburg Energy Center, a 1,080 MW gas-fired combined cycle electric generating plant in Lawrenceburg, Indiana. Future Outlook Power expects margin improvements in 2007 as higher prices for its nuclear and coal output are realized due to the rolling nature of its forward hedge positions and the expiration of its contract in
Connecticut. The sale of Lawrenceburg and anticipated improvements in margins on serving the BGSS contract are also expected to benefit future results. In addition, Power believes that the redesign in capacity markets, discussed above, could lead to changes in the value of the majority of its generating capacity and result in incremental margin of $100
million to $150 million in 2007, with higher increases in future years as the full year impact is realized and existing capacity contracts expire. A key factor in Power’s ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to
satisfy its obligations. Power’s ability to achieve its objectives will also depend on the implementation of reasonable capacity markets. Power must also be able to effectively manage its construction projects
and continue to economically operate its generation facilities under increasingly stringent environmental requirements. In addition, with an increase in competition and market complexity and constantly
changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While these increases may have a potentially significant beneficial impact on margins, they
could also raise any replacement power costs that Power may incur in the event of unanticipated outages, and could also further increase liquidity requirements as a result of contract obligations. Power
could also be impacted by the lack of consistent rules in markets outside of PJM, including rate-regulated utility ownership of generation and other regulatory 56
•
commenced commercial operations of its 1,186 MW, natural gas-fired combined cycle power generation plant in Linden, New Jersey;
actions favoring non-competitive markets. For additional information on liquidity requirements, see Liquidity and Capital Resources. Energy Holdings Energy Holdings’ operations are principally conducted through its subsidiaries Global, which has invested in international, rate-regulated distribution companies and domestic and international
generation companies, and Resources, which primarily invests in energy-related leveraged leases. Global Global has reduced its international risk by opportunistically monetizing investments that no longer had a strategic fit. During the past three years, Global has
reduced its overall investments from $2.6 billion to $1.9 billion, driven by sales of over $1 billion of investments in China, Brazil, Poland, India, Africa and the Middle East. See Note 4. Discontinued
Operations, Acquisitions, Dispositions and Impairments of the Notes, for a discussion of these sales. The decrease in Global’s portfolio size due to the above sales was partially offset by strong earnings from
its Texas merchant generation business and its electric distribution companies in Chile and Peru. Approximately 65% of Global’s remaining investments are in Chile and Peru with another 27% in the
United States. Other modest sized investments in Italy, India and Venezuela comprise the remaining 8% of Global’s portfolio. As a result of the investment sales, approximately 50% of Global’s future earnings is expected to be derived from its domestic generation business, of which over half is from its 2,000 MW gas-fired combined
cycle merchant generation business in Texas with the balance from its 12 fully contracted generating facilities in which Global’s ownership percentage equates to nearly 400 MW. The other 50% of Global’s
earnings is expected to be essentially from three rate-regulated electric distribution businesses in Chile and Peru which serve approximately two million customers and a 183 MW hydro generation facility in Peru. The
regulatory environment in both Chile and Peru has generally been constructive since Global acquired these investments. Chile maintains an investment grade rating and Peru’s rating, although non-investment grade, has improved. Energy Holdings continues to review Global’s portfolio, with a focus on its international investments. As part of this review, Energy Holdings considers the returns of its remaining investments against
alternative investments across the PSEG companies, while considering the strategic fit and relative risks of these businesses. Energy Holdings is also considering the impact of any potential sales of its
investments on its targeted credit metrics and debt service requirements and at present, Global anticipates that it will take into consideration an appropriate balance of the use of proceeds from any sales
with returns of equity to PSEG and debt repayments. Resources Resources primarily has invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments. Overview of 2006 During 2006, Energy Holdings had over $600 million of proceeds from the sales of Global’s investments in two generating stations in Poland, the sale of its interest in RGE, a distribution company in
Brazil and from its sale of its remaining 46% interest in Dhofar Power. Energy Holdings used this cash as well as funds on hand at December 31, 2005 and cash from operations to return $520 million of capital to PSEG, redeem all $309 million of its 7.75% 2007 Senior
Notes in January 2006 and redeem $300 million of its 8.625% 2008 Senior Notes in October 2006. Future Outlook Energy Holdings expects decreased margins at Global in 2007 primarily relating to the absence of mark-to-market gains, a slight reduction in spark spreads and anticipated maintenance outages at
Texas Independent Energy L.P. (TIE)’s plants. Also contributing to the expected decrease are higher taxes, the impact of adopting FIN 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of
FASB 57
Statement 109” (FIN 48) and related standards and lower earnings due to asset sales partly offset by the impact of early adoption of FAS 157. As discussed above, Global’s earnings are primarily derived from its investments in the United States, Chile and Peru. As such, Global’s success will depend on continued strong energy markets in
Texas and the economic and efficient operation of its electric distribution companies in Chile and Peru, including its ability to achieve reasonable rates and meeting expected growth in usage. The success of
Global’s foreign investments will also depend on stable political, regulatory and economic policies, including foreign currency exchange rates and interest rates, particularly for Chile and Peru. Resources’ ability to realize tax benefits associated with its leveraged lease investments is dependent upon taxable income generated by its affiliates. Resources’ earnings and cash flows are expected to
decrease in the future as the investment portfolio matures. Resources faces risks with regard to the creditworthiness of its counterparties; the weighted average credit rating of its lessees at December 31,
2006 was A–/A3. Certain lessees’ ratings are below investment grade. The lease structures have various credit enhancement mechanisms. Resources monitors the credit rating of the lessees very closely,
calling letters of credit and taking other measures when appropriate. Energy Holdings also faces risks related to the tax treatment of uncertain tax positions which will be impacted by new accounting guidance under FIN 48 and FASB Staff Position No. FAS 13-2,
“Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction”, both of which are effective as of January 1, 2007.
Based on its evaluation of this new guidance, Energy Holdings estimates that it will record a reduction to Retained Earnings of approximately $190 million to $215 million, effective January 1, 2007. In
addition, this new guidance will have an impact on Energy Holdings’ future revenues and earnings, including an anticipated earnings reduction of $25 million to $35 million in 2007, as compared to 2006,
which represents the majority of the anticipated impact on PSEG. See Note 2. Recent Accounting Standards of the Notes for further discussion. 58
PSEG, PSE&G, Power and Energy Holdings Net Income for the year ended December 31, 2006 was $739 million or $2.93 per share of common stock, diluted, based on approximately 252 million average shares outstanding. Net Income for the
year ended December 31, 2005 was $661 million or $2.71 per share of common stock, diluted, based on approximately 244 million average shares outstanding. Included in 2006 Net Income was a $208
million after-tax estimated loss on disposal related to an agreement to sell Lawrenceburg. Included in 2005 Net Income was a $178 million after-tax loss from the sale of Power’s Waterford generation
facility. See Note 4. Discontinued Operations, Acquisitions, Dispositions and Impairments of the Notes. Net Income for the year ended December 31, 2004 was approximately $726 million or $3.05 per share
of common stock, diluted, based on approximately 238 million average shares outstanding. PSE&G Power Energy Holdings: Global Resources Other(A) Total Energy Holdings Other(B) PSEG Income from Continuing Operations(C) Loss from Discontinued Operations, including Gain (Loss) on Disposal(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 (C) Loss from Discontinued Operations, including Gain (Loss) on Disposal(D) Cumulative Effect of a Change in Accounting Principle(E) PSEG Net Income (B) Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include interest on certain financing transactions, Merger expenses and
certain administrative and general expenses at PSEG (as parent company). (C) Global’s Income from Continuing Operations for 2006 includes the $178 million after-tax loss on the sale of Rio Grande Energia S.A. (RGE) in June 2006. 59
Earnings (Losses)
Years Ended December 31,
2006
2005
2004
(Millions)
$
265
$
348
$
346
515
434
367
(11
)
112
93
63
92
68
(3
)
(5
)
(10
)
49
199
151
(77
)
(95
)
(69
)
752
886
795
(13
)
(208
)
(69
)
—
(17
)
—
$
739
$
661
$
726
Contribution to Earnings Per
Share (Diluted)(F)
Years Ended December 31,
2006
2005
2004
$
1.05
$
1.42
$
1.45
2.04
1.78
1.55
(0.04
)
0.46
0.39
0.25
0.38
0.28
(0.01
)
(0.02
)
(0.04
)
0.20
0.82
0.63
(0.31
)
(0.39
)
(0.29
)
2.98
3.63
3.34
(0.05
)
(0.85
)
(0.29
)
—
(0.07
)
—
$
2.93
$
2.71
$
3.05
(A)
Other activities include non-segment amounts of Energy Holdings and its subsidiaries and intercompany eliminations. Non-segment amounts include interest on certain financing transactions and
certain other administrative and general expenses at Energy Holdings.
(D) Includes Discontinued Operations of Lawrenceburg, Skawina and Elcho in 2006, 2005 and 2004, Waterford in 2005 and 2004 and Carthage Power Company (CPC) in 2004 as well as an estimated loss in
2006 on the disposal of Lawrenceburg, the gain on disposal of Elcho and Skawina in 2006, the loss on disposal of Waterford in 2005 and the gain on disposal of CPC in 2004. See Note 4. Discontinued
Operations, Dispositions, Acquisitions and Impairments of the Notes. (E) Relates to the adoption of FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” in 2005. See Note 3. Asset Retirement Obligations of the Notes. (F) Earnings Per Share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct interest in PSEG’s assets and
liabilities as a whole. The year over year changes in PSEG’s Net Income primarily relates to changes in Net Income for PSE&G, Power and Energy Holdings, discussed below. Also included in PSEG’s results for each of the
periods were financing costs at the parent level and Merger and Merger-related costs. For the year ended December 31, 2006, PSEG’s after-tax costs were $77 million, a decrease $18 million as compared to
2005. For the year ended December 31, 2005, PSEG’s after-tax costs were $95 million, an increase of $26 million as compared to 2004. The primary reason for these changes was the change in after-tax
Merger and Merger-related costs which amounted to $8 million, $32 million and $4 million for the years ended December 31, 2006, 2005 and 2004, respectively. PSEG Operating Revenues Energy Costs Operation and Maintenance Write-down of Assets Depreciation and Amortization Income from Equity Method Investments Other Income and Deductions Interest Expense Income Tax Expense Loss from Discontinued Operations, including Gain (Loss) on Disposal, 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 For the year ended December 31, 2006, PSE&G had Net Income of $265 million, a decrease of $83 million as compared to the year ended December 31, 2005. This decrease was primarily due to delayed
decisions in its electric and gas base rate cases combined with the decline in electric and gas delivery volumes. Gas delivery volumes dropped 10% in 2006 as compared with 2005 and electric delivery
volumes were down 3%. The weather was the primary cause of these declines with a drop of 16% in the number of degree days impacting gas. Gas commodity prices were extremely high early in 2006,
which also contributed 60
For the Years
Ended December 31,
2006 vs 2005
2005 vs 2004
2006
2005
2004
Increase
(Decrease)
%
Increase
(Decrease)
%
(Millions)
(Millions)
$
12,164
$
12,164
$
10,610
$
—
—
$
1,554
15
$
6,769
$
7,040
$
5,824
$
(271
)
(4
)
$
1,216
21
$
2,297
$
2,282
$
2,147
$
15
1
$
135
6
$
318
$
—
$
—
$
318
N/A
$
—
—
$
832
$
731
$
683
$
101
14
$
48
7
$
120
$
124
$
119
$
(4
)
(3
)
$
5
4
$
83
$
140
$
121
$
(57
)
(41
)
$
19
16
$
(808
)
$
(784
)
$
(774
)
$
24
3
$
10
1
$
(454
)
$
(560
)
$
(484
)
$
(106
)
(19
)
$
76
16
$
(13
)
$
(208
)
$
(69
)
$
(195
)
(94
)
$
139
N/A
$
—
$
(17
)
$
—
$
17
N/A
$
(17
)
N/A
to a decline in weather normalized sales. THI hours were normal in 2006 but 18% less than 2005 negatively impacting electric sales. For the year ended December 31, 2005, PSE&G had Net Income of $348 million, a $2 million increase as compared to the year ended December 31, 2004. This slight increase resulted primarily from
higher margins, due to favorable weather conditions, and reduced interest expense being substantially offset by higher Operation and Maintenance costs. The year-over-year detail for these variances for these periods are discussed in more detail below: Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income and Deductions Interest Expense Income Tax Expense Operating Revenues PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM spot market; delivery revenues from the transmission and distribution of energy through
its system; and other operating revenues from the provision of various services. PSE&G makes no margin on gas commodity sales as the costs are passed through to customers. The difference between the gas costs paid under the requirements contract for residential customers and
the revenues received from residential customers is deferred and collected from or returned to customers in future periods. Gas commodity prices fluctuate monthly for commercial and industrial customers
and annually through the BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if
warranted, between annual BGSS proceedings. PSE&G makes no margin on electric commodity sales as the costs are passed through to customers. PSE&G secures its electric commodity through the annual BGS auction. Electric commodity supply
prices are set based on the results of these auctions for residential and smaller industrial and commercial customers, and are translated into seasonally-adjusted fixed rates. Electric supply for larger
industrial and commercial customers is provided at a rate principally based on the hourly PJM real-time energy price. Customers may obtain their electric supply through either the BGS default electric
supply service or through competitive third-party electric suppliers, and the majority of the customers subject to hourly pricing are currently receiving electric supply from third-party suppliers. Any
differences between amounts paid by PSE&G to BGS suppliers for electric commodity, and the amounts of electric commodity revenue collected from customers is deferred and collected or returned to
customers in subsequent months. The $55 million increase for the year ended December 31, 2006, as compared to 2005 was due to increases of $78 million in commodity revenues and $3 million in other operating revenues offset by a
decrease of $26 million in delivery revenues. The $704 million increase for the year ended December 31, 2005, as compared to 2004 was due to increases of $624 million in commodity revenues, $74 million in delivery revenues and $6 million in
other operating revenues. Commodity The $78 million increase in commodity revenues for the year ended December 31, 2006, as compared to 2005, was due to an increase in electric commodity revenues of $213 million offset by a decrease
of $135 million in gas commodity revenues. The increase in electric revenues was primarily due to $299 million in higher BGS revenues (higher auction prices of $346 million offset by reduced sales of $47
million) offset by $85 million in lower Non-Utility Generation (NUG) revenues (lower prices of $82 million and by $3 million 61
For the Years
Ended December 31,
2006 vs 2005
2005 vs 2004
2006
2005
2004
Increase
(Decrease)
%
Increase
(Decrease)
%
(Millions)
(Millions)
$
7,569
$
7,514
$
6,810
$
55
1
$
704
10
$
4,884
$
4,756
$
4,122
$
128
3
$
634
15
$
1,160
$
1,151
$
1,083
$
9
1
$
68
6
$
620
$
553
$
523
$
67
12
$
30
6
$
22
$
12
$
11
$
10
83
$
1
9
$
(346
)
$
(342
)
$
(362
)
$
4
1
$
(20
)
(6
)
$
(183
)
$
(235
)
$
(246
)
$
(52
)
(22
)
$
(11
)
(4
)
for lower volumes). The decrease in gas revenues was primarily due to $317 million in lower volumes due to weather and $58 million due to the expiration of the Third Party Shopping Incentive Clause in
July 2005. There is a corresponding $58 million increase in delivery revenues. These were offset by $240 million in higher BGSS prices. The $624 million increase in commodity revenues for the year ended December 31, 2005, as compared to 2004, was due to increases in electric and gas revenues of $313 million and $311 million,
respectively. The increase in electric revenues was primarily due to $216 million in higher BGS revenues (higher auction prices of $148 million and increased sales of $68 million) and $97 million in higher
NUG revenues (higher prices of $98 million offset by $1 million for lower volumes). The increase in gas revenues was primarily due to $291 million in higher BGSS prices and $62 million in higher volumes
due to weather offset by the decrease of $42 million due to the expiration of the Third Party Shopping Incentive Clause in July 2005. There is a corresponding $42 million increase in delivery revenues. Delivery The $26 million decrease in delivery revenues for the year ended December 31, 2006, as compared to 2005, was due to a $27 million decrease in gas and a $1 million increase in electric revenues. The
gas decrease was due to $101 million in lower volumes primarily due to weather offset by $74 million in increased prices, $58 million of which was due to the expiration of the Third Party Shopping
Incentive Clause in July 2005, described above in commodity revenues, $8 million due to rate relief effective November 9, 2006 and $8 million due to the Societal Benefits Clause (SBC) November 1, 2006
rate increase. The electric increase was due primarily to $13 million in higher securitization tariff rates and $8 million from a rate increase effective November 9, 2006, offset by $20 million in lower volumes
due to weather. The $74 million increase in delivery revenues for the year ended December 31, 2005, as compared to 2004, was due to increases in electric and gas revenues of $67 million and $7 million, respectively.
The electric increase was due primarily to $55 million in higher volumes due to weather and $12 million in higher rates. The gas increase was due to the expiration of the Third Party Shopping Incentive in
July 2005, resulting in an increase of $42 million in delivery revenues with a corresponding offset in commodity revenues, described above, and a $12 million increase in SBC revenues (offset in Operation
and Maintenance Costs below). This was offset by $9 million in lower volume and demand revenues due to weather and $37 million due to the expiration of the Gas Cost Underrecovery Adjustment
(GCUA) clause in January 2005. Operating Expenses Energy Costs The $128 million increase for the year ended December 31, 2006, as compared to 2005, was comprised of an increase of $211 million in electric costs offset by a decrease of $83 million in gas costs. The
increase in electric costs was caused by $255 million or 16% in higher prices for BGS and NUG purchases offset by $47 million in lower BGS volumes due to weather. The decrease in gas costs was caused
by a $362 million or 17% decrease in sales volumes due primarily to weather and $8 million due to the expiration of the GCUA clause in January 2005, offset by $287 million or 11% in higher prices. The $634 million increase for the year ended December 31, 2005, as compared to 2004, was comprised of increases of $319 million in electric costs and $315 million in gas costs. The increase in electric
costs was caused by a $264 million or 8% increase due to higher prices for BGS and NUG purchases and a $67 million increase due to higher BGS volumes, partially offset by a decrease of $12 million due
to lower NUG volumes. The increased gas costs were due to a $271 million or 16% increase in gas prices and an $81 million increase in sales volumes due primarily to higher sales to cogenerators. These
were offset by a $37 million decrease due to the expiration of the GCUA clause in January 2005. Operation and Maintenance The $9 million increase for the year ended December 31, 2006, as compared to 2005, was due primarily to $9 million in increased labor and fringe benefits due to increased wages and Other
Postretirement Benefits (OPEB) costs and $7 million in increased bad debt expense. These increases were offset by decreases of $3 million in injuries and damage claims and $2 million in write
offs and $2 million in Net Operating Loss (NOL) purchases. 62
The $68 million increase for the year ended December 31, 2005, as compared to 2004, was due to increased SBC expenses of $27 million ($15 million electric, $12 million gas); $23 million in labor and
fringe benefits; $6 million for increased injuries and damages reserves; $4 million for Merger-related expenses; $3 million for higher regulatory commission expenses; $2 million for higher bad debt expenses
and $2 million for the purchase of NOL. SBC costs are deferred when incurred and amortized to expense when recovered in revenues. Depreciation and Amortization The $67 million increase for the year ended December 31, 2006, as compared to 2005, was comprised of increases of $70 million from the expiration of an excess depreciation credit, $6 million due to
amortization of regulatory assets and $3 million due to additional plant in service. These increases were offset by decreases of $5 million due to revised plant depreciation and cost of removal rates, $3
million due to software amortization and $3 million due to the amortization of the Remediation Adjustment Clause (RAC). The $30 million increase for the year ended December 31, 2005, as compared to 2004, was due primarily to a $33 million increase in the amortization of securitized regulatory assets, a $4 million
increase due to additional plant in service and a $4 million increase in the amortization of the RAC. These were offset by an $8 million decrease in software amortization and a $3 million increase in excess
depreciation reserve amortization. Other Income and Deductions The $10 million increase for the year ended December 31, 2006, as compared to 2005, was primarily due to an $8 million income tax gross-up on contributions in aid of construction (CIAC) in 2006.
CIAC are taxable and PSE&G recognizes the gross-up as income when collected. Also included are increases of $1 million of short-term interest income and $1 million in gains on the sale of excess property. Interest Expense The $20 million decrease for the year ended December 31, 2005, as compared to 2004, was primarily due to decreases of $22 million due to lower average interest rates and lower amounts of long-term
debt outstanding, primarily offset by $5 million in higher short-term debt balances outstanding and higher interest rates. Income Taxes The $52 million decrease for the year ended December 31, 2006, as compared to 2005, was primarily due to $55 million in lower pre-tax income offset by $3 million in various flow-through adjustments. The $11 million decrease for the year ended December 31, 2005, as compared to 2004, was primarily due to decreases of $4 million in prior period adjustments, $3 million in various flow-through
benefits and $3 million in lower pre-tax income. Power For the year ended December 31, 2006, Power had Net Income of $276 million, an increase of $84 million as compared to the year ended December 31, 2005. The increase primarily resulted from
higher BGS contract prices and higher sales volumes in the various power pools, supported by improved nuclear operations and the commencement of commercial operations at Linden in May 2006 and at
the Bethlehem Energy Center (BEC) in July 2005 and lower generation costs due to lower pool prices and lower demand under the BGS contract. Power also had lower non-trading mark-to-market losses,
which were approximately $1 million, after-tax, in 2006 as compared to $8 million, after-tax, in 2005. Power’s increased earnings were partially offset by reduced margins on BGSS, as market prices for
natural gas declined from historically high price levels experienced in the second half of 2005 while the cost of gas in inventory was reasonably stable, and lower demand in 2006 due to a warmer winter
heating system and customer conservation. Power’s earnings were also offset by a $44 million write-down of four gas engine turbines which are planned for sale in 2007, a $30 million after-tax decrease in
Income from the NDT Funds and higher Operation and 63
Maintenance Costs, Depreciation and Amortization and Interest Expense related to operation of the Linden and BEC facilities. For the year ended December 31, 2005, Power had Net Income of $192 million, a decrease of $116 million as compared to the year ended December 31, 2004. The primary reason for the decrease was
the $178 million Loss on Disposal of Waterford and the $16 million Cumulative Effect of a Change in Accounting Principle recorded in 2005. Power’s Income from Continuing Operations for the year
ended December 31, 2005 was $434 million, an increase of $67 million as compared to 2004. This increase reflected higher pricing and increased sales in the various power pools and new wholesale contracts
and reduced Operation and Maintenance costs associated with the outage at Hope Creek in 2004. Marked improvement in Power’s nuclear operations provided additional low-cost energy to satisfy Power’s
contractual obligations and to sell into the market at higher prices. The increases at Power were partially offset by interest and depreciation costs related to facilities in Albany, New York, which
commenced operation in July 2005 and Lawrenceburg, Indiana, which commenced operation in June 2004. The year-over-year detail for these variances for these periods are discussed in more detail below: Operating Revenues Energy Costs Operation and Maintenance Write-Down of Assets Depreciation and Amortization Other Income and 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 The $30 million increase for the year ended December 31, 2006 as compared to 2005 was due to increases of $239 million in generation revenues and $27 million in trading revenues, which were
partially offset by a decrease of $236 million in gas supply revenues. The $861 million increase for the year ended December 31, 2005, as compared to 2004, was due to increases of $543 million in generation revenues and $368 million in gas supply revenues, which were
partially offset by a decrease of $50 million in trading revenues. Generation The $239 million increase in generation revenues for the year ended December 31, 2006, as compared to 2005, was primarily due to an increase of $238 million from higher sales volumes in the various
power pools, supported by improved nuclear operations and the commencement of the commercial operations of Linden in May 2006 and BEC in July 2005, partially offset by lower pool prices. Also
contributing to the increase was $92 million of higher BGS contract revenues due to higher contract prices which were partly offset by a reduction in load being served under the fixed-price BGS contracts
and termination of BGS hourly contracts in May 2006. The increases were partially offset by a decrease of $58 million due to certain wholesale contracts ending in 2005 and early 2006 and $33 million of
unrealized losses on asset-backed electric forward contracts. The $543 million increase in generation revenues for the year ended December 31, 2005, as compared to 2004, was primarily due to higher revenues of $226 million from higher pricing and increased
sales in the various power pools supported by improved nuclear capacity, partially offset by reduced load being served under the fixed-priced BGS contracts. Also contributing to the increase were increases
of $103 million from new wholesale contracts, $74 million from operations in New York, largely due to the commencement of 64
For the Years
Ended December 31,
2006 vs 2005
2005 vs 2004
2006
2005
2004
Increase
(Decrease)
%
Increase
(Decrease)
%
(Millions)
(Millions)
$
6,057
$
6,027
$
5,166
$
30
—
$
861
17
$
3,955
$
4,266
$
3,553
$
(311
)
(7
)
$
713
20
$
958
$
939
$
948
$
19
2
$
(9
)
(1
)
$
44
$
—
$
—
$
44
N/A
$
—
N/A
$
140
$
114
$
98
$
26
23
$
16
16
$
66
$
144
$
117
$
(78
)
(54
)
$
27
23
$
(148
)
$
(100
)
$
(90
)
$
48
48
$
10
11
$
(363
)
$
(318
)
$
(227
)
$
45
14
$
91
40
$
(239
)
$
(226
)
$
(59
)
$
13
6
$
167
N/A
$
—
$
(16
)
$
—
$
16
N/A
$
(16
)
N/A
BEC’s operations, $65 million from RMR revenues, which Power began receiving in 2005 for certain of its generating facilities, and $75 million from increased ancillary services and operating reserves. Gas Supply The $236 million decrease in gas supply revenues for the year ended December 31, 2006, as compared to 2005, was primarily due to decreases of $334 million due to lower demand under the BGSS
contract in 2006 due to a warmer winter heating season and improved customer conservation in 2006 and a $94 million in decreased prices and gas volumes and pipeline capacity sold to other gas
distributors. The decreases were partially offset by an increase of $188 million due to higher prices under the BGSS contract. The $368 million increase in gas supply revenues for the year ended December 31, 2005, as compared to 2004, was principally due to higher prices under the BGSS contract for gas and pipeline capacity
partially offset by lower demand, largely resulting from a warmer winter heating season in 2005 as compared to 2004. Trading The $27 million increase in trading revenues for the year ended December 31, 2006, as compared to 2005, was principally due to higher realized gains related to emissions credits. The $50 million decrease in trading revenues for the year ended December 31, 2005, as compared to 2004, resulted principally from reductions in realized gains related to emission credits. Operating Expenses Energy Costs Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS
contract with PSE&G. The $311 million decrease for the year ended December 31, 2006, as compared to 2005, was primarily due to decreases of $267 million from lower pool prices and lower demand under the BGS
contract, $144 million from a reduced volume of gas purchased to satisfy Power’s BGSS obligations, somewhat offset by higher gas prices related to inventory for the 2005/2006 winter heating season, and
$58 million due to favorable pricing of fuel-related asset-backed transactions in 2006. These decreases were partially offset by $80 million of losses realized on gas hedges in 2006, an increase of $42 million
in fuel costs and an increase of $35 million in transmission fees. The increase in fuel costs was largely due to higher volumes of gas purchased to meet increased production by the gas-fired plants, including
Linden and BEC, and higher oil prices, partially offset by lower gas prices during 2006 and a lower volume of oil purchases due to reduced running times of certain of the oil-fired plants in 2006. The $713 million increase for the year ended December 31, 2005, as compared to 2004, was primarily due to increased generation costs, reflecting higher fossil fuel prices and higher prices on an
increased volume of purchased power for new contracts and higher prices for gas purchased to satisfy Power’s BGSS obligations. Operation and Maintenance The $19 million increase for the year ended December 31, 2006, as compared to 2005, was principally due to higher maintenance costs of $60 million related to certain of the fossil plants and scheduled
outages at the nuclear units. These increases were partially offset by the absence of a $14 million restructuring charge recorded in 2005 related to Nuclear’s workforce realignment plan, a decrease of $10
million in payroll and benefits due to a reduction in employees and a decrease of $14 million in fees paid to Services for information technology and various administrative services. The $9 million decrease for the year ended December 31, 2005, as compared to 2004, was primarily due to a decrease of $36 million in equipment repair costs related to outages at the nuclear facilities,
$9 million of lower real estate taxes, $5 million of lower transmission fees in the power pools, $4 million of lower expenses related to reduced trading activities in 2005 and an $8 million settlement of co-
owner billings in 2004 related to Power’s jointly-owned facilities. The decreases were substantially offset by an increase of $11 million in pension, postretirement and other employee benefits, a $16 million
increase attributable to repairs for 65
outages at the fossil generation plants, the aforementioned $14 million restructuring charge and a $12 million settlement with the U.S. Department of Energy (DOE) in 2004. Write-Down of Assets The $44 million write-down of assets recorded in 2006 related to four turbines for which Power has no immediate use and intends to sell. For additional information, see Note 4. Discontinued
Operations, Dispositions, Acquisitions and Impairments of the Notes. Depreciation and Amortization The $26 million increase for the year ended December 31, 2006, as compared to 2005, was primarily due to the Linden and BEC plants being placed into service in May 2006 and July 2005, respectively. The $16 million increase for the year ended December 31, 2005, as compared to 2004, was primarily due to the BEC facility being placed into service and a higher depreciable asset base in 2005 at
Nuclear. Other Income and Deductions The $78 million decrease for the year ended December 31, 2006, as compared to 2005, was primarily due to decreased net realized income of $29 million and increased realized losses of $19 million
related to the NDT Funds. Also contributing to the decrease were charges recorded in 2006 of $14 million for an other-than-temporary impairment of certain NDT Fund securities and $14 million for
penalties related to negotiations concerning environmental concerns and an alternate pollution reduction plan for Power’s Hudson unit. The $27 million increase for the year ended December 31, 2006, as compared to 2004, was primarily due to increased realized gains and income of $13 million related to the NDT Funds, lower realized
losses of $8 million in 2005 on NDT Funds and a $5 million gain from the sale in September 2005 of four gas turbine generators located in Burlington, New Jersey. Interest Expense The $48 million increase for the year ended December 31, 2006, as compared to 2005, was due primarily to lower capitalized interest costs in 2006 related to commencement of operations of the Linden
and BEC facilities. The $10 million increase for the year ended December 31, 2005, as compared to 2004, was due primarily to $8 million of lower capitalized interest costs in 2005 related to commencement of operations
of BEC. Income Taxes The $45 million increase for the year ended December 31, 2006, as compared to 2005, was primarily due to higher pre-tax income. The $91 million increase for the year ended December 31, 2005, as compared to 2004, was primarily due to an increase of $63 million in taxes on pre-tax income, the recording in 2005 of $15 million of
taxes for the NDT Funds and the reversal in 2004 of $16 million of contingency reserves and other prior period adjustments. Loss from Discontinued Operations, including Loss on Disposal, net of tax On December 29, 2006, Power entered into an agreement to sell its Lawrenceburg generation facility for approximately $325 million and recognized an estimated loss on disposal of $208 million, net of
tax, in December 2006, for the initial write-down of its carrying amount of Lawrenceburg to its fair value less cost to sell. The transaction is anticipated to close in the second quarter of 2007. Losses from
Discontinued Operations of Lawrenceburg, not including the estimated Loss of Disposal, were $31 million, $28 million and $25 million for the years ended December 31, 2006, 2005 and 2004, respectively. On May 27, 2005, Power reached an agreement to sell its Waterford generation facility for approximately $220 million and recognized an estimated loss on disposal of $177 million, net of tax, for the
initial write-down of its carrying amount of Waterford to its fair value less cost to sell. On September 28, 66
2005, Power completed the sale of Waterford and recognized an additional loss of $1 million. Losses from Discontinued Operations of Waterford, not including the Loss of Disposal, were $20 million and
$34 million for the years ended December 31, 2005 and 2004, respectively. See Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes for additional information. Cumulative Effect of a Change in Accounting Principle For the year ended December 31, 2005, Power recorded an after-tax loss in the amount of $16 million due to the required recording of a liability for the fair value of asset-retirement costs primarily
related to its generation plants under FIN 47, which was adopted in December 2005. See Note 3. Asset Retirement Obligations of the Notes for additional information. Energy Holdings For the year ended December 31, 2006, Energy Holdings had Net Income of $275 million, an increase of $58 million as compared to the year ended December 31, 2005. Included in Energy Holdings’
Net Income for 2006 was a $178 million after-tax loss on the sale of RGE, which was more than offset by the $226 million after-tax gain on disposal of Elcho and Skawina. Strong operations combined with
approximately $29 million of after-tax mark-to-market gains on forward gas contracts in 2006 as compared to $3 million of after-tax mark-to-market losses in 2005 at TIE and higher sales volumes at
Sociedad Austral de Electricidad S.A. (SAESA) also contributed to the increase. The increases were partially offset by the absence of an after-tax gain of $43 million from the sale of Resources’ leveraged
lease investment in Generation Station Unit 2 (Seminole) in December 2005. For the year ended December 31, 2005, Energy Holdings had Net Income of $217 million, an increase of $76 million as compared to the year ended December 31, 2004. This increase was primarily due
to higher earnings due to improved operations at TIE and in South America and the aforementioned gain on the sale of Seminole in December 2005. The year-over-year detail for these variances for these periods are discussed in more detail below: Operating Revenues Energy Costs Operation and Maintenance Write-Down of Assets Depreciation and Amortization Income from Equity Method Investments Other Income and Deductions Interest Expense Income Tax Benefit (Expense) Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal The classification of the results of Global’s investments on Energy Holdings’ Consolidated Financial Statements is dependent upon Global’s ownership percentage in the underlying investment which
determines whether the investment is consolidated into Energy Holdings’ Consolidated Financial Statements or if it is accounted for under the equity method of accounting. Global owns 100% of TIE,
SAESA and Electroandes S.A. (Electroandes) and 85% of Prisma 2000 S.p.A. (Prisma). As a result, the revenues, expenses, assets and liabilities of those investments are reflected on Energy Holdings’
Consolidated Financial Statements. Global’s investments in Chilquinta Energia (Chilquinta), Luz del Sur S.A.A. (LDS), GWF, Kalaeloa Partners L.P. ( Kalaeloa) and several other smaller investments are
accounted for under the equity method of accounting. Therefore, Energy Holdings only records its share of the net income from these projects as Income from Equity Method Investments on its
Consolidated Statements of Operations. 67
For the Years
Ended December 31,
2006 vs 2005
2005 vs 2004
2006
2005
2004
Increase
(Decrease)
%
Increase
(Decrease)
%
(Millions)
(Millions)
$
1,357
$
1,302
$
836
$
55
4
$
466
56
$
739
$
675
$
322
$
64
9
$
353
N/A
$
208
$
215
$
171
$
(7
)
(3
)
$
44
26
$
274
$
—
$
—
$
274
N/A
$
—
N/A
$
52
$
46
$
44
$
6
13
$
2
5
$
120
$
124
$
119
$
(4
)
(3
)
$
5
4
$
11
$
(8
)
$
3
$
19
N/A
$
(11
)
N/A
$
(203
)
$
(213
)
$
(223
)
$
(10
)
(5
)
$
(10
)
(4
)
$
39
$
(69
)
$
(45
)
$
108
N/A
$
24
53
$
226
$
18
$
(10
)
$
208
N/A
$
28
N/A
The variances in Operating Revenues, Energy Costs, Operation and Maintenance, Depreciation and Amortization and Income from Equity Method Investments were primarily attributed to Global’s
increased revenues at TIE in 2006, as compared to same period in 2005, primarily due to unrealized gains on forward contracts and a stronger market and stronger spark spread (the difference between the
market price of electricity and the cost of natural gas fuel), the consolidation of Prisma in May 2006, which generated $32 million of revenue, and Global’s sale of a 35% interest in Dhofar Power Company
S.A.O.C. (Dhofar Power) through a public offering on the Omani Stock Exchange in April 2005 and sale of its remaining interest of 46% in November 2006, receiving net proceeds after-tax of
approximately $31 million, the approximate book value of the investment. The variances are also related to favorable foreign currency exchange rates and higher energy sales volumes at SAESA. Operating Revenues The increase of $55 million for the year ended December 31, 2006, as compared to 2005, was due to higher revenues at Global of $128 million, which was primarily related to a $79 million increase at
TIE due to higher unrealized gains on forward contracts which were slightly offset by a reduction in gas sales. Also contributing to the increase at Global was a $78 million increase at SAESA in Chile due
to higher energy sales volumes as well as tariff increases and favorable foreign currency exchange rates, a $24 million increase due to the consolidation of Prisma and $10 million of increased revenue from
Electroandes due to volume and price increases. These increases were partly offset by a $37 million decrease due to the absence of a gain from withdrawal from the Eagle Point Cogeneration Partnership in
the prior year and the absence of $20 million of revenue due to the deconsolidation of Dhofar Power. Offsetting the increases at Global were lower revenues at Resources of $73 million primarily due to the
absence of a $71 million pre-tax gain from the sale of Resources’ interest in Seminole Generation in December 2005 coupled with the absence of $20 million of leveraged lease income in 2006 due to the
Seminole sale, partially offset by a $21 million write-off of a leveraged lease investment with United Airlines in 2005. The increase of $466 million for the year ended December 31, 2005, as compared to 2004, was due to higher revenues at Global of $406 million, including a $279 million increase related to the
consolidation of TIE commencing July 1, 2004 and $136 million due to higher revenues at TIE in the second half of 2005 and a $62 million increase related to SAESA due to higher energy sales volumes
offset by a $43 million decrease related to the deconsolidation of Dhofar Power and the absence of a $35 million gain on the sale of Meiya Power Company Limited (MPC) in 2004. Also contributing to the
increase were higher revenues at Resources of $60 million primarily due to the $71 million pre-tax gain recognized in 2005 from the sale of its interest in Seminole offset by the absence of an $11 million
pre-tax charge recorded due to the termination of the lease investment in the Collins generating facility in 2004. Energy Costs The increase of $64 million for the year ended December 31, 2006, as compared to 2005, was primarily due to a $59 million increase at SAESA due to increased volume and higher spot prices for
energy and an $8 million increase due to the consolidation of Prisma in May 2006, partially offset by a $5 million decrease related to the deconsolidation of Dhofar Power. The increase of $353 million for the year ended December 31, 2005, as compared to 2004, was primarily due to a $219 million increase related to the consolidation of TIE commencing July 1, 2004, a
$99 million increase in energy costs at TIE in the second half of 2005 and a $44 million increase related to SAESA due to significant increases in Energy Costs, offset by a $13 million decrease related to the
deconsolidation of Dhofar Power. Operation and Maintenance The decrease of $7 million for the year ended December 31, 2006, as compared to 2005, was primarily due to a reduction of $9 million at Resources mainly due to a reduction of operating lease expense. The decrease is also due to a $4 million reduction in administrative expenses related to lower corporate assessments, wages and benefits, and legal and consulting expense. These decreases are offset by an $8 million increase at Global due to a $17 million increase related to the operations of SAESA, $5 million increase due to the consolidation of Prisma partially offset by a $9 million decrease at TIE and a $4 million decrease from the deconsolidation of Dhofar Power. 68
The increase of $44 million for the year ended December 31, 2005, as compared to 2004, was primarily due to a $41 million increase related to the consolidation of TIE commencing July 1, 2004 and a
$14 million increase related to SAESA offset by a $6 million decrease related to the deconsolidation of Dhofar Power and a $7 million decrease in energy costs at TIE in the second half of 2005. Write-Down of Assets The $274 million write-down of assets is primarily related to a $263 million pre-tax loss on Global’s sale of its 32% indirect ownership interest in RGE, $4 million pre-tax loss related to the sale of
Global’s interest in Magellan Capital Holdings Corporation (MCHC), and a $7 million pre-tax loss on the impairment of Global’s generation projects in Venezuela. See Note 4. Discontinued Operations,
Dispositions, Acquisitions and Impairments of the Notes. Depreciation and Amortization The increase of $6 million for the year ended December 31, 2006, as compared to 2005, was primarily due to a $3 million increase at Resources and a $3 million increase at Global due to a $4 million
increase related to the consolidation of Prisma and an increase of $3 million at SAESA, offset by a $4 million decrease resulting from the deconsolidation of Dhofar Power. The increase of $2 million for the year ended December 31, 2005, as compared to 2004, was primarily due to an $8 million increase related to the consolidation of TIE commencing July 1, 2004 and a $2
million increase related to Resources due to the conversion of the Delta and Northwest leases from leveraged leases to operating leases, offset by a $9 million decrease related to the deconsolidation of
Dhofar Power. Income from Equity Method Investments The decrease of $4 million for the year ended December 31, 2006, as compared to 2005, was primarily driven by the absence of $12 million of earnings due to the sale of RGE in 2006 partially offset by
the absence of foreign currency losses in 2005 from Prisma of $8 million. The increase of $5 million for the year ended December 31, 2005, as compared to 2004, was primarily due to a $20 million increase due to stronger results in South America (RGE and Chilquinta)
offset by an $11 million decrease related to the loss of earnings associated with the sale of Global’s equity interest in MPC in December 2004 and a $3 million decrease related to Global’s investment in
Prisma. Other Income and Deductions The increase of $19 million for the year ended December 31, 2006, as compared to 2005, was primarily due to an increase in interest and dividend income of approximately $10 million and lower losses
in foreign currency transactions due to favorable currency fluctuations mainly for Prisma operations in Italy. The decrease of $11 million for the year ended December 31, 2005, as compared to 2004, was primarily due to a loss on early extinguishment of debt of $7 million and foreign currency transaction losses
of $9 million primarily on notes receivables from Prisma, partially offset by interest income from PSEG related to inter-company loans. Interest Expense The decrease of $10 million for the year ended December 31, 2006, as compared to 2005, was mainly due to a decrease in Energy Holdings’ debt outstanding and a net decrease of $2 million resulting
from the consolidation of Prisma and the deconsolidation of Dhofar Power. The $10 million decrease for the year ended December 31, 2005, respectively, as compared to 2004, was primarily due an $11 million decrease related to the deconsolidation of Dhofar Power in May
2005 and an $8 million decrease related to Resources due to a reduction in intercompany interest charges offset by a $9 million increase related to the consolidation of TIE commencing on July 1, 2004. 69
Income Taxes The decrease of $108 million for the year ended December 31, 2006, as compared to 2005, was primarily attributable to a tax benefit resulting from Global’s sale of its 32% indirect ownership interest in
RGE and sale of SAESA’s 50% interest in Empresa de Energia Rio Negro S.A. (Argentine utility operation). The $24 million increase for the year ended December 31, 2005, as compared to 2004, was primarily due to the recording of $11 million of U.S. tax associated with repatriation of funds under the
American Jobs Creation Act of 2004 (Jobs Act), an increase in the mix of domestic earnings for Global due to improved results at TIE, taxes recognized of $28 million from the sale of Seminole and
additional benefits resulting from revisions to Resources’ lease runs performed in the fourth quarter of 2005. For further information on lease runs, see below in Resources’ forecast of state taxable income
and tax liability over the relevant lease terms. This forecast was embedded in the lease reruns and led to an income tax benefit of $43 million in 2004 to reflect the cumulative benefit of this adjustment. This
benefit was largely offset by the tax impact associated with a $31 million decrease in leveraged lease revenue. Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax Elcho and Skawina In 2006, Global sold its interest in two coal-fired plants in Poland, Elcho and Skawina. Proceeds, net of transaction costs, were $476 million, resulting in a gain of $227 million net of tax expense of $142
million. Income (Loss) from Discontinued Operations related to Elcho and Skawina for the years ended December 31, 2006, 2005 and 2004 was $227 million, $18 million and $(10) million, respectively. See
Note 4. Discontinued Operations, Dispositions, Acquisitions and Impairments of the Notes for additional information. LIQUIDITY AND CAPITAL RESOURCES The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, PSE&G, Power and Energy
Holdings. Financing Methodology PSEG, PSE&G, Power and Energy Holdings Capital requirements for PSE&G, Power and Energy Holdings are met through liquidity provided by internally generated cash flow and external financings. PSEG expects to be able to fund existing
commitments, reduce debt and meet dividend requirements using internally generated cash. PSEG, Power and Energy Holdings from time to time make equity contributions or otherwise provide credit
support to their respective direct and indirect subsidiaries to provide for part of their capital and cash requirements, generally relating to long-term investments. PSEG does not intend to contribute
additional equity to Energy Holdings. At times, PSEG utilizes intercompany dividends and intercompany loans (except however, that PSE&G may not, without prior BPU approval, and Fossil, Nuclear and ER&T may not without prior FERC approval make loans to their affiliates) to satisfy various
subsidiary or parental needs and efficiently manage short-term cash. Any excess funds are invested in short-term liquid investments. External funding to meet PSEG’s, PSE&G’s and Power’s needs and a majority portion of the requirements of Energy Holdings consist of corporate finance transactions. The debt incurred is the direct
obligation of those respective entities. Some of the proceeds of these debt transactions may be used by the respective obligor to make equity investments in its subsidiaries. As discussed below, depending on the particular company, external financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loans,
commercial paper and/or project financings. Some of these transactions involve special purpose entities (SPEs), formed in accordance with applicable tax and legal requirements in order to achieve specified
financial advantages, such as favorable legal liability treatment. PSEG consolidates SPEs, as applicable, in accordance with FIN No. 46, “Consolidation of Variable Interest Entities (VIEs)” (FIN 46). See
Note 2. Recent Accounting Standards of the Notes. 70
The availability and cost of external capital is affected by each entity’s performance, as well as by the performance of their respective subsidiaries and affiliates. This could include the degree of
structural separation between PSEG and its subsidiaries and the potential impact of affiliate ratings on consolidated and unconsolidated credit quality. Additionally, compliance with applicable financial
covenants will depend upon future financial position, earnings and net cash flows, as to which no assurances can be given. Over the next several years, PSEG, PSE&G, Power and Energy Holdings may be required to extinguish or refinance maturing debt and, to the extent there is not sufficient internally generated funds,
may incur additional debt and/or provide equity to fund investment activities. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at
current levels and reasonable interest rates may adversely affect PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective financial condition, results of operations and net cash flows. From time to time, PSEG, PSE&G, Power and Energy Holdings may repurchase portions of their respective debt securities using funds from operations, asset sales, commercial paper, debt issuances,
equity issuances and other sources of funding and may make exchanges of new securities, including common stock, for outstanding securities. Such repurchases may be at variable prices below, at or above
prevailing market prices and may be conducted by way of privately negotiated transactions, open-market purchases, tender or exchange offers or other means. PSEG, PSE&G, Power and Energy Holdings
may utilize brokers or dealers or effect such repurchases directly. Any such repurchases may be commenced or discontinued at any time without notice. Energy Holdings A portion of the financing for Global’s investments is normally provided by non-recourse financing transactions. These consist of loans from banks and other lenders that are typically secured by project
assets and cash flows. Non-recourse transactions generally impose no material obligation on the parent-level investor to repay any debt incurred by the project borrower. The consequences of permitting a
project-level default include the potential for loss of any invested equity by the parent. However, in some cases, certain obligations relating to the investment being financed, including additional equity
commitments, may be guaranteed by Global and/or Energy Holdings for their respective subsidiaries. PSEG does not provide guarantees or credit support to Energy Holdings or its subsidiaries. Operating Cash Flows PSEG, PSE&G, Power and Energy Holdings PSEG expects strong cash from operations primarily driven by earnings from Power supported by improved energy margins and capacity markets. Operating cash flows are expected to be sufficient to
fund capital expenditures and shareholder dividend payments, with excess cash available to invest in the business, reduce debt and/or repurchase common stock. PSEG For the year ended December 31, 2006, PSEG’s operating cash flow increased by approximately $959 million from $970 million to $1.9 billion, as compared to 2005, due to net increases from its
subsidiaries as discussed below. For the year ended December 31, 2005, PSEG’s operating cash flow decreased by approximately $635 million from $1.6 billion to $970 million, as compared to 2004, primarily due to net decreases at
Power for its working capital requirements, discussed below. PSE&G PSE&G’s operating cash flow increased approximately $115 million from $689 million to $804 million for the year ended December 31, 2006, as compared to 2005, primarily due to a decrease in customer
receivables, reflecting lower sales volumes due to a warmer winter heating season and lower gas prices in 2006. PSE&G’s operating cash flow decreased approximately $7 million from $696 million to $689 million for the year ended December 31, 2005, as compared to 2004. 71
Power Power’s operating cash flow increased approximately $907 million from $136 million to $1 billion for the year ended December 31, 2006, as compared to 2005, due to a significant reduction in margin
requirements and fuel inventories, largely resulting from decreases in commodity prices. Power’s operating cash flow decreased approximately $371 million from $507 million to $136 million for the year ended December 31, 2005, as compared to 2004 primarily due to increased margin
requirements and an increase in fuel inventory because of significantly increased commodity prices. Energy Holdings Energy Holdings’ operating cash flow decreased approximately $114 million from $273 million to $159 million for the year ended December 31, 2006, as compared to 2005. The decrease was mainly due
to taxes paid related to the sale of Elcho, Skawina and RGE in 2006. The proceeds from the these sales are included in Cash Flows from Investing Activities on Energy Holdings’ Consolidated Statements
of Cash Flows. Energy Holdings’ operating cash flow decreased approximately $130 million from $403 million to $273 million for the year ended December 31, 2005, as compared to 2004, due primarily to a decrease
in Resources’ cash flows, which was driven by the timing of receipt of tax benefits, and the monetization of the remaining receivables of PETAMC in 2004. Common Stock Dividends Dividend payments on common stock for the year ended December 31, 2006 were $2.28 per share and totaled approximately $574 million. Dividend payments on common stock for the year ended
December 31, 2005 were $2.24 per share and totaled approximately $541 million. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative
investment opportunities and other factors. On January 17, 2007, PSEG announced an increase in its dividend from $0.57 to $0.585 per share for the first quarter of 2007. This quarterly increase reflects an
indicated annual dividend rate of $2.34 per share. Short-Term Liquidity PSEG, PSE&G, Power and Energy Holdings In December 2006, PSEG and Power established new credit facilities, which are available for letters of credit and short-term funding, replacing their previous credit facilities. PSEG’s new facility also
provides liquidity backup for its $1 billion commercial paper program. Also in December 2006, PSE&G amended its $600 million credit facility to update the terms and extend the expiration date to June
2011. PSEG, PSE&G, Power and Energy Holdings each believe that sufficient liquidity exists to fund their respective short-term cash needs. As of December 31, 2006, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $3.3 billion of available liquidity under these facilities. In
addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted to availability and use to the specific companies as listed below. As of December 31, 2006,
PSEG has no loans outstanding under its uncommitted facility and PSE&G had $31 million of loans outstanding under its uncommitted facility. 72
Company PSEG: 5-year Credit Facility Uncommitted Bilateral Agreement PSE&G: 5-year Credit Facility Uncommitted Bilateral Agreement PSEG and Power:(A) Bilateral Credit Facility Power: 5-year Credit Facility Bilateral Credit Facility Energy Holdings: 5-year Credit Facility(B) (B) Energy Holdings/Global/Resources joint and several co-borrower facility. (C) These amounts relate to letters of credit outstanding. Power As of December 31, 2006, Power had borrowed $54 million from PSEG in the form of an intercompany loan. During the year ending December 31, 2006, Power’s required margin postings for sales contracts entered into in the normal course of business decreased as commodity prices declined. The required
margin postings will fluctuate based on volatility in commodity prices. Should commodity prices rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract
obligations are fulfilled, liquidity requirements are reduced. In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit
rating to below investment grade, which represents at least a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide performance
assurance, generally in the form of a letter of credit or cash. Providing this support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset
portfolio. Power believes it has sufficient liquidity to meet any required posting of collateral resulting from a credit rating downgrade. See Note 12. Commitments and Contingent Liabilities of the Notes for
further information. Energy Holdings Energy Holdings and its subsidiaries had $98 million in cash, including $38 million invested offshore as of December 31, 2006. In addition, as of December 31, 2006, Energy Holdings had an outstanding
demand loan receivable from PSEG of $28 million. See External Financings—Energy Holdings below for Energy Holdings’ additional use of its excess cash. 73
Expiration
Date
Total
Facility
Primary
Purpose
Usage
as of
December 31,
2006
Available
Liquidity
as of
December 31,
2006
(Millions)
Dec 2011
$
1,000
CP Support/Funding/Letters of Credit
$
354
$
646
N/A
$
N/A
Funding
$
—
$
N/A
June 2011
$
600
CP Support/Funding/Letters of Credit
$
—
$
600
N/A
N/A
Funding
$
31
$
N/A
June 2007
$
200
Funding/Letters of
Credit
$
19
(C)
$
181
Dec 2011
$
1,600
Funding/Letters of
Credit
$
20
(C)
$
1,580
March 2010
$
100
Funding/Letters of
Credit
$
—
$
100
June 2010
$
150
Funding/Letters of
Credit
$
6
(C)
$
144
(A)
PSEG/Power joint and several co-borrower facilities.
External Financings PSEG On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Prior to September 1, 2006, PSEG had purchased shares on the open market to meet the exercise of
stock options. As of December 31, 2006, PSEG issued 410,365 shares of its common treasury stock in connection with settling stock options for approximately $15 million. For the year ended December 31, 2006, PSEG issued approximately 1 million shares of its common stock under its Dividend Reinvestment Program and its Employee Stock Purchase Program for
approximately $68 million. In October 2006, PSEG repaid $49 million of its 6.89% Senior Notes which are due in equal installment payments through 2009. In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity
investment in the trust. PSE&G On June 23, 2006, PSE&G repaid at maturity $175 million of its Floating Rate Series A First and Refunding Mortgage Bonds. On March 1, 2006, PSE&G repaid at maturity $147 million of its 6.75% Series UU First and Refunding Mortgage Bonds. In December 2006, PSE&G issued $250 million of 5.70% Secured Medium Term Notes Series D due 2036. The proceeds were used to replace in part the aforementioned matured Floating Rate Series A
and 6.75% Series UU First and Refunding Mortgage Bonds. For the year ended December 31, 2006, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II) repaid approximately $155 million and $8
million, respectively, of their transition bonds. On January 2, 2007, PSE&G repaid at maturity $113 million of its 6.25% Series WW First and Refunding Mortgage Bonds. Power In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes. Energy Holdings In January 2006, Energy Holdings redeemed all $309 million of its 7.75% Senior Notes due in 2007. On February 17, 2006, the maturity of the Odessa–Ector Power Partners, L.P. (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above
LIBOR. On September 29, 2006, an interest rate swap took effect which converted the floating LIBOR interest rate on approximately 80% of Odessa’s debt to a fixed rate of 5.4275% through December
31, 2009. On October 23, 2006, Energy Holdings redeemed $300 million of its $507 million outstanding 8.625% Senior Notes due in 2008. During 2006, Energy Holdings made cash distributions to PSEG totaling $520 million in the form of returns of capital. Also during 2006, Energy Holdings’ subsidiaries repaid approximately $51 million of non-recourse debt, of which $43 million primarily related to SAESA and TIE, $6 million by Resources and $2
million by EGDC. Debt Covenants PSEG, PSE&G, Power and Energy Holdings PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective credit agreements may contain maximum debt to equity ratios, minimum cash flow tests and other restrictive covenants and conditions to
borrowing. Compliance with applicable financial covenants will depend upon the respective future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to
which no assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as financial performance or
liquidity measures. The debt 74
underlying the preferred securities of PSEG, which is presented in Long-Term Debt in accordance with FIN 46, is not included as debt when calculating these ratios, as provided for in the various credit
agreements. Energy Holdings’ credit agreement also contains customary provisions under which the lender could refuse to advance loans in the event of a material adverse change in the borrower’s business or
financial condition. PSEG Financial covenants contained in PSEG’s credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including
commercial paper and loans, certain letters of credit not related to collateral postings for commodity/energy contracts and similar instruments) to total capitalization (including preferred securities
outstanding and excluding any impacts for Accumulated Other Comprehensive Income adjustments related to marking energy contracts to market and equity reductions from the funded status of pensions
or benefit plans associated with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”) covenant. This covenant requires that such ratio not be more than
70.0%. As of December 31, 2006, PSEG’s ratio of debt to capitalization (as defined above) was 51.6%. PSE&G Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total
capitalization covenant. This covenant requires that such ratio will not be more than 65.0%. As of December 31, 2006, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 48.5%. In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of
earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2006, PSE&G’s Mortgage coverage ratio was 4.1 to 1 and the
Mortgage would permit up to approximately $2.1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements. Power Financial covenants contained in Power’s credit facility include a ratio of debt to total capitalization covenant. The Power ratio is the same debt to total capitalization calculation as set forth above for
PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets). This covenant requires that such ratio will not exceed 65.0%. As of December 31, 2006,
Power’s ratio of debt to total capitalization (as defined above) was 38.4%. Energy Holdings Energy Holdings’ bank revolving credit agreement has a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than
or equal to 1.75. As of December 31, 2006, Energy Holdings’ coverage of this covenant was 3.53. Additionally, Energy Holdings must maintain a ratio of net debt (recourse debt offset by funds loaned to
PSEG) to EBITDA of less than 5.25. As of December 31, 2006, Energy Holdings’ ratio under this covenant was 2.59. Energy Holdings is a co-borrower under this facility with Global and Resources, which
are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the
satisfaction of certain financial covenants. Net cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts
under the credit agreement. Net cash proceeds from asset sales during any 12-month period in excess of 10% of total assets must be retained by Energy Holdings or used to repay the debt of Energy
Holdings, Global or Resources. Energy Holdings’ indenture with respect to its senior notes does not permit liens securing indebtedness in excess of 10% of consolidated net tangible assets as calculated under the terms of the
indenture. The terms of Energy Holdings’ Senior Notes allow the holders to demand repayment if a transaction or series of related transactions causes the assets of Resources to be reduced by 20% or more
and as a direct result there is a downgrade of ratings. 75
Cross Default Provisions PSEG, PSE&G, Power and Energy Holdings The PSEG bank credit agreement contains default provisions under which a default by it in an aggregate amount of $50 million or greater would result in the potential acceleration of payment under
this agreement. Under certain conditions, a default by PSE&G or Power in an aggregate amount of $50 million or greater would also result in potential acceleration of payment under this agreement. PSEG
has removed Energy Holdings from all cross default provisions. PSEG’s bank credit agreement and note purchase agreements related to private placement of debt (collectively, Credit Agreements) contain cross default provisions under which certain payment
defaults by PSE&G or Power, certain bankruptcy events relating to PSE&G or Power, the failure by PSE&G or Power to satisfy certain final judgments or the occurrence of certain events of default under the
financing agreements of PSE&G or Power, would each constitute an event of default under the PSEG Credit Agreements. Under the note purchase agreements, it is also an event of default if PSE&G or Power
ceases to be wholly-owned by PSEG. Under the bank credit agreement, both PSE&G and Power would have to cease to be wholly-owned by PSEG before an event of default would occur. PSE&G PSE&G’s Mortgage has no cross defaults. The PSE&G Medium-Term Note Indenture has a cross default to the PSE&G Mortgage. The PSE&G credit agreement has a provision under which a default by
PSE&G in the aggregate of $50 million or greater would result in an event of default and the potential acceleration of payment under that agreement. Power The Power Senior Debt Indenture contains a default provision under which a default by Power, Nuclear, Fossil or ER&T in an aggregate amount of $50 million or greater would result in an event of
default and the potential acceleration of payment under the indenture. There are no cross defaults within Power’s indenture from PSEG, Energy Holdings or PSE&G. The Power credit agreement also has a provision under which a default by Power, Nuclear, Fossil or ER&T in an aggregate amount of $50 million or greater would result in an event of default and the
potential acceleration of payment under that agreement. Energy Holdings Energy Holdings’ credit agreement and Senior Note Indenture contain default provisions under which a default by it, Resources or Global in an aggregate amount of $25 million or greater would result
in an event of default and the potential acceleration of payment under that agreement or the Indenture. Ratings Triggers PSEG, PSE&G, Power and Energy Holdings The debt indentures and credit agreements of PSEG, PSE&G, Power and Energy Holdings do not contain any material ‘ratings triggers’ that would cause an acceleration of the required interest and
principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt
and certain collateral requirements. PSE&G In accordance with the BPU approved requirements under the BGS contracts that PSE&G enters into with suppliers, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to
lose its investment grade rating, PSE&G would be required to file with the BPU a plan to assure continued payment for the BGS requirements of its customers. PSE&G is the servicer for the bonds issued by Transition Funding and Transition Funding II. If PSE&G were to lose its investment grade rating, PSE&G would be required to remit collected cash daily to
the bond trustee. Currently, cash is remitted monthly. 76
Power In connection with the management and optimization of Power’s asset portfolio, ER&T maintains underlying agreements that require Power, as its guarantor under performance guarantees, to satisfy
certain creditworthiness standards. In the event of a deterioration of Power’s credit rating to below an investment grade rating, many of these agreements allow the counterparty to demand that ER&T
provide performance assurance, generally in the form of a letter of credit or cash. As of December 31, 2006, if Power were to lose its investment grade rating and assuming all the counterparties to
agreements in which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post collateral in an amount equal to
approximately $578 million. See Note 12. Commitments and Contingent Liabilities of the Notes. Credit Ratings PSEG, PSE&G, Power and Energy Holdings Following the termination of the Merger Agreement in September 2006, credit ratings remained unchanged as shown in the table below. Standard & Poor’s (S&P) affirmed its “BBB” corporate credit
rating for PSEG, Power, and PSE&G. S&P revised its outlook from watch developing to negative. Moody’s Investors Service (Moody’s) affirmed its credit ratings for PSEG and PSE&G while revising the
outlooks from stable to negative. The ratings and outlooks for Power and Energy Holdings were unchanged by Moody’s. Fitch Ratings (Fitch) announced there would be no immediate impact on ratings
and outlooks for PSEG and its subsidiaries. At that time, the agencies noted that the ratings below were predicated on continued improvement in financial metrics, specifically operating cash flows and
ongoing deleveraging, as well as continued strong operating performance from Power’s generating units and reasonable outcomes to PSE&G’s pending electric and gas rate cases. If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities and serve to materially
increase those companies’ cost of capital and limit their access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will
continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Each rating given by an agency should be evaluated
independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. PSEG: Outlook Preferred Securities Commercial Paper Senior Unsecured Debt PSE&G: Outlook Mortgage Bonds Preferred Securities Commercial Paper Power: Outlook Senior Notes Energy Holdings: Outlook Senior Notes (B) S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. (C) Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities. 77
Moody’s (A)
S&P (B)
Fitch (C)
Neg
Neg
Pos
Baa3
BB+
BBB–
P2
A3
F2
Baa2
BBB–
BBB
Neg
Neg
Stable
A3
A–
A
Baa3
BB+
BBB+
P2
A3
F2
Stable
Neg
Pos
Baa1
BBB
BBB
Neg
Neg
Neg
Ba3
BB–
BB
(A)
Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. /I 8iuok 0p
Other Comprehensive Income PSEG, Power and Energy Holdings For the year ended December 31, 2006, PSEG, PSE&G, Power and Energy Holdings had Other Comprehensive Income of $706 million, $5 million, $483 million and $217 million, respectively, due
primarily to a reduction in the net unrealized losses on derivatives accounted for as hedges in accordance with SFAS 133 at Power and foreign currency translation adjustments at Energy Holdings. During the year ended December 31, 2006, Power’s Accumulated Other Comprehensive Loss decreased from $487 million to $177 million. The primary cause was a decrease of approximately $310
million related to energy and related contracts that qualify for hedge accounting that were entered into by Power in the normal course of business. During the year ended December 31, 2006, the decrease in
gas and electric prices resulted in a reduction in unrealized losses on many of those contracts, which are recorded in Accumulated Other Comprehensive Loss. This decrease was partially offset by a $173
million adjustment recorded at Power in connection with the adoption of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158). As of December 31, 2006, Energy Holdings had Accumulated Other Comprehensive Income of $103 million. The primary reasons for the improvement, as compared to the Accumulated Other
Comprehensive Loss of $110 million as of December 31, 2005, were the realization of losses on Brazilian currency as a result of the sale of RGE and the unwinding of an interest rate swap due to the sale of
Global’s facilities in Poland. 78
PSEG, PSE&G, Power and Energy Holdings It is expected that the majority of each subsidiary’s capital requirements over the next five years will come from internally generated funds. Projected construction and investment expenditures,
excluding nuclear fuel purchases, for PSEG’s subsidiaries for the next five years are presented in the table below. These amounts are subject to change, based on various factors. PSE&G: Facility Support Environmental/Regulatory Facility Replacement System Reinforcement New Business Total PSE&G Power: Hudson Environmental
2007
2008
2009
2010
2011
(Millions)
$
41
$
77
$
76
$
45
$
48
44
30
31
28
28
173
175
178
165
179
183
183
185
165
161
164
163
161
157
159
605
628
631
560
575
68
143
229